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, 2010
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	32-0058047
(State or Other Jurisdiction of	(I.R.S. Employer
Incorporation or Organization)	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	Name of Each Exchange on Which Registered
Common stock, without par value	New York Stock Exchange

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

None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act of 1933.  Yes þ     No o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Securities Exchange Act of 1934.  Yes o     No þ

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes þ     No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes þ     No o

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

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

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

Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes o     No þ

The aggregate market value of the registrant’s common stock held by non-affiliates on June 30, 2010 was approximately $2.6 billion, based on the closing sale price as reported on the New York Stock Exchange. For purposes of this computation, all executive officers, directors and 10% beneficial owners of the registrant are assumed to be affiliates. Such determination should not be deemed an admission that such officers, directors and beneficial owners are, in fact, affiliates of the registrant.

The number of shares of the Registrant’s Common Stock, without par value, outstanding as of February 18, 2011 was 50,764,411.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Registrant’s definitive Proxy Statement for the Registrant’s 2011 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, 2010

INDEX

		Page
PART I			4
Item 1.	Business		4
Item 1A.	Risk Factors		16
Item 1B.	Unresolved Staff Comments		25
Item 2.	Properties		25
Item 3.	Legal Proceedings		26
PART II			27
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		27
Item 6.	Selected Financial Data		29
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		31
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		54
Item 8.	Financial Statements and Supplementary Data		56
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		109
Item 9A.	Controls and Procedures		109
Item 9B.	Other Information		110
PART III			110
Item 10.	Directors, Executive Officers, and Corporate Governance		110
Item 11.	Executive Compensation		110
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		110
Item 13.	Certain Relationships and Related Transactions, and Director Independence		111
Item 14.	Principal Accounting Fees and Services		111
PART IV			112
Item 15.	Exhibits and Financial Statement Schedules		112
Signatures			117
Exhibits			118
EX-3.2
EX-10.91
EX-10.92
EX-21
EX-23.1
EX-31.1
EX-31.2
EX-32
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT

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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, Limited Partnership, the sole member of METC and a 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;

•  “Detroit Edison” are references to The Detroit Edison Company, a wholly-owned subsidiary of DTE Energy;

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

•  “FERC” are references to the Federal Energy Regulatory Commission;

•  “FPA” are references to the Federal Power Act;

•  “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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•  “MISO” are references to 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.

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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 Detroit Edison, 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 currently operate high-voltage systems in Michigan’s Lower Peninsula and portions of Iowa, Minnesota, Illinois, Missouri and Kansas 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.

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, co-operatives, 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 emerging long-term energy policy. 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 Forecasts and Operating Results Trends” for additional details about our five-year capital investment program totaling $3.9 billion for the period 2011 through 2015. Additionally, 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 expected rate base and therefore our revenues. 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 $1.5 billion from 2011 through 2015 at our Regulated Operating Subsidiaries in order to maintain and replace the current transmission infrastructure, enhance system integrity and reliability and accommodate load growth.

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Generator Interconnections

We expect to invest approximately $1.0 billion from 2011 through 2015 to develop and build transmission infrastructure to support generator interconnections. In 2010, ITC received the initial MISO approval of the Thumb Loop Project located in ITCTransmission’s region. The Thumb Loop Project is a 140-mile, double-circuit 345 kV transmission line and three 345 kV 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.

Based on the anticipated growth of generating resources, we also foresee the need to construct additional transmission facilities that will provide interconnection opportunities for those wind facilities. The backbone transmission network, transmission for wind interconnection and for interconnection of other generating facilities may provide additional investment opportunities.

Development Projects

We expect to invest approximately $1.4 billion from 2011 through 2015 to construct our portions of various development projects that we are currently advancing. We are pursuing strategic development opportunities for transmission construction related to building regional transmission facilities, primarily to improve overall grid reliability, lower electricity congestion, enhance competitive markets and facilitate interconnections of new generating resources, including wind generation and other renewable resources. We have pursued the opportunity to invest in two projects in Kansas, through ITC Great Plains, known as the Spearville-Knoll-Axtell transmission project (the “KETA Project”) and the Kansas V-Plan Project transmission project running from Spearville substation to Medicine Lodge, Kansas. ITC Great Plains has established a formula rate for these two projects and other projects within the SPP region. In addition, in 2009, we announced the Green Power Express project, consisting of a network of transmission lines that would facilitate the movement of power from the wind-abundant areas in the Dakotas, Minnesota and Iowa to Midwest load centers that demand clean, renewable energy. Portions of the Green Power Express project fall within the service territory of ITC Midwest. Based on proposals by RTOs, including MISO and the SPP, we are exploring additional strategic opportunities to upgrade the transmission grid within the MISO and SPP regions and surrounding regions with a backbone transmission network, as well as other transmission investment opportunities.

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 17 to the consolidated financial statements.

Operations

As transmission-only companies, our Regulated Operating Subsidiaries function as conduits, allowing for power from generators to be transmitted to local distribution systems either entirely through their own systems or in conjunction with neighboring transmission systems. Third parties then transmit power through these local distribution systems to end-use consumers. The transmission of electricity by our Regulated Operating Subsidiaries is a central function to the provision of electricity to residential, commercial and industrial end-use consumers. The operations performed by our Regulated Operating Subsidiaries fall into the following categories:

•  asset planning;

•  engineering, design and construction;

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•  maintenance; and

•  real time operations.

Asset Planning

Our Asset Planning group uses detailed system models and long-term load forecasts to develop our system expansion capital plans. The expansion plans identify projects that would address potential future reliability issues and/or produce economic savings for customers by eliminating constraints.

Asset Planning 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

Our 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 some of our engineering and design and all of our 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, which is a division of Asplundh Tree Expert Co., to perform the majority of their maintenance. The agreements provide us with access to an experienced and scalable workforce with knowledge of our system at an established rate. The agreements are scheduled to terminate on August 29, 2013, but automatically renew for additional five year terms unless terminated by either party.

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 MISO 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. Similar system operations services for ITC Great Plains will be provided as new transmission lines are placed in service.

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 the 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.

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Operating Contracts

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

ITCTransmission

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

Generator Interconnection and Operation Agreement.  Detroit Edison 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 Detroit Edison’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 Detroit Edison 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 Detroit Edison regarding, among other things, the operation and interconnection of Detroit Edison’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

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rights of any third parties that had rights to use or occupy the premises or the facilities prior to April 1, 2001 in a manner not inconsistent with METC’s permitted uses.

METC pays Consumers Energy annual rent of $10.0 million, in equal quarterly installments, for the easement and related rights under the Easement Agreement. Although METC and Consumers Energy share the use of the premises and the facilities covered by the Easement Agreement, METC pays the entire amount of any rentals, property taxes, inspection fees and other amounts required to be paid to third parties with respect to any use, occupancy, operations or other activities on the premises or the facilities and is generally responsible for the maintenance of the premises and the facilities used for electric transmission at its expense. METC also must maintain commercial general liability insurance protecting METC and Consumers Energy against claims for personal injury, death or property damage occurring on the premises or the facilities and pay for all insurance premiums. METC is also responsible for patrolling the premises and the facilities by air at its expense at least annually and to notify Consumers Energy of any unauthorized uses or encroachments discovered. METC must indemnify Consumers Energy for all liabilities arising from the facilities covered by the Easement Agreement.

METC must notify Consumers Energy before altering, improving, relocating or constructing additional transmission facilities covered by the Easement Agreement. Consumers Energy may respond by notifying METC of reasonable work and design restrictions and precautions that are needed to avoid endangering existing distribution facilities, pipelines or communications lines, in which case METC must comply with these restrictions and precautions. METC has the right at its own expense to require Consumers Energy to remove and relocate these facilities, but Consumers Energy may require payment in advance or the provision of reasonable security for payment by METC prior to removing or relocating these facilities, and Consumers Energy need not commence any relocation work until an alternative right-of-way satisfactory to Consumers Energy is obtained at METC’s expense.

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

Amended and Restated Operating Agreement.  Under the Amended and Restated Operating Agreement (the “Operating Agreement”), dated as of April 29, 2002, METC agrees to operate its transmission system to provide all transmission customers with safe, efficient, reliable and non-discriminatory 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

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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 29, 2002 and amended most recently effective as of September 1, 2010, 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 April 22, 2010, specifies the terms and conditions under which Consumers Energy and METC maintain the interconnection of Consumers Energy’s generation resources and METC’s transmission assets. The Generator Interconnection Agreement is effective either until it is replaced by any MISO-required contract, or until mutually agreed by METC and Consumers Energy to terminate, but not later than the date that all listed generators cease commercial operation.

ITC Midwest

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

Distribution-Transmission Interconnection Agreement.  The Distribution-Transmission Interconnection Agreement (the “DTIA”), dated as of December 17, 2007, governs the rights, responsibilities and obligations of ITC Midwest and IP&L, with respect to the use of certain of their own and the other parties’ property, assets and facilities, and the construction of new facilities or modification of existing facilities. Additionally, the DTIA sets forth the terms pursuant to which the equipment and facilities and the interconnection equipment of IP&L will continue to connect ITC Midwest’s facilities through which ITC Midwest provides transmission service under the MISO Transmission and Energy Markets Tariff. The DTIA will remain in effect until terminated by mutual agreement by the parties (subject to any required FERC approvals) or as long as any interconnection point of IP&L is connected to ITC Midwest’s facilities, unless modified by written agreement of the parties.

Large Generator Interconnection Agreement.  ITC Midwest, IP&L and MISO entered into the Large Generator Interconnection Agreement (the “LGIA”), dated as of December 20, 2007, 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.

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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 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, 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 has purchased from Mid-Kansas. The Mid-Kansas Agreement has an initial term of ten years and automatic ten-year renewals unless terminated (1) due to a breach by the non-terminating party following notice and failure to cure, (2) by mutual consent of the parties, or (3) by ITC Great Plains under certain limited circumstances. Services must continue to be provided for at least six months subsequent to the termination date in any case.

Regulatory Environment

Many regulators and public policy makers support the need for further investment in the transmission grid. The growth in electricity generation, wholesale power sales and consumption combined with historically inadequate transmission investment have resulted in significant transmission constraints across the United States and increased stress on aging equipment. These problems will continue without increased investment in transmission infrastructure. Transmission system investments can also increase system reliability and reduce the frequency of power outages. Such investments can reduce transmission constraints and improve access to lower cost generation resources, resulting in a lower overall cost of delivered electricity for end-use consumers. After the 2003 blackout that affected sections of the Northeastern and Midwestern United States and Ontario, Canada, the Department of Energy (the “DOE”) established the Office of Electric Transmission and Distribution, 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.

On August 8, 2005, the Energy Policy Act was enacted, which requires the FERC to implement mandatory electric transmission reliability standards to be enforced by an Electric Reliability Organization. Effective June 2007, the FERC approved mandatory adoption of certain reliability standards and approved 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 these reliability standards established by the NERC, as well as the standards of applicable regional entities under the NERC that have been delegated certain authority for

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the purpose of proposing and enforcing reliability standards. Finally, the Energy Policy Act repealed the Public Utility Holding Company Act of 1935, which was replaced by the Public Utility Holding Company Act of 2005. It also subjected utility holding companies to regulations of the FERC related to access to books and records, and amended Section 203 of the FPA to provide explicit authority for the FERC to review 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.

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 certain of these revenue requirements are subject to an annual true-up. The separate calculations of revenue requirement impact only which parties ultimately pay for the transmission services related to these projects and not 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 Multi-Value Projects (“MVPs”), which include the Thumb Loop Project. The FERC accepted MISO’s MVP filing in 2010. Additionally, certain projects at ITC Great Plains are eligible for recovery through a region-wide charge in the SPP tariff: the KETA Project, which was part of the balanced portfolio of projects approved by SPP in 2009 and the Kansas V-Plan Project, which is subject to SPP’s highway/byway cost allocation. The FERC approved SPP’s highway/byway cost allocation methodology in 2010. These projects are described in more detail in “Item 7 Management’s

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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 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 ch. 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 ch. 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 ch. 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.

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 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/Office of Energy Security, and certain local authorities for compliance with applicable environmental standards and regulations.

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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. In this regard, on August 30, 2007, the MOPSC granted ITC Midwest a certificate of public convenience and necessity to own, operate and maintain a 161 kV transmission line of approximately 9.5 miles located in Clark County, Missouri which connects the substation in Keokuk, Iowa with Ameren Energy Generating Company’s transmission substation near Wayland, Missouri. 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 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

On September 11, 2008, ITC Great Plains received 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.

ITC Great Plains does not currently own or operate transmission facilities in Oklahoma, but is constructing an approximately 19-mile 345 kV transmission line and associated facilities in southeastern Oklahoma, known as the Hugo to Valliant project.

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 their actual net 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 net 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 Detroit Edison, Consumers Energy and IP&L, which accounted for approximately 33.1%, 23.6% and 23.9%, respectively, of our total operating revenues for the year ended December 31, 2010. One or more of these customers together have consistently represented a significant percentage of our operating revenue. These percentages of total operating revenues of Detroit Edison, Consumers Energy and IP&L include an estimate for the 2010 revenue accruals and deferrals that were included in our 2010 operating revenues, but will not be billed to our customers until 2012. We have assumed that the revenues billed to these customers in 2012 would be in the same proportion of the respective percentages of network and regional cost sharing revenues billed to them in 2010. 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 transmission services and administers the transmission tariff in the MISO service territory. As the billing agent for our MISO Regulated Operating Subsidiaries, MISO bills Detroit Edison, Consumers Energy, IP&L and other customers on a monthly basis and collects fees for the use of our transmission systems.

SPP is responsible for billing and collection for transmission services and administers the transmission tariff in the SPP service territory of which ITC Great Plains is a member. As the billing agent for ITC Great Plains, SPP independently administers the transmission tariff.

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. 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 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, 2010, we had 433 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 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 adverse effect on our results of operations, financial position or liquidity.

Our assets and operations also involve the use of materials classified as hazardous, toxic or otherwise dangerous. Many of the properties 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

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practicable after they are electronically filed with the Securities and Exchange Commission (the “SEC”). Also on our web site are our:

•  Corporate Governance Guidelines;

•  Code of Business Conduct and Ethics; and

•  Committee Charters for the Audit and Finance Committee, Compensation Committee and Nominating/Corporate Governance Committee.

Our Code of Business Conduct and Ethics applies to all directors, officers and employees, including our Chairman, President and Chief Executive Officer and our Executive Vice President, Treasurer 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’ cost recovery through rates can be 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 recent acquisitions (including ITC Midwest’s acquisition of IP&L’s electric transmission assets) that could have an adverse effect on our business, financial condition, results of operations and cash flows.

Our Regulated Operating Subsidiaries provide transmission service under rates regulated by the FERC. The FERC has approved the cost-based formula rate templates used by our Regulated Operating Subsidiaries, 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, ITCTransmission’s, METC’s, ITC Midwest’s and ITC Great Plains’ respective allowed 13.88%, 13.38%, 12.38% and 12.16% rates of return on the actual equity portion of their respective 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 in a proceeding under Section 206 of the FPA. 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.

On November 18, 2008, IP&L filed a complaint against ITC Midwest with the FERC under Section 206 of the Federal Power Act. The complaint alleged that: (1) the operations and maintenance expenses and administrative and general expenses projected in the 2009 ITC Midwest rate appeared excessive; (2) the true-up amount related to ITC Midwest’s posted network rate for the period through December 31, 2008 would cause ITC Midwest to charge an excessive rate in future years; and (3) the methodology of allocating

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administrative and general expenses among ITC Holdings’ operating companies was changed, resulting in such additional expenses being allocated to ITC Midwest. Among other things, IP&L’s complaint sought investigative action by the FERC relating to ITC Midwest’s transmission service charges reflected in its 2009 rate, as well as hearings regarding the justness and reasonableness of the 2009 rate (with the ultimate goal of reducing such rate).

On April 16, 2009, the FERC issued an order that dismissed the IP&L complaint, citing that IP&L failed to meet its burden to establish that the current rate is unjust and unreasonable and that IP&L’s alternative rate proposal is just and reasonable. Requests for rehearing have been filed with the FERC and, therefore the April 16 order remains subject to rehearing and ultimately to an appeal to a Federal Court of Appeals within 30 days of any decision on rehearing.

The FERC’s order approving our acquisition of METC was conditioned upon ITCTransmission and METC not recovering “merger-related costs” in their rates, as described in the order, unless a separate informational filing is submitted to the FERC. The informational filing, which could be challenged by interested parties, would need to identify those costs and show that such costs are outweighed by the benefits of the acquisition. Determinations by ITCTransmission or METC that expenses included in their formula rate template for recovery are not acquisition related costs are also subject to challenge by interested parties at the FERC. If challenged at the FERC and ITCTransmission or METC fail to show that costs included for recovery are not merger-related, this also could result in lowered rates and/or refunds of amounts collected. We have not sought recovery of merger-related costs at ITCTransmission or METC.

Under the FERC’s order approving ITC Midwest’s asset acquisition, ITC Midwest agreed to a hold harmless commitment in which no acquisition premium will be recovered in rates, nor will ITC Midwest recover through transmission rates any transaction-related costs that exceed demonstrated transaction-related savings for a period of five years. If during the five year period ITC Midwest seeks to recover transaction-related costs through its formula rate, ITC Midwest must make an informational filing at the FERC that identifies the transaction-related costs sought to be recovered and demonstrates that those costs are exceeded by transaction-related savings. If challenged at the FERC and ITC Midwest fails to show that transaction-related costs included for recovery do not exceed transaction-related savings, ITC Midwest could be subject to lowered rates and/or refunds of amounts previously collected. Additionally, in Iowa and Minnesota, as part of the regulatory approval process, ITC Midwest committed not to recover the first $15.0 million in transaction-related costs under any circumstances. We have not sought recovery of transaction-related costs at ITC Midwest.

In the Minnesota regulatory proceeding, ITC Midwest also 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 close 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-Hazelton line, the IUB must provide certain regulatory approvals, but, due to the current case schedule, we do not expect the approvals to be received in time to allow the project to be completed by December 31, 2011. While we believe we have used commercially reasonable best efforts to meet the December 31, 2011 deadline, any of the events described above could have a material 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 expected rate base and therefore our expected revenues and earnings. In addition, we expect to invest in strategic development opportunities to improve the efficiency

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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 when placed in service. We anticipate making significant capital investments over the next five 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 expenditures 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 or regulatory approvals for reasons relating to rate construct, environmental, siting, regional planning, cost recovery and other issues or as a result of legal proceedings and variances between estimated and actual costs of construction contracts awarded. 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 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 strategic development opportunities for construction of transmission facilities and interconnections with generating resources. These projects require regulatory approval by the FERC, applicable RTOs and state 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. In addition, we are subject to state and/or local regulations relating to, among other things, facility siting. If we fail to comply with these local regulations, we may incur liabilities for such failure.

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Changes in federal energy laws, regulations or policies could impact cash flows and could reduce the dividends we may be able to pay our stockholders.

The formula rate templates used by our Regulated Operating Subsidiaries to calculate their respective annual revenue requirements will be used by our Regulated Operating Subsidiaries for that purpose until and unless the FERC determines that such rate formula is unjust and unreasonable or that another mechanism is more appropriate. Such determinations could result from challenges initiated at the FERC by interested parties, by the FERC on its own initiative in a proceeding under Section 206 of the FPA or by a successful application initiated by any of our Regulated Operating Subsidiaries under Section 205 of the FPA. 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.

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, 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 weather, 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.

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 would adversely affect our revenues and our ability to service our debt obligations and affect our ability to pay dividends.

ITCTransmission derives a substantial portion of its revenues from the transmission of electricity to Detroit Edison’s local distribution facilities. Detroit Edison accounted for 77.5% of ITCTransmission’s total operating revenues for the year ended December 31, 2010 and is expected to constitute the majority of ITCTransmission’s revenues for the foreseeable future. Detroit Edison is rated BBB+/stable and Baa1/stable by Standard & Poor’s Ratings Services and Moody’s Investors Services, Inc., respectively. Similarly, Consumers Energy accounted for 72.3% of METC’s total operating revenues for the year ended December 31, 2010 and is expected to constitute the majority of METC’s revenues for the foreseeable future. Consumers Energy is rated BBB-/stable and Baa2/stable by Standard & Poor’s Ratings Services and Moody’s Investors Service, Inc., respectively. Further, IP&L accounted for 82.5% of ITC Midwest’s total operating revenues for the year ended December 31, 2010 and is expected to constitute the majority of ITC Midwest’s revenues for the foreseeable future. IP&L is rated BBB+/stable and A3/stable by Standard & Poor’s Ratings Services and Moody’s Investors Service, Inc., respectively. These percentages of total operating revenues of Detroit Edison, Consumers Energy and IP&L include an estimate for the 2010 revenue accrual and deferrals that were included in our 2010 operating revenues, but will not be billed to our customers until 2012. We have assumed that the revenues billed to these customers in 2012 would be in the same proportion of the respective percentages of network and regional cost sharing revenues billed to them in 2010.

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Any material failure by Detroit Edison, Consumers Energy or IP&L to make payments for transmission services could adversely affect our financial condition and results of operations and our ability to service our debt obligations, and could impact the amount of dividends we pay our stockholders.

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.

If ITC Midwest’s Operations Services Agreement with IP&L is terminated, ITC Midwest may face a shortage of labor or replacement contractors to provide the services formerly provided by IP&L.

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 prior written notice to the other party. If the OSA is terminated for any reason or at a time when ITC Midwest is unprepared for such termination, ITC Midwest may face difficulty finding a qualified replacement work force to provide such services, which could have a material adverse effect on its ability to carry on its business and on its 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

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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. 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 adverse effect on our business, financial condition and results of operations.

Our Regulated Operating Subsidiaries are subject to various regulatory requirements, including reliability standards. Violations of these requirements, whether intentional or unintentional, may result in penalties that, under some circumstances, could have a material adverse effect on our 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 financial condition, results of operations and cash flows.

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Acts of war, terrorist attacks and threats or the escalation of military activity in response to such attacks or otherwise may negatively affect our business, financial condition and cash flows.

Acts of war, terrorist attacks and threats or the escalation of military activity in response to such attacks or otherwise may negatively affect our business, financial condition and cash flows in unpredictable ways, such as increased security measures and disruptions of markets. Strategic targets, such as energy related assets, including, for example, our Regulated Operating Subsidiaries’ transmission facilities and Detroit Edison’s, Consumers Energy’s and IP&L’s generation and distribution facilities, may be at risk of future terrorist attacks. In addition to the increased costs associated with heightened security requirements, such events may have an adverse effect on the economy in general. A lower level of economic activity could result in a decline in energy consumption, which may adversely affect our business, financial condition and cash flows.

Risks Relating to Our Structure and Financial Leverage

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, deferred tax assets relating primarily to federal income tax NOLs and cash on hand. Our only sources of cash to pay dividends to our stockholders are dividends and other payments received by us from time to time from our Regulated Operating Subsidiaries and our other subsidiaries and the proceeds raised from the sale of our debt and equity securities. 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’ stockholders 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. 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 are highly leveraged and our dependence on debt may limit our ability to fulfill our debt obligations and/or to obtain additional financing.

We are highly leveraged and our consolidated indebtedness consists of various outstanding debt securities and borrowings under various revolving credit agreements. This capital structure can have several important consequences, including, but not limited to, the following:

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

•  If future cash flows are insufficient, we may need to incur further 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 reducing the funds available for the payment of dividends on our common stock.

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•  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.

•  Market conditions could affect our access to capital markets, restrict our ability to secure financing to make the capital expenditures and other expenses or investments planned by us and 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 leverage-related risks described here.

Certain provisions in our debt instruments limit our financial flexibility.

Our debt instruments include senior notes, secured notes, first mortgage bonds and revolving credit agreements containing 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 and ITCTransmission’s capital stock and METC’s, ITC Midwest’s, and ITC Great Plains’ member capital.

The revolving credit agreements, ITC Holdings’ senior notes, ITCTransmission’s first mortgage bonds, ITC Midwest’s first mortgage bonds and METC’s senior secured notes 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 the 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 credit agreements.

The amount of our federal income tax NOLs that we may use to reduce our tax liability in any given period is limited.

We have significant federal income tax NOLs resulting in part from accelerated depreciation methods for property, plant and equipment for income tax reporting purposes. These federal income tax NOLs may

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be used to offset future taxable income and thereby reduce our U.S. federal income taxes otherwise payable. Section 382 of the Internal Revenue Code of 1986, as amended imposes an annual limit on the ability of a corporation that undergoes an “ownership change” to use its federal income tax NOLs to reduce its tax liability. We are subject to annual limitations on the use of such federal income tax NOLs as a result of changes in our ownership in 2006. We have not recorded a valuation allowance relating to our federal income tax NOLs. In the event it becomes more likely than not that any portion of the federal income tax NOLs will expire unused, we would be required to recognize an expense to establish a valuation allowance in the period in which the determination is made. If the expense is significant, it could have a material adverse effect on our results of operations.

Provisions in our Articles of Incorporation and bylaws, Michigan corporate law and our debt agreements may impede efforts by our shareholders to change the direction or management of our company.

Our Articles of Incorporation and bylaws contain provisions that might enable our management to resist a proposed takeover. These provisions could discourage, delay or prevent a change of control or an acquisition at a price that our shareholders may find attractive. These provisions also may discourage proxy contests and make it more difficult for our shareholders to elect directors and take other corporate actions. The existence of these provisions could limit the price that investors are willing to pay in the future for shares of our common stock. These provisions include:

•  a 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 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

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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 the lower peninsula of Michigan and portions of Iowa, Minnesota, Illinois, Missouri and Kansas. 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 2,800 circuit miles of overhead and underground transmission lines rated at voltages of 120 kV to 345 kV;

•  approximately 18,700 transmission towers and poles;

•  station assets, such as transformers and circuit breakers, at 170 stations and substations which either interconnect our transmission facilities or connect ITCTransmission’s facilities with generation or distribution facilities owned by others;

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

•  warehouses and related equipment;

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

•  an approximately 188,000 square-foot corporate headquarters facility and operations control room in Novi, Michigan, including furniture, fixtures and office equipment; and

•  an approximately 40,000 square-foot facility in Ann Arbor, Michigan that includes a back-up operations control room.

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

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

•  approximately 5,500 circuit miles of overhead transmission lines rated at voltages of 120 kV to 345 kV;

•  approximately 36,400 transmission towers and poles;

•  station assets, such as transformers and circuit breakers, at 93 stations and substations which either interconnect our 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.

Amounts borrowed under METC’s revolving credit agreement are secured by a first priority security interest on all of METC’s assets through the issuance of senior secured bonds, collateral series, under METC’s first mortgage indenture and the second supplemental indenture thereto.

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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 6,800 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 256 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.

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

ITC Great Plains owns the assets of two electric transmission substations in Kansas. As of December 31, 2010, 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 from time to time 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. The resolution of pending proceedings is not expected to have a material effect on our operations or financial statements in the period they are resolved.

On November 18, 2008, IP&L filed a complaint with the FERC against ITC Midwest under Section 206 of the Federal Power Act. The complaint alleged that: (1) the operations and maintenance expenses and administrative and general expenses projected in the 2009 ITC Midwest rate appeared excessive; (2) the true-up amount related to ITC Midwest’s posted network rate for the period through December 31, 2008 would cause ITC Midwest to charge an excessive rate in future years; and (3) the methodology of allocating administrative and general expenses among ITC Holdings’ operating companies was changed, resulting in such additional expenses being allocated to ITC Midwest. Among other things, IP&L’s complaint sought investigative action by the FERC relating to ITC Midwest’s transmission service charges reflected in its 2009 rate, as well as hearings regarding the justness and reasonableness of the 2009 rate (with the ultimate goal of reducing such rate).

On April 16, 2009, the FERC dismissed the IP&L complaint, citing that IP&L failed to meet its burden as the complainant to establish that the current rate is unjust and unreasonable and that IP&L’s alternative rate proposal is just and reasonable. Requests for rehearing have been filed with the FERC and, therefore,

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the April 16 order remains subject to rehearing and ultimately to an appeal to a federal Court of Appeals within 30 days of any decision on rehearing.

Refer to Notes 4 and 16 to the consolidated financial statements for a description of other pending litigation.

ITEM 4.   (RESERVED AND REMOVED)

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 18, 2011, there were approximately 522 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 2010 and 2009, as reported on the NYSE and the cash dividends per share paid during the periods indicated.

Year Ended December 31, 2010	High		Low		Dividends
Quarter ended December 31, 2010	$	63.17	$	59.77	$	0.335
Quarter ended September 30, 2010	$	63.89	$	51.65	$	0.335
Quarter ended June 30, 2010(a)	$	56.66	$	21.80	$	0.320
Quarter ended March 31, 2010	$	56.04	$	50.75	$	0.320

Year Ended December 31, 2009	High		Low		Dividends
Quarter ended December 31, 2009	$	52.77	$	42.90	$	0.320
Quarter ended September 30, 2009	$	48.69	$	41.90	$	0.320
Quarter ended June 30, 2009	$	46.82	$	40.57	$	0.305
Quarter ended March 31, 2009	$	46.50	$	32.26	$	0.305

(a) The low sales price per share for the quarter ended June 30, 2010 occurred on May 6, 2010, the day when security prices on the New York Stock Exchange experienced an intraday decline of over 1000 points within a few minutes before partially recovering. Excluding the sales price per share that occurred on May 6, 2010, the lowest sales price per share for the quarter ended June 30, 2010 was $47.45.

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 our 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, deferred tax assets relating primarily to federal income tax NOLs and cash. ITC Holdings’ material cash inflows are only from dividends and other payments received from time to time from its subsidiaries and the proceeds raised from the sale of debt and equity securities. ITC Holdings may not be able to access cash generated by its subsidiaries in order to pay dividends to shareholders. The ability of ITC Holdings’ subsidiaries to make dividend and other payments to ITC Holdings is subject to the availability of funds after taking into account the subsidiaries’ funding requirements, the terms of the subsidiaries’ indebtedness, the regulations of the FERC under FPA, and applicable state laws. The debt agreements to which we are parties contain numerous financial covenants that could limit ITC Holdings’ ability to pay dividends, as well as covenants that prohibit ITC Holdings from paying dividends if we are in

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default under our revolving 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 us.

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.

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

	Total Number of		Average Price
	Shares Purchased		Paid Per Share
October 1 through October 31, 2010		—	$	—
November 1 through November 30, 2010(a)		621	$	60.73
December 1 through December 31, 2010		—	$	—

(a) Shares acquired were delivered to us by employees as payment of tax withholdings due to us upon the vesting of restricted stock. We did not repurchase any shares of common stock during this period as part of a publicly announced repurchase plan or program and do not have such a plan or program.

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ITEM 6.   SELECTED FINANCIAL DATA.

The selected historical financial data presented below should be read together with our consolidated financial statements and the notes to those statements and “Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations,” included elsewhere in this Form 10-K.

	ITC Holdings and Subsidiaries(a)
	Year Ended December 31,
	2010			2009			2008			2007			2006
(In thousands, except per share data)
OPERATING REVENUES(b)	$	696,843		$	621,015		$	617,877		$	426,249		$	223,622
OPERATING EXPENSES
Operation and maintenance(c)		126,528			95,730			113,818			81,406			35,441
General and administrative(c)(d)		78,120			69,231			81,296			62,089			40,632
Depreciation and amortization(e)		86,976			85,949			94,769			67,928			40,156
Taxes other than income taxes		48,195			43,905			41,180			33,340			22,156
Other operating income and expense — net		(297	)		(667	)		(809	)		(688	)		(842	)
Total operating expenses		339,522			294,148			330,254			244,075			137,543
OPERATING INCOME		357,321			326,867			287,623			182,174			86,079
OTHER EXPENSES (INCOME)
Interest expense		142,553			130,209			122,234			81,863			42,049
Allowance for equity funds used during construction		(13,412	)		(13,203	)		(11,610	)		(8,145	)		(3,977	)
Loss on extinguishment of debt		—			1,263			—			349			1,874
Other income		(2,340	)		(2,792	)		(3,415	)		(3,457	)		(2,348	)
Other expense		2,588			2,918			3,944			1,618			1,629
Total other expenses (income)		129,389			118,395			111,153			72,228			39,227
INCOME BEFORE INCOME TAXES		227,932			208,472			176,470			109,946			46,852
INCOME TAX PROVISION(f)		82,254			77,572			67,262			36,650			13,658
INCOME BEFORE CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE		145,678			130,900			109,208			73,296			33,194
CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE
(NET OF TAX OF $16)		—			—			—			—			29
NET INCOME	$	145,678		$	130,900		$	109,208		$	73,296		$	33,223
Basic earnings per share	$	2.89		$	2.62		$	2.22		$	1.72		$	0.94
Diluted earnings per share	$	2.84		$	2.58		$	2.18		$	1.68		$	0.91
Dividends declared per share	$	1.310		$	1.250		$	1.190		$	1.130		$	1.075

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	ITC Holdings and Subsidiaries(a)
	As of December 31,
	2010		2009		2008		2007			2006
(In thousands)
BALANCE SHEET DATA:
Cash and cash equivalents	$	95,109	$	74,853	$	58,110	$	2,616		$	13,426
Working capital (deficit)		69,338		147,335		1,095		(30,370	)		10,107
Property, plant and equipment — net		2,872,277		2,542,064		2,304,386		1,960,433			1,197,862
Goodwill		950,163		950,163		951,319		959,042			624,385
Total assets		4,307,873		4,029,716		3,714,565		3,213,297			2,128,797
Long-term debt:
ITC Holdings		1,459,178		1,458,757		1,327,741		1,687,193			775,963
Regulated Operating Subsidiaries		1,037,718		975,641		920,512		556,231			486,315
Total long-term debt		2,496,896		2,434,398		2,248,253		2,243,424			1,262,278
Total stockholders’ equity		1,117,433		1,011,523		929,063		563,075			532,244

	ITC Holdings and Subsidiaries(a)
	Year Ended December 31,
	2010		2009		2008		2007		2006
(In thousands)
CASH FLOWS DATA:
Capital expenditures	$	388,401	$	404,514	$	401,840	$	287,170	$	167,496

(a)	METC’s results of operations, cash flows and balances are included for the periods presented subsequent to its acquisition on October 10, 2006. In addition, ITC Midwest’s results of operations, cash flows and balances are included for the periods presented subsequent to its acquisition of the electric transmission assets of IP&L on December 20, 2007.
(b)	ITCTransmission’s and METC’s implementation of its cost-based formula rate with a true-up mechanism for rates beginning January 1, 2007 resulted in increases in operating revenues for the years presented subsequent to December 31, 2006. Refer to “Cost-Based Formula Rates with True-Up Mechanism” in Note 4 to the consolidated financial statements.
(c)	The reduction in expenses for 2009 were due, in part, to efforts to mitigate operation and maintenance expenses and general and administrative expenses to offset the impact of lower network load on cash flows and any potential revenue accrual relating to 2009.
(d)	During 2009, we recognized $10.0 million of regulatory assets associated with the development activities of ITC Great Plains as well as certain pre-construction costs for the KETA project. Upon initial establishment of these regulatory assets in 2009, $8.0 million of general and administrative expenses were reversed, of which $5.9 million were incurred in periods prior to 2009.
(e)	In 2009, the FERC accepted the depreciation studies filed by ITCTransmission and METC that revised their depreciation rates. In 2010, the FERC accepted a depreciation study filed by ITC Midwest which revised its depreciation rates. These changes in accounting estimates resulted in lower composite depreciation rates for ITCTransmission, METC and ITC Midwest primarily due to the revision of asset service lives and cost of removal values. The revised estimate of annual depreciation expense was reflected in 2009 for ITCTransmission and METC and in 2010 for ITC Midwest. See discussion in Note 4 to the consolidated financial statements under “Depreciation Studies.”

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(f) The increase in the income tax provision for 2008 compared to 2007 is due in part to the implementation of the Michigan Business Tax, which is accounted for as an income tax, compared to the previous Michigan Single Business Tax that was accounted for as a tax other than income tax.

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 disclosed under “Item 1A Risk Factors.”

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. Actual future results may vary materially. Except as required by law, we undertake no obligation to publicly update any of our forward-looking or other statements, whether as a result of new information, future events, or otherwise.

Overview

Through our Regulated Operating Subsidiaries, we operate high-voltage systems in Michigan’s Lower Peninsula and portions of Iowa, Minnesota, Illinois, Missouri and Kansas that transmit electricity from generating stations to local distribution facilities connected to our systems. Our business strategy is to operate, maintain and invest in transmission infrastructure in order to enhance system integrity and reliability, to reduce transmission constraints and to allow new generating resources to interconnect to our transmission systems. We also are pursuing development projects not within our existing systems, which are also intended to improve overall grid reliability, lower electricity congestion 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.”

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, balancing electricity generation

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and demand, maintaining appropriate system voltages and monitoring flows over transmission lines and other facilities to ensure physical limits are not exceeded.

Significant recent matters that influenced our financial position and results of operations and cash flows for the year ended December 31, 2010 or may affect future results include:

•  Our capital investment of $454.6 million at our Regulated Operating Subsidiaries ($67.1 million, $137.7 million, $232.5 million and $17.3 million at ITCTransmission, METC, ITC Midwest and ITC Great Plains, respectively) for the year ended December 31, 2010, primarily to improve system reliability, replace aging infrastructure and interconnect new generating resources;

•  Collection of the 2008 formula rate revenue accruals and related accrued interest totaling $83.8 million and higher monthly peak loads than what were forecasted in developing the network transmission rates for 2010, resulting in higher operating cash flows for the year ended December 31, 2010;

•  Debt issuances and borrowings under our revolving credit agreements in 2010 and 2009 to fund capital investment at our Regulated Operating Subsidiaries, resulting in higher interest expense; and

•  Our development activities relating to ITC Great Plains and Green Power Express. Certain development activities are expensed in the period incurred as they are not yet probable of recovery and there is no corresponding revenue recognized for these expenses.

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

Cost-Based Formula Rates with True-Up Mechanism

Our Regulated Operating Subsidiaries calculate their revenue requirements using cost-based formula rate templates and are effective without the need to file rate cases with the FERC, although the rates are subject to legal challenge at the FERC. Under 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 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 requirements. 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 — 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 accrual/deferral 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 formula rates that contain a true-up mechanism, our Regulated Operating Subsidiaries

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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 revenue requirement for a reporting period, a revenue accrual is recorded for the difference. To the extent that amounts billed are more than our 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 continues to have an impact on 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. The following table sets forth the monthly peak loads during the last three calendar years.

Monthly Peak Load (in MW)(a)

	2010						2009						2008
	ITCTransmission		METC		ITC Midwest		ITCTransmission		METC		ITC Midwest		ITCTransmission		METC		ITC Midwest
January		7,255		5,947		2,838		7,314		6,009		2,952		7,890		6,215		2,871
February		6,998		5,800		2,782		7,176		5,818		2,816		7,715		6,159		2,950
March		6,620		5,376		2,517		7,070		5,548		2,696		7,532		5,797		2,720
April		6,501		5,112		2,425		6,761		5,112		2,428		6,926		5,223		2,587
May		9,412		7,240		3,052		6,801		5,296		2,421		7,051		5,328		2,523
June		9,722		7,128		3,207		10,392		8,063		3,385		10,624		7,241		2,906
July		11,451		8,498		3,422		8,751		6,523		2,843		11,016		8,042		3,382
August		11,082		8,422		3,400		9,823		7,181		3,103		10,890		7,816		3,210
September		10,817		7,344		2,774		8,049		5,919		2,596		10,311		7,622		3,205
October		6,725		5,414		2,449		6,456		5,258		2,494		6,893		5,514		2,725
November		6,926		5,735		2,718		6,996		5,778		2,634		7,205		5,823		2,834
December		7,824		6,526		2,936		7,661		6,192		2,856		7,636		6,281		2,986
Total		101,333		78,542		34,520		93,250		72,697		33,224		101,689		77,061		34,899

(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 requirements 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 that are relevant to our cash flows since January 1, 2008:

Network Transmission Rate	ITCTransmission		METC		ITC Midwest
January 1, 2008 to December 31, 2008	$	2.350	$	1.985	$	2.446
January 1, 2009 to December 31, 2009	$	2.520	$	2.522	$	4.162
January 1, 2010 to December 31, 2010	$	2.818	$	2.370	$	6.882
January 1, 2011 to December 31, 2011	$	2.495	$	2.331	$	6.694

ITC Great Plains does not receive revenue based on a peak load each month and therefore 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 the annual projected net revenue requirement and is not based on a network transmission rate.

Net Revenue Requirement Calculation

Under their cost-based formula rate templates, each of our Regulated Operating Subsidiaries separately calculates a net revenue requirement based on financial information specific to each company. The calculation of actual net 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

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calculation of projected net revenue requirements is used to establish the transmission rate used for billing purposes, and follows the same methodology as the calculation of actual net revenue requirement. The following steps illustrate the calculation of net 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.

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

Rate base is projected using the average of the 13 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.

Step Three — Calculate Projected Net Revenue Requirement

After calculating the projected gross revenue requirement in Step Two above, the projected gross revenue requirement is adjusted for any prior year true-up adjustment discussed in Step Four and is reduced for certain revenues, 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

Step Four — Calculate True-up Adjustment

The actual transmission revenues billed for 2009 were compared to 2009 actual net revenue requirement which is based primarily on amounts from the completed FERC Form No. 1 for 2009. The true-up adjustment that results from the difference between the actual revenue billed and actual net revenue requirement for 2009 was added to the 2011 projected net revenue requirement used to determine the 2011 network transmission rate. Interest is also applied to the true-up adjustment.

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, 2011 through December 31, 2011, that was based primarily upon projections of

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ITCTransmission’s 2011 FERC Form No. 1 data. Amounts below are approximations of the amounts used to establish ITCTransmission’s 2011 projected net revenue requirement.

Line	Item	Instructions	Amount
1	Projected rate base (the average of the 13 months ended December 31, 2010 through December 31, 2011)		$	987,400,000
2	Multiply by projected 13 month weighted average cost of capital(a)			10.50%
3	Projected allowed return on rate base	(Line 1 × Line 2)	$	103,677,000
4	Projected recoverable operating expenses for 2011		$	58,000,000
5	Projected taxes and depreciation and amortization for 2011		$	129,100,000
6	Projected gross revenue requirements for 2011	(Line 3 + Line 4 + Line 5)	$	290,777,000
7	Less projected revenue credits for 2011		$	(41,900,000	)
8	Plus/(less) 2009 true-up adjustment		$	(4,700,000	)
9	Projected net revenue requirement for 2011	(Line 6 + Line 7 + Line 8)	$	244,177,000
10	Projected average monthly 2011 network load (in kW)			8,154,000
11	Annual component of the joint zone network transmission rate	(Line 9 divided by Line 10)	$	29.946
12	Monthly component of the joint zone network transmission rate ($/kW per month)	(Line 11 divided by 12 months)	$	2.496

(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	%	5.43% (Pre-tax) =		2.17	%
Equity		60.00	%	13.88% (After tax) =		8.33	%
		100.00	%			10.50	%

Capital Investment Forecasts 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 and interconnect 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 accessibility to generation sources of choice, including renewable sources. The Energy Policy Act requires the FERC to implement mandatory electric transmission reliability standards to be enforced by an Electric Reliability Organization. Effective June 2007, the FERC approved mandatory adoption of certain reliability standards and approved enforcement actions for violators, including fines of up to $1.0 million per day. The

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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.

On October 7, 2010, the NERC issued a recommendation for transmission owners such as our MISO Regulated Operating Subsidiaries to inspect their transmission systems in order to verify their facility ratings methodology is based on actual field conditions. Each of our MISO Regulated Operating Subsidiaries will undertake a program to assess its system over the next three years as a response to the recommendation. There are likely to be costs associated with the assessment and potential system modifications to mitigate instances where actual field conditions necessitate a facility rating that is unacceptable to the reliable operation of the transmission system. The costs for this mitigation will be determined after the assessment is completed, and the appropriate mitigation is planned and may result in significant operating expenses and/or capital investment. These operating expenses and capital investments would be recovered through higher revenue requirements under the cost-based formula rates of our MISO Regulated Operating Subsidiaries.

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:

			Actual Capital		Forecasted Capital
			Investment for the		Investment for the
	Five-Year Capital		Year Ended		Year Ending
(In millions)	Investment Program		December 31,		December 31,
Operating Subsidiary	2011-2015		2010(a)		2011
ITCTransmission	$	796	$	67.1	$	60 – 75
METC		682		137.7		155 – 170
ITC Midwest		1,087		232.5		225 – 250
ITC Great Plains		1,058		17.3		120 – 145
Other(b)		306		—		—
Total	$	3,929	$	454.6	$	560 – 640

(a)

Capital investment amounts differ from cash expenditures for property, plant and equipment included in our consolidated statements of cash flows due in part to differences in construction costs incurred compared to cash paid during that period, as well as payments for major equipment inventory that are included in cash expenditures but not included in capital investment until transferred to construction work in progress, among other factors.

(b)

Includes Green Power Express and other development initiatives.

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 financing for such expenditures, if necessary, limitations on the amount of construction that can be undertaken on our systems at any one time, regulatory approvals for reasons relating to rate construct, environmental, siting, regional planning, cost recovery or other issues or as a result of legal proceedings and variances between estimated and actual costs of construction contracts awarded. In addition, investments in transmission

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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

ITC Great Plains

KETA Project

The KETA Project is a 225-mile transmission line that will run between Spearville, Kansas and Axtell, Nebraska. On January 19, 2010, the FERC issued an order approving the novation agreements required by SPP for the designation of the right and obligation to build the Kansas portion of this project to ITC Great Plains by Sunflower Electric Power Corporation and Midwest Energy, Inc. The portion of the transmission line that ITC Great Plains is responsible for constructing will run approximately 174 miles. ITC Great Plains has commenced construction for the first phase of the 345 kV KETA Project, which will run from Spearville, Kansas to Hays, Kansas. In June 2010, ITC Great Plains received siting approval for the second phase of the project, which will run from Hays, Kansas to the Nebraska border and has secured the regulatory approvals required to complete the second phase of the KETA Project. At December 31, 2010, we had a construction work in progress balance for KETA project of $13.2 million, which includes the substation construction relating to the project. We estimate that the cost for ITC Great Plains’ portion of the KETA project will be approximately $203 million.

Kansas V-Plan Project

The Kansas V-Plan Project is a 180-mile transmission line that will run between Spearville and Wichita, Kansas. In 2009, the KCC authorized ITC Great Plains to build a portion of the segment from Spearville to Medicine Lodge, Kansas. The portion of the transmission line that ITC Great Plains is responsible for constructing will run approximately 110 miles. In April 2010, SPP approved construction of the Kansas V-Plan as a 345 kV double circuit facility. SPP then issued Notifications to Construct to the affected transmission owners. ITC Great Plains is now in the process of obtaining additional regulatory approvals necessary to begin construction related activities for the project. ITC Great Plains estimates it will invest approximately $300 million to construct its portions of the project.

Regulatory Assets

As of December 31, 2010, we have recorded approximately $10.5 million of regulatory assets for start-up and development expenses incurred by ITC Great Plains as well as certain costs incurred for the KETA Project prior to construction. Based on ITC Great Plains’ application and the related FERC order, ITC Great Plains will be required to make an additional filing with the FERC under Section 205 of the Federal Power Act in order to recover these start-up, development and pre-construction expenses.

The regulatory assets recorded at ITC Great Plains do not include amounts associated with pre-construction costs for the Kansas V-Plan Project, which have been recorded to expenses in the periods in which they were incurred. If in a future reporting period it becomes probable that future revenues will result from the authorization to recover certain pre-construction expenses for the Kansas V-Plan Project, which totaled $1.5 million at December 31, 2010, we will recognize those expenses as regulatory assets. No regulatory assets for the Kansas V-Plan have been recorded as of December 31, 2010.

Development Bonuses

During 2010, we recognized general and administrative expenses of $1.9 million for bonuses for the successful completion of certain regulatory milestones relating to the KETA Project. It is reasonably possible that future development-related bonuses would be authorized and awarded for this or other development projects.

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Green Power Express

The Green Power Express project consists of transmission line segments that would facilitate the movement of power from the wind-abundant areas in the Dakotas, Minnesota and Iowa to Midwest load centers that demand clean, renewable energy. The FERC issued an order authorizing certain transmission investment incentives, including the establishment of a regulatory asset for start-up and development costs of Green Power Express and certain pre-construction costs for the project to be recovered pursuant to a future FERC filing. Further, the FERC order conditionally accepted Green Power Express’ proposed formula rate tariff sheets, subject to refund, and set them for hearing and settlement procedures. On February 22, 2010, Green Power Express filed an Offer of Settlement that intended to resolve all of the issues set for hearing and is pending further action by the FERC. Interested parties have filed comments and reply comments. The original FERC order remains subject to several requests for rehearing. The amount of any future capital expenditures on this project is currently unknown.

The total development expenses through December 31, 2010 that may be recoverable through regulatory assets were approximately $5.5 million, which have been recorded to expenses in the periods in which they were incurred. If in a future reporting period it becomes probable that future revenues will result from the authorization to recover these development expenses, we will recognize the regulatory assets. No regulatory assets for Green Power Express have been recorded as of December 31, 2010.

Thumb Loop Project

In 2010, we received MISO approval of the Thumb Loop Project located in ITCTransmission’s region with a total expected capital investment of $510 million. The Thumb Loop Project 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. Siting application approval was filed with the MPSC in August 2010. Significant capital investments for this project are expected to occur beginning in 2012.

ITC Midwest Depreciation Study

During the third quarter of 2010, the FERC accepted a depreciation study filed by ITC Midwest which revised its depreciation rates. This change in accounting estimate resulted in lower composite depreciation rates for ITC Midwest primarily due to the revision of asset service lives and cost of removal values.

For ratemaking purposes, the FERC accepted our filing such that the full annual impact of the revised depreciation rates has been reflected in ITC Midwest’s 2010 revenue requirement. This resulted in a $5.1 million reduction in revenue recognized for the year ended December 31, 2010. The revised estimate of 2010 annual depreciation expense was reflected in depreciation expense beginning in the third quarter of 2010 and resulted in a reduction of depreciation expense of $5.1 million for the year ended December 31, 2010. Because of the inclusion of depreciation expense as a component of net revenue requirement under ITC Midwest’s cost-based formula rate, the offsetting effect on revenues and expenses from the change in depreciation rates had an immaterial effect on net income and earnings per share amounts for the year ended December 31, 2010.

ITC Midwest’s depreciation study also resulted in revised estimates for the amount of accrued removal costs we have recorded in our consolidated statement of financial position, and we recorded the net effect of this revision as a decrease in our regulatory liability for accrued removal costs and an increase in accumulated depreciation of $17.9 million.

Significant Components of Results of Operations

Revenues

We derive nearly all of our revenues from providing network transmission service, point-to-point transmission service and other related services over our Regulated Operating Subsidiaries’ transmission systems to Detroit Edison, Consumers Energy, IP&L and to other entities such as alternative electricity

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suppliers, power marketers and other wholesale customers that provide electricity to end-use consumers and from transaction-based capacity reservations on our transmission systems. 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 Detroit Edison, 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.

Our rates at ITC Great Plains are billed ratably each month based on its annual projected net revenue requirement 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 in net revenue requirement for network revenues calculated 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. 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.

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. Revenues that are allocated by MISO to our MISO Regulated Operating Subsidiaries relating to these services are determined based on projected expenses incurred but are not subject to a true-up. In any given year, our MISO Regulated Operating Subsidiaries may earn more or less scheduling, control and dispatch revenues than our actual expenses incurred for control room activities.

Other Revenues consist of rental revenues, easement revenues and amounts from providing ancillary services to customers.

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Operating Expenses

Operation and Maintenance Expenses consist primarily of the costs of contractors to operate and maintain our transmission systems and costs for our personnel involved in operation and maintenance activities.

Operation expenses include activities related to control area operations, which involve balancing loads and generation and transmission system operations activities, including monitoring the status of our transmission lines and stations. The expenses relating to 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 finance, human resources, regulatory, information technology and legal organizations, general office expenses and fees for professional services. Professional services are principally composed of outside legal, audit and information technology services. We capitalize to property, plant and equipment portions of certain general and administrative expenses such as compensation, office rent, utilities and information technology.

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 to property, plant and equipment depreciation expense for vehicles and equipment used in our construction activities.

Taxes other than Income Taxes consist primarily of property taxes and payroll taxes.

Other Operating Income and Expense — Net consists primarily of gains and losses associated with the sale of assets. Additionally, this item consists of income recognized for tax gross-ups received from developers or generators for construction projects as described in Note 2 to the consolidated financial statements under “Generator Interconnection Projects.” The tax gross-up represents the difference between taxable income associated with the contribution compared to the present value of tax depreciation of the property constructed using the taxable contribution in aid of construction.

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.

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 primarily of federal income taxes. Additionally, we record income tax provisions for the various state income taxes to which we are subject.

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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
	2010			2009			(Decrease)			(Decrease)			2008			(Decrease)			(Decrease)
(In thousands)
OPERATING REVENUES	$	696,843		$	621,015		$	75,828			12.2	%	$	617,877		$	3,138			0.5	%
OPERATING EXPENSES
Operation and maintenance		126,528			95,730			30,798			32.2	%		113,818			(18,088	)		(15.9	)%
General and administrative		78,120			69,231			8,889			12.8	%		81,296			(12,065	)		(14.8	)%
Depreciation and amortization		86,976			85,949			1,027			1.2	%		94,769			(8,820	)		(9.3	)%
Taxes other than income taxes		48,195			43,905			4,290			9.8	%		41,180			2,725			6.6	%
Other operating income and expense — net		(297	)		(667	)		370			(55.5	)%		(809	)		142			(17.6	)%
Total operating expenses		339,522			294,148			45,374			15.4	%		330,254			(36,106	)		(10.9	)%
OPERATING INCOME		357,321			326,867			30,454			9.3	%		287,623			39,244			13.6	%
OTHER EXPENSES (INCOME)
Interest expense		142,553			130,209			12,344			9.5	%		122,234			7,975			6.5	%
Allowance for equity funds used during construction		(13,412	)		(13,203	)		(209	)		1.6	%		(11,610	)		(1,593	)		13.7	%
Loss on extinguishment of debt		—			1,263			(1,263	)		(100.0	)%		—			1,263			n/a
Other income		(2,340	)		(2,792	)		452			(16.2	)%		(3,415	)		623			(18.2	)%
Other expense		2,588			2,918			(330	)		(11.3	)%		3,944			(1,026	)		(26.0	)%
Total other expenses (income)		129,389			118,395			10,994			9.3	%		111,153			7,242			6.5	%
INCOME BEFORE INCOME TAXES		227,932			208,472			19,460			9.3	%		176,470			32,002			18.1	%
INCOME TAX PROVISION		82,254			77,572			4,682			6.0	%		67,262			10,310			15.3	%
NET INCOME	$	145,678		$	130,900		$	14,778			11.3	%	$	109,208		$	21,692			19.9	%

Operating Revenues

Year ended December 31, 2010 compared to year ended December 31, 2009

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

														Percentage
	2010					2009					Increase			Increase
	Amount		Percentage			Amount		Percentage			(Decrease)			(Decrease)
(In thousands)
Network revenues	$	595,071		85.4	%	$	547,279		88.1	%	$	47,792			8.7	%
Regional cost sharing revenues		55,638		8.0	%		39,710		6.4	%		15,928			40.1	%
Point-to-point		26,063		3.7	%		17,087		2.8	%		8,976			52.5	%
Scheduling, control and dispatch		14,525		2.1	%		14,578		2.3	%		(53	)		(0.4	)%
Other		5,546		0.8	%		2,361		0.4	%		3,185			134.9	%
Total	$	696,843		100.0	%	$	621,015		100.0	%	$	75,828			12.2	%

Network revenues increased due primarily to higher net revenue requirements at our Regulated Operating Subsidiaries during the year ended December 31, 2010 as compared to the same period in 2009. Higher net revenue requirements were due primarily to higher rate bases associated with higher balances of property, plant and equipment in-service and higher recoverable expenses due primarily to higher operation and maintenance expenses, partially offset by higher regional cost sharing and point-to-point revenues.

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Regional cost sharing revenues increased due primarily to additional capital projects that have been identified by MISO and SPP as eligible for regional cost sharing. We expect to continue to receive regional cost sharing revenues and the amounts could increase in the near future, including revenues associated with projects that have been or are expected to be approved for regional cost sharing.

Point-to point revenues increased due primarily to an increase in scheduled transmission flow on our transmission systems.

Other revenues increased due primarily to revenue recognized at METC for utilization of its jointly-owned lines under its transmission ownership and operating agreements.

Operating revenues for the year ended December 31, 2010 include the network revenue accruals (deferrals) and regional cost sharing revenue accruals (deferrals) as calculated below:

														Total
											ITC			Net Revenue
Line		Item	ITCTransmission			METC			ITC Midwest		Great Plains			Deferral
(In thousands)
	1	Estimated net revenue requirement (network revenues recognized)(a)	$	238,818		$	171,259		$	183,095	$	1,899
	2	Network revenues billed(b)		267,441			173,710			183,027		1,070
	3	Network revenue accruals (deferrals) (line 1 — line 2)		(28,623	)		(2,451	)		68		829
	4	Regional cost sharing revenue accrual (deferrals)(c)		(740	)		(7,086	)		1,464		(745	)
	5	Total revenue accruals (deferrals) (line 3 + line 4)	$	(29,363	)	$	(9,537	)	$	1,532	$	84		$	(37,284	)

(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. Regional cost sharing revenues have a separate true-up mechanism and the related revenue accruals or deferrals are included in the regional cost sharing revenue amounts.
(b)	Network revenues billed at our MISO Regulated Operating Subsidiaries were calculated based on the joint zone monthly network peak load multiplied by our effective monthly network rates for 2010. The rates for 2010 include amounts for the collection of the 2008 revenue accruals and the revenues billed in 2010 associated with the 2008 revenue accruals are not included in these amounts. Our rates at ITC Great Plains are billed ratably each month on its annual projected net revenue requirement.
(c)	Regional cost sharing revenues are subject to a true-up mechanism whereby our Regulated Operating Subsidiaries accrue or defer revenues for any over- or under-recovery.

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Year ended December 31, 2009 compared to year ended December 31, 2008

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

														Percentage
	2009					2008					Increase			Increase
	Amount		Percentage			Amount		Percentage			(Decrease)			(Decrease)
(In thousands)
Network revenues	$	547,279		88.1	%	$	558,896		90.5	%	$	(11,617	)		(2.1	)%
Regional cost sharing revenues		39,710		6.4	%		15,534		2.5	%		24,176			155.6	%
Point-to-point		17,087		2.8	%		23,417		3.8	%		(6,330	)		(27.0	)%
Scheduling, control and dispatch		14,578		2.3	%		16,972		2.7	%		(2,394	)		(14.1	)%
Other		2,361		0.4	%		3,058		0.5	%		(697	)		(22.8	)%
Total	$	621,015		100.0	%	$	617,877		100.0	%	$	3,138			0.5	%

Network revenues decreased due primarily to lower net revenue requirements at our MISO Regulated Operating Subsidiaries during 2009 as compared to 2008. Lower net revenue requirements were due primarily to our expense mitigation efforts, other reductions to operating expenses as a result of higher capitalization, the reduction of depreciation expense as a result of the ITCTransmission and METC depreciation studies and an increase in regional cost sharing revenues. Partially offsetting these decreases was an increase due to higher rate base primarily associated with higher balances of property, plant and equipment in-service.

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

Point-to-point revenues decreased due primarily to fewer point-to-point reservations caused by a reduction of usage related to unfavorable regional economic conditions and unfavorable weather conditions.

Scheduling, control and dispatch revenues decreased due primarily to lower network peak load at ITCTransmission.

Operating revenues for the year ended December 31, 2009 include the network revenue accruals (deferrals) as calculated below:

													Total
											ITC		Net Revenue
Line		Item	ITCTransmission			METC			ITC Midwest		Great Plains		Accrual
(In thousands)
	1	Estimated net revenue requirement (network revenues recognized)(a)	$	232,253		$	154,280		$	159,960	$	786
	2	Network revenues billed(b)		235,216			161,299			140,136		261
	3	Network revenue accruals (deferrals) (line 1 — line 2)(c)	$	(2,963	)	$	(7,019	)	$	19,824	$	525	$	10,367

(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. Regional cost sharing revenues have a separate true-up mechanism and the related revenue accruals or deferrals are included in the regional cost sharing revenue amounts.

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(b)

Network revenues billed at our MISO Regulated Operating Subsidiaries were calculated based on the joint zone monthly network peak load multiplied by our effective monthly network rates for 2009. The rates for 2009 include amounts for the collection or refund of the 2007 revenue accruals and deferrals and the revenues billed or refunded in 2009 associated with the 2007 revenue accruals and deferrals are not included in these amounts. Our rates at ITC Great Plains are billed ratably each month on its annual projected net revenue requirement.

(c)

Revenue accruals (deferrals) relating to regional cost sharing revenues in 2009 were not separately estimated until June 2010 and the revenue deferral amount for regional cost sharing revenues of $2.0 million for 2009 was included in the total network revenue deferral line.

Operating Expenses

Operation and maintenance expenses

Year ended December 31, 2010 compared to year ended December 31, 2009

Operation and maintenance expenses increased by $15.1 million due to higher vegetation management expenses, $6.7 million due to higher equipment and structure maintenance, $4.7 million due to higher tower painting expenses and $4.4 million due to higher substation facility maintenance expenses. The lower operation and maintenance expenses in 2009 were due in part to efforts to mitigate operation and maintenance expenses and general and administrative expenses to offset the impact of lower network load on cash flows and any potential revenue accrual relating to 2009.

Year ended December 31, 2009 compared to year ended December 31, 2008

Operation and maintenance expenses decreased by $13.0 million due to lower field maintenance expenses consisting primarily of reductions in inspections, vegetation management, tower painting, overhead structure maintenance and field operations and training. These items were due in part to the expense mitigation efforts. Operation and maintenance expenses also decreased by $1.2 million for lower control center expenses and $5.1 million as a result of the expense capitalization process which focused on activities performed by employees directly related to construction programs at our Regulated Operating Subsidiaries. In addition, operation and maintenance expenses decreased by $1.5 million due to lower emergency station expenses at ITC Midwest that resulted from the 2008 floods in Iowa and by $1.2 million for lower incentive bonuses related to the ITC Midwest integration activities. These decreases were partially offset by higher information technology system maintenance expenses of $3.5 million, due in part to additional operating control room software and expanded financial systems and the expenses to support those systems.

General and administrative expenses

Year ended December 31, 2010 compared to year ended December 31, 2009

General and administrative expenses increased by $8.0 million due to the reduction of expenses in 2009 in connection with the recognition of regulatory assets relating to development activities of ITC Great Plains as well as certain pre-construction costs for the KETA Project. In addition, general and administrative expenses increased by $11.0 million due to higher compensation and benefit expenses due in part to personnel additions, stock compensation expense and the development bonuses as described above under “ITC Great Plains — Development Bonuses.” These increases were partially offset by lower professional advisory and consulting services of $4.9 million as well as lower general business expenses of $4.0 million.

Year ended December 31, 2009 compared to year ended December 31, 2008

General and administrative expenses decreased by $9.6 million as a result of the aforementioned expense capitalization process and $7.4 million due to lower business expenses and professional advisory and consulting services resulting, in part, from our expense mitigation efforts described above. In addition,

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general and administrative expenses decreased by $8.0 million due to the recognition of regulatory assets relating to start-up and development activities of ITC Great Plains as well as pre-construction costs for the KETA Project. Partially offsetting these decreases was an increase of $6.8 million due to higher compensation and benefits expenses, due in part to personnel additions, stock compensation expense associated with our 2008 and 2009 long term incentive plan grants and net pension cost. There was an additional $4.7 million increase for salaries, benefits and general business expenses associated with increased development activities at ITC Grid Development and Green Power Express, which are not included in the increases explained above.

Depreciation and amortization expenses

Year ended December 31, 2010 compared to year ended December 31, 2009

Depreciation and amortization expenses at our Regulated Operating Subsidiaries increased due to a higher depreciable rate base resulting from property, plant and equipment additions. This increase was partially offset by the effects of the ITC Midwest depreciation study, which revised ITC Midwest’s depreciation rates used to calculate depreciation expense for the 2010 calendar year and resulted in a reduction of depreciation expense of $5.1 million as described in Note 4 to the consolidated financial statements.

Year ended December 31, 2009 compared to year ended December 31, 2008

Depreciation and amortization expenses at our Regulated Operating Subsidiaries decreased due primarily to the ITCTransmission and METC depreciation studies described in Note 4 to the consolidated financial statements, which revised their depreciation rates used to calculate depreciation expense for the entire 2009 calendar year and resulted in a reduction of depreciation expense of $14.2 million and $5.3 million for ITCTransmission and METC, respectively. Partially offsetting this decrease was an increase in depreciation expense due to a higher depreciable rate base resulting from property, plant and equipment additions.

Taxes other than income taxes

Year ended December 31, 2010 compared to year ended December 31, 2009

Taxes other than income taxes increased due to higher property tax expenses primarily due to our MISO Regulated Operating Subsidiaries’ 2009 capital additions, which are included in the assessments for 2010 personal property taxes.

Year ended December 31, 2009 compared to year ended December 31, 2008

Taxes other than income taxes increased due to higher property tax expenses primarily due to our MISO Regulated Operating Subsidiaries’ 2008 capital additions, which are included in the assessments for 2009 personal property taxes.

Other expenses (income)

Year ended December 31, 2010 compared to year ended December 31, 2009

Interest expense increased due primarily to additional interest expense associated with ITC Holdings’ $200 million debt issuance in December 2009. This increase was partially offset by the effects of lower borrowing levels and interest rates under our revolving credit agreements.

AFUDC equity increased due to increased property, plant and equipment expenditures and the resulting higher construction work in progress balances during 2010 compared to 2009.

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Year ended December 31, 2009 compared to year ended December 31, 2008

Interest expense increased due primarily to additional interest expense associated with the $186.1 million of additional indebtedness incurred during 2009. This increase was partially offset by the effects of lower interest rates under our revolving credit agreements.

AFUDC equity increased due to increased property, plant and equipment expenditures and the resulting higher construction work in progress balances during 2009 compared to 2008.

Other expenses increased due primarily to realized and unrealized losses on our trading securities recognized during 2008 as a result of financial market conditions that caused a decrease in our investment values.

Income Tax Provision

Year ended December 31, 2010 compared to year ended December 31, 2009

Our effective tax rate for the years ended December 31, 2010 and 2009 are 36.1% and 37.2%, respectively. Our effective rate differs from our 35% statutory federal income tax rate due primarily to state income tax provision of $5.9 million (net of federal deductibility) recorded during the year ended December 31, 2010 and $8.0 million (net of federal deductibility) recorded during the year ended December 31, 2009, partially offset by the tax effects of AFUDC equity which reduces the effective tax rate. The amount of income tax expense relating to AFUDC equity is recognized as a regulatory asset and not included in the income tax provision. Our Regulated Operating Subsidiaries include taxes payable relating to AFUDC equity in their actual net revenue requirements. Additionally, the income tax provision for the year ended December 31, 2010 has been reduced by $0.7 million for the settlement of an uncertain tax position resulting from the deductibility of transaction costs incurred in connection with the METC acquisition (as described in Note 10 to the consolidated financial statements under “METC Uncertain Tax Position”).

Year ended December 31, 2009 compared to year ended December 31, 2008

Our effective tax rate for the years ended December 31, 2009 and 2008 are 37.2% and 38.1%, respectively. Our effective rate differs from our 35% statutory federal income tax rate due primarily to state income tax provision of $8.0 million (net of federal deductibility) recorded during the year ended December 31, 2009 and $9.0 million (net of federal deductibility) recorded during the year ended December 31, 2008, partially offset by the tax effects of AFUDC equity.

Liquidity and Capital Resources

We expect to fund our future capital requirements with cash from operations, our existing cash and cash equivalents and amounts available under our revolving credit agreements (the terms of which are described in Note 8 to the consolidated financial statements). In addition, we may from time to time secure debt and equity funding in the capital markets, although we can provide no assurance that we will be able to obtain financing on favorable terms or at all. We expect that our capital requirements will arise principally from our need to:

•  Fund capital expenditures at our Regulated Operating Subsidiaries. Our plans with regard to property, plant and equipment investments are described in detail above under “Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations — Capital Investment Forecasts and Operating Results Trends.”

•  Fund business development expenses and related capital expenditures. We are pursuing development activities at ITC Grid Development and Green Power Express that will continue to result in the incurrence of development expenses and could result in significant capital expenditures.

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•  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 dividends to holders of our common stock.

•  Fund contributions to our retirement plans, as described in Note 11 to the consolidated financial statements. The impact of the growth in the number of participants in our retirement benefit plans, the recent financial market conditions that have caused a decrease in the value of our retirement plan assets 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, an adverse determination in our appeal relating to the recent denial of our ability to use the sales and use tax exemption as described in Note 16 to the consolidated financial statements would result in additional capital requirements.

We believe that we have sufficient capital resources to meet our currently anticipated short-term needs. We rely on both internal and external sources of liquidity to provide working capital and to fund capital investments. We expect to continue to utilize our revolving credit agreements and our cash and cash equivalents as needed to meet our short-term cash requirements. As of December 31, 2010, we had consolidated indebtedness under our revolving credit agreements of $53.4 million, with unused capacity under the agreements of $231.6 million. In addition, as of December 31, 2010, we had $95.1 million of cash and cash equivalents on hand.

On July 22, 2010, we amended our revolving credit facilities to remove Lehman Brothers Bank, FSB’s commitments of $19.8 million, $16.7 million, $9.5 million and $9.0 million for ITC Holdings, ITCTransmission, METC and ITC Midwest, respectively, and to permit us in the future to terminate or replace certain lenders that default on their obligations under the credit facilities. We believe we have sufficient unused capacity under our revolving credit agreements to meet our short-term capital requirements. Additionally, if necessary, we believe we would be able to access the financial markets to satisfy short-term capital requirements.

For our long-term capital requirements, we expect that we will need to obtain additional debt and equity 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 as needed in amounts and upon terms that will be reasonably satisfactory to us.

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

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securities. Ratings are subject to revision or withdrawal at any time and each rating should be evaluated independently of any other rating. Our current credit ratings are displayed in the following table. An explanation of these ratings may be obtained from the respective rating agency.

		Standard and Poor’s	Moody’s Investor
Issuer	Issuance	Ratings Services(a)	Service, Inc.(b)
ITC Holdings	Senior 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	BBB	Baa1

(a)	All of the Standard and Poor’s Ratings Services ratings have a positive outlook.
(b)	All of the Moody’s Investor Service, Inc. ratings have a stable outlook.

Covenants

Our debt instruments include senior notes, secured notes, first mortgage bonds and revolving credit agreements containing numerous financial and operating covenants that place significant restrictions on certain transactions and require us to maintain certain financial ratios, as described in Note 8 to the consolidated financial statements. We are currently 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.

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Cash Flows

The following table summarizes cash flows for the periods indicated:

	Year Ended December 31,
	2010			2009			2008
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	145,678		$	130,900		$	109,208
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense		86,976			85,949			94,769
Revenue accruals and deferrals — including accrued interest		121,315			10,912			(83,390	)
Deferred income tax expense		76,746			75,001			65,054
Other		579			(7,574	)		(1,240	)
Changes in assets and liabilities, exclusive of changes shown separately		(7,961	)		(27,253	)		11,020
Net cash provided by operating activities		423,333			267,935			195,421
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment		(388,401	)		(404,514	)		(401,840	)
Other		(460	)		(4,448	)		520
Net cash used in investing activities		(388,861	)		(408,962	)		(401,320	)
CASH FLOWS FROM FINANCING ACTIVITIES
Net issuance/repayment of long-term debt (including revolving credit agreements)		62,034			185,802			4,516
Issuance of common stock		8,908			3,575			310,543
Dividends on common stock		(66,041	)		(62,408	)		(58,935	)
Refundable deposits from and repayments to generators for transmission network upgrades — net		(18,295	)		35,051			13,309
Other		(822	)		(4,250	)		(8,040	)
Net cash (used in) provided by financing activities		(14,216	)		157,770			261,393
NET INCREASE IN CASH AND CASH EQUIVALENTS		20,256			16,743			55,494
CASH AND CASH EQUIVALENTS — Beginning of period		74,853			58,110			2,616
CASH AND CASH EQUIVALENTS — End of period	$	95,109		$	74,853		$	58,110

Cash Flows From Operating Activities

Year ended December 31, 2010 compared to year ended December 31, 2009

Net cash provided by operating activities increased $155.4 million in 2010 over 2009. The increase in cash provided by operating activities was due primarily to an increase in cash received from operating revenues of $173.9 million due to the collection of $83.8 million of the 2008 formula rate revenue accruals and related accrued interest, as well as the additional revenues collected as a result of higher monthly peak loads in 2010 compared to what had been forecasted in developing the network transmission rates for our MISO Regulated Operating Subsidiaries. These increases were partially offset by $10.5 million of

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additional interest payments (net of interest capitalized) due primarily to higher outstanding balances of long-term debt as well as higher income taxes paid of $6.9 million during 2010 compared to 2009.

Year ended December 31, 2009 compared to year ended December 31, 2008

Net cash provided by operating activities increased $72.5 million in 2009 over 2008. The increase in cash provided by operating activities was due to an increase in cash received for operating revenues of $95.8 million, primarily as a result of additional revenues collected at ITC Midwest in 2009 subsequent to the rate freeze that was in effect during 2008. This increase was partially offset by $23.1 million of additional interest payments (net of interest capitalized) during 2009 compared to 2008 due primarily to higher outstanding balances of long-term debt.

Cash Flows From Investing Activities

Year ended December 31, 2010 compared to year ended December 31, 2009

Net cash used in investing activities decreased $20.1 million in 2010 over 2009. The decrease in cash used in investing activities was due primarily to lower payments during 2010 for amounts accrued for property, plant and equipment compared to payments for such amounts during 2009.

Year ended December 31, 2009 compared to year ended December 31, 2008

Net cash used in investing activities was consistent in 2009 compared to 2008, as a result of similar levels of capital investment.

Cash Flows From Financing Activities

Year ended December 31, 2010 compared to year ended December 31, 2009

Net cash from financing activities decreased $172.0 million in 2010 compared to 2009. The decrease in cash from financing activities was due primarily to a reduction in net proceeds associated with refundable deposits for transmission network upgrades of $53.3 million during 2010 as compared to 2009. In addition, the issuance of the $200.0 million received in December 2009 from the issuance of ITC Holdings 5.50% Senior Notes, due January 15, 2020, and the proceeds from the issuance of the $35.0 million ITC Midwest 4.60% First Mortgage Bonds, Series D (“Series D Bonds”), due December 17, 2024, exceeded the proceeds of $40.0 million from the closing of the Series D Bonds and proceeds of $50.0 million received from the issuance of METC’s 5.64% Senior Secured Notes during 2010. These decreases were partially offset by a net increase of $19.9 million in amounts outstanding under our revolving credit agreements.

Year ended December 31, 2009 compared to year ended December 31, 2008

Net cash provided by financing activities decreased $103.6 million in 2009 compared to 2008. The decrease was due to the $307.0 million of proceeds of common stock issuance costs associated with the January 2008 public common stock offering and the net decrease in borrowings under our revolving credit facilities of $34.6 million during 2009 as compared to 2008. These decreases were partially offset by the 2009 issuances of the $200.0 million ITC Holdings Senior Secured Notes and proceeds from the issuance of the $35.0 million ITC Midwest First Mortgage Bonds, Series D.

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Contractual Obligations

The following table details our contractual obligations as of December 31, 2010:

			Less Than		1-3		4-5		More Than
	Total		1 Year		Years		Years		5 Years
(In thousands)
Long-term debt:
ITC Holdings Senior Notes	$	1,462,000	$	—	$	317,000	$	255,000	$	890,000
ITCTransmission First Mortgage Bonds		385,000		—		185,000		—		200,000
ITCTransmission/METC revolving credit agreement		13,800		—		13,800		—		—
METC Senior Secured Notes		275,000		—		50,000		175,000		50,000
ITC Midwest First Mortgage Bonds		325,000		—		—		—		325,000
ITC Midwest revolving credit agreement		39,600		—		39,600		—		—
Interest payments:
ITC Holdings Senior Notes		836,998		85,683		235,767		133,545		382,003
ITCTransmission First Mortgage Bonds		217,284		20,108		48,317		23,750		125,109
METC Senior Secured Notes		145,671		16,198		48,483		15,143		65,847
ITC Midwest First Mortgage Bonds		384,922		19,606		58,816		39,210		267,290
Operating leases		1,598		429		1,160		4		5
Purchase obligations		54,683		46,940		6,412		1,331		—
METC Easement Agreement		399,884		10,041		30,123		20,082		339,638
Total obligations	$	4,541,440	$	199,005	$	1,034,478	$	663,065	$	2,644,892

Interest payments included above relate only to our fixed-rate long-term debt outstanding at December 31, 2010. We also expect to pay interest and commitment fees under our variable-rate revolving credit agreements that have not been included above due to varying amounts of borrowings and interest rates under the facilities. In 2010, we paid $0.4 million of interest and commitment fees under our revolving credit agreements.

Purchase obligations represent commitments for materials, services and equipment that had not been received as of December 31, 2010, 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 Easement Agreement provides METC with an easement for transmission purposes and rights-of-way, leasehold interests, fee interests and licenses associated with the land over which the transmission lines cross. The cost for use of the rights-of-way is $10.0 million per year. The term of the Easement Agreement runs through December 31, 2050 and is subject to 10 automatic 50-year renewals thereafter unless METC gives notice of nonrenewal of at least one year in advance. Payments to Consumers Energy under the Easement Agreement are charged to operation and maintenance expense.

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.

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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 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 $170.7 million relating to the regulatory assets at December 31, 2010 that are described in Note 5 to the consolidated financial statements. We also may be required to record losses of $50.0 million relating to intangible assets at December 31, 2010 that are described in Note 6 to the consolidated financial statements. Additionally, we may be required to record gains of $151.8 million relating to regulatory liabilities at December 31, 2010, 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 Mechanisms

Beginning January 1, 2007 for ITCTransmission and METC, January 1, 2008 for ITC Midwest and August 18, 2009 for ITC Great Plains, 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 net 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 formula rates include a true-up mechanism, whereby our Regulated Operating Subsidiaries compare their actual net revenue requirement 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 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.

The true-up mechanisms 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 net revenue requirements calculated using the cost-based formula rate. Our Regulated Operating Subsidiaries accrue or defer revenues to the extent that their actual net 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.

52

ITCTransmission’s Rate Freeze Revenue Deferral

ITCTransmission’s revenue deferral results from the regulatory authority to bill and collect certain revenue requirements calculated for historical periods. This revenue deferral resulted from the difference between the revenue ITCTransmission would have collected under its cost based formula rate and the actual revenue ITCTransmission received based on the frozen rate of $1.075 kW/month for the period from February 28, 2003 through December 31, 2004. The cumulative revenue deferral at the end of the rate freeze was $59.7 million ($38.8 million net of tax). The revenue deferral and related taxes are not reflected as assets and liabilities in our consolidated financial statements because they do not meet the criteria to be recorded as regulatory assets. Similarly none of the revenue deferral amortization used in ratemaking is reflected in our consolidated financial statements. The proper revenue recognition relating to the revenue deferral occurs when we charge the rate that includes the amortization of the revenue deferral. The revenue deferral is being amortized for ratemaking on a straight-line basis for five years from June 2006 through May 2011 and has been or will be included in ITCTransmission’s revenue requirement for those periods. Revenues of $11.9 million were recognized in 2010 relating to the rate freeze revenue deferral and will be $5.0 million for January through May 2011. The $6.9 million reduction in revenues is also expected to result in a reduction to earnings of approximately $4.3 million in 2011 compared to 2010.

Valuation of Goodwill

We have goodwill resulting from our acquisitions of ITCTransmission and METC and ITC Midwest’s acquisition of the IP&L transmission assets. In accordance with the standards set forth by the FASB for goodwill, we are required to perform an impairment test annually or whenever events or circumstances indicate that the value of goodwill may be impaired. In order to perform these impairment tests, we determined fair value using quoted market prices in active markets, and valuation techniques based on discounted future cash flows under various scenarios. We also considered estimates of market-based valuation multiples for companies within our Regulated Operating Subsidiaries’ peer group. The market-based multiples involve judgment regarding the appropriate peer group and the appropriate multiple to apply in the valuation and the cash flow estimates involve judgments based on a broad range of assumptions, information and historical results. To the extent estimated market-based valuation multiples and/or discounted cash flows are revised downward, we may be required to write down all or a portion of goodwill, which would adversely impact earnings. As of December 31, 2010, consolidated goodwill totaled $950.2 million and we determined that no impairment existed, nor do we believe there is a material risk of being impaired in the near term at ITCTransmission, METC or ITC Midwest as of our goodwill impairment testing date of October 1, 2010.

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 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 potential lawsuits or complaints in which we may be or have been named as a defendant.

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•  Resolution or progression of existing matters through the legislative process, the courts, the Internal Revenue Service, or the Environmental Protection Agency.

Valuation of Share-Based Payments

Our accounting for share-based payments requires us to determine the fair value of awards of ITC Holdings’ common stock. We use the value of ITC Holdings’ common stock at the date of grant in the calculation of the fair value of our share-based awards. The fair value of stock options held by our employees is determined using a Black-Scholes option valuation method, which is a valuation technique that is acceptable for share-based payment accounting. Key assumptions in determining fair value include volatility, risk-free interest rate, dividend yield and expected lives. 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.

Pension and Postretirement Costs

We sponsor certain post-employment benefits to 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 plan assets, 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.

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Interest Rate Risk

Fixed Rate Long Term 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, excluding revolving credit agreements, was $2,747.2 million at December 31, 2010. The total book value of our consolidated long-term debt, excluding revolving credit agreements, was $2,443.5 million at December 31, 2010. We performed an analysis calculating the impact of changes in interest rates on the fair value of long-term debt, excluding revolving credit agreements, at December 31, 2010. An increase in interest rates of 10% (from 7.0% to 7.7%, for example) at December 31, 2010 would decrease the fair value of debt by $81.1 million, and a decrease in interest rates of 10% at December 31, 2010 would increase the fair value of debt by $87.3 million at that date.

Revolving Credit Agreements

At December 31, 2010, we had a consolidated total of $53.4 million outstanding under our revolving credit agreements, which are variable rate loans and therefore fair value approximates book value. A 10% increase or decrease in borrowing rates under the revolving credit agreements compared to the weighted average rates in effect at December 31, 2010 would increase or decrease the total interest expense by $0.1 million, respectively, for an annual period on a constant borrowing level of $53.4 million.

Credit Risk

Our credit risk is primarily with Detroit Edison, Consumers Energy and IP&L, which were responsible for 33.1%, 23.6% and 23.9%, respectively, or $230.9 million, $164.6 million and $166.9 million, respectively, of our consolidated operating revenues for 2010. These percentages assume a portion of the 2010 revenue accruals and deferrals included in our 2010 operating revenues, which will be billed or refunded to our customers in 2012, would be paid by Detroit Edison, Consumers Energy and IP&L in the future based on the respective percentage of network and regional cost sharing revenues billed to them in 2010. Under Detroit Edison’s and Consumers Energy’s current rate structure, Detroit Edison 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 Detroit Edison, 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 Detroit Edison, Consumers Energy, IP&L and other customers on a monthly basis and collects fees for the use of our transmission systems. SPP, the billing agent for ITC Great Plains, began to bill ITC Great Plains’ 2009 network revenues in January 2010, retroactive to August 18, 2009. 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		57
Report of Independent Registered Public Accounting Firm		58
Report of Independent Registered Public Accounting Firm		59
Consolidated Statements of Financial Position as of December 31, 2010 and 2009		60
Consolidated Statements of Operations for the Years Ended December 31, 2010, 2009 and 2008		61
Consolidated Statements of Changes in Stockholders’ Equity and Comprehensive Income for the Years Ended December 31, 2010, 2009 and 2008		62
Consolidated Statements of Cash Flows for the Years Ended December 31, 2010, 2009 and 2008		63
Notes to Consolidated Financial Statements		64
Schedule I — Condensed Financial Information of Registrant		113

56

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 framework in Internal Control — Integrated Framework 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, 2010.

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, 2010. Deloitte & Touche LLP’s report, which expresses an unqualified opinion on the effectiveness of our internal control over financial reporting, is included herein.

57

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of:

ITC Holdings Corp.

We have audited the accompanying consolidated statements of financial position of ITC Holdings Corp. and subsidiaries (the “Company”) as of December 31, 2010 and 2009 and the related consolidated statements of operations, changes in stockholders’ equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2010. 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, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010, 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, 2010, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 23, 2011 expressed an unqualified opinion on the Company’s internal control over financial reporting.

/s/  DELOITTE & TOUCHE LLP

Detroit, Michigan

February 23, 2011

58

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

ITC Holdings Corp.:

We have audited the internal control over financial reporting of ITC Holdings Corp. and subsidiaries (the “Company”) as of December 31, 2010, based on criteria established in Internal Control — Integrated Framework 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, 2010, based on the criteria established in Internal Control — Integrated Framework 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, 2010 of the Company and our report dated February 23, 2011 expressed an unqualified opinion on those financial statements and financial statement schedule.

/s/  DELOITTE & TOUCHE LLP

Detroit, Michigan

February 23, 2011

59

ITC HOLDINGS CORP. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

	December 31,
(In thousands, except share data)	2010		2009
ASSETS
Current assets
Cash and cash equivalents	$	95,109	$	74,853
Accounts receivable		80,417		72,352
Inventory		42,286		36,834
Deferred income taxes		—		23,859
Regulatory assets — revenue accruals, including accrued interest		28,637		82,871
Other		5,293		3,244
Total current assets		251,742		294,013
Property, plant and equipment (net of accumulated depreciation and amortization of $1,129,669 and $1,051,045, respectively)		2,872,277		2,542,064
Other assets
Goodwill		950,163		950,163
Intangible assets (net of accumulated amortization of $12,176 and $9,095, respectively)		49,985		51,987
Regulatory assets — revenue accruals, including accrued interest		3,947		20,406
Other regulatory assets		138,152		134,924
Deferred financing fees (net of accumulated amortization of $11,750 and $9,616, respectively)		19,949		21,672
Other		21,658		14,487
Total other assets		1,183,854		1,193,639
TOTAL ASSETS	$	4,307,873	$	4,029,716
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Accounts payable	$	66,953	$	43,508
Accrued payroll		18,606		13,648
Accrued interest		42,725		39,099
Accrued taxes		19,461		21,188
Regulatory liabilities — revenue deferrals, including accrued interest		17,658		—
Refundable deposits from generators for transmission network upgrades		10,492		25,891
Other		6,509		3,344
Total current liabilities		182,404		146,678
Accrued pension and postretirement liabilities		35,811		31,158
Deferred income taxes		314,979		255,516
Regulatory liabilities — revenue deferrals, including accrued interest		43,202		10,238
Regulatory liabilities — accrued asset removal costs		90,987		112,430
Refundable deposits from generators for transmission network upgrades		14,515		17,664
Other		11,646		10,111
Long-term debt		2,496,896		2,434,398
Commitments and contingent liabilities (Notes 4 and 16)
STOCKHOLDERS’ EQUITY
Common stock, without par value, 100,000,000 shares authorized, 50,715,805 and 50,084,061 shares issued and outstanding at December 31, 2010 and 2009, respectively		886,808		862,512
Retained earnings		229,437		149,776
Accumulated other comprehensive income (loss)		1,188		(765	)
Total stockholders’ equity		1,117,433		1,011,523
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	4,307,873	$	4,029,716

See notes to consolidated financial statements.

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ITC HOLDINGS CORP. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

	Year Ended December 31,
(In thousands, except per share data)	2010			2009			2008
OPERATING REVENUES	$	696,843		$	621,015		$	617,877
OPERATING EXPENSES
Operation and maintenance		126,528			95,730			113,818
General and administrative		78,120			69,231			81,296
Depreciation and amortization		86,976			85,949			94,769
Taxes other than income taxes		48,195			43,905			41,180
Other operating income and expense — net		(297	)		(667	)		(809	)
Total operating expenses		339,522			294,148			330,254
OPERATING INCOME		357,321			326,867			287,623
OTHER EXPENSES (INCOME)
Interest expense		142,553			130,209			122,234
Allowance for equity funds used during construction		(13,412	)		(13,203	)		(11,610	)
Loss on extinguishment of debt		—			1,263			—
Other income		(2,340	)		(2,792	)		(3,415	)
Other expense		2,588			2,918			3,944
Total other expenses (income)		129,389			118,395			111,153
INCOME BEFORE INCOME TAXES		227,932			208,472			176,470
INCOME TAX PROVISION		82,254			77,572			67,262
NET INCOME	$	145,678		$	130,900		$	109,208
Basic earnings per common share (Note 9)	$	2.89		$	2.62		$	2.22
Diluted earnings per common share (Note 9)	$	2.84		$	2.58		$	2.18
Dividends declared per common share	$	1.310		$	1.250		$	1.190

See notes to consolidated financial statements.

61

ITC HOLDINGS CORP. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN
STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME

										Accumulated
										Other			Total
	Common Stock						Retained			Comprehensive			Stockholders’			Comprehensive
	Shares			Amount			Earnings			Income (Loss)			Equity			Income
(In thousands, except share and per share data)
BALANCE, DECEMBER 31, 2007		42,916,852		$	532,103		$	31,864		$	(892	)	$	563,075
Net income		—			—			109,208			—			109,208		$	109,208
Common stock issuance costs		—			(755	)		—			—			(755	)		—
Dividends declared on common stock ($1.190 per share)		—			—			(58,953	)		—			(58,953	)		—
Issuance of common stock		6,420,737			308,317			—			—			308,317			—
Stock option exercises		141,883			1,460			—			—			1,460			—
Shares issued under the Employee Stock Purchase Plan		18,593			766			—			—			766			—
Issuance of restricted stock		172,261			—			—			—			—			—
Forfeiture of restricted stock		(15,808	)		—			21			—			21			—
Amortization of share-based compensation, net of forfeitures		—			7,251			—			—			7,251			—
Amortization of interest rate lock cash flow hedges, net of tax of $34		—			—			—			63			63			63
Other		—			(518	)		—			—			(518	)		—
Comprehensive income																$	109,271
Employers’ accounting for defined benefit pension and other postretirement plans change in measurement date provisions
Service cost, interest cost, and expected return on plan assets for October 1 — December 31, 2007, net of tax of $400		—			—			(647	)		—			(647	)
Amortization of prior service cost and losses for October 1 — December 31, 2007, net of tax of $140		—			—			(225	)		—			(225	)
BALANCE, DECEMBER 31, 2008		49,654,518		$	848,624		$	81,268		$	(829	)	$	929,063
Net income		—			—			130,900			—			130,900		$	130,900
Repurchase and retirement of common stock		(700	)		(31	)		—			—			(31	)		—
Dividends declared on common stock ($1.250 per share)		—			—			(62,421	)		—			(62,421	)		—
Stock option exercises		223,975			2,522			—			—			2,522			—
Shares issued under the Employee Stock Purchase Plan		28,681			1,053			—			—			1,053			—
Issuance of restricted stock		189,264			—			—			—			—			—
Forfeiture of restricted stock		(16,894	)		—			29			—			29			—
Vesting of deferred stock units		5,217			—			—			—			—			—
Amortization of share-based compensation, net of forfeitures		—			9,977			—			—			9,977			—
Amortization of interest rate lock cash flow hedges, net of tax of $34		—			—			—			64			64			64
Tax deduction for stock compensation exceeding book value		—			129			—			—			129			—
Other		—			238			—			—			238			—
Comprehensive income																$	130,964
BALANCE, DECEMBER 31, 2009		50,084,061		$	862,512		$	149,776		$	(765	)	$	1,011,523
Net income		—			—			145,678			—			145,678		$	145,678
Repurchase and retirement of common stock		(1,057	)		(61	)		—			—			(61	)		—
Dividends declared on common stock ($1.310 per share)		—			—			(66,048	)		—			(66,048	)		—
Stock option exercises		464,264			7,786			—			—			7,786			—
Shares issued under the Employee Stock Purchase Plan		24,840			1,122			—			—			1,122			—
Issuance of restricted stock		152,737			—			—			—			—			—
Forfeiture of restricted stock		(14,404	)		—			31			—			31			—
Vesting of deferred stock units		5,364			—			—			—			—			—
Amortization of share-based compensation, net of forfeitures		—			14,843			—			—			14,843			—
Amortization of interest rate lock cash flow hedges, net of tax of $34		—			—			—			64			64			64
Fair value of interest rate swap, net of tax of $1,211		—			—			—			1,889			1,889			1,889
Tax deduction for stock compensation exceeding book value		—			320			—			—			320			—
Other		—			286			—			—			286			—
Comprehensive income																$	147,631
BALANCE, DECEMBER 31, 2010		50,715,805		$	886,808		$	229,437		$	1,188		$	1,117,433

See notes to consolidated financial statements.

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CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended December 31,
(In thousands)	2010			2009			2008
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	145,678		$	130,900		$	109,208
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense		86,976			85,949			94,769
Revenue accruals and deferrals — including accrued interest		121,315			10,912			(83,390	)
Deferred income tax expense		76,746			75,001			65,054
Allowance for equity funds used during construction		(13,412	)		(13,203	)		(11,610	)
Recognition of ITC Great Plains regulatory assets		—			(8,191	)		—
Other		13,991			13,820			10,370
Changes in assets and liabilities, exclusive of changes shown separately:
Accounts receivable		(9,479	)		(12,986	)		(14,455	)
Inventory		(5,452	)		(14,599	)		(10,237	)
Other current assets		(2,049	)		903			(629	)
Accounts payable		2,210			(6,097	)		14,948
Accrued payroll		4,893			2,003			778
Accrued interest		3,626			1,320			14,693
Accrued taxes		(2,071	)		3,073			3,600
Other current liabilities		2,770			(2,049	)		1,191
Other non-current assets and liabilities, net		(2,409	)		1,179			1,131
Net cash provided by operating activities		423,333			267,935			195,421
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment		(388,401	)		(404,514	)		(401,840	)
Proceeds from sale of securities		14,576			1,182			—
Purchases of securities		(14,587	)		(5,309	)		—
Other		(449	)		(321	)		520
Net cash used in investing activities		(388,861	)		(408,962	)		(401,320	)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt		90,000			333,670			782,782
Repayment of long-term debt		—			(100,000	)		(765,000	)
Borrowings under revolving credit agreements		475,627			623,966			657,733
Repayments of revolving credit agreements		(503,593	)		(671,834	)		(670,999	)
Issuance of common stock		8,908			3,575			310,543
Dividends on common stock		(66,041	)		(62,408	)		(58,935	)
Refundable deposits from generators for transmission network upgrades		21,618			40,279			15,661
Repayment of refundable deposits from generators for transmission network upgrades		(39,913	)		(5,228	)		(2,352	)
Other		(822	)		(4,250	)		(8,040	)
Net cash (used in) provided by financing activities		(14,216	)		157,770			261,393
NET INCREASE IN CASH AND CASH EQUIVALENTS		20,256			16,743			55,494
CASH AND CASH EQUIVALENTS — Beginning of period		74,853			58,110			2,616
CASH AND CASH EQUIVALENTS — End of period	$	95,109		$	74,853		$	58,110

See notes to consolidated financial statements.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.   GENERAL

ITC Holdings Corp. (“ITC Holdings,” and together with its subsidiaries, “we,” “our” or “us”) was incorporated for the purpose of acquiring International Transmission Company (“ITCTransmission”) from DTE Energy Company (“DTE Energy”). Following the approval of the transaction by the Federal Energy Regulatory Commission (the “FERC”), ITC Holdings acquired the outstanding ownership interests of ITCTransmission on February 28, 2003.

On October 10, 2006, ITC Holdings acquired an indirect ownership (through various intermediate entities) of all the partnership interests in Michigan Transco Holdings, Limited Partnership (“MTH”), the sole member of Michigan Electric Transmission Company, LLC (“METC”).

On December 20, 2007, ITC Midwest LLC (“ITC Midwest”), a wholly-owned subsidiary of ITC Holdings, completed the acquisition of the transmission assets of Interstate Power and Light Company (“IP&L”), an Alliant Energy Corporation subsidiary.

On August 18, 2009, ITC Great Plains, LLC (“ITC Great Plains”), a wholly-owned subsidiary of ITC Grid Development, LLC (“ITC Grid Development”), which is a wholly-owned subsidiary of ITC Holdings, completed the acquisition of two electric transmission substations from Mid-Kansas Electric Company LLC (“Mid-Kansas”) and became an electric utility with rates regulated by FERC.

Through ITCTransmission, METC, ITC Midwest and ITC Great Plains (together, our “Regulated Operating Subsidiaries”), we are engaged in the transmission of electricity in the United States. We operate high-voltage systems in Michigan’s Lower Peninsula and portions of Iowa, Minnesota, Illinois, Missouri and Kansas 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. The Midwest Independent Transmission System Operator, Inc. (“MISO”) bills and collects revenues from ITCTransmission, METC, and ITC Midwest (“MISO Regulated Operating Subsidiaries”) customers. 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,

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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, 2010, 2009 and 2008:

	Year Ended December 31,
	2010		2009		2008
(In thousands)
Supplementary cash flows information:
Interest paid (net of interest capitalized)	$	135,771	$	125,254	$	102,149
Income taxes paid		8,844		1,971		2,012
Supplementary non-cash investing and financing activities:
Additions to property, plant and equipment(a)		44,496		23,169		54,689
Allowance for equity funds used during construction		13,412		13,203		11,610

(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, 2010, 2009 or 2008, respectively, but have been or will be included as a cash outflow from investing activities for expenditures for property, plant and equipment when paid.

Accounts Receivable — We recognize losses for uncollectible accounts based on specific identification of any such items. As of December 31, 2010 and 2009, 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 $77.8 million, $76.8 million and $85.6 million for 2010, 2009 and 2008, 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

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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 2.4%, 2.6% and 3.0% for 2010, 2009 and 2008, respectively. Both ITCTransmission and METC implemented new depreciation rates effective for the year ended December 31, 2009 and ITC Midwest implemented new depreciation rates effective for the year ended December 31, 2010. Refer to Note 4 for additional discussion of these depreciation rate changes. 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 $3.9 million, $3.9 million and $3.5 million for 2010, 2009 and 2008, respectively, was a reduction to interest expense. The AFUDC equity was $13.4 million, $13.2 million and $11.6 million for 2010, 2009 and 2008, respectively. Certain projects at ITC Great Plains have been granted an incentive to include construction work in progress balances in rate base, and we do not accrue 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.

We capitalize the costs associated with computer software we develop or obtain for use in our business, which is included in property, plant and equipment. We amortize computer software costs on a straight-line basis over the expected period of benefit once the installed software is ready for its intended use.

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.

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 are subject to fair value-based rules for measuring impairment, and resulting write-downs, if any, are to be reflected in operating expense. In order to perform these impairment tests, we determined fair value using

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valuation techniques based on discounted future cash flows under various scenarios and we also considered estimates of market-based valuation multiples for companies within the peer group of the reporting unit that has goodwill recorded. These accounting standards require that goodwill be reviewed at least annually for impairment and whenever facts or circumstances indicate that the carrying amounts may not be recoverable. We have goodwill recorded relating to the acquisitions of each our MISO Regulated Operating Subsidiaries. We completed our annual goodwill impairment test for each of our MISO Regulated Operating Subsidiaries as of October 1, 2010 and determined that no impairment exists, nor do we believe there is material risk of being impaired in the near term. There were no events subsequent to October 1, 2010 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 deferred and amortized over the life of the debt issue. The debt discount or premium related to the issuance of long-term debt is recorded to long-term debt and amortized over the life of the debt issue. We recorded to interest expense the amortization of deferred financing fees and the amortization of our debt discounts for 2010, 2009 and 2008 of $3.1 million, $3.3 million and $3.2 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. Our asset retirement obligations as of December 31, 2010 and 2009 of $3.3 million and $3.5 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 during the period of change.

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 MISO Regulated Operating Subsidiaries relates to investments we make under generator interconnection agreements. The generator interconnection agreements typically consist of both transmission network upgrades, which

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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 network upgrade facilities are recorded to property, plant and equipment. For direct connection facilities, we collect a contribution in aid of construction from the generator for the cost of the facilities and offset the contribution against the plant investment recorded to property, plant and equipment.

We receive deposits or letters of credit from the generator for the network upgrade facilities in advance of construction. When the generator meets certain criteria of Attachment FF of the MISO tariff, such as having a long-term sales agreement at the commercial operation date for the generating capacity of the facility, we refund the cash deposits or release letter of credit that was provided. If the generator does not meet these criteria, the deposit is retained or other security drawn upon, and is recorded as an offset against the plant investment recorded to property, plant and equipment. When the cash or other security received is not refunded under the criteria of Attachment FF, the receipt of cash becomes taxable income for us for which we bill the generator a tax gross-up. The tax gross-up represents the difference between taxable income associated with the contribution compared to the present value of tax depreciation of the property constructed using the taxable contribution in aid of construction. The deferred revenues associated with the tax gross-up are recorded to other long-term liabilities when collected, and amortized over the tax depreciation life of the asset to other operating income and expense-net.

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 (the “2003 Stock Purchase and Option Plan”) and an Amended and Restated 2006 Long-Term Incentive Plan (the “LTIP”) pursuant to which we grant various share-based awards, including options and restricted stock and deferred stock units. Compensation expense for employees and directors is recorded for stock options, restricted stock awards and deferred stock units 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 entire vesting 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,

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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 and any gain or loss recognized for the effective portion of our interest rate swap.

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 2006 and earlier. The Internal Revenue Service completed its examination of our 2006 federal tax returns in January 2010. State and city jurisdictions that remain subject to examination range from tax years 2006 to 2009. The Internal Revenue Service examination did not result in any material adjustments to our consolidated financial statements. 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

Fair Value Measurements

The guidance set forth by the FASB for fair value measurements was revised to require additional disclosure as part of our consolidated financial statements. We are required to disclose separately the amounts of and reasons for, significant transfers between Level 1 and Level 2 of the fair value hierarchy and significant transfers into and out of Level 3 of the fair value hierarchy for the reconciliation of Level 3 measurements. In addition, we are required to provide disclosures about the valuation techniques and inputs used to measure fair value for both recurring and nonrecurring fair value measurements in Level 2 or Level 3 of the fair value hierarchy and for each class of assets and liabilities. Effective for the year ended December 31, 2010, we are required to provide Level 3 activity of purchases, sales, issuances and settlements on a gross basis. The new disclosure requirements did not have a material impact on our consolidated financial statements. Refer to Note 11 and Note 12 for our fair value measurement disclosures.

Consolidation of Variable Interest Entities

The new consolidation guidance set forth by the FASB applicable to a variable interest entity (“VIE”) and the guidance governing the determination of whether an enterprise is the primary beneficiary of a VIE, and is, therefore, required to consolidate an entity requires a qualitative analysis rather than a quantitative analysis. The qualitative analysis will include, among other things, consideration of who has the power to direct the activities of the entity that most significantly impact the entity’s economic performance and who has the obligation to absorb losses or the right to receive benefits of the VIE that could potentially be significant to the VIE. Continuous reassessments of whether an enterprise is the primary beneficiary of a VIE and enhanced disclosures about an enterprise’s involvement with a VIE are also required. Previously, reconsideration of whether an enterprise was the primary beneficiary of a VIE arose only when specific

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events had occurred. These requirements became effective for us in the first quarter of 2010 and did not have a material effect on our consolidated financial statements.

4.   REGULATORY MATTERS

ITC Great Plains

On August 18, 2009, ITC Great Plains acquired two electric transmission substations and became an independent transmission company in SPP. SPP began to bill ITC Great Plains’ 2009 network revenues in January 2010, retroactive to August 18, 2009. ITC Great Plains has committed to construct certain transmission projects in the SPP region, including the Kansas Electric Transmission Authority (“KETA”) Project (also known as the Spearville — Knoll — Axtell Project) and a segment of the Kansas V-Plan.

In 2009, ITC Great Plains filed an application for a formula rate under Section 205 of the Federal Power Act. The FERC conditionally accepted the proposed formula rate tariff sheets, subject to refund, and set them for hearing and settlement procedures. In addition, the FERC approved certain transmission investment incentives, including the establishment of regulatory assets for start-up and development costs of ITC Great Plains and certain pre-construction costs specific to the KETA Project and the Kansas V-Plan to be recovered pursuant to future FERC filings. During the first quarter of 2010, the FERC accepted ITC Great Plains’ cost-based formula rate tariff sheets, which include an annual true-up mechanism, and their corresponding implementation protocols.

As of December 31, 2010, we have recorded approximately $10.5 million of regulatory assets for start-up and development expenses incurred by ITC Great Plains as well as certain pre-construction costs for the KETA Project. Based on ITC Great Plains’ application and the FERC order, ITC Great Plains will be required to make an additional filing with the FERC under Section 205 of the Federal Power Act in order to recover these start-up, development and pre-construction expenses.

The regulatory assets recorded at ITC Great Plains do not include amounts associated with pre-construction costs for the Kansas V-Plan, which have been recorded to expenses in the period in which they were incurred. If in a future period it becomes probable that future revenues will result from the authorization to recover certain pre-construction expenses for the Kansas V-Plan, which totaled $1.5 million at December 31, 2010, we will recognize the regulatory asset. No regulatory assets for Kansas V-Plan have been recorded as of December 31, 2010.

Green Power Express

The Green Power Express consists of transmission line segments that would facilitate the movement of power from the wind-abundant areas in the Dakotas, Minnesota and Iowa to Midwest load centers that demand clean, renewable energy. In 2009, Green Power Express filed an application with the FERC for approval of a cost-based formula rate with a true-up mechanism and incentives for the construction of the Green Power Express project, including the approval of a regulatory asset for recovery of development expense previously incurred as well as future development costs for the project.

The FERC issued an order authorizing certain transmission investment incentives, including the establishment of a regulatory asset for start-up and development costs of Green Power Express and certain pre-construction costs for the project to be recovered pursuant to a future FERC filing. Further, the FERC order conditionally accepted Green Power Express’ proposed formula rate tariff sheets, subject to refund, and set them for hearing and settlement procedures. On February 22, 2010, Green Power Express filed an Offer of Settlement that intended to resolve all of the issues set for hearing and is pending further action by the FERC. Interested parties have filed comments and reply comments. The original FERC order remains subject to several requests for rehearing. As of December 31, 2010, there are no projects under construction and no revenues earned relating to the Green Power Express.

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The total development expenses through December 31, 2010 that may be recoverable through regulatory assets were approximately $5.5 million, which have been recorded to expenses in the periods in which they were incurred. If in a future reporting period it becomes probable that future revenues will result from the authorization to recover these development expenses, we will recognize the regulatory assets. No regulatory assets for Green Power Express have been recorded as of December 31, 2010.

Cost-Based Formula Rates with True-Up Mechanism

The transmission rates at our Regulated Operating Subsidiaries are set annually and remain in effect for a one-year period. Rates are posted on the Open Access Same-Time Information System each year. By completing their formula rate template 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 the 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 true-up amount is reflected in customer bills within two years under the provisions of the formula rate templates.

The changes in regulatory assets and liabilities (net) associated with our Regulated Operating Subsidiaries’ formula rate revenue accruals and deferrals, including accrued interest, were as follows during the year ended December 31, 2010:

							ITC			ITC
	ITCTransmission			METC			Midwest			Great Plains		Total
(In thousands)
Balance as of December 31, 2009	$	15,267		$	4,848		$	72,395		$	529	$	93,039
Collection of 2008 revenue accruals including interest		(18,490	)		(12,197	)		(53,068	)		—		(83,755	)
Revenue accruals (deferrals) for the year ended December 31, 2010		(29,363	)		(9,537	)		1,532			84		(37,284	)
Accrued interest receivable (payable) for the year ended December 31, 2010		(468	)		(350	)		529			13		(276	)
Balance as of December 31, 2010	$	(33,054	)	$	(17,236	)	$	21,388		$	626	$	(28,276	)

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

							ITC			ITC
	ITCTransmission			METC			Midwest			Great Plains			Total
(In thousands)
Current assets	$	1,906		$	2,074		$	24,033		$	624		$	28,637
Non-current assets		—			—			3,197			750			3,947
Current liabilities		(5,633	)		(9,639	)		(2,386	)		—			(17,658	)
Non-current liabilities		(29,327	)		(9,671	)		(3,456	)		(748	)		(43,202	)
Balance as of December 31, 2010	$	(33,054	)	$	(17,236	)	$	21,388		$	626		$	(28,276	)

Complaint of IP&L

On November 18, 2008, IP&L filed a complaint with the FERC against ITC Midwest under Section 206 of the Federal Power Act. The complaint alleged that: (1) the operations and maintenance expenses and administrative and general expenses projected in the 2009 ITC Midwest rate appeared excessive; (2) the true-up amount related to ITC Midwest’s posted network rate for the period through December 31, 2008, will cause ITC Midwest to charge an excessive rate in future years; and (3) the methodology of allocating administrative and general expenses among ITC Holdings’ operating companies was changed, resulting in such additional expenses being allocated to ITC Midwest. Among other things, IP&L’s complaint sought investigative action by the FERC relating to ITC Midwest’s transmission service charges reflected in its 2009 rate, as well as hearings regarding the justness and reasonableness of the 2009 rate (with the ultimate goal of reducing such rate).

On April 16, 2009, the FERC dismissed the IP&L complaint, citing that IP&L failed to meet its burden as the complainant to establish that the current rate is unjust and unreasonable and to establish that IP&L’s alternative rate proposal is just and reasonable. Requests for rehearing have been filed with the FERC and, therefore, the April 16 order remains subject to rehearing and ultimately to an appeal to a federal Court of Appeals within 30 days of any decision on rehearing.

ITC Midwest’s Rate Discount

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

ITCTransmission Rate Freeze Revenue Deferral

ITCTransmission’s revenue deferral results from the regulatory authority to bill and collect certain revenue requirements calculated for historical periods. This revenue deferral resulted from the difference between the revenue ITCTransmission would have collected under its cost based formula rate and the actual revenue ITCTransmission received based on the frozen rate of $1.075 kW/month for the period from February 28, 2003 through December 31, 2004. The cumulative revenue deferral at the end of the rate freeze was $59.7 million ($38.8 million net of tax). The revenue deferral and related taxes are not reflected as assets and liabilities in our consolidated financial statements because they do not meet the criteria to be recorded as regulatory assets. Similarly none of the revenue deferral amortization used in ratemaking is

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reflected in our consolidated financial statements. The proper revenue recognition relating to the revenue deferral occurs when we charge the rate that includes the amortization of the revenue deferral. The revenue deferral is being amortized for ratemaking on a straight-line basis for five years from June 2006 through May 2011 and has been or will be included in ITCTransmission’s revenue requirement for those periods. As of December 31, 2010 and 2009, the balance of ITCTransmission’s revenue deferral that has not yet been recognized as revenue was $5.0 million (net of accumulated amortization of $54.7 million) and $16.9 million (net of accumulated amortization of $42.8 million), respectively.

Depreciation Studies

ITC Midwest

During the third quarter of 2010, the FERC accepted a depreciation study filed by ITC Midwest which revised its depreciation rates. This change in accounting estimate resulted in lower composite depreciation rates for ITC Midwest primarily due to the revision of asset service lives and cost of removal values.

For ratemaking purposes, the FERC accepted our filing such that the impact of the revised depreciation rates has been reflected in ITC Midwest’s 2010 revenue requirement. This resulted in a $5.1 million reduction in revenue recognized for the year ended December 31, 2010. The revised estimate of 2010 annual depreciation expense was reflected in depreciation expense beginning in the third quarter of 2010 and resulted in a reduction of depreciation expense of $5.1 million for the year ended December 31, 2010. Because of the inclusion of depreciation expense as a component of net revenue requirement under ITC Midwest’s cost-based formula rate, the offsetting effect on revenues and expenses from the change in depreciation rates had an immaterial effect on net income and earnings per share amounts for both the year ended December 31, 2010.

ITC Midwest’s depreciation study also resulted in revised estimates for the amount of accrued removal costs we have recorded in our consolidated statement of financial position, and the net effect of this resulted in a decrease in our regulatory liability for accrued removal costs and an increase in accumulated depreciation of $17.9 million.

ITCTransmission and METC

During the third and fourth quarter of 2009, the FERC accepted depreciation studies filed by ITCTransmission and METC, respectively, which revised their depreciation rates. This change in accounting estimate results in lower composite depreciation rates for ITCTransmission and METC primarily due to the revision of asset service lives and cost of removal values.

For ratemaking purposes, the FERC accepted our filing such that the impact of the revised depreciation rates was reflected in ITCTransmission’s and METC’s 2009 revenue requirement. The revised depreciation rates resulted in a reduction of depreciation expense of $21.9 million and $19.5 million for the years ended December 31, 2010 and 2009, respectively, as compared to the amount of depreciation expense that would have been recognized under the previous depreciation rates utilized by ITCTransmission and METC. Because of the inclusion of depreciation expense as a component of net revenue requirement under their cost-based formula rates, the offsetting effect on revenues and expenses from the change in depreciation rates had an immaterial effect on net income and earnings per share amounts for the years ended December 31, 2010 and 2009.

The depreciation studies also resulted in revised estimates for the amount of accrued removal costs we have recorded in our consolidated statement of financial position, and the net effect of this resulted in a decrease in our regulatory liability for accrued removal costs and an increase in accumulated depreciation of $84.3 million.

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5.   REGULATORY ASSETS AND LIABILITIES

Regulatory Assets

The following table summarizes the regulatory asset balances at December 31, 2010 and 2009:

(In thousands)	2010		2009
Regulatory Assets:
Revenue accruals:
Current (including accrued interest of $266 and $2,652 as of December 31, 2010 and 2009, respectively)	$	28,637	$	82,871
Non-current (including accrued interest of $22 and $75 as of December 31, 2010 and 2009, respectively)		3,947		20,406
Other:
ITCTransmission ADIT Deferral (net of accumulated amortization of $23,736 and $20,706 as of December 31, 2010 and 2009, respectively)		36,866		39,896
METC ADIT Deferral (net of accumulated amortization of $9,435 and $7,076 as of December 31, 2010 and 2009, respectively)		33,021		35,380
METC Regulatory Deferrals (net of accumulated amortization of $3,086 and $2,314 as of December 31, 2010 and 2009, respectively)		12,342		13,114
Income taxes recoverable related to AFUDC equity		28,687		22,296
ITC Great Plains Start-up and Development Regulatory Asset		8,783		8,757
KETA Project Regulatory Asset		1,748		1,202
Pensions and postretirement		16,705		14,279
Total	$	170,736	$	238,201

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 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 being recognized in rates and amortized on a straight-line basis over 20 years. ITCTransmission recorded amortization expense of $3.0 million annually during 2010, 2009 and 2008, which is included in depreciation and amortization.

METC ADIT Deferrals

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 Deferrals of $42.5 million is recognized in rates and amortized over 18 years beginning

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January 1, 2007, which corresponds to the amortization period established in the METC’s rate case settlement in 2007. METC earns a return on the remaining unamortized balance of the regulatory asset for METC ADIT Deferrals that is included in rate base. METC recorded amortization expense of $2.4 million annually during 2010, 2009 and 2008, respectively, which is included in depreciation and amortization.

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, which corresponds to the amortization period established in METC’s rate case settlement in 2007. METC earns a return on the remaining unamortized balance of the regulatory asset for METC Regulatory Deferrals that is included in rate base. METC recorded amortization expense of $0.8 million during 2010, 2009 and 2008, respectively, which is included in depreciation and amortization.

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. Under our Regulated Operating Subsidiaries’ cost-based formula rates with true-up mechanisms, the future taxes payable relating to AFUDC equity will be recovered from customers in future rates. The true-up mechanism allows our Regulated Operating Subsidiaries to collect their actual net revenue requirement, which includes taxes payable relating to depreciation of AFUDC equity. Because AFUDC equity is a component of property, plant and equipment that is included in rate base when the plant is placed in service, and the related deferred tax liabilities are not a reduction to rate base, we effectively earn a return on this regulatory asset.

ITC Great Plains Start-up and Development Regulatory Asset

The start-up and development regulatory asset 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. 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, as well as obtaining the necessary approvals and authorizations for the state regulators in Kansas and Oklahoma.

The startup and development regulatory asset accrues 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 ITC Great Plains’ formula rate template for that year. The equity component of these carrying charges, totaling $1.1 million as of December 31, 2010, 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. The carrying charges began to accrue in March 2009 as authorized by the FERC Order and will continue until such time that the regulatory asset is included in rate base.

Recovery of the start-up and development regulatory asset requires FERC authorization upon ITC Great Plains making an additional filing under Section 205 of the Federal Power Act to demonstrate that the costs to be recovered are just and reasonable. Subsequent to FERC authorization, ITC Great Plains

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will include the unamortized balance of the start-up and development regulatory assets in its rate base and will begin amortizing it over a ten-year period upon the in-service date of the KETA Project, the Kansas V-Plan or when the total in-service gross property, plant and equipment at ITC Great Plains exceeds $100 million, whichever occurs first. The amortization expense will be recovered through ITC Great Plains’ cost-based formula rate template beginning in the period in which amortization begins.

KETA Project Regulatory Asset

The KETA Project regulatory asset includes certain costs incurred associated with regulatory activities in Kansas and Oklahoma and with participants in SPP to obtain the necessary approvals and authorization before proceeding further with plans, 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 Project prior to construction. The KETA Project regulatory asset accrues 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 our formula rate template for that year. The equity component of these carrying charges, totaling $0.2 million as of December 31, 2010, are not recorded for GAAP accounting and reporting as the equity return does not meet the recognition criteria of a incurred costs eligible for deferral under GAAP. The carrying charges began to accrue in March 2009 as authorized by the FERC Order and will continue until such time that the regulatory asset is included in rate base.

Recovery of the KETA Project regulatory asset requires FERC authorization upon ITC Great Plains making an additional filing under Section 205 of the Federal Power Act to demonstrate that the costs to be recovered are just and reasonable. Subsequent to FERC authorization, ITC Great Plains will include the unamortized balance of the KETA Project Regulatory Asset in its rate base and begin amortizing it over a ten-year period upon the in-service date of the KETA Project. The amortization expense will be recovered through ITC Great Plains’ cost-based formula rate template beginning in that year.

Pensions and Postretirement

Accounting standards for defined benefit pension and other postretirement plans require 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.

Regulatory Liabilities

The following table summarizes the regulatory liabilities balances at December 31, 2010 and 2009:

(In thousands)	2010		2009
Regulatory Liabilities:
Accrued asset removal costs	$	90,987	$	112,430
Revenue deferrals(a):
Current (including accrued interest of $876 as of December 31, 2010)		17,658		—
Non-current (including accrued interest of $680 and $186 as of December 31, 2010 and 2009, respectively)		43,202		10,238
Total	$	151,847	$	122,668

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(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.

Accrued Asset Removal Costs

The carrying amount of the accrued asset removal costs represents the accrued asset removal costs to remove the asset 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. As a result of ITC Midwest’s depreciation studies as discussed in Note 4 under “Depreciation Studies,” we recorded a decrease in our regulatory liability for accrued removal costs of $17.9 million during 2010.

6.   GOODWILL AND INTANGIBLE ASSETS

At December 31, 2010, 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. At December 31, 2009, we had goodwill balances recorded at ITCTransmission, METC and ITC Midwest of $173.4 million, $453.8 million and $323.0 million, 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 Deferrals. The carrying amount of the intangible asset for METC Regulatory Deferrals at December 31, 2010 and 2009 is $31.7 million and $33.6 million, respectively, and is amortized over 20 years beginning January 1, 2007, which corresponds to the amortization period established in METC rate case settlement in 2007. The carrying amount of the intangible asset for METC ADIT Deferrals at December 31, 2010 and 2009 is $14.6 million and $15.7 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 Deferrals.

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. The carrying amount of these intangible assets is $3.7 million and $2.7 million (net of accumulated amortization of $0.1 million and less than $0.1 million) as of December 31, 2010 and 2009, respectively.

During the year ended December 31, 2010, we recognized $3.1 million of amortization expense of our intangible assets. During each of the years ended December 31, 2009 and 2008, we recognized

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$3.0 million of amortization expense of our intangible assets. We expect the annual amortization of our intangible assets that have been recorded as of December 31, 2010 to be as follows:

(In thousands)
2011	$	3,100
2012		3,100
2013		3,100
2014		3,100
2015		3,100
2016 and thereafter		34,485
Total	$	49,985

7.   PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment-net consisted of the following at December 31, 2010 and 2009:

(In thousands)	2010			2009
Property, plant and equipment
Regulated Operating Subsidiaries:
Property, plant and equipment in service	$	3,722,937		$	3,330,057
Construction work in progress		197,985			167,092
Capital equipment inventory		62,168			76,697
Other		12,432			12,114
ITC Holdings and other		6,424			7,149
Total		4,001,946			3,593,109
Less accumulated depreciation and amortization		(1,129,669	)		(1,051,045	)
Property, plant and equipment-net	$	2,872,277		$	2,542,064

Additions to property, plant and equipment in service and construction work in progress during 2010 and 2009 were primarily for projects to upgrade or replace existing transmission plant to improve the reliability of our transmission systems.

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8.   LONG-TERM DEBT

The following amounts were outstanding at December 31, 2010 and 2009:

(In thousands)	2010		2009
ITC Holdings 5.25% Senior Notes due July 15, 2013 (net of discount of $302 and $421, respectively)	$	266,698	$	266,579
ITC Holdings 6.04% Senior Notes, Series A, due September 20, 2014		50,000		50,000
ITC Holdings 5.875% Senior Notes due September 30, 2016 (net of discount of $19 and $22, respectively)		254,981		254,978
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 $197 and $205, respectively)		254,803		254,795
ITC Holdings 6.050% Senior Notes due January 31, 2018 (net of discount of $1,118 and $1,276, respectively)		383,882		383,724
ITC Holdings 5.500% Senior Notes due January 15, 2020 (net of discount of $1,186 and $1,319, respectively)		198,814		198,681
ITC Holdings Revolving Credit Agreement due March 29, 2012		—		—
ITCTransmission 4.45% First Mortgage Bonds, Series A, due July 15, 2013 (net of discount of $30 and $42, respectively)		184,970		184,958
ITCTransmission 6.125% First Mortgage Bonds, Series C, due March 31, 2036 (net of discount of $93 and $96, respectively)		99,907		99,904
ITCTransmission 5.75% First Mortgage Bonds, Series D, due April 1, 2018 (net of discount of $83 and $95, respectively)		99,917		99,905
ITCTransmission/METC Revolving Credit Agreement due March 29, 2012		13,800		57,803
METC 5.75% Senior Secured Notes due December 10, 2015		175,000		175,000
METC 6.63% Senior Secured Notes due December 18, 2014		50,000		50,000
METC 5.64% Senior Secured Notes due May 6, 2040		50,000		—
ITC Midwest 6.15% First Mortgage Bonds, Series A, due January 31, 2038 (net of discount of $476 and $493, respectively)		174,524		174,507
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		35,000
ITC Midwest Revolving Credit Agreement due January 29, 2013		39,600		23,564
Total long-term debt	$	2,496,896	$	2,434,398

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The annual maturities of long-term debt as of December 31, 2010 are as follows:

(In thousands)
2011	$	—
2012		13,800
2013		491,600
2014		100,000
2015		175,000
2016 and thereafter		1,720,000
Total	$	2,500,400

ITC Holdings

Term Loan Agreement

On April 29, 2009, ITC Holdings entered into a two year Term Loan Agreement (the “Term Loan Agreement”) with various financial institutions as lenders. The Term Loan Agreement established an unguaranteed, unsecured $100 million term facility, under which the entire $100 million was drawn at closing. Amounts outstanding under the Term Loan Agreement accrued interest at 350 basis points over the applicable LIBOR rate and could be repaid without penalty in increments of $5 million in advance of the maturity date. The funds provided under the Term Loan Agreement were used for general corporate purposes.

In December 2009, we repaid in full all amounts outstanding under the Term Loan Agreement using proceeds of ITC Holdings’ $200.0 million 5.50% Senior Notes due January 15, 2020. ITC Holdings incurred a loss on extinguishment of debt of $1.3 million related to the write-off of deferred debt issuance costs.

Senior Notes

The ITC Holdings Senior Notes are issued under ITC Holdings’ indenture. All issuances of ITC Holdings Senior Notes are unsecured.

ITCTransmission

The ITCTransmission First Mortgage Bonds are issued under ITCTransmission’s First Mortgage and Deed of Trust, and therefore have the benefit of a first mortgage lien on substantially all of ITCTransmission’s property.

METC

On May 6, 2010, METC issued $50.0 million aggregate principal amount of its 5.64% Senior Secured Notes, due May 6, 2040 (the “METC Senior Secured Notes”). The METC Senior Secured Notes are secured by a first mortgage lien on substantially all of METC’s real property and tangible personal property. The proceeds were used primarily to repay amounts outstanding under the ITCTransmission/METC Revolving Credit Agreement, to partially fund capital expenditures and for general corporate purposes.

ITC Midwest

On December 17, 2009, ITC Midwest issued $35.0 million of the total face amount of $75.0 million of its 4.60% First Mortgage Bonds, Series D, due December 17, 2024 (“Series D Bonds”). ITC Midwest closed on the additional $40.0 million of Series D Bonds in February 2010. The proceeds were used to

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repay a portion of the amounts outstanding under the ITC Midwest Revolving Credit Agreement. All of ITC Midwest’s First Mortgage Bonds are issued under its First Mortgage and Deed of Trust, and therefore have the benefit of a first mortgage lien on substantially all of ITC Midwest’s property.

Derivative Instruments and Hedging Activities

We 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. On September 27, 2010, ITC Holdings entered into a 10-year forward starting interest rate swap agreement with a notional amount of $50.0 million. The interest rate swap manages interest rate risk associated with the forecasted future issuance of fixed-rate debt related to the expected refinancing of the maturing $267.0 million ITC Holdings 5.25% Senior Notes due July 15, 2013.

The interest rate swap calls for ITC Holdings to receive interest quarterly at a variable rate equal to LIBOR and to pay interest semi-annually at a fixed rate of 3.60% effective for the ten-year period beginning July 15, 2013. The agreement will be terminated no later than the effective date of the interest rate swap of July 15, 2013. The interest rate swap has been determined to be highly effective at offsetting changes in the cash flows of the forecasted interest payments associated with the expected debt issuance attributable to changes in benchmark interest rates from the trade date of the interest rate swap to the issuance date of the debt obligation. As of December 31, 2010, there has been no ineffectiveness recorded on the consolidated statement of operations. The interest rate swap qualifies for hedge accounting treatment, whereby any pre-tax gain or loss recognized from the trade date to the effective date for the effective portion of the hedge is recorded in accumulated other comprehensive income (loss). These amounts will be accumulated and amortized as a component of interest expense over the life of the forecasted debt. As of December 31, 2010, the fair value of the derivative instrument was an asset of $3.1 million.

Revolving Credit Agreements

ITC Holdings Revolving Credit Agreement

ITC Holdings has a revolving credit agreement, (the “ITC Holdings Revolving Credit Agreement”), dated as of March 29, 2007, that establishes an unguaranteed, unsecured revolving credit facility under which ITC Holdings may borrow and issue letters of credit up to $105.2 million. The maturity date of the ITC Holdings Revolving Credit Agreement is March 29, 2012. With consent of the lenders holding a majority of the commitments under the ITC Holdings Revolving Credit Agreement, ITC Holdings may extend the maturity date of the ITC Holdings Revolving Credit Agreement for up to two additional one-year periods. Loans under the ITC Holdings Revolving Credit Agreement are variable rate loans, with rates on LIBOR-based loans varying from 20 to 110 basis points over the applicable LIBOR rate, depending on ITC Holdings’ credit rating and the amount of the credit line in use, and rates on other loans at the higher of prime or 50 basis points over the federal funds rate. At December 31, 2010 and 2009, ITC Holdings had no outstanding amounts under the ITC Holdings Revolving Credit Agreement. The ITC Holdings Revolving Credit Agreement also provides for the payment to the lenders of a commitment fee on the average daily unused commitments at rates varying from 0.05% to 0.20% each year, depending on ITC Holdings’ credit rating.

ITCTransmission/METC Revolving Credit Agreement

ITCTransmission and METC have a revolving credit agreement (the “ITCTransmission/METC Revolving Credit Agreement”), dated as of March 29, 2007, that establishes an unguaranteed, unsecured revolving credit facility under which ITCTransmission may borrow and issue letters of credit up to

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$88.3 million and METC may borrow and issue letters of credit up to $50.5 million. The maturity date of the ITCTransmission/METC Revolving Credit Agreement is March 29, 2012. With consent of the lenders holding a majority of the commitments under the ITCTransmission/METC Revolving Credit Agreement, ITCTransmission and METC may extend the maturity date of the ITCTransmission/METC Revolving Credit Agreement for up to two additional one-year periods. Loans made under the ITCTransmission/METC Revolving Credit Agreement are variable rate loans, with rates on LIBOR-based loans varying from 20 to 110 basis points over the applicable LIBOR rate, depending on ITCTransmission and METC’s credit ratings and the amount of the credit line in use, and rates on other loans at the higher of prime or 50 basis points over the federal funds rate. At December 31, 2010 and 2009, ITCTransmission had $11.6 million and $20.9 million, respectively, outstanding under the ITCTransmission/METC Revolving Credit Agreement. At December 31, 2010 and 2009, METC had $2.2 million and $36.9 million, respectively, outstanding under the ITCTransmission/METC Revolving Credit Agreement. The weighted-average interest rate of borrowings outstanding under the agreement at December 31, 2010 and 2009 was 3.3% and 0.6%, respectively, for both ITCTransmission and METC. The ITCTransmission/METC Revolving Credit Agreement also provides for the payment to the lenders of a commitment fee on the average daily unused commitments at rates varying from 0.05% to 0.20% each year, depending on ITCTransmission’s and METC’s credit ratings.

ITC Midwest Revolving Credit Agreement

ITC Midwest has a revolving credit agreement (the “2008 ITC Midwest Revolving Credit Agreement”), dated as of January 28, 2008, that establishes an unguaranteed, unsecured revolving credit facility under which ITC Midwest may borrow and issue letters of credit up to $41.0 million. The maturity date of the 2008 ITC Midwest Revolving Credit Agreement is January 29, 2013. ITC Midwest’s loans made under the 2008 ITC Midwest Revolving Credit Agreement bear interest at a variable rate, with rates on LIBOR-based loans varying from 20 to 110 basis points over the applicable LIBOR rate, depending on ITC Midwest’s credit rating and the amount of the credit line in use, and rates on other loans at the higher of prime or 50 basis points over the federal funds rate. At December 31, 2010 and 2009, ITC Midwest had $39.6 million and $23.6 million, respectively, outstanding under the 2008 ITC Midwest Revolving Credit Agreement. The weighted-average interest rate of borrowings outstanding under the agreement was 0.6% at both December 31, 2010 and 2009. The 2008 ITC Midwest Revolving Credit Agreement also provides for the payment to the lenders of a commitment fee on the average daily unused commitments at rates varying from 0.05% to 0.20% each year, depending on ITC Midwest’s credit rating.

On February 11, 2011, ITC Midwest entered into a new revolving credit agreement (the “2011 ITC Midwest Revolving Credit Agreement”) that establishes an unguaranteed, unsecured revolving facility under which ITC Midwest may borrow up to $75.0 million, in addition to the borrowing capacity under the 2008 ITC Midwest Revolving Credit Agreement. The maturity date of the 2011 ITC Midwest Revolving Credit Agreement is February 11, 2013. ITC Midwest’s loans made under the 2011 ITC Midwest Revolving Credit Agreement bear interest at a variable rate, with rates on LIBOR-based loans varying from 125 to 150 basis points over the applicable LIBOR rate, depending on ITC Midwest’s credit rating, and rates on other loans at the higher of prime, 50 basis points over the federal funds rate or 100 basis points over the one month LIBOR plus an applicable margin varying from 25 basis points to 50 basis points in each case, depending on ITC Midwest’s credit rating. The 2011 ITC Midwest Revolving Credit Agreement also provides for the payment to the lenders of a commitment fee on the average daily unused commitments at rates varying from 0.125% to 0.175% each year, depending on ITC Midwest’s credit rating.

ITC Great Plains Revolving Credit Agreement

On February 16, 2011, ITC Great Plains entered into a revolving credit agreement (the “ITC Great Plains Revolving Credit Agreement”) that established an unguaranteed, unsecured revolving credit facility

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under which ITC Great Plains may borrow and issue letters of credit up to $150.0 million. The maturity date of the ITC Great Plains Revolving Credit Agreement is February 16, 2015. ITC Great Plain’s loans made under the ITC Great Plains Revolving Credit Agreement will bear interest at a variable rate, with rates on LIBOR-based loans varying from 150 to 275 basis points over the applicable LIBOR rate, depending on ITC Great Plains’ credit rating and rates on other loans at the higher of prime, 50 basis points over the federal funds rate or 100 basis points over the one month LIBOR rate plus an applicable margin varying from 50 basis points to 175 basis points in each case, depending on ITC Great Plains credit rating. The ITC Great Plains Revolving Credit Agreement also provides for the payment to the lenders of a commitment fee on the average daily unused commitments at rates varying from 0.25% to 0.50% each year, depending on ITC Great Plains’ credit rating.

Lehman Commitment

On July 22, 2010, we amended our revolving credit facilities to remove Lehman Brothers Bank, FSB’s unfulfilled commitments of $19.8 million, $16.7 million, $9.5 million and $9.0 million for ITC Holdings, ITCTransmission, METC and ITC Midwest, respectively, and to permit us in the future to terminate or replace certain lenders that default on their obligations under the credit facilities.

Covenants

Our debt instruments described above 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. We are currently in compliance with all debt covenants.

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9.   EARNINGS PER SHARE

We report both basic and diluted earnings per share. A reconciliation of both calculations for the years ended December 31, 2010, 2009 and 2008 is presented in the following table:

(In thousands, except share, per share data and percentages)	2010			2009			2008
Numerator:
Net income	$	145,678		$	130,900		$	109,208
Less: dividends declared — common shares, restricted shares and deferred stock units(a)		(66,017	)		(62,392	)		(58,933	)
Undistributed earnings		79,661			68,508			50,275
Percentage allocated to common shares(b)		98.3	%		98.6	%		98.9	%
Undistributed earnings — common shares		78,307			67,549			49,722
Add: dividends declared — common shares		64,926			61,517			58,318
Numerator for basic and diluted earnings per common share	$	143,233		$	129,066		$	108,040
Denominator:
Denominator for basic earnings per common share — weighted-average common shares		49,526,580			49,196,470			48,592,534
Incremental shares for stock options and employee stock purchase plan		871,459			880,963			1,035,353
Denominator for diluted earnings per common share — adjusted weighted-average shares and assumed conversion		50,398,039			50,077,433			49,627,887
Per common share net income:
Basic	$	2.89		$	2.62		$	2.22
Diluted	$	2.84		$	2.58		$	2.18
(a) Includes dividends paid in the form of shares for deferred stock units
(b) Weighted-average common shares outstanding		49,526,580			49,196,470			48,592,534
Weighted-average restricted shares and deferred stock units (participating securities)		842,108			705,716			517,248
Total		50,368,688			49,902,186			49,109,782
Percentage allocated to common shares		98.3	%		98.6	%		98.9	%

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.

The retroactive application of the two-class method resulted in a decrease in basic earnings per share of $0.03 per share for the year ended December 31, 2008 as compared to the earnings per share calculations used and disclosed in our Form 10-K for the annual period ended December 31, 2008. The retroactive application of the two-class method decreased diluted earnings per share by $0.01 per share for the year ended December 31, 2008.

At December 31, 2010, 2009 and 2008, we had 2,436,742, 2,673,121 and 2,603,115 of outstanding stock options, respectively. Stock options are included in the diluted earnings per share calculation using

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the treasury stock method, unless the effect of including the stock options would be anti-dilutive. At December 31, 2010, 2009, and 2008, 225,740, 814,914 and 502,511 anti-dilutive stock options were excluded from the diluted earnings per share calculations, respectively.

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)	2010			2009			2008
Income tax expense at 35% statutory rate	$	79,776		$	72,965		$	61,765
State income taxes (net of federal benefit)		4,208			7,230			6,769
Valuation allowance — state income taxes		1,719			785			1,829
AFUDC equity		(3,998	)		(4,336	)		(3,601	)
Other — net		549			928			500
Income tax provision	$	82,254		$	77,572		$	67,262

Components of the income tax provision were as follows:

(In thousands)	2010		2009		2008
Current income tax expense	$	5,508	$	2,571	$	2,208
Deferred income tax expense		6,989		74,001		65,054
Benefits of operating loss carryforward		69,757		1,000		—
Total income tax provision	$	82,254	$	77,572	$	67,262

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 noncurrent 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.

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

(In thousands)	2010			2009
Property, plant and equipment	$	(246,354	)	$	(209,169	)
Federal income tax NOLs		2,347			80,437
Michigan Business Tax deductions		21,697			21,697
METC regulatory deferral(a)		(16,947	)		(17,395	)
Acquisition adjustments — ADIT deferrals(a)		(16,454	)		(15,704	)
Goodwill		(75,017	)		(57,555	)
Revenue accruals/deferrals — net (including accrued interest)(a)		9,522			(41,970	)
Pension and postretirement liabilities		14,030			12,506
State income tax NOLs		20,152			17,103
Other — net		(25,706	)		(18,994	)
Deferred tax asset valuation allowance(b)		(2,645	)		(2,613	)
Net deferred tax liabilities	$	(315,375	)	$	(231,657	)
Gross deferred income tax liabilities	$	(414,616	)	$	(382,244	)
Gross deferred income tax assets		101,886			153,200
Deferred tax asset valuation allowance(b)		(2,645	)		(2,613	)
Net deferred tax liabilities	$	(315,375	)	$	(231,657	)

(a)	Described in Note 5.
(b)	Amounts relate primarily to state income tax NOLs for which it is more likely than not that a tax benefit will not be realized.

We have estimated federal income tax NOLs of $61.2 million as of December 31, 2010, all of which we expect to use prior to their expiration. These federal income tax NOLs result in part from accelerated depreciation methods for property, plant and equipment for income tax reporting purposes. Portions of our federal income tax NOLs would expire beginning in 2019, with the majority of federal income tax NOLs expiring in 2028 and 2029.

Included in the $61.2 million total estimated federal income tax NOLs is $54.5 million ($19.1 million tax effected) of federal income tax NOLs relating to tax deductions for share-based compensation not recognized in the consolidated financial statements. The accounting standards for share-based compensation require that the tax deductions that exceed book value be recognized as increases to common stock only if that deduction reduces taxes payable as a result of a realized cash benefit from the deduction. For the years ended December 31, 2010, 2009 and 2008, we did not recognize the tax effects of the excess federal tax deductions as increases in common stock or increases to NOL deferred tax assets, as the deductions have not resulted in a reduction of taxes payable due to our federal income tax NOLs. For the year ended December 31, 2010 and 2009, we recognized the tax effects of the excess state tax deduction as common stock of $0.3 million and $0.1 million, respectively. No state tax deductions were recognized for the year ended December 31, 2008.

METC Uncertain Tax Position

At December 31, 2009, we had an uncertain tax position resulting from an analysis we performed on various transaction costs incurred in connection with the METC acquisition. In applying the measurement provisions of income taxes, this tax position resulted in an immaterial reduction to the deferred tax asset

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recorded in purchase accounting. This tax position was settled in January 2010 upon completion of the Internal Revenue Service audit of our 2006 tax year. The settlement of this tax position resulted in a reduction of our income tax provision by $0.7 million when recorded in the first quarter of 2010.

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 $6.1 million, $3.2 million and $2.1 million to the retirement plan in 2010, 2009 and 2008, respectively, although we had no minimum funding requirements. We expect to contribute up to $3.6 million to the defined benefit retirement plan relating to the 2010 plan year in 2011.

We have also established two supplemental nonqualified, noncontributory, retirement 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 $10.8 million and $9.4 million at December 31, 2010 and 2009, 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, 2010, 2009 and 2008, we contributed $0.5 million, $4.0 million and $1.0 million, respectively, to these supplemental nonqualified, noncontributory, retirement benefit plans. We account for the assets contributed under the supplemental nonqualified, noncontributory, retirement benefit plan and held in a trust as trading securities under the ASC for certain investments in debt and equity securities. Accordingly, realized and unrealized gains or losses on the investments are recorded as investment income or loss. We recognized gains of $0.9 million and $0.7 million in other income during 2010 and 2009, respectively, and losses of $1.8 million in other expenses during 2008 associated with realized and unrealized gains and losses on the investments held in trust associated with our supplemental nonqualified retirement plans.

The plan assets consisted of the following assets by category:

Asset Category	2010			2009
Fixed income securities		47.2	%		57.8	%
Equity securities		52.8	%		42.2	%
Total		100.0	%		100.0	%

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Net pension cost for 2010, 2009 and 2008 includes the following components:

(In thousands)	2010			2009			2008
Service cost	$	2,868		$	2,674		$	1,977
Interest cost		2,222			1,691			1,164
Expected return on plan assets		(1,388	)		(987	)		(1,038	)
Amortization of prior service cost		(42	)		(42	)		(882	)
Amortization of actuarial loss		1,722			2,250			1,762
Net pension cost	$	5,382		$	5,586		$	2,983

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, 2010 and 2009:

(In thousands)	2010			2009
Change in Benefit Obligation:
Beginning projected benefit obligation	$	(35,734	)	$	(26,175	)
Service cost		(2,868	)		(2,674	)
Interest cost		(2,222	)		(1,691	)
Actuarial net loss		(4,856	)		(5,820	)
Benefits paid		576			626
Ending projected benefit obligation	$	(45,104	)	$	(35,734	)
Change in Plans’ Assets:
Beginning plan assets at fair value	$	16,503		$	12,294
Actual return on plan assets		2,632			1,648
Employer contributions		6,088			3,187
Benefits paid		(576	)		(626	)
Ending plan assets at fair value	$	24,647		$	16,503
Funded status, underfunded	$	(20,457	)	$	(19,231	)
Ending accumulated benefit obligation	$	(33,830	)	$	(25,534	)
Amounts recorded as:
Funded Status:
Accrued pension and postretirement liabilities	$	(23,165	)	$	(19,231	)
Pension assets — other assets — other		2,708			—
Total	$	(20,457	)	$	(19,231	)
Unrecognized Amounts in Other Regulatory Assets:
Net actuarial loss	$	13,288		$	11,398
Prior service credit		(142	)		(184	)
Total	$	13,146		$	11,214

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.

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We also recorded a deferred income tax liability on the regulatory asset in deferred income tax liabilities 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 2010, 2009 and 2008 are listed below:

	2010			2009			2008
Discount rate		5.60	%		6.00	%		5.95	%
Annual rate of salary increases		5.00	%		5.00	%		5.00	%

Actuarial assumptions used to determine the benefit cost for 2010, 2009 and 2008 are listed below:

	2010			2009			2008
Discount rate		6.00	%		5.95	%		6.19	%
Annual rate of salary increases		5.00	%		5.00	%		5.00	%
Expected long-term rate of return on plan assets		7.50	%		7.25	%		7.25	%

At December 31, 2010, the projected benefit payments for the defined benefit retirement plan calculated using the same assumptions as those used to calculate the benefit obligation described above are listed below:

(In thousands)
2011	$	575
2012		1,202
2013		1,914
2014		3,388
2015		3,830
2016 through 2020		22,525

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 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.

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The fair value measurement of the retirement plan as of December 31, 2010, 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	$	—	$	10,502	$	—
Pooled separate accounts — international equity securities		—		2,506		—
Pooled separate accounts — fixed income securities		—		9,999		—
Guaranteed deposit fund		—		1,640		—
Total	$	—	$	24,647	$	—

The fair value measurement of the retirement plan as of December 31, 2009, 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:
Short term investments	$	—	$	3,599	$	—
Pooled separate accounts — U.S. equity securities		—		5,487		—
Pooled separate accounts — international equity securities		—		1,469		—
Pooled separate accounts — fixed income securities		—		4,618		—
Guaranteed deposit fund		—		1,330		—
Total	$	—	$	16,503	$	—

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 $3.1 million, $2.5 million and $1.3 million to the postretirement benefit plan in 2010, 2009 and 2008, respectively. We expect to contribute up to $3.5 million to the plan in 2011.

The plan assets consisted of the following assets by category:

Asset Category	2010			2009
Fixed income securities		53.2	%		73.3	%
Equity securities		46.8	%		26.7	%
Total		100.0	%		100.0	%

Our measurement of the accumulated postretirement benefit obligation as of December 31, 2010 and 2009 does not reflect any potential amounts associated with subsidies under the Medicare Prescription Drug, Improvement and Modernization Act of 2003.

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Net postretirement cost for 2010, 2009 and 2008 includes the following components:

(In thousands)	2010			2009			2008
Service cost	$	2,809		$	1,841		$	1,632
Interest cost		984			921			672
Expected return on plan assets		(469	)		(228	)		(218	)
Amortization of unrecognized prior service cost		313			314			580
Amortization of actuarial loss		—			166			—
Net postretirement cost	$	3,637		$	3,014		$	2,666

The following table reconciles the obligations, assets and funded status of the plans as well as the amounts recognized as accrued postretirement liability in the consolidated statement of financial position as of December 31, 2010 and 2009:

(In thousands)	2010			2009
Change in Benefit Obligation:
Beginning accumulated postretirement obligation	$	(17,757	)	$	(13,419	)
Service cost		(2,809	)		(1,841	)
Interest cost		(984	)		(921	)
Actuarial net loss		(1,189	)		(1,625	)
Benefits paid		330			49
Ending accumulated postretirement obligation	$	(22,409	)	$	(17,757	)
Change in Plan’s Assets:
Beginning plan assets at fair value	$	5,830		$	3,005
Actual return on plan assets		850			297
Employer contributions		3,083			2,528
Employer provided retiree premiums		330			49
Benefits paid		(330	)		(49	)
Ending Plan assets at fair value	$	9,763		$	5,830
Funded status, underfunded	$	(12,646	)	$	(11,927	)
Amounts recorded as:
Funded Status:
Accrued pension and postretirement liabilities	$	(12,646	)	$	(11,927	)
Total	$	(12,646	)	$	(11,927	)
Unrecognized Amounts in Other Regulatory Assets:
Net actuarial loss	$	3,121		$	2,314
Prior service cost		438			751
Total	$	3,559		$	3,065

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. We also recorded a deferred income tax liability on the regulatory asset in deferred income tax liabilities on our consolidated

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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 2010, 2009 and 2008 are as follows:

	2010			2009			2008
Discount rate		5.60	%		6.00	%		5.95	%
Annual rate of salary increases		5.00	%		5.00	%		5.00	%
Health care cost trend rate assumed for next year		9.00	%		9.00	%		10.00	%
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		2016			2015			2015
Annual rate of increase in dental benefit costs		5.00	%		5.00	%		5.00	%

Actuarial assumptions used to determine the benefit cost for 2010, 2009 and 2008 are as follows:

	2010			2009			2008
Discount rate		6.00	%		5.95	%		6.19	%
Annual rate of salary increases		5.00	%		5.00	%		5.00	%
Health care cost trend rate assumed for next year		9.00	%		10.00	%		10.50	%
Rate to which the cost trend rate is assumed to decline		5.00	%		5.00	%		5.00	%
Year that the rate reaches the ultimate trend rate		2015			2015			2015

At December 31, 2010, 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)
2011	$	202
2012		284
2013		419
2014		592
2015		742
2016 through 2020		8,141

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 2010 and the postretirement benefit obligation at December 31, 2010:

	One-Percentage-		One-Percentage-
(In thousands)	Point Increase		Point Decrease
Effect on total of service and interest cost	$	681	$	(545	)
Effect on postretirement benefit obligation		2,524		(2,053	)

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

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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.

The fair value measurement of the other postretirement benefit plans as of December 31, 2010, 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	$	27	$	—	$	—
Pooled separate accounts — U.S. equity securities		—		859		—
Pooled separate accounts — international equity securities		—		188		—
Pooled separate accounts — fixed income securities		—		813		—
Mutual funds — equity securities		3,515		—		—
Mutual funds — fixed income securities		3,350		—		—
Guaranteed deposit fund		—		1,011		—
Total	$	6,892	$	2,871	$	—

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The fair value measurement of the other postretirement benefit plans as of December 31, 2009, 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	$	2,836	$	—	$	—
Pooled separate accounts — U.S. equity securities		—		723		—
Pooled separate accounts — international equity securities		—		174		—
Pooled separate accounts — fixed income securities		—		749		—
Mutual funds — equity securities		662		—		—
Mutual funds — fixed income securities		519		—		—
Guaranteed deposit fund		—		167		—
Total	$	4,017	$	1,813	$	—

Defined Contribution Plans

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 $2.7 million, $2.6 million and $1.8 million in 2010, 2009 and 2008, 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.

Our assets measured at fair value subject to the three-tier hierarchy at December 31, 2010, were 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 — cash equivalents	$	10	$	84,726	$	—
Mutual funds — fixed income securities		10,479		—		—
Mutual funds — equity securities		876		—		—
Interest rate swap derivative		—		3,099		—
Total	$	11,365	$	87,825	$	—

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Our assets measured at fair value subject to the three-tier hierarchy at December 31, 2009, were 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 — cash equivalents	$	70,558	$	—	$	—
Mutual funds — fixed income securities		6,091		—		—
Mutual funds — equity securities		3,775		—		—
Total	$	80,424	$	—	$	—

As of December 31, 2010, we held certain assets that are required to be measured at fair value on a recurring basis. These consist of investments recorded within cash and cash equivalents and other long-term assets, including investments held in trust associated with our nonqualified, noncontributory, supplemental retirement benefit plans for selected management and employees that are classified as trading securities discussed in Note 11 and our interest rate swap discussed in Note 8. Our investments included in cash equivalents consist of money market funds recorded at cost plus accrued interest to approximate fair value. Our investments classified as trading securities consist primarily of mutual funds and equity securities that are publicly traded and for which market prices are readily available. 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 if fair value falls below recorded cost. The fair value of our interest rate swap derivative as of December 31, 2010 is determined based on a discounted cash flow method.

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 take any impairment charges on long-lived assets and no other significant events requiring non-financial assets and liabilities to be measured at fair value occurred (subsequent to initial recognition) during the year ended December 31, 2010.

Fair Value of Long-Term Debt

Fixed Rate Long-Term 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 as described in Note 8, excluding revolving credit agreements, was $2,747.2 million and $2,165.9 million at December 31, 2010 and 2009, respectively. The total book value of our consolidated long-term debt, excluding revolving credit agreements, was $2,443.5 million and $2,353.0 million at December 31, 2010 and 2009, respectively.

Revolving Credit Agreements

At December 31, 2010 and 2009, we had a consolidated total of $53.4 million and $81.4 million, respectively, outstanding under our revolving credit agreements, which are variable rate loans. The fair value of these loans approximates book value.

Trade Accounts Receivables and Payables

As of December 31, 2010, our accounts receivable and accounts payable balances approximate fair value due to their short term nature.

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13.   STOCKHOLDERS’ EQUITY

Common Stock

General — ITC Holdings’ authorized capital stock consists of:

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

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

As of December 31, 2010, there were 50,715,805 shares of our common stock outstanding, no shares of preferred stock outstanding and 515 holders of record of our common stock.

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 stockholders, 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 relating primarily to federal income tax NOLs 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’ stockholders 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.

Each of the ITC Holdings Revolving Credit Agreement, the ITCTransmission/METC Revolving Credit Agreement, the ITC Midwest Revolving Credit Agreements, the ITC Great Plains Revolving Credit Agreement and the note purchase agreements governing ITC Holdings’ Senior Notes imposes 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 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 the requirements of SEC Regulation S-X Rule 4-08(e), Schedule I is required because of restrictions which limit the payment of dividends to ITC Holdings by its subsidiaries. ITCTransmission, METC and ITC Midwest 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

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covenants under our revolving credit agreements, we may not be able to disburse dividends. ITCTransmission, METC and ITC Midwest were in compliance with the covenants under their revolving credit agreements during 2010.

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 2010 and 2009, we repurchased 1,057 and 700 shares of common stock for an aggregate of $0.1 million and less than $0.1 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. No shares of common stock were repurchased during 2008.

ITC Holdings’ Common Stock Offerings

In January 2008, ITC Holdings completed an underwritten public offering of its common stock. ITC Holdings sold 6,420,737 newly-issued common shares in the offering, which resulted in proceeds of $308.3 million (net of underwriting discount of $13.7 million and before issuance costs of $0.8 million). The proceeds from this offering were used to partially finance ITC Midwest’s asset acquisition and for general purposes.

ITC Holdings Sales Agency Financing Agreement

On June 27, 2008, ITC Holdings entered into a Sales Agency Financing Agreement (the “SAFE Agreement”) with BNY Mellon Capital Markets, LLC (“BNYMCM”). Under the terms of the SAFE Agreement, ITC Holdings may issue and sell shares of common stock, without par value, from time to time, up to an aggregate sales price of $150.0 million. The term of the SAFE Agreement is for a period of up to June 2011, subject to continued approval from the FERC authorizing ITC Holdings to issue equity. BNYMCM will act as ITC Holdings’ agent in connection with any offerings of shares under the SAFE Agreement. The shares of common stock may be offered in one or more selling periods, none of which will exceed 20 trading days. Any shares of common stock sold under the SAFE Agreement will be offered at market prices prevailing at the time of sale. Moreover, ITC Holdings will specify to BNYMCM (i) the aggregate selling price of the shares of common stock to be sold during each selling period, which may not exceed $40.0 million without BYNMCM’s prior written consent and (ii) the minimum price below which sales may not be made, which may not be less than $10.00 per share without BNYMCM’s prior written consent. ITC Holdings will pay BNYMCM a commission equal to 1% of the sales price of all shares of common stock sold through it as agent under the SAFE Agreement, plus expenses. The shares we would issue under the SAFE Agreement have been registered under ITC Holdings’ automatic shelf registration statement on Form S-3 (File No. 333- 163716) filed on December 14, 2009 with the SEC. As of December 31, 2010, we have not issued shares under the SAFE Agreement.

14.   SHARE-BASED COMPENSATION

Our Long Term Incentive Plan, which was adopted in 2006 and amended and restated in 2008 (the “LTIP”), permits the compensation committee to make grants of a variety of share-based awards (such as

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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, 2012. Prior to the adoption of the LTIP, we made various share-based awards under the 2003 Stock Purchase and Option Plan (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, 2010, 3,305,528 shares were available for future issuance under our 2003 Plan, ESPP and 2006 LTIP, including 2,436,742 shares issuable upon the exercise of outstanding stock options, of which 1,778,451 were vested.

We recorded share-based compensation in 2010, 2009 and 2008 as follows:

(In thousands)	2010		2009		2008
Operation and maintenance expenses	$	2,098	$	1,581	$	1,152
General and administrative expenses		8,074		4,999		4,674
Amounts capitalized to property, plant and equipment		4,702		3,426		1,446
Total share-based compensation	$	14,874	$	10,006	$	7,272
Total tax benefit recognized in the consolidated statement of operations	$	4,028	$	2,621	$	2,328

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 year ended December 31, 2010, 2009 and 2008, we did not recognize excess federal tax deductions for option exercises and restricted stock vesting of $6.1 million, $2.4 million, and $2.0 million, respectively, in common stock, as the deductions have not resulted in a cash benefit due to our federal income tax NOLs. We will recognize these excess federal tax deductions in common stock when the tax benefits are realized. For the year ended December 31, 2010 and 2009, we recognized the tax effects of the excess state tax deduction as common stock of $0.3 million and $0.1 million, respectively. No state tax deduction was recognized for the year ended December 31, 2008.

Options

Our option grants vest in equal annual installments over a three- or five-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 2010 was as follows:

				Weighted
	Number of			Average
	Options			Exercise Price
Outstanding at January 1, 2010 (1,852,682 exercisable with a weighted average exercise price of $16.50)		2,673,373		$	24.10
Granted		232,537			52.47
Exercised		(464,264	)		16.65
Forfeited		(4,904	)		40.64
Outstanding at December 31, 2010 (1,778,451 exercisable with a weighted average exercise price of $21.21)		2,436,742		$	27.96

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Grant date fair value of the stock options was determined using a Black-Scholes option pricing model. The following assumptions were used in determining the weighted-average fair value per option:

	2010			2009			2008
	Option Grants			Option Grants			Options Grants
Weighted-average grant-date fair value per option	$	16.01		$	11.93		$	13.31
Weighted-average expected volatility(a)		37.4	%		37.5	%		24.7	%
Weighted-average risk-free interest rate		2.5	%		2.4	%		3.4	%
Weighted-average expected term(b)		6 years			6 years			6 years
Weighted-average expected dividend yield		2.44	%		2.95	%		2.14	%
Estimated fair value of underlying shares	$	52.47		$	41.37		$	56.88

(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 period of time our equity shares have been publicly traded.

At December 31, 2010, the aggregate intrinsic value and the weighted-average remaining contractual term for all outstanding options were approximately $82.4 million and 5.2 years, respectively. At December 31, 2010, the aggregate intrinsic value and the weighted-average remaining contractual term for exercisable options were $72.5 million and 4.2 years, respectively. The aggregate intrinsic value of options exercised during 2010, 2009 and 2008 were $19.3 million, $7.5 million and $6.2 million, respectively. At December 31, 2010, the total unrecognized compensation cost related to the unvested options awards was $5.8 million and the weighted-average period over which it is expected to be recognized was 1.8 years.

We estimate that 2,411,840 of the options outstanding at December 31, 2010 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, 2010 was $28.00 per share, $82.0 million and 5.2 years, respectively.

Restricted Stock Awards

Holders of restricted stock awards have all the rights of a holder of common stock of ITC Holdings, including dividend and voting rights. The holder becomes vested as a result of certain events such as death or disability of the holder, but not later than the vesting date of the awards. The weighted-average expected remaining vesting period at December 31, 2010 is 1.6 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.

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Restricted stock award activity for 2010 was as follows:

	Number of			Weighted-
	Restricted			Average
	Stock			Grant Date
	Awards			Fair Value
Unvested restricted stock awards at January 1, 2010		756,939		$	44.55
Granted		152,737			53.28
Vested		(9,932	)		40.87
Forfeited		(14,404	)		45.10
Unvested restricted stock awards at December 31, 2010		885,340		$	46.12

The weighted-average grant date fair value of restricted stock awarded during 2009 and 2008 was $41.81 and $55.07 per share, respectively. The aggregate fair value of restricted stock awards as of December 31, 2010 was $54.9 million. The aggregate fair value of restricted stock awards that vested during 2010, 2009 and 2008 was $0.6 million, $0.3 million and $0.1 million, respectively. At December 31, 2010, the total unrecognized compensation cost related to the restricted stock awards was $19.1 million and the weighted-average period over which that cost is expected to be recognized was 2.1 years.

As of December 31, 2010, we estimate that 796,238 shares of the restricted shares outstanding at December 31, 2010 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 $45.92 per share, $49.4 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 2010, 2009 and 2008, employees purchased 24,840, 28,681 and 18,593 shares, respectively, resulting in proceeds from the sale of our common stock of $1.1 million, $1.1 million and $0.8 million, respectively, under the ESPP. The total share-based compensation amortization for the ESPP was $0.3 million, $0.3 million and $0.2 million in 2010, 2009 and 2008, respectively.

Deferred Stock Units

Our deferred stock units are paid in shares of common stock on each of the following three anniversaries of the grant date, in equal installments. The deferred stock units do not contain any vesting provisions; that is, our common stock will be issued at the anniversary dates of the grant dates irrespective of employment status. The deferred stock units do not provide for any voting rights until the deferred stock units are delivered as shares of our common stock. The deferred stock units have dividend equivalent rights, providing the holder with the right to any dividends declared on our common stock subsequent to the grant date, such that the holders receive additional deferred stock units with a fair market value equal to the cash dividends they would have received on the shares underlying the deferred stock units they hold as if such underlying shares of common stock had been outstanding on the record date for the dividend. The additional dividend equivalent units granted will be settled in shares of our common stock at the same time as the deferred stock units on which the dividend equivalents were received. The deferred stock units are not transferable by the holders, but the shares issued upon each settlement date will be immediately transferable.

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Deferred stock unit activity for 2010 was as follows:

	Number of			Weighted-
	Deferred			Average
	Stock			Grant Date
	Units			Fair Value
Deferred stock units at January 1, 2010		10,731		$	55.16
Granted		122			57.60
Vested		(5,364	)		55.16
Deferred stock units at December 31, 2010		5,489		$	55.21

The weighted-average grant date fair value of deferred stock units awarded during 2009 and 2008 was $43.54 and $55.49 per share, respectively. The aggregate fair value of deferred stock units as of December 31, 2010 was $0.3 million. The aggregate fair value of deferred stock units that vested as of December 31, 2010 and 2009 was $0.3 million and $0.2 million, respectively. The weighted-average remaining contractual term for the deferred stock units outstanding as of December 31, 2010 was 0.1 years. As of December 31, 2010, there is no unrecognized compensation costs related to the deferred stock units and we expect all of the deferred stock units to vest.

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 operating 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, 2010:

			Construction
(In thousands)	Net Investment(a)		Work in Progress
Substations	$	16,904	$	1,453
Lines		83,934		—
Total	$	100,838	$	1,453

(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 totaled $21.5 million as of December 31, 2010. 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

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the operation and management of the transmission lines. The MPPA is responsible for the capital and operating 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 municipals and other generators. As of December 31, 2010, METC had net investments in jointly owned assets within substations including jointly owned assets under construction totaling $10.7 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, 2010, METC had net investments in jointly shared transmission lines totaling $41.0 million of which METC’s ownership percentages for these jointly owned lines ranged from 35.2% to 64.5%.

ITC Midwest

ITC Midwest has joint sharing of several substations and transmission lines with various parties. As of December 31, 2010, ITC Midwest had net investments in jointly shared substations facilities including jointly shared substations facilities under construction totaling $7.7 million of which ITC Midwest’s ownership percentages for these jointly owned substations facilities ranged from 48.0% to 70.0%. As of December 31, 2010, ITC Midwest had net investments in jointly shares transmission lines including jointly shared transmission lines under construction totaling $21.4 million of which ITC Midwest’s ownership percentage for the jointly owned substation facilities and lines ranged from 28.0% to 70.0%.

16.   COMMITMENTS AND CONTINGENCIES

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. 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

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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. The resolution of pending proceedings is not expected to have a material effect on our operations or consolidated financial statements in the period in which they are resolved.

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.

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The amount of use tax liability associated with the exemptions taken by ITCTransmission through December 31, 2010 is estimated to be approximately $7.4 million, which includes approximately $3.5 million assessed for the audit period April 1, 2005 through June 30, 2008, including interest. 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 $9.9 million for periods still subject to audit since 2006. These higher use tax expenses would be passed on to ITCTransmission’s and METC’s customers as the amounts are included as components of net revenue requirements and resulting rates.

FERC audit of ITC Midwest

The staff of the FERC has 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 by ITC Midwest of the transmission assets of Interstate Power and Light Company. On February 8, 2011, FERC staff provided a draft audit report to us for review and comment. The draft audit report contains certain proposed findings and recommendations which, if finalized and approved by FERC, have the potential to result in adjustments to ITC Midwest’s revenue requirement calculations for 2008 through 2010 which could result in refunds and have a negative effect on our results of operations. We intend to both vigorously defend our position and seek an agreed-upon resolution of the audit findings. We believe it is reasonably possible for an unfavorable outcome, but do not believe the range of potential loss would be material to the consolidated financial statements.

Purchase Obligations and Leases

At December 31, 2010, we had purchase obligations of $54.7 million representing commitments for materials, services and equipment that had not been received as of December 31, 2010, 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 2011.

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 $0.9 million, $0.4 million and $0.6 million for the years ended December 31, 2010, 2009 and 2008, 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, 2010 were:

(In thousands)
2011	$	429
2012		424
2013		405
2014		331
2015 and thereafter		9
Total minimum lease payments	$	1,598

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Other Commitments

ITCTransmission

In August 2003, ITCTransmission entered into an Operation and Maintenance Agreement with its primary maintenance contractor and a Supply Chain Management Agreement with its primary purchasing and inventory management contractor. ITCTransmission is not obligated to take any specified amount of services under the terms of the Operation and Maintenance Agreement or the Supply Chain Management Agreement, which have five-year terms ending August 29, 2013 and automatically renew for additional five year terms unless terminated by either party.

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, with the most recent renewal effective May 1, 2010. 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 asset acquisition, 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

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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. To complete this project, the IUB must provide certain regulatory approvals but, due to the current case schedule, we do not expect the approvals to be received in time to allow the project to be completed by December 31, 2011. ITC Midwest believes it has made commercially reasonable best efforts toward completion of the project by the stipulated deadlines and will continue to do so and, therefore, we believe the likelihood of any adverse effect 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, 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 has purchased from Mid-Kansas. The Mid-Kansas Agreement has an initial term of ten years and automatic ten-year renewal terms unless terminated (1) due to a breach by the non-terminating party following notice and failure to cure, (2) by mutual consent of the parties, or (3) by ITC Great Plains under certain limited circumstances. Services must continue to be provided for at least six months subsequent to the termination date in any case.

Concentration of Credit Risk

Our credit risk is primarily with Detroit Edison, Consumers Energy and IP&L, which were responsible for approximately 33.1%, 23.6% and 23.9%, respectively, or $230.9 million, $164.6 million and $166.9 million, respectively, of our consolidated operating revenues for the year ended December 31, 2010. These percentages and amounts of total operating revenues of Detroit Edison, Consumers Energy and IP&L include an estimate for the 2010 revenue accruals and deferrals that were included in our 2010 operating revenues, but will not be billed or refunded to our customers until 2012. We have assumed that the revenues associated with the revenue accruals and deferrals would be billed or refunded to these customers in 2012 in the same proportion of the respective percentages of network and regional cost sharing revenues billed to them in 2010. Any financial difficulties experienced by Detroit Edison, Consumers Energy or IP&L could negatively impact our business. MISO, as our MISO Regulated Operating Subsidiaries’ billing agent, bills Detroit Edison, 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.   SEGMENT INFORMATION

We identify reportable segments based on the criteria set forth by the FASB regarding disclosures about segments of an enterprise. We determine our reportable segments based primarily on the regulatory environment of our subsidiaries and the business activities performed to earn revenues and incur expenses. During the third quarter of 2009, ITC Great Plains implemented its cost-based formula rate in SPP to record revenues. As a result, the newly regulated transmission business at ITC Great Plains is now included in the Regulated Operating Subsidiaries segment.

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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
2010	Subsidiaries		and Other			Reconciliations			Eliminations			Total
(In thousands)
Operating revenues	$	696,885	$	425		$	—		$	(467	)	$	696,843
Depreciation and amortization		86,621		355			—			—			86,976
Interest expense		54,983		87,665			—			(95	)		142,553
Income before income taxes		330,207		(102,275	)		—			—			227,932
Income tax provision (benefit)(b)		98,995		(16,741	)		—			—			82,254
Net income(b)		231,212		145,678			—			(231,212	)		145,678
Property, plant and equipment, net		2,867,008		5,269			—			—			2,872,277
Goodwill		950,163		—			—			—			950,163
Total assets(c)		4,180,485		2,762,210			(11,878	)		(2,622,944	)		4,307,873
Capital expenditures		391,252		45			—			(2,896	)		388,401

	Regulated
	Operating		ITC Holdings
2009	Subsidiaries(a)		and Other			Reconciliations			Eliminations			Total
(In thousands)
Operating revenues	$	621,061	$	329		$	—		$	(375	)	$	621,015
Depreciation and amortization		85,622		327			—			—			85,949
Interest expense		49,605		80,604			—			—			130,209
Income before income taxes		297,241		(88,769	)		—			—			208,472
Income tax provision (benefit)(b)		90,532		(12,960	)		—			—			77,572
Net income(b)		206,709		130,900			—			(206,709	)		130,900
Property, plant and equipment, net		2,535,826		6,238			—			—			2,542,064
Goodwill		950,163		—			—			—			950,163
Total assets(c)		3,890,874		2,614,394			(1,940	)		(2,473,612	)		4,029,716
Capital expenditures		410,086		47			—			(5,619	)		404,514

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	Regulated
	Operating		ITC Holdings
2008	Subsidiaries		and Other			Reconciliations			Eliminations			Total
(In thousands)
Operating revenues	$	617,924	$	254		$	—		$	(301	)	$	617,877
Depreciation and amortization		94,477		292			—			—			94,769
Interest expense		43,579		79,394			—			(739	)		122,234
Income before income taxes		267,530		(91,060	)		—			—			176,470
Income tax provision (benefit)(b)		82,919		(15,657	)		—			—			67,262
Net income(b)		184,611		109,208			—			(184,611	)		109,208
Property, plant and equipment, net		2,297,799		6,587			—			—			2,304,386
Goodwill		951,319		—			—			—			951,319
Total assets(c)		3,667,660		2,354,510			(3,154	)		(2,304,451	)		3,714,565
Capital expenditures		398,618		492			—			2,730			401,840

(a)	Amounts include the results of operations from ITC Great Plains for the period August 18, 2009 through December 31, 2009.
(b)	Income tax provision and net income for our Regulated Operating Subsidiaries do not include any allocation of taxes for METC. METC is organized as a single-member limited liability company that is a disregarded entity for federal income tax purposes. METC is treated as a branch of MTH, which is taxed as a multiple-partner limited partnership for federal income tax purposes. Since METC and MTH, its immediate parent, file as a partnership for federal income tax purposes, they are exempt from federal income taxes. As a result, METC does not record a provision for federal income taxes in its statements of operations or record amounts for federal deferred income tax assets or liabilities on its statements of financial position. For FERC regulatory reporting, however, METC computes theoretical federal income taxes as well as the associated deferred income taxes and includes an annual allowance for income taxes in its net revenue requirement used to determine its rates.
(c)	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 statement of financial position.

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18.   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(a)		Quarter		Year
2010
Operating revenue	$	161,288	$	168,468	$	178,020	$	189,067	$	696,843
Operating income		85,348		88,898		93,213		89,862		357,321
Net income		34,204		36,301		38,394		36,779		145,678
Basic earnings per share	$	0.68	$	0.72	$	0.76	$	0.73	$	2.89
Diluted earnings per share	$	0.67	$	0.71	$	0.75	$	0.71	$	2.84
2009
Operating revenue	$	155,941	$	157,238	$	151,328	$	156,508	$	621,015
Operating income		74,661		78,267		89,057		84,882		326,867
Net income		28,725		30,793		37,818		33,564		130,900
Basic earnings per share	$	0.58	$	0.62	$	0.76	$	0.67	$	2.62
Diluted earnings per share	$	0.57	$	0.61	$	0.74	$	0.66	$	2.58

(a) During 2009, we recognized $10.0 million of regulatory assets associated with both the start-up and development costs at ITC Great Plains and development costs for the KETA project. Upon initial establishment of these regulatory assets in the third quarter of 2009, $8.2 million of operating expenses were reversed of which $5.9 million were incurred in periods prior to 2009. This resulted in an increase in operating income, net income and earnings per share in the third quarter of 2009 as compared to other quarters in 2009.

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

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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, 2010 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B.   OTHER INFORMATION.

None.

PART III

ITEM 10.   DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.

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

ITEM 11.   EXECUTIVE COMPENSATION.

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

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

At December 31, 2010, the 2003 Stock Purchase and Option Plan and the LTIP were in place, pursuant to which we grant stock options and restricted stock and other equity based compensation to employees, officers, and directors, as well as the ESPP. Each of these plans has been approved by shareholders.

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The following table sets forth certain information with respect to our equity compensation plans at December 31, 2010 (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		2,437	$	27.96		3,306

(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, 2010 upon exercise of stock options; 2) the number of common shares to 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 ACCOUNTING FEES AND SERVICES.

The information required by this Item is contained under the caption “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, 2010 and 2009

Consolidated Statements of Operations for the Years Ended December 31, 2010, 2009 and 2008

Consolidated Statements of Changes in Stockholders’ Equity and Comprehensive Income for the Years Ended December 31, 2010, 2009 and 2008

Consolidated Statements of Cash Flows for the Years Ended December 31, 2010, 2009 and 2008

Notes to Consolidated Financial Statements

(2) Financial Statement Schedule

Schedule I — Condensed Financial Information of Registrant

All other schedules for which provision is made in Regulation S-X either (i) are not required under the related instructions or are inapplicable and, therefore, have been omitted, or (ii) the information required is included in the consolidated financial statements or the notes thereto that are a part hereof.

(b) The exhibits included as part of this report are listed in the attached Exhibit Index, which is incorporated herein by reference. At the request of any shareholder, ITC Holdings will furnish any exhibit upon the payment of a fee of $.10 per page to cover the costs of furnishing the exhibit.

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SCHEDULE I — Condensed Financial Information of Registrant

ITC HOLDINGS CORP.

CONDENSED STATEMENTS OF FINANCIAL POSITION (PARENT COMPANY ONLY)

	December 31,
	2010		2009
(In thousands, except share data)
ASSETS
Current assets
Cash and cash equivalents	$	71,384	$	70,583
Accounts receivable from subsidiaries		49,645		30,373
Deferred income taxes		—		4,672
Other		2,520		438
Total current assets		123,549		106,066
Other assets
Investment in subsidiaries		2,492,969		2,375,583
Deferred income taxes		9,474		30,675
Deferred financing fees (net of accumulated amortization of $5,397 and $4,610, respectively)		9,094		10,296
Other		33,877		24,156
Total other assets		2,545,414		2,440,710
TOTAL ASSETS	$	2,668,963	$	2,546,776
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Accounts payable	$	1,804	$	3,432
Accrued payroll		18,606		13,648
Accrued interest		30,827		26,352
Deferred income taxes		2,348		—
Other		931		52
Total current liabilities		54,516		43,484
Accrued pension and other postretirement liabilities		35,811		31,158
Other		2,025		1,854
Long-term debt (net of discounts of $2,822 and $3,243, respectively)		1,459,178		1,458,757
STOCKHOLDERS’ EQUITY
Common stock, without par value, 100,000,000 shares authorized, 50,715,805 and 50,084,061 shares issued and outstanding at December 31, 2010 and 2009, respectively		886,808		862,512
Retained earnings		229,437		149,776
Accumulated other comprehensive loss		1,188		(765	)
Total stockholders’ equity		1,117,433		1,011,523
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	2,668,963	$	2,546,776

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

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ITC HOLDINGS CORP.

CONDENSED STATEMENTS OF OPERATIONS (PARENT COMPANY ONLY)

	Year Ended December 31,
	2010			2009			2008
(In thousands)
Other income	$	1,518		$	1,154		$	1,392
General and administrative expense		(8,899	)		(5,539	)		(5,232	)
Interest expense		(87,610	)		(80,638	)		(79,394	)
Loss on extinguishment of debt		—			(1,263	)		—
Other expense		(281	)		(344	)		(1,965	)
LOSS BEFORE INCOME TAXES		(95,272	)		(86,630	)		(85,199	)
INCOME TAX BENEFIT		(41,457	)		(35,798	)		(35,881	)
LOSS AFTER TAXES		(53,815	)		(50,832	)		(49,318	)
EQUITY IN SUBSIDIARIES’ NET EARNINGS		199,493			181,732			158,526
NET INCOME	$	145,678		$	130,900		$	109,208

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

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ITC HOLDINGS CORP.

CONDENSED STATEMENTS OF CASH FLOWS (PARENT COMPANY ONLY)

	Year Ended December 31,
	2010			2009			2008
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	145,678		$	130,900		$	109,208
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Equity in subsidiaries’ earnings		(199,493	)		(181,732	)		(158,526	)
Dividends from subsidiaries		231,101			189,200			84,039
Deferred income tax expense		(34,623	)		(31,776	)		(36,109	)
Intercompany tax payments from subsidiaries		59,643			26,950			30,900
Share-based compensation expense		14,874			10,006			7,272
Other		1,795			3,369			2,341
Changes in assets and liabilities, exclusive of changes shown separately:
Accounts receivable from subsidiaries		(26,361	)		(14,377	)		15,376
Other current assets		(2,082	)		(18	)		4
Accrued payable		(1,539	)		(342	)		622
Accrued payroll		4,958			3,319			1,848
Accrued interest		4,475			517			8,355
Other current liabilities		3,156			(2,617	)		(528	)
Non-current assets and liabilities, net		(1,806	)		(1,731	)		4,673
Net cash provided by operating activities		199,776			131,668			69,475
CASH FLOWS FROM INVESTING ACTIVITIES
Equity contributions to subsidiaries		(141,904	)		(152,522	)		(117,050	)
Proceeds from sale of securities		14,576			—			—
Purchases of securities		(14,587	)		—			—
Repayment of advance to ITC Midwest		—			—			175,000
Other		—			3,495			—
Net cash (used in) provided by investing activities		(141,915	)		(149,027	)		57,950
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt		—			298,670			383,422
Repayment of long-term debt		—			(100,000	)		(765,000	)
Borrowings under revolving credit agreements		—			90,715			153,807
Repayments of revolving credit agreements		—			(158,668	)		(131,954	)
Issuance of common stock		8,908			3,575			310,543
Dividends on common stock		(66,041	)		(62,408	)		(58,935	)
Debt issuance costs		(185	)		(3,412	)		(575	)
Other		258			98			(881	)
Net cash (used in) provided by financing activities		(57,060	)		68,570			(109,573	)
NET INCREASE IN CASH AND CASH EQUIVALENTS		801			51,211			17,852
CASH AND CASH EQUIVALENTS — Beginning of period		70,583			19,372			1,520
CASH AND CASH EQUIVALENTS — End of period	$	71,384		$	70,583		$	19,372
Supplementary cash flows information:
Interest paid	$	81,416		$	78,181		$	68,794
Income taxes paid		8,844			1,967			1,317
Supplementary noncash investing and financing activities:
Equity transfers to subsidiaries		7,090			4,149			3,537

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

115

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, deferred tax assets relating primarily to federal income tax operating loss carryforwards and cash. 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. Each of our subsidiaries, however, is legally distinct from us and has no obligation, contingent or otherwise, to make funds available to us.

2.   LONG-TERM DEBT

As of December 31, 2010, the maturities of our long-term debt outstanding were as follows:

(In thousands)
2011	$	—
2012		—
2013		267,000
2014		50,000
2015		—
2016 and thereafter		1,145,000
Total	$	1,462,000

Refer to Note 8 to the consolidated financial statements for a description of the ITC Holdings Senior Notes and the ITC Holdings Revolving Credit Agreement and related items.

Based on the borrowing rates currently available to us for loans with similar terms and average maturities, the fair value of the ITC Holdings Senior Notes is $1,634.7 million at December 31, 2010. The total book value of the ITC Holdings Senior Notes net of discount is $1,459.2 million at December 31, 2010.

At December 31, 2010, we were in compliance with all covenants.

3.   RELATED-PARTY TRANSACTIONS

ITCTransmission, MTH, ITC Midwest and other subsidiaries paid cash dividends to ITC Holdings totaling $231.1 million, $189.2 million and $84.0 million in 2010, 2009 and 2008, respectively.

Additionally, ITCTransmission paid amounts of $52.8 million, $23.5 million and $30.9 million to ITC Holdings under an intercompany tax sharing arrangement during 2010, 2009 and 2008, respectively. METC paid $3.5 million to ITC Holdings under an intercompany tax sharing arrangement during both 2010 and 2009. No payment was made by METC in 2008. Additionally, ITC Midwest paid $3.3 million to ITC Holdings under an intercompany tax sharing arrangement during 2010. No payments were made by ITC Midwest in 2009 and 2008.

116

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 23, 2011.

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 Joseph L. Welch	Chairman, President and Chief Executive Officer (principal executive officer)	February 23, 2011
/s/  Cameron M. Bready Cameron M. Bready	Executive Vice President, Treasurer and Chief Financial Officer (principal financial officer and principal accounting officer)	February 23, 2011
/s/  Edward G. Jepsen Edward G. Jepsen	Director	February 23, 2011
/s/  Richard D. McLellan Richard D. McLellan	Director	February 23, 2011
/s/  William J. Museler William J. Museler	Director	February 23, 2011
/s/  Hazel R. O’Leary Hazel R. O’Leary	Director	February 23, 2011
/s/  Gordon Bennett Stewart, III Gordon Bennett Stewart, III	Director	February 23, 2011
/s/  Lee C. Stewart Lee C. Stewart	Director	February 23, 2011

117

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 (filed with Registrant’s Registration Statement on Form S-1, as amended, Reg. No. 333-123657)
	3	.2	Third Amended and Restated Bylaws of Registrant dated as of February 16, 2011
	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)

118

Exhibit No			Description of Exhibit
	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)
	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 Form 8-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 May 10, 2010)
	*10	.13	Amended and Restated 2003 Stock Purchase and Option Plan for Key Employees of the Registrant and its Subsidiaries (filed as an exhibit to Registrant’s Registration Statement on Form S-1, as amended, Reg. No. 333-123657)

119

Exhibit No			Description of Exhibit
	*10	.27	Deferred Compensation Plan (filed as an exhibit to 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 as an exhibit to 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 as Exhibit 10.34 to Registrant’s Form 10-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 as Exhibit 10.35 to 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 as Exhibit 10.38 to 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 Agreement, 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	.58	Revolving Credit Agreement, dated as of March 29, 2007, among the Registrant, 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, J.P. Morgan Securities Inc., as Sole Lead Arranger and Sole Bookrunner, and Comerica Bank, Credit Suisse (Cayman Islands Branch) and Lehman Brothers Bank, FSB, as Co-Syndication Agents (filed with Registrant’s Form 8-K filed on April 4, 2007)
	10	.59	Revolving Credit Agreement, dated as of March 29, 2007, among International Transmission Company and Michigan Electric Transmission Company, LLC, as the Borrowers, Various Financial Institutions and Other Persons from Time to Time Parties Hereto, as the Lenders, JPMorgan Chase Bank, N.A., as the Administrative Agent, J.P. Morgan Securities Inc., as Sole Lead Arranger and Sole Bookrunner, and Comerica Bank, Credit Suisse (Cayman Islands Branch) and Lehman Brothers Bank, FSB, as Co-Syndication Agents (filed with Registrant’s Form 8-K filed on April 4, 2007)
	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)

120

Exhibit No			Description of Exhibit
	10	.62	Form of Large Generator Interconnection Agreement, entered into by the Midwest Independent Transmission System Operator, Inc., Interstate Power and Light Company and ITC Midwest LLC (filed with Registrant’s Form 8-K filed on December 21, 2007)
	10	.63	Revolving Credit Agreement, dated as of January 29, 2008, 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, J.P. Morgan Securities Inc., as Sole Lead Arranger and Sole Bookrunner, Credit Suisse (Cayman Islands Branch), as Syndication Agent and Lehman Brothers Bank, FSB, as Documentation Agent (filed with Registrant’s Form 8-K filed on January 31, 2008)
	*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	.66	ITC Holdings Corp. Employee Stock Purchase Plan, as amended June 8, 2007 (filed with Registrant’s 2007 Form 10-K)
	10	.67	Commitment Increase Supplements of the Lenders, dated December 27, 2007, related to the Revolving Credit Agreement, dated as of March 29, 2007, among International Transmission Company and Michigan Electric Transmission Company, LLC, as the Borrowers, Various Financial Institutions and Other Persons from Time to Time Parties Hereto, as the Lenders, JPMorgan Chase Bank, N.A., as the Administrative Agent, J.P. Morgan Securities Inc., as Sole Lead Arranger and Sole Bookrunner, and Comerica Bank, Credit Suisse (Cayman Islands Branch) and Lehman Brothers Bank, FSB, as Co-Syndication Agents (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	.69	Amended and Restated Registrant 2006 Long Term Incentive Plan effective May 21, 2008 (filed with Registrant’s Form 8-K filed on May 23, 2008)
	10	.70	Sales Agency Financing Agreement, dated June 27, 2008, between Registrant and BNY Mellon Capital Markets, LLC (filed with Registrant’s Form 8-K filed on June 27, 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)
	*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)

121

Exhibit No			Description of Exhibit
	*10	.82	Employment Agreement between the Registrant and Joseph L. Welch (filed with Registrant’s 2008 Form 10-K)
	*10	.83	Form of Employment Agreements between the Registrant and Linda H. Blair, Jon E. Jipping, Edward M. Rahill, Daniel J. Oginsky and Cameron Bready (filed with Registrant’s 2008 Form 10-K)
	10	.85	Term Loan Agreement, dated as of April 29, 2009, among the Registrant, as the Borrower, Various Financial Institutions and Other Parties from Time to Time Parties Thereto, as the Lenders, JPMorgan Chase Bank, N.A., as the Administrative Agent, J.P. Morgan Securities Inc., as Sole Lead Arranger and Sole Bookrunner, and PNC Bank, National Association, as Syndication Agent (filed with Registrant’s 2009 Form 10-K)
	10	.86	First Amendment, dated as of July 22, 2010, to the Revolving Credit Agreement, dated as of March 29, 2007, among the Registrant, as borrower, the lenders party thereto, JPMorgan Chase Bank, N.A., as the administrative agent, J.P. Morgan Securities Inc., as sole lead arranger and sole bookrunner, and Comerica Bank, Credit Suisse, Cayman Islands Branch and Lehman Brothers Bank, FSB as co-syndication agents (filed with Registrant’s Form 8-K filed July 27, 2010)
	10	.87	First Amendment, dated as of July 22, 2010, to the Revolving Credit Agreement, dated as of March 29, 2007, among International Transmission Company and Michigan Electric Transmission Company, LLC, as borrowers, the lenders party thereto, JPMorgan Chase Bank, N.A., as the administrative agent, J.P. Morgan Securities Inc., as sole lead arranger and sole bookrunner, and Comerica Bank, Credit Suisse, Cayman Islands Branch and Lehman Brothers Bank, FSB as co-syndication agents (filed with Registrant’s Form 8-K filed July 27, 2010)
	10	.88	Second Amendment, dated as of July 22, 2010, to the Revolving Credit Agreement, dated as of January 29, 2008, among ITC Midwest LLC, as borrower, the lenders party thereto, JPMorgan Chase Bank, N.A., as the administrative agent, J.P. Morgan Securities Inc., as sole lead arranger and sole bookrunner, Credit Suisse, Cayman Islands Branch as syndication agent and Lehman Brothers Bank, FSB as documentation agent (filed with Registrant’s Form 8-K filed July 27, 2010)
	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	.91	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 September 1, 2010
	10	.92	Amended and Restated Generator Interconnection Agreement entered into by the Midwest Independent Transmission System Operator, Inc., Michigan Electric Transmission Company and Consumers Energy Company, effective April 22, 2010
	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

122

Exhibit No			Description of Exhibit
	31	.2	Certification of Chief Financial Officer pursuant to Rule 13a-14 of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
	32		Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
	**101	.INS	XBRL Instance Document
	**101	.SCH	XBRL Taxonomy Extension Schema
	**101	.CAL	XBRL Taxonomy Extension Calculation Linkbase
	**101	.DEF	XBRL Taxonomy Extension Definition Database
	** 101	.LAB	XBRL Taxonomy Extension Label Linkbase
	** 101	.PRE	XBRL Taxonomy Extension Presentation Linkbase

*	Management contract or compensatory plan or arrangement.
**	XBRL (Extensible Business Reporting Language) information is furnished and not filed herewith, is not a part of a registration statement or prospectus for purposes of sections 11 or 12 of the Securities Act of 1933, is deemed not filed for purposes of section 18 of the Securities Exchange Act of 1934, and otherwise is not subject to liability under these sections.

123

EX-3.2

Exhibit 3.2

THIRD AMENDED AND RESTATED BYLAWS
OF
ITC HOLDINGS CORP.
(THE “CORPORATION”)

ARTICLE I

OFFICES

1.01 Principal Office. The principal office of the Corporation shall be at such place as the Board of Directors shall from time to time determine.

1.02 Other Offices. The Corporation also may have offices at such other places as the board of directors from time to time determines or the business of the Corporation requires.

ARTICLE II

SEAL

2.01 Seal. The Corporation may have a seal in the form that the board of directors may from time to time determine. The seal may be used by causing it or a facsimile to be impressed, affixed or otherwise reproduced. Documents otherwise properly executed on behalf of the corporation shall be valid and binding upon the corporation without a seal whether or not one is in fact designated by the Board of Directors.

ARTICLE III

CAPITAL STOCK

3.01 Issuance of Shares. The shares of capital stock of the Corporation shall be issued in the amounts, at the times, for the consideration, and on the terms and conditions that the board of directors shall deem advisable, subject to the articles of incorporation and any requirements of the laws of the state of Michigan.

3.02 Certificates for Shares. The certificated shares of the Corporation shall be represented by certificates signed by the chairperson of the board of directors, the president, or a vice president, and also may be signed by the treasurer, assistant treasurer, secretary, or assistant secretary, and may be sealed with the seal of the Corporation, if any, or a facsimile of it. The signatures of the officers may be facsimiles if the certificate is countersigned by a transfer agent or registered by a registrar other than the corporation itself or its employee. In case an officer who has signed or whose facsimile signature has been placed upon a certificate ceases to be such officer before the certificate is issued, it may be issued by the Corporation with the same effect as if he or she were such officer at the date of issuance. A certificate representing shares shall

state on its face that the Corporation is formed under the laws of the state of Michigan and shall also state the name of the person to whom it is issued, the number and class of shares and the designation of the series, if any, that the certificate represents, and any other provisions that may be required by the laws of the state of Michigan. Notwithstanding the foregoing, the Board of Directors may authorize the issuance of some or all of the shares without certificates to the fullest extent permitted by law. Within a reasonable time after the issuance or transfer of shares without certificates, the Corporation shall send the shareholder a written statement of the information required on certificates by applicable law.

3.03 Transfer of Shares. The certificated shares of the capital stock of the Corporation are transferable only on the books of the Corporation upon surrender of the certificate for the shares, properly endorsed for transfer, and the presentation of the evidences of ownership and validity of the assignment that the Corporation may require. Transfers of uncertificated shares shall be made by such written instrument as the board of directors shall from time to time specify, together with such proof of the authenticity of signatures as the Corporation or its agents may require.

3.04 Registered Shareholders. The Corporation shall be entitled to treat the person in whose name any share of stock is registered as the owner of it for the purpose of dividends and other distributions or for any recapitalization, merger, plan of share exchange, reorganization, sale of assets, or liquidation, for the purpose of votes, approvals, and consents by shareholders, for the purpose of notices to shareholders, and for all other purposes whatever, and shall not be bound to recognize any equitable or other claim to or interest in the shares by any other person, whether or not the Corporation shall have notice of it, except as expressly required by the laws of the state of Michigan.

3.05 Lost or Destroyed Certificates. On the presentation to the Corporation of a proper affidavit attesting to the loss, destruction, or mutilation of any certificate or certificates for shares of stock of the Corporation and such other evidence as the Corporation or its transfer agent may require, the board of directors shall direct the issuance of a new certificate or certificates to replace the certificates so alleged to be lost, destroyed, or mutilated. The Corporation may require as a condition precedent to the issuance of new certificates a bond or agreement of indemnity, in the form and amount and with or without sureties, as the board of directors may direct or approve.

3.06 Transfer Agents and Registrars. The board of directors may, in its discretion, appoint one or more banks or trust companies in the State of Michigan and in such other state or states (or countries) as the board of directors may deem advisable, from time to time, to act as transfer agents and registrars of the shares of the Corporation; and upon such appointments being made, no certificate representing shares shall be valid until countersigned by one of such transfer agents and registered by one of such registrars.

ARTICLE IV

SHAREHOLDERS AND MEETINGS OF SHAREHOLDERS

4.01 Place of Meetings. All meetings of shareholders shall be held at the principal office of the Corporation or at any other place that shall be determined by the board of directors and stated in the meeting notice or, at the direction of the board of directors to the extent permitted by applicable law, may be held by remote communication if stated in the meeting notice. The board of directors may allow participation at any meeting of shareholders by remote communication.

4.02 Annual Meeting. The annual meeting of the shareholders of the Corporation shall be held at such time as the board of directors may select. Directors shall be elected at each annual meeting and such other business transacted as may come before the meeting. The board of directors acting by resolution may postpone and reschedule any previously scheduled annual meeting of shareholders. Any annual meeting of shareholders may be adjourned by the person presiding at the meeting or pursuant to a resolution of the board of directors.

4.03 Special Meetings. Special meetings of shareholders may be called by the board of directors, the chairperson of the board of directors (if the office is filled) or the president and shall be called by the president or secretary at the written request of shareholders holding a majority of the outstanding shares of stock of the Corporation entitled to vote. The request shall state the purpose or purposes for which the meeting is to be called.

4.04 Notice of Meetings. Except as otherwise provided by statute, written notice of the time, place, if any, and purposes of a shareholders meeting shall be given not less than 10 nor more than 60 days before the date of the meeting to each shareholder of record entitled to vote at the meeting, either personally or by mailing the notice to his or her last address as it appears on the books of the Corporation, or by a form of electronic transmission to which the shareholder has consented. The notice shall include notice of proposals from shareholders that are proper subjects for shareholder action and are intended to be presented by shareholders who have so notified the Corporation in accordance with applicable law. If a shareholder may be present and vote at the meeting by remote communication, the means of remote communication allowed shall be included in the notice. No notice need be given of an adjourned meeting of the shareholders provided that the time and place to which the meeting is adjourned are announced at the meeting at which the adjournment is taken, and at the adjourned meeting the only business to be transacted is business that might have been transacted at the original meeting. However, if after the adjournment a new record date is fixed for the adjourned meeting, a notice of the adjourned meeting shall be given to each shareholder of record entitled to notice on the new record date as provided in this bylaw.

4.05 Record Dates. The board of directors may fix in advance a record date for the purpose of determining shareholders entitled to notice of and to vote at a meeting of shareholders or an adjournment of the meeting or to express consent to or to dissent from a proposal without a meeting; for the purpose of determining shareholders entitled to receive

payment of a dividend or an allotment of a right; or for the purpose of any other action. The date fixed shall not be more than 60 nor less than 10 days before the date of the meeting, nor more than 60 days before any other action. In such case only the shareholders that shall be shareholders of record on the date so fixed and that are entitled to vote with respect to the matters to be considered at such meeting shall be entitled to notice of and to vote at the meeting or an adjournment of the meeting or to express consent to or to dissent from the proposal; to receive payment of the dividend or the allotment of rights; or to participate in any other action, notwithstanding any transfer of any stock on the books of the Corporation, after any such record date. If a record date is not fixed, (a) the record date for determination of shareholders entitled to notice of or to vote at a meeting of shareholders shall be the close of business on the date on which notice is given, or, if no notice is given, the day next preceding the day on which the meeting is held, and (b) the record date for determining shareholders for any purpose other than that specified in item (a) shall be the close of business on the day on which the resolution of the board of directors relating thereto is adopted. Nothing in this bylaw shall affect the rights of a shareholder and his or her transferee or transferor as between themselves.

4.06 List of Shareholders. The secretary or the agent of the Corporation having charge of the stock transfer records for shares of the Corporation shall make and certify a complete list of the shareholders entitled to vote at a shareholders meeting or any adjournment of it. The list shall be arranged alphabetically within each class and series and include the address of, and the number of shares held by, each shareholder; be produced at the time and place of the meeting; be subject to inspection by any shareholder during the whole time of the meeting; and be prima facie evidence of which shareholders are entitled to examine the list or vote at the meeting. If the meeting is held solely by means of remote communication, the list shall be open to the examination of any shareholder during the entire meeting by posting the list on a reasonably accessible electronic network, and the information required to access the list shall be provided with the notice of the meeting.

4.07 Quorum; Adjournment; Attendance by Remote Communication.

(a) Unless a greater or lesser quorum is required in the articles of incorporation or by the laws of the state of Michigan, the shareholders present at a meeting in person or by proxy who, as of the record date for the meeting, were holders of a majority of the outstanding shares of the Corporation entitled to vote at the meeting, shall constitute a quorum at the meeting. When the holders of a class or series of shares are entitled to vote separately on an item of business, this bylaw applies in determining the presence of a quorum of the class or series for transacting the item of business. The shareholders present, in person or by proxy, at such meeting may continue to do business until adjournment, notwithstanding the withdrawal of enough shareholders to have less than a quorum.

(b) Whether or not a quorum is present, a meeting of shareholders may be adjourned by a vote of the shares present in person or by proxy.

(c) Subject to any guidelines and procedures adopted by the board of directors, shareholders and proxy holders not physically present at a meeting of shareholders may participate in the meeting by means of remote communication, are considered present in

person for all relevant purposes, and may vote at the meeting if all of the following conditions are satisfied: (1) the Corporation implements reasonable measures to verify that each person considered present and permitted to vote at the meeting by means of remote communication is a shareholder or proxy holder, (2) the Corporation implements reasonable measures to provide each shareholder and proxy holder with a reasonable opportunity to participate in the meeting and to vote on matters submitted to the shareholders, including an opportunity to read or hear the proceedings of the meeting substantially concurrently with the proceedings, and (3) if any shareholder or proxy holder votes or takes other action at the meeting by means of remote communication, a record of the vote or other action is maintained by the Corporation.

(d) A shareholder or proxy holder may be present and vote at the adjourned meeting by means of remote communication if he or she was permitted to be present and vote by that means of remote communication in the original meeting notice.

4.08 Proxies. A shareholder entitled to vote at a shareholders meeting or to express consent or to dissent without a meeting may authorize other persons to act for the shareholder by proxy. A proxy shall be in writing and shall be signed by the shareholder or the shareholder’s authorized agent or representative or shall be transmitted electronically to the person who will hold the proxy or to an agent fully authorized by the person who will hold the proxy to receive that transmission and include or be accompanied by information from which it can be determined that the electronic transmission was authorized by the shareholder. A complete copy, fax, or other reliable reproduction of the proxy may be substituted or used in lieu of the original proxy for any purpose for which the original could be used. A proxy shall not be valid after the expiration of three years from its date unless otherwise provided in the proxy. A proxy is revocable at the pleasure of the shareholder executing it except as otherwise provided by the laws of the state of Michigan.

4.09 Voting. Each outstanding share is entitled to one vote on each matter submitted to a vote, unless the articles of incorporation provide otherwise. Votes may be cast orally or in writing, but if more than 25 shareholders of record are entitled to vote, then votes shall be cast in writing signed by the shareholder or the shareholder’s proxy. When an action, other than the election of directors, is to be taken by a vote of the shareholders, it shall be authorized by a majority of the votes cast by the holders of shares entitled to vote on it, unless a greater vote is required by the articles of incorporation or by the laws of the state of Michigan. Except as otherwise provided by the articles of incorporation, directors shall be elected by a plurality of the votes cast by holders of common stock of the Corporation at any election.

4.10 Conduct of Meeting. At each meeting of shareholders, a chair shall preside. In the absence of a specific selection by the board of directors, the chair shall be the Chairperson of the board of directors as provided in Section 8.01. The chair shall determine the order of business and shall have the authority to establish rules for the conduct of the meeting which are fair to shareholders. The chair of the meeting shall announce at the meeting when the polls close for each matter voted upon. If no announcement is made, the polls shall be deemed to have closed upon the final adjournment of the meeting. After the polls close, no ballots, proxies or votes, nor any revocations or changes thereto may be accepted. If participation is permitted by

remote communication, the names of the participants in the meeting shall be divulged to all participants.

4.11 Advance Notice Provisions for Shareholder Business and Nominations.

(a) Director Nominations.

(1) Only persons who are nominated in accordance with the procedures set forth in this Section 4.11(a) shall be eligible to serve as directors of the Corporation. Nominations of persons for election to the Board of Directors may be made at an annual or special meeting of shareholders (i) by or at the direction of the Board of Directors or any duly authorized committee thereof (including, without limitation, by making reference to the nominees in the proxy statement delivered to shareholders on behalf of the Board of Directors), or (ii) by any shareholder of the Corporation who was a shareholder of record both at the time of giving of notice provided for in this Section 4.11(a) and at the time of the shareholders meeting, who is entitled to vote at the meeting, who complies with the notice procedures set forth in this Section 4.11(a) and who attends, or whose duly qualified representative attends, the meeting and makes such nomination(s). Unless otherwise provided in the Corporation’s articles of incorporation, Section 4.11(a)(1)(ii) shall be the exclusive means for a shareholder to propose or make any nomination of a person or persons for election to the Board to be considered by the shareholders at an annual meeting or special meeting.

(2) Without qualification, for nominations to be made by a shareholder at an annual meeting or, if the Board has first determined that directors are to be elected at a special meeting, at a special meeting, the shareholder must (i) provide Timely Notice thereof in writing and in proper form (as provided in Section 4.11(a)(3)) to the secretary of the Corporation at the Corporation’s principal office and (ii) provide any updates or supplements to such notice at the times and in the form required by Section 4.11(c).

(3) To be in proper form for purposes of this Section 4.11(a), a shareholder’s notice must set forth the following information:

(i) as to each person whom the shareholder proposes to nominate for election or reelection as a director (A) all information relating to such proposed nominee that would be required to be set forth in a shareholder’s notice pursuant to this Section 4.11 if such proposed nominee were a Proposing Person, (B) all information relating to such proposed nominee that is required to be disclosed in a proxy statement or other filings required to be made in connection with solicitations of proxies for election of directors in a contested election pursuant to Section 14 under the Exchange Act and the rules and regulations thereunder (including such proposed nominee’s written consent to being named in the proxy statement as a nominee and to serving as a director if elected), (C) a description of all direct and indirect compensation and other material monetary agreements, arrangements and understandings during the past three years, and any other material relationships, arrangements or understandings between or among any Proposing Person and each proposed nominee, and his or her respective affiliates and associates, (D) the amount of any equity securities beneficially owned (as defined in Rule 13d-3 (or any successor thereof) under the Exchange Act) in any direct competitor of the Corporation or its operating subsidiaries if such ownership by the nominee(s) and the Proposing

Persons, in the aggregate, beneficially own 5% or more of the class of equity securities, and (E) an undertaking from each such person to be nominated that, if elected to the Board, they will comply with corporate governance, conflict of interest, confidentiality and stock ownership and trading policies and guidelines of the Corporation that are generally applicable to directors who are not employees of the Corporation;

(ii) as to each Proposing Person, (A) the name and address of such Proposing Person and, as to the shareholder providing the notice, such name and address as they appear on the Corporation’s books, (B) a statement describing and quantifying in reasonable detail any Material Ownership Interests, (C) the amount of any equity securities beneficially owned (as defined in Rule 13d-3 (or any successor thereof) under the Exchange Act) in any direct competitor of the Corporation or its operating subsidiaries if such ownership by the nominee(s) and the Proposing Persons, in the aggregate, beneficially own 5% or more of the class of equity securities, and (D) whether the Proposing Person intends to solicit proxies from shareholders in support of such nominee(s); and

(iii) a representation that the shareholder providing the notice intends to appear in person or by proxy at the meeting to nominate the person(s) named in its notice.

(4) The shareholder providing the notice shall furnish such other information as may reasonably be requested by the Corporation to determine the eligibility of such proposed nominee to serve as an independent director of the Corporation or that could be material to a reasonable shareholder’s understanding of the independence or lack of independence of such nominee.

(5) Notwithstanding anything in the Timely Notice requirement in Section 4.11(a)(2) to the contrary, in the event that the number of directors to be elected to the Board is increased and there is no Public Announcement by the Corporation naming all of the nominees for director or, in the alternative, specifying the size of the increased Board at least 100 days prior to the first anniversary of the preceding year’s annual meeting of shareholders, a shareholder’s notice required by this Section 4.11 shall also be considered timely, but only with respect to nominees for any new positions created by such increase, if it shall be delivered to or mailed and received by the secretary at the principal executive offices of the Corporation not later than the close of business on the 10th day following the day on which such Public Announcement is first made by the Corporation.

(b) Other Business.

(1) At an annual meeting of shareholders, only such business shall be conducted as shall have been properly brought before the meeting. To be properly brought before an annual meeting, business (except as provided in the next sentence), must be (A) specified in the notice of meeting given by or at the direction of the Board of Directors (or any duly authorized committee thereof), (B) brought before the meeting by or at the direction of the Board of Directors or (C) otherwise properly brought by any shareholder of the Corporation who was a shareholder of record both at the time of giving of notice provided for in this Section and at the time of the annual meeting, who is entitled to vote at the meeting, who complies with the notice procedures set forth in this Section 4.11(b) and who attends, or whose duly qualified representative attends, the meeting and presents such business to the meeting. Except for (i) proposals made in accordance with the

procedures and conditions set forth in Rule 14a-8 (or any successor thereof) under the Exchange Act and included in the notice of meeting and proxy statement given by or at the direction of the Board of Directors (or any duly authorized committee thereof), and (ii) director nominations (which shall be governed by Section 4.11(a)), clause (C) of the preceding sentence shall be the exclusive means for a shareholder to propose business to be brought before an annual meeting of shareholders. At a special meeting of shareholders, only such business shall be conducted as shall have been properly brought before the meeting pursuant to the Corporation’s notice of meeting and applicable law.

(2) Without qualification, for business to be properly brought before an annual meeting by a shareholder pursuant to this Section 4.11(b), (i) the business must otherwise be a proper matter for shareholder action under applicable law and (ii) the shareholder must (A) provide Timely Notice thereof in writing and in proper form to the secretary of the Corporation at the Corporation’s principal office and (B) provide any updates or supplements to such notice at the times and in the form required by Section 4.11(c).

(3) To be in proper form for purposes of this Section 4.11(b), a shareholder’s notice shall set forth the following information:

(i) a brief description of the business desired to be brought before the meeting (including the text of any resolutions or bylaw amendments proposed for consideration) and the reasons for conducting such business at the meeting;

(ii) all information relating to such proposed business that is required to be included in a proxy statement or other filings required to be made in connection with solicitations of proxies pursuant to Section 14 under the Exchange Act and the rules and regulations thereunder in connection with the meeting at which such proposed business is to be acted upon;

(iii) a brief description of any material interest in such business of each Proposing Person and a brief description of all agreements, arrangements and understandings between such Proposing Person and any other person or persons (including their names) in connection with the proposal of such business;

(iv) as to each Proposing Person, (A) the name and address of such Proposing Person and, as to the shareholder providing the notice, such name and address as they appear on the Corporation’s books, (B) a statement describing and quantifying in reasonable detail any Material Ownership Interests, and (C) whether the Proposing Person intends to solicit proxies from shareholders in support of such business; and

(v) a representation that the shareholder providing the notice intends to appear in person or by proxy at the meeting to propose the business identified in the shareholder’s notice.

(c) Requirement to Update Information. A shareholder providing any notice as provided in Section 4.11(a) or (b) shall further update and supplement such notice, if necessary, so that the information provided or required to be provided in such notice pursuant to

Section 4.11(a) or 4.11(b), as applicable, shall be true and correct as of the record date for the meeting and as of the date that is ten (10) business days prior to the meeting date or any adjournment or postponement thereof, and such update and supplement shall be delivered to or otherwise received by the secretary at the principal executive offices of the Corporation not later than two (2) business days after the record date for the meeting (in the case of the update and supplement required to be made as of the record date) and not later than eight (8) business days prior to the date for the meeting or any adjournment or postponement thereof (in the case of the update and supplement required to be made as of ten (10) business days prior to the meeting or any adjournment or postponement thereof).

(d) Determination of Improperly Brought Nomination or Business. The chairman of the meeting shall, if the facts so warrant, determine and declare to the meeting that one or more nominations or other business was not properly brought before the meeting in accordance with the provisions of this Section 4.11 and, if the chairman should so determine, the chairman shall so declare to the meeting and any such defective nomination shall be disregarded and any such improperly brought business shall not be transacted, notwithstanding that proxies in respect of such vote may have been received by the Corporation.

(e) Definitions. As used in this Section 4.11, the following terms have the meanings ascribed to them below.

(1) “Exchange Act” means the Securities Exchange Act of 1934, as amended.

(2) “Material Ownership Interests” means (i) the class or series and number of shares of the Corporation which are, directly or indirectly, owned beneficially (as defined in Rule 13d-3 (or any successor thereof) under the Exchange Act) and of record by such Proposing Person, (ii) any option, warrant, convertible security, stock appreciation right, or similar right with an exercise or conversion privilege or a settlement payment or mechanism at a price related to any class or series of shares of the Corporation or with a value derived in whole or in part from the value of any class or series of shares of the Corporation (a “Derivative Instrument”) directly or indirectly owned beneficially by such Proposing Person, (iii) any proxy, contract, arrangement, understanding, or relationship pursuant to which such Proposing Person has a right to vote any shares of any security of the Corporation, (iv) any short interest beneficially owned or held by such Proposing Person in any security of the Corporation, (v) any rights to dividends on the shares of the Corporation owned beneficially by such Proposing Person that are separated or separable from the underlying shares of the Corporation, (vi) any proportionate interest in shares of the Corporation or Derivative Instruments held, directly or indirectly, by a (A) limited liability company in which the Proposing Person is a member or, directly or indirectly, beneficially owns an interest in a member, or (B) general or limited partnership in which such Proposing Person is a general partner or, directly or indirectly, beneficially owns an interest in a general partner, and (vii) any performance related fees (other than an asset-based fee) to which such Proposing Person is entitled based on any increase or decrease in the value of shares of the Corporation or Derivative Instruments, if any, as of the date of such notice.

(3) “Proposing Person” means (i) the shareholder providing the notice of the nomination or business proposed to be made or presented at the meeting, (ii) the beneficial owner, if different,

on whose behalf the nomination or business proposed to be made or presented at the meeting is made, (iii) any affiliate or associate of such beneficial owner (as such terms are defined in Rule 12b-2 (or any successor thereof) under the Exchange Act), and (iv) any other person with whom such shareholder or such beneficial owner (or any of their respective affiliates or associates) is acting in concert.

(4) “Public Announcement” means disclosure in a press release reported by the Dow Jones News Service, Associated Press, Prime Newswire, Marketwire, PR Newswire or comparable news service or in a document furnished to or filed by the Corporation with the Securities and Exchange Commission pursuant to Section 13, 14 or 15(d) of the Exchange Act and publicly available.

(5) “Timely Notice.”

(i) With respect to an annual meeting, a notice is a Timely Notice if it (A) is delivered to the secretary at the principal executive offices of the Corporation not earlier than the close of business on the 120^th day and not later than the close of business on the 90th day prior to the one-year anniversary of the preceding year’s annual meeting, and (B) contains all of the information required to be contained therein by the applicable provisions of this Section 4.11; provided, however, that in the event that the date of the annual meeting is advanced by more than 30 days or delayed by more than 70 days from such anniversary date or if the Corporation did not hold an annual meeting in the preceding fiscal year, notice by the shareholder to be timely must be so delivered not earlier than the close of business on the 120^th day prior to such annual meeting and not later than the close of business on the 90th day prior to such annual meeting or, if later, the tenth day following the day on which a Public Announcement of the date of such meeting is first made by the Corporation.

(ii) With respect to a special meeting, a notice is a Timely Notice if it (A) is delivered to the secretary at the principal executive offices of the Corporation not earlier than the close of business on the 120th day prior to such special meeting and not later than the close of business on the later of the 90th day prior to such special meeting or, if later, the tenth day following the day on which a Public Announcement is first made of the date of the special meeting and (B) contains all of the information required to be contained therein by the applicable provisions of this Section 4.11.

(iii) In no event shall the public announcement of a postponement or adjournment of an annual or special meeting to a later date or time commence a new time period for the giving of a shareholder’s notice as described above.

(f) Compliance With Applicable Law. Notwithstanding the foregoing provisions of this Section 4.11, a shareholder shall also comply with all applicable requirements of state law and of the Exchange Act and the rules and regulations thereunder with respect to the matters set forth in this Section. Nothing in this Section shall be deemed to affect any rights of (i) shareholders to request inclusion of proposals in the Corporation’s proxy statement pursuant to Rule 14a-8 (or any successor thereof) under the Exchange Act, or (ii) the holders of any series of Preferred Stock to elect directors pursuant to any applicable provisions of the articles of incorporation.

4.12 Inspectors of Election. The board of directors, or the chair presiding at any shareholders’ meeting, may appoint one or more inspectors. If appointed, the inspectors shall determine the number of shares outstanding and the voting power of each, the shares represented at the meeting, the existence of a quorum and the validity and effect of proxies, and shall receive votes, ballots or consents, hear and determine challenges or consents, determine the result, and do such acts as are proper to conduct the election or vote with fairness to all shareholders. On request of the person presiding at the meeting, the inspectors shall make and execute a written report to the person presiding at the meeting of any of the facts found by them and matters determined by them. The report shall be prima facie evidence of the facts stated and of the vote as certified by the inspectors.

ARTICLE V

DIRECTORS

5.01 Number. The business and affairs of the Corporation shall be managed by or under the direction of a board of not less than two (2) nor more than ten (10) directors as shall be fixed from time to time by the board of directors. The directors need not be residents of Michigan or shareholders of the Corporation.

5.02 Election, Resignation, and Removal. Unless otherwise provided in the articles of incorporation, directors shall be elected at each annual shareholders meeting, each director to hold office until the next annual shareholders meeting and until the director’s successor is elected and qualified, or until the director’s resignation or removal. Unless otherwise provided in the articles of incorporation, a director may resign by written notice to the Corporation. The resignation is effective on its receipt by the Corporation or at a subsequent time as set forth in the notice of resignation. A director or the entire board of directors may be removed, with or without cause and at any time (with or without a meeting), by vote of the holders of a majority of the shares entitled to vote at an election of directors. Cause for removal is defined as any director who has been judicially declared of unsound mind or who has been convicted of an offense punishable by imprisonment for a term of more than one year.

5.03 Vacancies. Vacancies in the board of directors occurring by reason of death, resignation, removal, increase in the number of directors, or otherwise shall be filled by the affirmative vote of a majority of the remaining directors though less than a quorum of the board of directors, unless filled by proper action of the shareholders of the Corporation. Unless otherwise provided in the articles of incorporation or elsewhere in these bylaws, each person so elected shall be a director for a term of office continuing only until the next election of directors by the shareholders. A vacancy that will occur at a specific date, by reason of a resignation effective at a later date or otherwise, may be filled before the vacancy occurs, but the newly elected director may not take office until the vacancy occurs.

5.04 Annual Meeting. The board of directors shall meet each year immediately after the annual meeting of the shareholders, or within three days of such time, excluding Sundays and legal holidays, if the later time is deemed advisable, at the place where the

shareholders meeting has been held or any other place that the board of directors may determine or by remote communication, for the purpose of electing officers and considering such business that may properly be brought before the meeting; provided that, if less than a majority of the directors appear for an annual meeting of the board of directors, the holding of the annual meeting shall not be required and the matters that might have been taken up in it may be taken up at any later regular, special or annual meeting, or by consent resolution.

5.05 Regular and Special Meetings. Regular meetings of the board of directors may be held at the times and places (or by remote communication) that the majority of the directors may from time to time determine at a prior meeting or as shall be directed or approved by the vote or written consent of all the directors; provided that the board of directors shall meet no fewer than once per fiscal quarter. Special meetings of the board of directors may be called by the chairperson of the board of directors (if the office is filled) or the president, and shall be called by the president or secretary on the written request of any two directors.

5.06 Notices. No notice shall be required for annual or regular meetings of the board of directors or for adjourned meetings, whether regular or special. Three days written notice, 24-hour telephonic notice, or 24-hour notice by electronic communication shall be given for special meetings of the board of directors, and the notice shall state the time, place, and purpose or purposes of the meeting.

5.07 Quorum. A majority of the board of directors then in office, or of the members of a board committee, constitutes a quorum for the transaction of business. The vote of a majority of the directors present at any meeting at which there is a quorum constitutes the action of the board of directors or of the committee, except when a larger vote may be required by the laws of the state of Michigan. A member of the board of directors or of a committee designated by the board of directors may participate in a meeting by conference telephone or other means of remote communication through which all persons participating in the meeting can communicate with each other. Participation in a meeting in this manner constitutes presence in person at the meeting.

5.08 Dissents. A director who is present at a meeting of the board of directors, or a board committee of which the director is a member, at which action on a corporate matter is taken, is presumed to have concurred in that action unless the director’s dissent is entered in the minutes of the meeting or unless the director files a written dissent to the action with the person acting as secretary of the meeting before the adjournment of it or forwards the dissent by registered mail to the secretary of the Corporation promptly after the adjournment of the meeting. The right to dissent does not apply to a director who voted in favor of the action. A director who is absent from a meeting of the board of directors or a board committee of which the director is a member, at which any such action is taken, is presumed to have concurred in the action unless he or she files a written dissent with the secretary within a reasonable time after the director has knowledge of the action.

5.09 Compensation. The board of directors, by affirmative vote of a majority of directors in office and irrespective of any personal interest of any of them, may establish reasonable compensation of directors for services to the Corporation as directors, committee

members or officers. Nothing herein shall be construed to preclude any director from serving the Corporation in any other capacity and receiving compensation therefor.

5.10 Executive and Other Committees. The board of directors may, by resolution passed by a majority of the whole board of directors, appoint three or more members of the board of directors as an executive committee to exercise all powers and authorities of the board of directors in managing the business and affairs of the Corporation, except that the committee shall not have power or authority to (a) amend the articles of incorporation, except that a committee may prescribe the relative rights and preferences of the shares of a series if the articles of incorporation authorize the board of directors to do so; (b) adopt an agreement of merger or plan of share exchange; (c) recommend to shareholders the sale, lease, or exchange of all or substantially all of the Corporation’s property and assets; (d) recommend to shareholders a dissolution of the Corporation or revocation of a dissolution; (e) amend these bylaws; (f) fill vacancies in the board of directors; or (g) declare a dividend or authorize the issuance of stock, unless expressly authorized by the board of directors.

The board of directors from time to time may, by like resolution, appoint any other committees of one or more directors to have the authority that shall be specified by the board of directors in the resolution making the appointments. Committees and committee members serve as such at the pleasure of the board of directors. The board of directors may designate one or more directors as alternate members of any committee to replace an absent or disqualified member at any committee meeting.

5.11 Retirement Policy. The board of directors does not believe it should establish term limits other than the current annual terms of office. However, if the board of directors believes it is necessary that a director should not stand for reelection due to his or her age, the board of directors, through resolution, may act on establishing the appropriate term limit for the particular director.

ARTICLE VI

NOTICES, WAIVERS OF NOTICE, AND MANNER OF ACTING

6.01 Notices. All notices of meetings required to be given to shareholders, directors, or any committee of directors may be given personally or by mail, telecopy, or electronic transmission to any shareholder, director, or committee member at his or her last address as it appears on the books of the Corporation or by electronic transmission, but in the case of shareholders, only in the form consented to by the shareholder. The notice shall be deemed to be given at the time it is mailed or otherwise dispatched or, if given by electronic transmission, when electronically transmitted to the person entitled to the notice, but in the case of shareholders only if sent in a manner authorized by the shareholder. Telephonic notice may be given for special meetings of the board of directors as provided in Section 5.06.

6.02 Waiver of Notice. Notice of the time, place, and purpose of any meeting of shareholders, directors, or committee of directors may be waived by telecopy or other writing, or by electronic transmission, either before or after the meeting, or in any other manner that may be

permitted by the laws of the state of Michigan. Attendance of a person at any shareholders meeting, in person or by proxy, or at any meeting of directors or of a committee of directors, constitutes a waiver of notice of the meeting except as follows:

(a) In the case of a shareholder, unless the shareholder at the beginning of the meeting objects to holding the meeting or transacting business at the meeting, or unless with respect to consideration of a particular matter at the meeting that is not within the purpose or purposes described in the meeting notice, the shareholder objects to considering the matter when it is presented; or

(b) In the case of a director, unless he or she at the beginning of the meeting, or upon his or her arrival, objects to the meeting or the transacting of business at the meeting and does not thereafter vote for or assent to any action taken at the meeting.

A shareholder’s attendance at a meeting of shareholders, whether in person or by proxy, will constitute (1) waiver of any objection to lack of notice or defective notice, unless the shareholder at the beginning of the meeting objects to holding the meeting or transacting business at the meeting, and (2) waiver of any objection to consideration of a particular matter at the meeting that is not within the purpose or purposes described in the meeting notice, unless the shareholder objects to considering the matter when it is presented.

6.03 Action Without a Meeting. Except as the articles of incorporation may otherwise provide for action to be taken by shareholders, any action required or permitted at any meeting of shareholders, directors, or a committee of directors may be taken without a meeting, without prior notice, and without a vote, if all of the shareholders, directors, or committee members entitled to vote on it consent to it in writing or, to the extent permitted by law, by electronic transmission, before or after the action is taken. Such consents shall be filed with the minutes of the proceedings of the shareholders, board, or committee, as applicable.

ARTICLE VII

OFFICERS

7.01 Number. The board of directors shall elect or appoint a president, a secretary, and a treasurer, and may select a chairperson of the board of directors and one or more vice presidents, assistant secretaries, or assistant treasurers, and other officers as it shall deem appropriate. The president and chairperson of the board of directors, if any, shall be members of the board of directors. Any two or more of the preceding offices, except those of president and vice president, may be held by the same person. No officer shall execute, acknowledge, or verify an instrument in more than one capacity if the instrument is required by law, the articles of incorporation, or these bylaws to be executed, acknowledged, or verified by one or more officers.

7.02 Term of Office, Resignation, and Removal. An officer shall hold office for the term for which he or she is elected or appointed and until his or her successor is elected or appointed and qualified, or until his or her resignation or removal. An officer may resign by written notice to the Corporation. The resignation is effective on its receipt by the Corporation

or at a subsequent time specified in the notice of resignation. An officer may be removed by the board of directors with or without cause. The removal of an officer shall be without prejudice to his or her contract rights, if any. The election or appointment of an officer does not of itself create contract rights.

7.03 Vacancies. The board of directors may fill any vacancies in any office occurring for whatever reason.

7.04 Authority. All officers, employees, and agents of the Corporation shall have the authority and perform the duties to conduct and manage the business and affairs of the Corporation that may be designated by the board of directors and these bylaws.

ARTICLE VIII

DUTIES OF OFFICERS

8.01 Chairperson of the Board. The chairperson of the board of directors, if the office is filled, shall preside at all meetings of the shareholders and of the board of directors at which the chairperson is present unless otherwise determined by the board of directors pursuant to Section 4.10 of Article 4.

8.02 President. The president shall be the chief executive officer of the Corporation. The president shall see that all orders and resolutions of the board of directors are carried into effect, and the president shall have the general powers of supervision and management usually vested in the chief executive officer of a corporation, including the authority to vote all securities of other corporations and business organizations held by the Corporation. In the absence or disability of the chairperson of the board of directors, or if that office has not been filled, the president also shall perform the duties of the chairperson of the board of directors as set forth in these bylaws.

8.03 Vice Presidents. The vice presidents, in order of their seniority, shall, in the absence or disability of the president, perform the duties and exercise the powers of the president and shall perform any other duties that the board of directors or the president may from time to time prescribe.

8.04 Secretary. The secretary shall attend all meetings of the board of directors and shareholders and shall record all votes and minutes of all proceedings in a book to be kept for that purpose; shall give or cause to be given notice of all meetings of the shareholders and the board of directors; and shall keep in safe custody the seal of the Corporation, if any, and, when authorized by the board of directors, affix it to any instrument requiring it, and when so affixed it shall be attested to by the signature of the secretary or by the signature of the treasurer or an assistant secretary. The secretary may delegate any of the duties, powers, and authorities of the secretary to one or more assistant secretaries, unless the delegation is disapproved by the board of directors.

8.05 Treasurer. The treasurer shall have the custody of the corporate funds and securities, shall keep full and accurate accounts of receipts and disbursements in the books of the Corporation, and shall deposit all moneys and other valuable effects in the name and to the credit of the Corporation in the depositories that may be designated by the board of directors. The treasurer shall render to the president and directors, whenever they may require it, an account of his or her transactions as treasurer and of the financial condition of the Corporation. The treasurer may delegate any of his or her duties, powers, and authorities to one or more assistant treasurers unless the delegation is disapproved by the board of directors.

8.06 Assistant Secretaries and Treasurers. The assistant secretaries, in order of their seniority, shall perform the duties and exercise the powers and authorities of the secretary in case of the secretary’s absence or disability. The assistant treasurers, in the order of their seniority, shall perform the duties and exercise the powers and authorities of the treasurer in case of the treasurer’s absence or disability. The assistant secretaries and assistant treasurers shall also perform the duties that may be delegated to them by the secretary and treasurer, respectively, and also the duties that the board of directors may prescribe.

ARTICLE IX

SPECIAL CORPORATE ACTS

9.01 Orders for Payment of Money. All checks, drafts, notes, bonds, bills of exchange, and orders for payment of money of the Corporation shall be signed by the officer or officers or any other person or persons that the board of directors may from time to time designate.

9.02 Contracts and Conveyances. The board of directors of the Corporation may in any instance designate the officer and/or agent who shall have authority to execute any contract, conveyance, mortgage, or other instrument on behalf of the Corporation, or may ratify or confirm any execution. When the execution of any instrument has been authorized without specification of the executing officers or agents, the chairperson of the board of directors, the president or any vice president, and the secretary, assistant secretary, treasurer, or assistant treasurer may execute the instrument in the name and on behalf of the Corporation and may affix the corporate seal, if any, to it. No officer shall execute, acknowledge or verify an instrument in more than one capacity if the instrument is required by law, by the articles of incorporation or by these bylaws to be executed, acknowledged or verified by two or more officers.

ARTICLE X

BOOKS AND RECORDS

10.01 Maintenance of Books and Records. The proper officers and agents of the Corporation shall keep and maintain the books, records, and accounts of the Corporation’s business and affairs, minutes of the proceedings of its shareholders, board of directors, and committees, if any, and the stock ledgers and lists of shareholders, as the board of directors shall deem advisable and as shall be required by the laws of the state of Michigan and other states or

jurisdictions empowered to impose such requirements. Books, records, and minutes may be kept within or without the state of Michigan in a place that the board of directors shall determine.

10.02 Reliance on Books and Records. In discharging his or her duties, a director or an officer of the Corporation, when acting in good faith, may rely on information, opinions, reports, or statements, including financial statements and other financial data, if prepared or presented by any of the following:

(a) One or more directors, officers, or employees of the Corporation, or of a business organization under joint control or common control, whom the director or officer reasonably believes to be reliable and competent in the matters presented;

(b) Legal counsel, public accountants, engineers, or other persons as to matters the director or officer reasonably believes are within the person’s professional or expert competence; or

(c) A committee of the board of directors of which he or she is not a member if the director or officer reasonably believes the committee merits confidence.

A director or officer is not entitled to rely on the information set forth above if he or she has knowledge concerning the matter in question that makes reliance otherwise permitted unwarranted.

ARTICLE XI

INDEMNIFICATION

11.01 Indemnification. Subject to all of the other provisions of Article XI, 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 and whether 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 or officer 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 expenses (including actual and reasonable attorney fees and disbursements), judgments (other than an action by or in the right of the Corporation), penalties, fines, excise taxes and amounts paid in settlement actually and incurred by him or her in connection with such action, suit, or proceeding, to the maximum extent permitted by the MBCA. The termination of any action, suit, or proceeding by judgment, order, settlement, conviction, or on a plea of nolo contendere or its equivalent, shall not, of itself, create a presumption that any person otherwise entitled to indemnification hereunder (i) did not act in good faith and in a manner that the person reasonably believed to be in or not opposed to the best interests of the Corporation or its shareholders, (ii) with respect to any criminal action or proceeding, had reasonable cause to believe that his or her conduct was unlawful, or (iii)

received a financial benefit to which he or she is not entitled, intentionally inflicted harm on the Corporation or its shareholders, violated Section 551 of the MBCA or intentionally committed a criminal act.

11.02 Expenses of Successful Defense. To the extent that a director or officer of the Corporation has been successful on the merits or otherwise in defense of any action, suit, or proceeding referred to in Sections 11.01, or in defense of any claim, issue, or matter in the action, suit, or proceeding, the director or officer shall be indemnified against actual and reasonable expenses (including attorney fees) incurred by the person in connection with the action, suit, or proceeding and any action, suit, or proceeding brought to enforce the mandatory indemnification provided by this Section 11.02.

11.03 Definition. For the purposes of Sections 11.01, “serving at the request of the Corporation” shall include any service as a director, officer, employee, or agent of the Corporation that imposes duties on, or involves services by, the director or officer with respect to an employee benefit plan, its participants, or its beneficiaries; and a person who acted in good faith and in a manner the person reasonably believed to be in the interest of the participants and beneficiaries of an employee benefit plan shall be considered to have acted in a manner “not opposed to the best interests of the Corporation or its shareholders” as referred to in Sections 11.01.

11.04 Contract Right; Limitation on Indemnity. The right to indemnification conferred in Article XI shall be a contract right and shall apply to services of a director or officer as an employee or agent of the Corporation as well as in the person’s capacity as a director or officer. Except as otherwise expressly provided in this Article XI, the Corporation shall have no obligations under Article XI to indemnify any person in connection with any proceeding, or part thereof, initiated by the person without authorization by the board of directors.

11.05 Determination That Indemnification Is Proper. Any indemnification under Sections 11.01 (unless ordered by a court) shall be made by the Corporation only as authorized in the specific case upon a determination that indemnification of the person is proper in the circumstances because the person has met the applicable standard of conduct set forth in Sections 11.01, whichever is applicable, and upon an evaluation of the reasonableness of expense and amounts paid in settlement. The determination and evaluation shall be made in any of the following ways:

(a) By a majority vote of a quorum of the board of directors consisting of directors who are not parties or threatened to be made parties to the action, suit, or proceeding;

(b) If the quorum described in clause (a) above is not obtainable, then by majority vote of a committee of directors duly designated by the board of directors and consisting solely of two or more directors who are not at the time parties or threatened to be made parties to the action, suit, or proceeding;

(c) By independent legal counsel in a written opinion, which counsel shall be selected in one of the following ways: (i) by the board of directors or its committee in the

manner prescribed in subparagraph (a) or (b); or (ii) if a quorum of the board of directors cannot be obtained under subparagraph (a) and a committee cannot be designated under subparagraph (b), by the board of directors; or

(d) By the shareholders, but shares held by directors, officers, employees, or agents who are parties or threatened to be made parties to the action, suit, or proceeding may not be voted.

(e) By all independent directors (as defined by Section 107(3) of the Michigan Business Corporation Act) who are not parties or threatened to be made parties to the action, suit, or proceeding.

If the articles of incorporation of this Corporation include a provision eliminating or limiting the liability of a director pursuant to Section 209 of the MBCA, the Corporation shall indemnify a director for the expenses and liabilities described below in this paragraph without a determination that the director has met the standard of conduct set forth in the MBCA, but no indemnification may be made except to the extent authorized in Section 564c of the MBCA, if the director received a financial benefit to which he or she was not entitled, intentionally inflicted harm on the Corporation or its shareholders, violated Section 551 of the MBCA, or intentionally violated criminal law. In connection with an action or suit by or in the right of the Corporation, indemnification may be for expenses, including attorneys’ fees, actually and reasonably incurred. In connection with an action, suit or proceeding other than one by or in the right of the Corporation, indemnification may be for expenses, including attorneys’ fees, actually and reasonably incurred, and for judgments, penalties, fines, and amounts paid in settlement actually and reasonably incurred.

11.06 Authorizations of Payment. Authorizations of payment under Sections 11.01 shall be made in any of the following ways:

(a) by the board of directors:

(i) if there are two or more directors who are not parties or threatened to be made parties to the action, suit or proceeding, by a majority vote of all such directors (a majority of whom shall for this purpose constitute a quorum)or by a majority of the members of a committee of two or more directors who are not parties or threatened to be made parties to the action, suit or proceeding;

(ii) if the Corporation has one or more independent directors who are not parties or threatened to be made parties to the action, suit or proceeding, by a majority vote of all such directors (a majority of whom shall for this purpose constitute a quorum); or

(iii) if there are no independent directors and fewer than two directors who are not parties or threatened to be made parties to the action, suit or proceeding, by the vote

necessary for action by the board of directors in accordance with Section 3.07, in which authorization all directors may participate; or

(b) by the shareholders, but shares held by directors, officers, employees, or agents who are parties or threatened to be made parties to the action, suit, or proceeding may not be voted on the authorization.

11.07 Proportionate Indemnity. If a person is entitled to indemnification under Sections 11.01 for a portion of expenses, including attorney fees, judgments, penalties, fines, and amounts paid in settlement, but not for the total amount, the Corporation shall indemnify the person for the portion of the expenses, judgments, penalties, fines, or amounts paid in settlement for which the person is entitled to be indemnified.

11.08 Expense Advance. The Corporation shall pay or reimburse the reasonable expenses incurred by a person referred to in Sections 11.01 who is a party or threatened to be made a party to an action, suit, or proceeding in advance of final disposition of the proceeding if the person furnishes the Corporation a written undertaking executed personally, or on his or her belief, to repay the advance if it is ultimately determined that he or she did not meet the standard of conduct, if any, required by the MBCA for the indemnification of the person under the circumstances. An evaluation of reasonableness under this Section 11.08 shall be made as specified in Section 11.05, and authorizations shall be made in the manner specified in Section 11.06, unless the advance is mandatory. A provision in the articles of incorporation, these bylaws, a resolution by the board of directors or the shareholders, or an agreement making indemnification mandatory shall also make advancement of expenses mandatory unless the provision specifically provides otherwise.

11.09 Non-Exclusivity of Rights. The indemnification or advancement of expenses provided under this article is not exclusive of other rights to which a person seeking indemnification or advancement of expenses may be entitled under a contractual arrangement with the Corporation. However, the total amount of expenses advanced or indemnified from all sources combined shall not exceed the amount of actual expenses incurred by the person seeking indemnification or advancement of expenses.

11.10 Indemnification of Employees and Agents of the Corporation. The Corporation may, to the extent authorized from time to time by the board of directors, grant rights to indemnification and to the advancement of expenses to any employee or agent of the Corporation to the fullest extent of the provisions of Article XI with respect to the indemnification and advancement of expenses of directors and officers of the Corporation.

11.11 Former Directors and Officers. The indemnification provided in Article XI continues for a person who has ceased to be a director or officer and shall inure to the benefit of the heirs, executors, and administrators of the person.

11.12 Insurance. The Corporation may purchase and maintain insurance on behalf of any person who is or was a director, officer, employee, or agent of the Corporation, or is or was serving at the request of the Corporation as a director, officer, partner, trustee, employee, or

agent of another corporation, partnership, joint venture, trust, or other enterprise, against any liability asserted against the person and incurred by him or her in any such capacity or arising out of his or her status as such, whether or not the Corporation would have power to indemnify the person against the liability under these bylaws or the laws of the state of Michigan. If the articles of incorporation of this Corporation include a provision eliminating or limiting the liability of a director pursuant to Section 209(1)(c) of the MBCA, such insurance may be purchased from an insurer owned by the Corporation, but such insurance may insure against monetary liability to the Corporation or its shareholders only to the extent to which the Corporation could indemnify the director under Section 11.05.

11.13 Changes in Michigan Law. If there is any change of the Michigan statutory provisions applicable to the Corporation relating to the subject matter of Article XI, then the indemnification to which any person shall be entitled under this article shall be determined by the changed provisions, but only to the extent that the change permits the Corporation to provide broader indemnification rights than the provisions permitted the Corporation to provide before the change. Subject to Section 11.14, the board of directors is authorized to amend these bylaws to conform to any such changed statutory provisions.

11.14 Amendment or Repeal of Article XI. No amendment or repeal of Article XI shall apply to or have any effect on any director or officer of the Corporation for or with respect to any acts or omissions of the director or officer occurring before the amendment or repeal.

11.15 Enforcement Of Rights. Any determination with respect to indemnification or payment in advance of final disposition under this Article XI shall be made promptly, and in any event within 30 days, after written request to the corporation by the person seeking such indemnification or payment. If it is determined that such indemnification or payment is proper and if such indemnification or payment is authorized (to the extent such authorization is required) in accordance with this Article XI, then such indemnification or payment in advance of final disposition under this Article XI shall be made promptly, and in any event within 30 days after such determination has been made, such authorization that may be required has been given and any conditions precedent to such indemnification or payment set forth in this Article XI, the articles of incorporation or applicable law have been satisfied. The rights granted by this Article XI shall be enforceable by such person in any court of competent jurisdiction.

ARTICLE XII

AMENDMENTS

12.01 Amendments. The bylaws of the Corporation may be amended, altered, or repealed, in whole or in part, by the shareholders or by the board of directors at any meeting duly held in accordance with these bylaws, provided that notice of the meeting includes notice of the proposed amendment, alteration, or repeal.

ARTICLE XIII

CONTROL SHARE ACQUISITIONS

13.01 Control Share Acquisitions. Chapter 7B of the MBCA shall not apply to control share acquisitions of shares of the Corporation.

As adopted by the board of directors on February 16, 2011

EX-10.91

Exhibit 10.91

SA 1926 DTIA Consumers-METC Version: 0.0.0 Effective: 9/1/2010

Midwest ISO	Second Revised Service Agreement No. 1926
FERC Electric Tariff,	Superseding First Revised Service Agreement No. 1926
Fifth Revised Volume No. 1

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

Issued by: Stephen G. Kozey, Issuing Officer	Effective: September 1, 2010
Issued on: August 31, 2010

TABLE OF CONTENTS

ARTICLE 1.	Definitions
ARTICLE 2.	Operational Requirements
ARTICLE 3:	Operation and Maintenance
ARTICLE 4.	Supervisory Control and Data Acquisition, SCADA
ARTICLE 5.	Revenue Metering
ARTICLE 6.	Protective Relaying and Control
ARTICLE 7.	Planning and Obligation to Serve
ARTICLE 8.	Transmission Service Level
ARTICLE 9.	New Construction and Modification
ARTICLE 10.	Access to Facilities
ARTICLE 11.	Notifications and Reporting
ARTICLE 12.	Safety
ARTICLE 13.	Environmental Compliance and Procedures
ARTICLE 14.	Billings and Payment
ARTICLE 15.	Applicable Regulations and Interpretation
ARTICLE 16.	Force Majeure
ARTICLE 17.	Indemnification
ARTICLE 18.	Insurance
ARTICLE 19.	Several Obligations
ARTICLE 20.	Confidentiality
ARTICLE 21.	Breach, Default and Remedies
ARTICLE 22.	Term

ARTICLE 23.	Assignment/Change in Corporate Identity
ARTICLE 24.	Subcontractors
ARTICLE 25.	Dispute Resolution
ARTICLE 26.	Miscellaneous Provisions
EXHIBIT 1.	Interconnection Points (Substations) Addendum 5, Final 06/10/10
EXHIBIT 2.	Contact Information for Local Distribution Company’s Representatives and Transmission Provider’s Representatives
EXHIBIT 3.	Special Manufacturing Contracts Influenced by Transmission System
EXHIBIT 4.	Metering Specifications
EXHIBIT 5.	Respective Ownership of Substation Facilities Since August 7, 2007
EXHIBIT 6.	Jointly Owned Assets — Ownership by Percent of Major Equipment Addendum 5, Final 06/10/10

Amendment and Restatement of the
DISTRIBUTION TRANSMISSION INTERCONNECTION AGREEMENT

      This Amendment and Restatement of the April 1, 2001 Distribution Transmission Interconnection Agreement (“Agreement”) is entered into April 29, 2002, by and between the Michigan Electric Transmission Company, LLC, a Michigan corporation (“Transmission Provider”), having a place of business at 27175 Energy Way, Novi, Michigan 48377, and Consumers Energy Company (“Local Distribution Company”), a Michigan company, doing business in Michigan and having a place of business at One Energy Plaza, Jackson, Michigan, 49201. Transmission Provider and Local Distribution Company are individually referred to herein as a “Party” and collectively as “Parties.” This Agreement amends, restates and completely replaces the April 1, 2001 Distribution Transmission Interconnection Agreement between the Parties, effective on the date indicated above.

     WHEREAS, Transmission Provider requires access to parts of Local Distribution Company’s assets, and Local Distribution Company requires access to parts of Transmission Provider’s assets; and

     WHEREAS, the Parties have agreed to execute this mutually acceptable Agreement in order to provide interconnection of the Local Distribution Company with the Transmission Provider and to define the continuing rights, responsibilities, and obligations of the Parties with respect to the use of certain of their own and the other Party’s property, assets, and facilities.

NOW, THEREFORE, in consideration of their respective commitments set forth herein, and intending to be legally bound hereby, the Parties covenant and agree as follows:

ARTICLE 1. Definitions

     Wherever used in this Agreement with initial capitalization, the following terms shall have the meanings specified or referred to in this Article 1.

1.1 Administrative Committee means the committee established pursuant to Article 6 of the Operating Agreement dated April 1, 2001, as amended and restated, between Local Distribution Company and Transmission Provider.

1.2 Agreement means this Interconnection Agreement between Local Distribution Company and Transmission Provider, including all attachments hereto, as the same may be amended, supplemented, or modified in accordance with its terms

1.3 Black Start Capability shall mean a generating unit that is capable of starting without an outside electrical supply.

1.4 Black Start Plan shall mean a plan utilizing Black Start Capability designed and implemented by the Transmission Provider 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.

1.5 Commission shall mean the Michigan Public Service Commission (MPSC), or its successor.

1.6 Confidential Information shall have the meaning set forth in Section 20.1 hereof.

1.7 Control Area shall mean an electric system, bounded by interconnection metering and telemetry. Generation within the Control Area is directed to operate in a manner prescribed by guidelines established by ECAR and NERC and in accordance with Good Utility Practice to (a) maintain scheduled interchange with other Control Areas, (b) maintain the operating frequency and (c) provide sufficient generating capacity to maintain operating reserves.

1.8 Distribution System shall mean the equipment and facilities and the Interconnection Equipment owned by the Local Distribution Company and used to deliver power and energy to end users including transformers, switches, and feeders rated at Nominal Voltage of 138 kilovolts (kV) or less.

1.9 Distribution System Control shall mean the entity that has the ability and the obligation to operate the Distribution System Control Area to ensure that the aggregate electrical demand and energy requirements of the load is met at all times, taking into account scheduled and reasonably expected unscheduled outages of system elements.

1.10 Distribution System Control Area shall mean a Control Area whose load and generation, and other bulk power supply points are integrated by the Transmission System.

1.11 Distribution System Control Center shall mean the electric Distribution System Control Center(s) that is/are responsible for monitoring and controlling the Distribution System in real time.

1.12 Distribution Transformer shall mean an electrical transformer which, generally, has its secondary low-side windings rated at Nominal Voltage of less than 138 kV.

1.13 Due Diligence shall mean the exercise of good faith efforts to perform a required act on a timely basis and in accordance with Good Utility Practice using the necessary technical and personnel resources.

1.14 ECAR is an acronym, which stands for the East Central Area Reliability coordination agreement. This is the Agreement under which Transmission Providers, who are signatories of the agreement, establish regional coordination practices and guides to govern the electric coordinated operation and reliability of the East Central Region of North America.

1.15 Effective Date shall mean the closing date as defined in the Membership Interests Purchase Agreement between the Parties.

1.16 Eligible Customer shall have the same meaning as that term is defined under the Transmission Provider’s OATT on file with the FERC.

1.17 Emergency means a condition or situation that in the reasonable good faith determination of the affected Party in accordance with Good Utility Practice contributes to an existing or imminent physical threat of danger to life or a significant threat to health, property or the environment.

1.18 Extended Outage shall mean an Unplanned Outage, in which facilities are automatically removed from service (typically by relay-action operating circuit breakers), with a duration of more than two (2) minutes.

1.19	FERC shall mean the Federal Energy Regulatory Commission or its successor federal agency.
1.20	Force Majeure shall have the meaning set forth under Article 16 hereof.

1.21 Forced Outage shall mean an Unplanned Outage, in which facilities are removed from service by operator intervention and not automatically such as by relay-action operating circuit breakers.

1.22 Good Utility Practice shall mean any of the practices, methods and acts engaged in or approved by a significant portion 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 includes all acceptable practices, methods, or acts generally accepted in the region.

1.23

Governmental Authority shall mean any foreign, federal, state, local or other governmental regulatory or administrative agency, court, commission, department, board, or other governmental subdivision, legislature, rulemaking board, tribunal, arbitrating body, or other governmental authority; provided such entity possesses valid jurisdictional authority to regulate the Parties and the terms and conditions of this Agreement.

1.24

ISO means Independent System Operator.

1.25 Interconnection Equipment shall mean all the equipment that is necessary for the interconnection of the Distribution System to the Transmission

System which is located at the substations listed in Exhibit 1 hereto as it may be revised from time to time.

1.26 Interconnection Point(s) shall mean the point(s) at which the Distribution System is connected to the Transmission System, as set forth in Exhibit 1 hereto as it may be revised from time to time.

1.27 Interconnection Service shall mean the services provided by the Transmission Provider for the interconnection of the Distribution System with the Transmission System. Interconnection Service does not include the right to transmission service on the Transmission System, which service shall be obtained in accordance with the provisions of the Transmission Provider’s OATT.

1.28 Interconnection Standards shall be those standards provided by the Transmission Provider to the Local Distribution Company to establish and maintain interconnection operation in compliance with standards of NERC, ECAR, applicable state or federal regulations or by mutual agreement of the Parties.

1.29 Interest Rate shall mean an annual percentage rate of interest equal to the lesser of (a) the prime rate published by the Wall Street Journal (which represents the base rate on corporate loans posted by at least 75% of the nation’s banks) on the date due, plus 2%, or (b) the highest rate permitted by law.

1.30 Jointly Owned Assets shall mean those assets in which the Transmission Provider and Local Distribution Company have undivided ownership interests. Due to the nature of substation designs, many of the supporting substation assets (e.g., station batteries, fence, control houses, ground grid, yard stone, steel structures, and some protective relay equipment) 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 6.

1.31 Knowledge shall mean actual knowledge of the corporate officers or managers of the specified Person charged with responsibility for the particular function as of the Effective Date of this Agreement, or, with respect to any certificate delivered pursuant to the Agreement, the date of delivery of the certificate.

1.32 Least-Cost shall mean the lowest Transmission System and Distribution System facility costs, over the life of the facility, to accommodate an improvement need while adequately providing for reliability, operating, and maintenance requirements.

1.33 Local Distribution Company shall mean Consumers Energy Company and its successors and assigns.

1.34 Local Distribution Company Provided Services shall mean those services provided by the Local Distribution Company for the Transmission Provider by mutual agreement or contract.

1.35 Local Distribution Company’s Representative shall be that person(s) identified as the point of contact for day-to-day operations of the Distribution System, identified in Section 2.3.

1.36 Momentary Outage shall mean a Distribution or Transmission System (in whole or in part) interruption in service with a duration of two (2) minutes or less.

1.37 Momentary Outage Event shall mean one or more Momentary Outages within any 60-minute period that are attributable to the same root cause.

1.38 NERC shall mean the North American Electric Reliability Council or its successor.

1.39 Network Security shall mean the ability of the Transmission System to withstand sudden disturbances such as unforeseen conditions, electric short circuits or unanticipated loss of system elements consistent with reliability principles used to design, plan, operate, and assess the actual or projected reliability of an electric system that are established by any Governmental Authority, NERC or ECAR and which are implemented by Transmission Provider or required of Transmission Provider in compliance with Security Coordinator directives.

1.40 Network Security Condition shall mean a condition or situation in which, in the reasonable good faith determination of Transmission Provider, Network Security is not satisfied or is threatened.

1.41 Nominal Voltage shall mean an accepted standard voltage level offered by the Transmission Provider, at various points on the Transmission System, including but not limited to 120 kV, 138 kV and 345 kV.

1.42 Normal System Condition shall mean any operating conditions of the Transmission System other than an Emergency or Network Security Condition.

1.43	Open Access Transmission Tariff or OATT shall mean the Open Access Transmission Tariff of the Transmission Provider on file with the FERC.
1.44	Operating Committee means the committee established pursuant to Section 6.4.3 of the Operating Agreement dated April 1, 2001, as

	amended and restated, between Local Distribution Company and Transmission Provider.
1.45	Party or Parties shall have the meaning set forth in the introductory paragraph of this Agreement.

1.46	Person shall mean any individual, partnership, limited liability company, joint venture, corporation, trust, unincorporated organization, or governmental entity or any department or agency thereof.
1.47	Planned Outage shall mean action by (i) Local Distribution Company or Transmission Provider to take its equipment, facilities or systems out of service, partially or completely, to perform work on specific components that is scheduled in advance and has a predetermined start date and duration pursuant to the procedures set forth in Sections 3.9.1, 3.9.2, and 3.9.4. Planned Outage shall not include the construction of new facilities or system elements, the modification of existing facilities or system elements addressed in Article 9, which includes, but is not limited to, activities associated with the construction of third party facilities or with the modifications required to accommodate third party facilities.
1.48	Planning Committee means the committee established pursuant to Section 6.4.3 of the Operating Agreement dated April 1, 2001, as amended and restated, between Local Distribution Company and Transmission Provider.
1.49	Protective Relay is a device which detects abnormal power system conditions and, in response, initiates automatic control action
1.50	Protective Relay System is a group of Protective Relays and associated sensing devices and communications equipment that detects system abnormalities and performs automatic control action to mitigate or reduce adverse effects of such abnormalities.
1.51	Qualified Personnel shall mean individuals trained for their positions in accordance with Good Utility Practice.
1.52	RTO means Regional Transmission Organization.
1.53	Regulated Substance means any contaminant, hazardous waste, hazardous substance, hazardous constituent, or toxic substance, as defined in the Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), 42 USC 9601 et seq, Resource Conservation and Recovery Act (RCRA), 42 USC 6901 et seq, Toxic Substances Control Act (TSCA), 15 USC 2601 et seq, The Michigan Natural

	Resources and Environmental Protection Act (MCLA 324.101 et seq); or any other similar statutes now or hereafter in effect.
1.54	Release shall mean, spill, leak, discharge, dispose of, pump, pour, emit, empty, inject, leach, dump, or allow to escape into or through the environment.
1.55	Revenue Quality Metering System shall mean a system which includes current and voltage instrument transformers, secondary wiring, test switches, meter transducer(s), meter and loss compensation as set forth in Article 5.
1.56	RTU — Remote Terminal Units shall mean a device connected by a communication system to one or more master computers with appropriate software placed at various locations to collect data and perform remote control. It may also perform intelligent autonomous control of electrical systems and report the results back to the master computer(s).
1.57	Security Coordinator shall mean a NERC-approved entity that provides the security assessment and emergency operations coordination for one or more Control Areas or transmission providers and which has operational authority under NERC standards over the Transmission Provider.
1.58	Steady-State Voltage shall mean the value of a voltage after all transients have decayed to a negligible value. The root-mean-square value in the steady-state does not vary with time.
1.59	Supervisory Control and Data Acquisition (SCADA) shall mean a system that provides data acquisition, supervisory control and alarm display and control from remote field locations to control centers.
1.60	Transmission Provider shall mean the Michigan Electric Transmission Company, LLC and its successors and assigns.
1.61	Transmission Provider’s Representative(s) shall be that person(s) identified as the point for contact for day-to-day operations of the Transmission System, identified in Section 2.3.
1.62	Transmission System shall mean all the facilities of the Transmission Provider that perform a “Transmission” function, as defined in Section 1.1 of the Easement Agreement between the Parties, dated April 29, 2002, as modified by Section 3.4 of this Agreement.
1.63	Transmission System Operations Center(s) shall mean the electric Transmission System control center(s) that is/are responsible for monitoring and controlling the Transmission System in real time.

1.64 Unplanned Outage shall mean action by Local Distribution Company or Transmission Provider to take its equipment, facilities or systems out of service, partially or completely, due to an unanticipated failure, when such removal from service was not scheduled in accordance with Sections 3.9.1, 3.9.2, and 3.9.4. Such removal from service may be automatic such as by relay-action operating circuit breakers or by operator intervention. Momentary interruptions are excluded from the definition of Unplanned Outages. Unplanned Outages include Forced Outages as well as Extended Outages.

ARTICLE 2. Operational Requirements

2.1 Subject to the terms and conditions of this Agreement, Transmission Provider shall provide Local Distribution Company Interconnection Service for each Interconnection Point identified in Exhibit 1, from the Effective Date for the term of this Agreement.

2.2 The Interconnection Points between the Transmission System and Distribution System are listed in Exhibit 1. It shall be the Transmission Provider’s responsibility to annually prepare an addendum to this exhibit that shows all new or modified interconnections. The original Exhibit 1 and all addendums shall be retained for future reference.

2.3	Local Distribution Company’s Representatives and Transmission Provider’s Representatives are listed in Exhibit 2, as may be modified from time to time by either Party, giving written notice of changes regarding its Representative(s) to the other Party.
2.4	Interconnection Standards

2.4.1 The Interconnection Point(s) shall be established and maintained in accordance with Good Utility Practice and the applicable NERC, Federal, State, OATT and ECAR standards and policies for Transmission Provider service to Local Distribution Company.

2.4.2 Reactive Power. Transmission Provider and Local Distribution Company recognize and agree that they have a mutual responsibility for maintaining voltage at the Interconnection Points. Transmission Provider is responsible for maintaining Transmission System voltage as listed in Sections 8.1, 8.2 and 8.3 and reasonably compensating for reactive power losses resulting from transmission service. The Local Distribution Company is responsible for controlling Distribution System voltage and compensating for Distribution System reactive power losses and reactive power consumed by retail customers. The Local Distribution Company may use a combination of static and dynamic reactive resources at

various locations around the Transmission Provider’s system. The Local Distribution Company’s and the Transmission Provider’s SCADA systems shall be used to determine the net exchange of reactive power on a total interconnections basis. For those distribution substations where there are no SCADA facilities in place the reactive flows shall be determined from SCADA data on the connecting lines in conjunction with computer load flow simulations. At load levels below 90% of peak the system should be designed such that the average power factor for the sum of all Interconnection Points is between 90% lagging and 90% leading (“peak” as used here shall refer to a current year’s maximum MW load for the Local Distribution Company). For load levels above 90% of peak the power factor should be at 98% (lagging or leading), or better. If the power factor falls below this minimum the Planning Committee shall review available options and determine the best method of addressing any resulting system problems.

2.5(a)  The Local Distribution Company shall comply with Transmission Provider’s reasonable operating requirements or switching procedures. The Local Distribution Company shall verbally notify the Transmission Provider if the Local Distribution Company is unable to comply with this Section at any time during the term of the Agreement.

(b) The Transmission Provider shall comply with Local Distribution Company’s reasonable operating requirements or switching procedures. The Transmission Provider shall verbally notify the Local Distribution Company if the Transmission Provider is unable to comply with this Section at any time during the term of the Agreement.

2.6 Local Distribution Company shall comply with the requests, orders, directives and requirements of Transmission Provider in its role of implementing the directives of the Security Coordinator. Any such requests, orders, directives or requirements of Transmission Provider must be (a) issued in accordance with Good Utility Practice, (b) not unduly discriminatory, (c) otherwise in accordance with applicable tariffs or applicable federal, state or local laws, (d) in conformance with NERC operating procedures, and (e) reasonably necessary to maintain the integrity of the Transmission System.

2.7 Load Shedding

2.7.1 Local Distribution Company shall comply, as part of a Control Area program, with installation of automatic underfrequency load shedding equipment and maintain compliance with the standards set forth in NERC and ECAR operating standards and policies at Transmission Provider’s expense.

2.7.2 The Transmission Provider may direct the Local Distribution Company to shed load to maintain the reliability and integrity of the Transmission System, in accordance with the OATT. The Transmission Provider and the Local Distribution Company will comply with MPSC directives and will endeavor to minimize the impact on the Local Distribution Company customers.

2.8 Not a Reservation for Transmission Service

2.8.1 Local Distribution Company, or an Eligible Customer under the OATT, shall be responsible for making arrangements under the OATT for transmission and any ancillary services associated with the delivery of capacity and/or energy purchased or produced by the Local Distribution Company, which services shall not be provided under this Agreement.

2.8.2 Local Distribution Company and Transmission Provider make no guarantees to the other under this Agreement with respect to transmission service that is available under the Transmission Provider’s OATT or any other tariff under which transmission service may be available in the region. Nothing in this Agreement shall constitute an express or implied representation or warranty with respect to the current or future availability of transmission service. Should the Parties enter into an arrangement under the OATT or another tariff, any terms in this Interconnection Agreement that may be in conflict with that tariff shall be subordinate to the terms of that tariff.

ARTICLE 3. Operation and Maintenance

3.1 The Operating Committee shall develop specific methods and procedures with respect to Local Distribution Company’s and Transmission Provider’s systems covering at least, but not limited to, the following areas: safety, voltage control, outage planning and implementation, service restoration, emergency operations procedures, frequency controls, environmental matters, and maintenance planning and execution.

3.2 Exhibit 5 reflects ownership changes since August 7, 2007. Exhibit 5 Wiring Diagrams (WDs) will be updated continuously in each Party’s Drawing Management System (DMS) which is shared between the Parties and approved by both Parties at least annually when Exhibit 6 is updated to show changes in ownership. For purpose of this Section 3.2, such submission and approval of changes shall be in writing consistent with Section 11.1. For current ownership (reflecting ownership changes since August 7, 2007), see the WDs in the DMS. The original Exhibit 5 WDs and all updates will be retained for future reference.

3.3 All operation and maintenance activities will be the financial responsibility of the owning Party. All operation and maintenance activities on Jointly Owned Assets will be under the direction and control of the Party that owns the greater percentage of the major equipment at that location. In the case where both Parties own an equal share the Local Distribution Company shall have such direction and control. The Parties’ respective share of responsibility for the costs of all operation and maintenance activities on Jointly Owned Assets shall be the same percentage as the percentage of major equipment owned by the Party in that substation as set forth in Exhibit 6 and its subsequent addendums. All generation-related assets owned by the Local Distribution Company in a substation will be included as a part of the Local Distribution Company’s assets in making this calculation. Responsibilities related to third-party owned generation-related assets will be split according to the nominal operating voltage at the point of connection of the generation circuit. At 120kV and above the third-party generation-related assets will be included as a part of the Transmission Provider’s assets for purposes of making this calculation. Below 120 kV the third-party generation-related assets will be included as a part of the Local Distribution Company’s assets for purposes of making this calculation. Major equipment shall be defined as main power transformers, 23 kV, 46 kV, 138 kV, and 345 kV circuit breakers, power system regulators and reclosers, and 46 kV and 138 kV capacitor banks. (Any three-phase installation of such equipment shall count as a single unit). Exhibit 6 will be updated with an addendum at least annually by the Transmission Provider and approved in writing by the Local Distribution Company to show all changes in equipment ownership in the joint substations. The original Exhibit 6 and all addendums will be retained for future reference. In those substations where each Party owns assets each Party shall be financially responsible for its appropriate share of station power energy usage.

3.4 The Parties agree that the principles upon which the initial identification was made of facilities as being either Transmission or Distribution (See the definitions of “Transmission” and “Distribution” in Section 1.1 of the Amended and Restated Easement Agreement dated April 29, 2002 between the Parties) shall continue to be applied for the future unless modification is agreed to by both Parties. Should future system modifications result in the reclassification of assets, the Parties agree to convey ownership of those assets to the appropriate Party. However, no such reclassification shall affect how the other Sections of this Agreement are applied until there is a change in ownership of the facilities involved and until any related changes are made to this Agreement and its exhibits. Upon such a change in ownership, the Planning Committee shall revise Exhibits 6 and/or 7 when needed to reflect the change in ownership. The conveyed facilities shall be priced at 1.18 times the seller’s net plant value but in any case shall not be less than zero dollars (i.e. no payment from

seller to purchaser will occur as a result of net plant value being less than zero). As used herein, ”net plant value” shall mean the asset’s original cost depreciated according to the seller’s accepted accounting method. In addition, should either Party plan to abandon or otherwise take out of service any facilities which could be of use as part of the other Party’s system, it shall offer to convey to the other Party such facilities before they are taken out of service under the same pricing formula outlined above. All types of conveyances discussed in this paragraph shall be subject to the following conditions:

(a) The Planning Committee shall within 12 months of the Effective Date of this Agreement develop appropriate timeframes and procedures for accomplishing such conveyances.

(b) At least 12 months (or as close as feasible to 12 months) before implementing system modifications which would result in such a conveyance, the Party planning to do such modifications shall notify the other Party of such plans. The other Party, if it wishes, shall then have 2 months within which to propose an alternative modification which is consistent with Good Utility Practice, which would reduce or eliminate the need for conveyances, and which would cost the Party seeking to do the modifications no more than the originally proposed modification. If such an alternative is provided in a timely manner, the Party proposing to do the modification shall consider the alternative and shall not unreasonably refuse to pursue the alternative instead of the original proposal.

(c) Possible impediments to timely conveying the property in question (e.g. difficulty in getting release from the conveyor’s indenture) shall be referred to the Administrative Committee. The Administrative Committee is authorized to modify the requirements of this Section with regard to such a specific proposed modification however it deems appropriate in light of the possible impediment and other circumstances.

3.5 Each Party shall operate any equipment that might reasonably be expected to have impact on the operations of the other Party in a safe and efficient manner and in accordance with all applicable federal, state, and local laws, NERC operating practices, and Good Utility Practice, and otherwise in accordance with the terms of this Agreement. Each Party shall comply with the reasonable requests, orders, directives and requirements of the other Party, which are authorized under this Agreement.

3.6(a)  Without limiting the generality of Section 3.5, Local Distribution Company shall own, operate and maintain its Distribution System in a manner in accordance with Good Utility Practice to prevent degradation of voltage or services of the Transmission System. The Local Distribution Company shall be responsible for the costs to repair or replace the Distribution System and Local Distribution Company’s Interconnection Equipment.

3.6(b)  Without limiting the generality of Section 3.5, Transmission Provider shall own, operate and maintain its Transmission System in a manner in accordance with Good Utility Practice to prevent degradation of voltage or services of Local Distribution Company’s Distribution System. The Transmission Provider shall be responsible for the costs to repair or replace the Transmission System and Transmission Provider’s Interconnection Equipment.

3.6(c)  Without limiting the generality of Section 3.5, Local Distribution Company or Transmission Provider, as appropriate pursuant to Section 3.3 hereof, shall operate and maintain Jointly Owned Assets in a manner in accordance with Good Utility Practice to prevent degradation of voltage or services to either Party.

3.7(a)  Except during an Emergency, Local Distribution Company shall not, without prior Transmission Provider authorization, operate any Transmission Provider circuit, including transformer, line or bus elements. Local Distribution Company shall retain the right to operate Transmission Provider equipment during an Emergency for imminent personnel safety threat, to prevent damage to equipment or to maintain the integrity of the Distribution System. When practical, prior to operation of such equipment, Local Distribution Company shall provide notice to the Transmission Provider. The Local Distribution Company shall not operate any Transmission System circuit if upon notice the Transmission Provider expressly refuses to grant permission to the Local Distribution Company. Within five (5) working days of such Emergency, Local Distribution Company shall provide written explanation of such Emergency to Transmission Provider.

3.7(b)  Except during an Emergency, Transmission Provider shall not, without prior Local Distribution Company authorization, operate any Local Distribution Company circuit, including transformer, line or bus elements. Transmission Provider shall retain the right to operate Local Distribution Company equipment, during an Emergency for imminent personnel safety threat, to prevent damage to equipment or to maintain the integrity of the Transmission System. When practical, prior to operation of such equipment, Transmission Provider shall provide notice to Local Distribution Company. Transmission Provider shall not operate any Distribution System circuit. If upon notice the Local Distribution Company

expressly refuses to grant permission to the Transmission Provider. Within five (5) working days of such Emergency, Transmission Provider shall provide written explanation of such Emergency to Local Distribution Company.

3.7(c)  In an Emergency, joint facilities shall be operated by the Party able to first respond with Qualified Personnel.

3.8 Local Distribution Company and Transmission Provider shall design, install, test, calibrate, set, and maintain their respective Protective Relay equipment in accordance with Good Utility Practice, applicable federal, state or local laws and this Agreement, as set forth in Article 6 hereof. In the case of jointly owned relaying equipment, the Party having direction and control pursuant to Section 3.3 hereof shall design, install, calibrate, set, and maintain Protective Relay equipment in accordance with Good Utility Practice. Without limiting the generality of Section 3.5(c) above, costs for such work will be split between the Companies on a predetermined ownership percentage basis as set forth in the then-current version of Exhibit 6.

3.9(a)  If Transmission Provider reasonably determines that (i) any of Local Distribution Company’s Interconnection Equipment fails to perform in a manner in accordance with Good Utility Practice or this Agreement, or (ii) Local Distribution Company has failed to perform proper testing or maintenance of its Interconnection Equipment in accordance with Good Utility Practice or this Agreement, Transmission Provider shall give Local Distribution Company written notice to take corrective action. Such written notice shall be provided by Transmission Provider to Local Distribution Company’s Representative as soon as practicable upon such determination. If Local Distribution Company fails to initiate corrective action promptly, and in no event later than seven (7) days after the delivery of such notification, and if in Transmission Provider’s reasonable judgment leaving Local Distribution Company’s Distribution System connected with Transmission System would create an Emergency or Network Security Condition, Transmission Provider may, with as much prior verbal notification to Local Distribution Company and Distribution System Control as practicable, open only the Interconnection Point(s) needing corrective action connecting the Local Distribution Company and Transmission Provider until appropriate corrective actions have been completed by Local Distribution Company, as verified by Transmission Provider. Prior to taking such action, Transmission Provider shall give appropriate consideration to the needs of the Local Distribution Company’s end-use customers. Transmission Provider’s judgment with regard to an interruption of service under this paragraph shall be made in accordance with Good Utility Practice and subject to Section 3.1 hereto. In the case of such interruption, Transmission Provider shall immediately

confer with Local Distribution Company regarding the conditions causing such interruption and its recommendation concerning timely correction thereof. Both Parties shall act promptly to correct the condition leading to such interruption and to restore the connection.

3.9(b)

If Local Distribution Company reasonably determines that (i) any of Transmission Provider’s Interconnection Equipment fails to perform in a manner in accordance with Good Utility Practice or this Agreement, or (ii) Transmission Provider has failed to perform proper testing or maintenance of its Interconnection Equipment in accordance with Good Utility Practice or this Agreement, Local Distribution Company shall give Transmission Provider written notice to take corrective action. Such written notice shall be provided by Local Distribution Company to Transmission Provider’s Representative as soon as practicable upon such determination. If Transmission Provider fails to initiate corrective action promptly, and in no event later than seven (7) days after the delivery of such notification, and if in Local Distribution Company’s reasonable judgment leaving Transmission System connected with Local Distribution Company’s Distribution System would create an Emergency, Local Distribution Company may, with as much prior verbal notification to Transmission Provider and Distribution System Control as practicable, open only the Interconnection Point(s) needing corrective action connecting the Transmission Provider and Local Distribution Company until appropriate corrective actions have been completed by Transmission Provider, as verified by Local Distribution Company. Local Distribution Company’s judgment with regard to an interruption of service under this paragraph shall be made in accordance with Good Utility Practice and subject to Section 3.1 hereto. In the case of such interruption, Local Distribution Company shall immediately confer with Transmission Provider regarding the conditions causing such interruption and its recommendation concerning timely correction thereof. Both Parties shall act promptly to correct the condition leading to such interruption and to restore the connection.

3.10

Outages

3.10.1 Outage Authority and Coordination. In accordance with Good Utility Practice, each Party may, in close cooperation with the other, remove from service its system elements that may impact the other Party’s system as necessary to perform maintenance or testing or to replace installed equipment. Absent the existence of an Emergency, the Party scheduling a removal of a system element from service will schedule such removal on a date mutually acceptable to both Parties, in accordance with Good Utility Practice.

3.10.2

The Parties shall coordinate inspections, Planned Outages, and maintenance of their respective equipment, facilities and systems so as to minimize the impact on the availability, reliability and security of both Parties’ systems and operations when the outage is likely to have a materially adverse impact on the other Party’s system or the Local Distribution Company’s end-use customers. Subject to the confidentiality provisions of Article 20, on or before October 1 of each year during the term hereof, the Parties shall exchange non-binding Planned Outage schedules for the following calendar year, which shall be developed and followed in accordance with Good Utility Practice, for the Distribution System and Transmission System. The Parties shall communicate the outage schedules as promptly as possible, provided that in no event shall such schedule be provided less than fifteen (15) days prior to a Planned Outage. The Parties shall keep each other updated regarding any changes to such schedules.

3.10.3

Unplanned Outages

3.10.3.1

Distribution System Unplanned Outage. In the event of an Unplanned Outage of a system element of the Distribution System adversely affecting the Transmission System, the Local Distribution Company will act in accordance with Good Utility Practice to promptly restore that system element to service unless the Local Distribution Company obtains concurrence from the Transmission Provider that some deferral is reasonable, and this concurrence shall not be unreasonably withheld. The Local Distribution Company shall plan and maintain its Distribution System such that the average length of distribution system outages having a direct impact on the Transmission System shall not exceed 166 minutes per event on an annual basis. For any year in which the average outage duration exceeds this limit, the Local Distribution Company shall develop a plan to improve the outage restoration process and reduce outages and shall obtain the Transmission Provider’s concurrence with this plan. Within forty-eight hours (48) of the beginning of any Unplanned Outage, the Local Distribution Company shall provide the Transmission Provider with a restoration plan.

3.10.3.2

Transmission System Unplanned Outage. In the event of an Unplanned Outage of a system element of the Transmission System adversely affecting the Local Distribution Company’s Distribution System, the

Transmission Provider will restore the system to normal as soon as possible unless the Transmission Provider obtains concurrence from the Local Distribution Provider that some deferral is reasonable, and this concurrence shall not be unreasonably withheld. The Transmission Provider shall plan and maintain its Transmission System such that the average length of Transmission System outages having a direct impact on customers of the Local Distribution Company shall not exceed 166 minutes on an annual basis. For any year in which the average outage duration exceeds this limit, the Transmission Provider shall develop a plan to improve the outage restoration process and reduce outages and shall obtain the Local Distribution Company’s concurrence with this plan. Within forty-eight hours (48) of the beginning of any Unplanned Outage the Transmission Provider shall provide the Local Distribution Company with a restoration plan. For any 138 kV system outage it is expected that the system will be restored to its normal configuration within seven (7) days; for any 345 kV system outage it is expected that the system will be restored to its normal configuration within thirty (30) days. If it is expected that any Unplanned Outage will exceed these limits the Transmission Provider shall provide the Local Distribution Company with detailed information on measures being taken to minimize the outage time.

3.10.4 Planned Outages

3.10.4.1

Distribution System Planned Outage. In the event of a Planned Outage of a system element of the Distribution System adversely affecting the Transmission System, the Local Distribution Company will act in accordance with Good Utility Practice to promptly restore that system element to service in accordance with its schedule for the work that necessitated the Planned Outage.

3.10.4.2

Transmission System Planned Outage. The Transmission Provider shall review all Transmission System Planned Outages with the Local Distribution Company. In the event of a Planned Outage of a system element of the Transmission System adversely affecting the Local Distribution Company’s Distribution System, the Transmission Provider will act in accordance with Good Utility Practice to promptly restore that system element to

service in accordance with its schedule for the work that necessitated the Planned Outage.

3.11 The Parties shall use best efforts in accordance with Good Utility Practice to coordinate operations in the event of any Forced or Planned Outage that affects the other Party’s system.

3.12 Black Start Plan Participation. In accordance with Good Utility Practice, Local Distribution Company agrees to participate in Transmission Provider’s Black Start Plan for the Distribution System and the Transmission System, as well as any verification testing.

3.13 The Parties shall notify and make available in a timely manner, electric system modeling information necessary for the other Party to monitor, analyze, and protect its facilities in a real time environment, no less than 30 days prior to the energization of new or reconfigured network facilities.

ARTICLE 4. Supervisory Control and Data Acquisition, SCADA

4.1 If the Transmission Provider chooses to operate its own SCADA system, or to make modifications or additions to the existing system, the following terms and conditions of this Article 4 will apply.

4.2 Interconnection Points containing SCADA and communications equipment installed prior to April 1, 2001, shall be considered to satisfy the terms and conditions of this article. For those Interconnection Points that existed prior to April 1, 2001 that did not contain SCADA and communications equipment, and for new Interconnection Points installed after April 1, 2001 where SCADA and communications equipment is necessary for and requested by the Transmission Provider to perform monitoring, state estimation and contingency analysis, the Local Distribution Company shall install and operate such equipment at the Transmission Provider’s expense. Each Interconnection Point or other mutually agreeable location with SCADA and communications equipment shall have one dedicated communications path to the Local Distribution Company’s control center for the RTU data. The cost of the dedicated communications path and general use station phone shall be shared on an equal basis. Additional data paths and communications equipment requested, either emanating from the substation, the Local Distribution Company’s control center, or the Transmission Provider’s control center, will be at the expense of the requestor. This data and status information may be real time or with a time delay mutually acceptable to the Parties. The method of providing this data and control will be via an industry standard protocol such as Inter-Control Center Protocol (ICCP) or other method agreed to by the

Parties. Such data may include, but not be limited to megawatts, megavars, voltage, amperes, device status, interchange schedule error, and communication system status.

4.3 The Transmission Provider reserves the right at its expense, to require, for new, or modified Local Distribution Company Interconnection Points, installation of a Transmission Provider’s RTU or installation of a dual port RTU to provide data and control directly to the Transmission Provider within the Local Distribution Company’s substation. The Local Distribution Company will assist in furnishing desired inputs for the Transmission Provider’s RTU.

4.4 The operating metering system shall consist of instantaneous values of MW, MVAR, and voltage.

4.4.1 Values shall be inputted to a RTU or comparable communication device for communication with the Party having Control Area responsibility.

4.4.2 Transducers may utilize the voltage transformers and current transformer secondary circuits also utilized by the revenue metering equipment for a particular interconnection. In such case, the performance criteria listed in Exhibit 4 of the Agreement, Metering Specifications, for the voltage transformers and the current transformers, shall apply. Relaying class voltage transformers and or current transformers shall not be utilized unless mutually agreed between all the owners of the metering equipment and the Local Distribution Company.

4.4.3 Transducers shall have maximum 0.3% inaccuracy. Transducers shall be field calibrated as necessary but at least once every ten (10) years and documentation shall be retained showing the calibration results until next calibration.

4.4.4 Telemetry shall be maintained and calibrated such that overall inaccuracy of MW, MVAR, and voltage values is less than 1.0% of full scale.

4.5 To the extent new RTUs and associated communications equipment is to be installed, the Local Distribution Company shall install or facilitate installation of the RTU and associated communications equipment as soon as practicable, provided that installation shall be accomplished within a time period of no more than 270 days following notice by Transmission Provider or prior to commissioning of any new Interconnection Points.

ARTICLE 5. Revenue Metering

5.1 Transmission Provider shall own, operate, test and maintain any metering equipment at the Interconnection Points, as required by this Article 5 not including any metering equipment owned by the Local Distribution Company for use in metering its end-use customers. Transmission Provider and Local Distribution Company agree that, as to all Interconnection Points in existence as of the Effective Date, no new or different metering equipment or arrangements shall be required. For existing Interconnection Points where low-side metering exists without loss compensation, the Parties will agree to adjust the metering data in such a manner to account for any real power losses between the location of the meter and the Interconnection Point. To the extent existing metering equipment is replaced and when new metering equipment is installed at Interconnection Points in existence as of the Effective Date, such replacements or installations shall meet the standards set in Section 5.2. Transmission Provider shall provide, install, own, operate, test and maintain the new metering equipment located at the Interconnection Points.

5.2 The Revenue Quality Metering System shall consist of all instrument transformers (current and voltage), secondary wiring, test switches, and meter(s) required to determine the metering values for record for any given metering point.

5.2.1 Metering shall be form 9, 3-element for 4-wire systems and form 5, 2-element for 3-wire systems.

5.2.2 Meters shall measure, at a minimum, megawatt hours and megavar hours and have bi-directional capability, where applicable. All measured values shall have individual outputs where applicable and a minimum 35-day interval data recording capability for each measured value.

5.2.3 Whenever feasible, any new metering facilities shall be located at the same physical location as the Interconnection Point. If it is not reasonable to have the metering facilities and the Interconnection Point at the same physical location, the metering data will be adjusted to account for real power losses between the location of the meter and the Interconnection Point.

5.2.4 Transmission Provider shall maintain records that demonstrate compliance with all meter tests and maintenance conducted in accordance with Good Utility Practice for the life of the

Interconnection Point. Local Distribution Company shall have reasonable access to the records.

5.2.5 For installations where the metering is performed using loss compensation, the factory certified test results of the power transformer, if available, including load, no-load losses and calculated meter loss calculations, shall be recorded in a written record. Local Distribution Company shall have reasonable access to the records.

5.2.6 Transmission Provider shall maintain records of the factory certified test results, or the utility test shop test results, showing compliance of the meters with the applicable metering test standards.

5.2.7 Transmission Provider’s Metering equipment shall be tested by Transmission Provider at its own expense not less than once every year, unless an extension of the testing cycle is agreed upon by the Parties. The accuracy of such metering equipment shall be maintained by Transmission Provider in accordance with applicable regulatory standards. At the request of either Party, special tests shall be made. If any special meter test discloses the metering device to be registering within acceptable limits of accuracy as specified herein, then the Party requesting such special meter test shall bear the expense thereof. Otherwise, the expense of such test shall be borne by the owner. Representatives of either Party shall be afforded opportunity to be present at all routine or special tests and upon occasions when any readings for purposes of settlements hereunder are taken from meters not producing an automatic record.

5.2.8 If, as a result of any test, any meter shall be found to be registering more than two (2) percent above or below one hundred (100) percent of accuracy, the account between the Parties hereto shall be corrected for a period equal to one-half of the elapsed time since the last prior test, according to the percentage of inaccuracy so found, except that if the meter shall have become defective or inaccurate at a reasonably ascertainable time since the last prior test of such meter, the correction shall extend back to such time. No meter shall be left in service if found to be more than two (2) percent above or below one hundred (100) percent of accuracy. Should metering equipment at any time fail to register, the energy delivered shall be determined from the best available data. All meters shall be kept under seal, such seals to be broken only when the meters are to be tested or adjusted.

5.2.9 Test switches shall be installed to allow independent testing and/or replacement of each meter and transducer utilizing the secondary circuit so as not to interrupt the operation of other devices utilizing the secondary circuit.

5.2.10 In substations where an RTU or other remote data collecting and telecommunication device is present, meters shall have form C, 3-wire outputs with programmable values determined by the Transmission Provider for bi-directional MWHs and MVARs.

5.2.11 In the event an interconnection meter needs replacement or repair, a representative from Local Distribution Company shall be given a reasonable opportunity to be present during such repair or replacement.

ARTICLE 6. Protective Relaying and Control

6.1 Transmission Provider and the Local Distribution Company shall, in accordance with Good Utility Practice, coordinate, review and approve all new Protective Relaying equipment, including equipment settings, Protective Relay schemes, drawings, and functionality associated with each Interconnection Point. Protective Relaying equipment and schemes installed before the date of this agreement shall be considered to satisfy the terms and conditions of this Article 6. When existing equipment or schemes are replaced or when new equipment or schemes are installed per this Article 6 or in association with new Interconnection Points, then the terms and conditions of Article 6 shall apply. Each Party shall incur the expense for the work on its system.

6.2 To the extent that there is generation on the Distribution System which, in the reasonable judgment of either Party, may contribute material amounts of current to a fault on the Transmission System, the Local Distribution Company shall have and enforce standards to ensure the provision, installation and maintenance of relays, circuit breakers, and all other devices necessary to promptly remove any fault contribution of such generation to any short circuit occurring on the Transmission System and not otherwise isolated by the Transmission Provider equipment. Such standards will be included in the Local Distribution Company’s connection requirements for generation. Transmission Provider and Local Distribution Company shall not be responsible for protection of such generation.

6.3 Transmission Provider shall own, operate, maintain and test those Protective Relay Systems that control their breakers or equivalent protective devices. Local Distribution Company shall own, operate, maintain, and test those Protective Relay Systems that control their

breakers or equivalent protective devices governed by this Article 6. The Parties shall maintain, and, as necessary, upgrade their respective Protective Relay Systems and shall provide the other Party with access to available copies of operation and maintenance manuals and test records for all relay equipment upon request. The Transmission Provider will provide protective relay settings for the relays that control breakers or equivalent protective devices owned by the Local Distribution Company that also protect Transmission Provider’s equipment. The Local Distribution Company will review and apply the settings.

6.4 The owner (Transmission Provider or Local Distribution Company) of the line will provide the relay communication channel necessary for line protection at its expense. Owner will participate with other Party to test communication schemes upon request without charge.

6.5 The Parties shall test their respective relays associated with the Interconnection Points for correct calibration and operation. Parties shall coordinate design, installation, operation, and testing of Protective Relay schemes to insure that such relays operate in a coordinated manner so as to not cause adverse operating conditions on the other Party’s system.

6.6 Local Distribution Company shall be responsible for Protective Relay maintenance, calibration and functional testing of relay systems that protect Local Distribution Company’s equipment associated with the Interconnection Points and that protect Transmission Provider from Local Distribution Company’s Interconnection Equipment to the extent such calibration and testing are in accordance with Good Utility Practice. All such maintenance and testing must be performed by Qualified Personnel selected by the Local Distribution Company. In addition, Local Distribution Company shall allow Transmission Provider to conduct visual inspection of all Protective Relays and associated maintenance records directly related to the interconnection. Related maintenance and operational records shall be maintained by the Local Distribution Company in accordance with Good Utility Practice. Upon completion of Protective Relay calibration testing and relay functional testing, Local Distribution Company shall make available copies of test reports and related records for review by Transmission Provider upon request. Local Distribution Company shall review test reports and document that Protective Relay System’s tests and settings, as shown on such test reports, have been done in accordance with the equipment’s specifications and Good Utility Practice.

6.7(a)  As Transmission Provider’s system protection requirements change, Transmission Provider will upgrade its Protective Relaying System in accordance with Good Utility Practice. If these upgrades affect the serviceability and acceptability of the Protective Relaying Systems on the

Interconnection Equipment which may be installed, owned, and operated by Local Distribution Company, the Local Distribution Company must upgrade its Protective Relay Systems at its expense (unless such modifications are required in association with the addition of generation to the system in which case Section 9.8 shall apply) as necessary to bring them into compatibility with that installed by Transmission Provider. Transmission Provider shall give Local Distribution Company notice of such upgrade as soon as practicable prior to the anticipated date of such upgrade. Any proposed protective system upgrades shall be reviewed by the Planning Committee in accordance with Section 7.3 (vi) hereof.

6.7(b)  As Local Distribution Company’s system protection requirements change, Local Distribution Company will upgrade its Protective Relaying System in accordance with Good Utility Practice. If these upgrades affect the serviceability and acceptability of the Protective Relaying Systems on the Interconnection Equipment which may be installed, owned, and operated by Transmission Provider, Transmission Provider must upgrade its Protective Relaying Systems at its expense (unless such modifications are required in association with the addition of generation to the system in which case Section 9.8 shall apply) as necessary to bring them into compatibility with that installed by Local Distribution Company. Local Distribution Company shall give Transmission Provider notice of such upgrade as soon as practicable prior to the anticipated date of such upgrade. Any proposed protective system upgrades shall be reviewed by the Planning Committee in accordance with Section 7.3 (vi) hereof.

6.8 Local Distribution Company shall provide necessary space to install or expand relay panels for substation system protection if requested by Transmission Provider. Any incremental costs required to accommodate such request shall be the responsibility of the Transmission Provider.

6.9 Transmission Provider shall provide the necessary space to install or expand relay panels for substation system protection if requested by Local Distribution Company. Any incremental costs required to accommodate such request shall be the responsibility of the Local Distribution Company.

6.10 Each Party will provide access to the other to fault recorder, sequence of events and relay information such as dial up access of digital relays.

ARTICLE 7. Planning and Obligation to Serve

7.1 Adequacy Obligation. Subject to applicable regulatory approvals, including adherence to Least-Cost planning requirements and principles, adherence to applicable NERC, ECAR or other regional reliability council

or successor organization’s reliability requirements, and all other applicable operating reliability criteria and subject to the oversight and direction of the appropriate RTO or ISO, the Transmission Provider shall operate, maintain, plan and construct its Transmission System in accordance with Good Utility Practice in order to:

(i)	deliver on a reliable basis the projected capacity and energy needs of all loads served by the Local Distribution Company’s Distribution System and dependent upon the Transmission Provider’s facilities for delivery of such energy to the Distribution System;
(ii)	provide needed support to the Local Distribution Company where a transmission addition is the Least-Cost electric solution to an improvement need, including but not limited to, the reliability needs of the Local Distribution Company; and
(iii)	deliver energy from both existing and new generating facilities connected to and dependent upon Transmission Provider’s transmission of such energy

7.2 With regard to planning and construction of projects which affect Local Distribution Company and Local Distribution Company’s load-serving area, the Parties shall develop methods and procedures covering at least the following areas:

(i)	coordination between short-term and long-term distribution and transmission planning;
(ii)	developing and sharing computer simulation models needed to support Transmission Provider and Local Distribution Company planning activities;
(iii)	coordination of permitting (including local and state approvals) and siting;
(iv)	engineering and scheduling of new projects;
(v)	construction and inspection standards;
(vi)	information-sharing and priority-setting; and
(vii)	health and safety issues.

7.3 With respect to Local Distribution Company’s load-serving area, the Planning Committee, shall:

(i)	implement the methods and procedures developed pursuant to Section 7.2;
(ii)	review planning studies and reports regarding projects needed or proposed for the area in the next five (5) years, or as determined by the Planning Committee;
(iii)	recommend additional studies or evaluation of plans;
(iv)	follow Least-Cost planning principles in recommending specific projects;
(v)	at least once every year, prepare a planning report which shall include in priority order a list of projects proposed by either Party for the next year, the estimated costs of such projects, and the timetable for such projects, including the in-service date; and
(vi)	review proposed programmatic changes to the electric system, including protective system upgrades

7.4 If the Parties agree upon the need for any such project, they shall cooperate and coordinate in seeking all necessary regulatory approvals for such project. Transmission Provider shall coordinate and cooperate with Local Distribution Company with respect to all communications and commitments to municipal, county, and state agencies involved in such project.

7.5

If Local Distribution Company proposes construction of a transmission project and Transmission Provider does not agree that such project is needed, Local Distribution Company shall have the right to petition an appropriate RTO, ISO or applicable regulatory agency for a declaratory ruling on whether the proposed project is needed pursuant to Transmission Provider’s public-utility duty to plan and construct a reliable, adequate Transmission System.

7.6

Load Growth and Reliability Needs. Transmission Provider is obligated to plan and install any Transmission System components that may be necessary, as determined by a Least-Cost planning process in accordance with Section 7.1 and consistent with the established and consistently applied reliability criteria of the Parties, to accommodate Local Distribution Company’s planned load growth and planned reliability improvements. Transmission Provider will construct new interconnections to Local Distribution Company facilities in accordance with Transmission Provider’s planning criteria, other agreements in effect between the Parties, and Good Utility Practice. Transmission Provider shall bear the responsibility for such planning and installing in accordance

with this Article 7. Transmission Provider’s obligations under this Section 7.6 shall include the planning and installation of any new Interconnection Points that may be necessary to accommodate Local Distribution Company’s planned load growth and planned reliability improvements. Recovery of the cost of such additions shall be in accordance with the OATT or other applicable tariff.

7.7 Local Distribution Company shall be the first point of contact and the wire-services provider for end-use customers.

7.8 Transmission Provider shall annually submit to Local Distribution Company, no later than February 1 of each year:

(i) Transmission Provider’s plans covering the next five (5) years, or as determined by the Planning Committee, for installing Transmission System components that may be necessary to accommodate Local Distribution Company’s planned load growth and reliability improvements as described in Section 7.6. Transmission Provider’s plans shall include, but not be limited to, cost estimates and installation schedules for Transmission System components, and shall provide specific detail sufficient to allow Local Distribution Company to compare Transmission Provider’s plans with Local Distribution Company’s in-service requirements to meet its planned load growth and reliability needs.

(ii) A description of any changes to the Local Distribution Company’s Distribution System that may be needed to accommodate Transmission Provider’s plans set forth in Section 7.8(i) will be requested by the Transmission Provider.

(iii) Projected voltage levels under Normal System Conditions and Transmission Provider’s FERC 715 Planning criteria conditions at anticipated annual peak load and 80% of anticipated annual peak load for each Interconnection Point with planned additions for the next five (5) years, or as determined by the Planning Committee.

7.9 Local Distribution Company shall annually submit to Transmission Provider,

(a) no later than December 1 of each year, the most recent actual summer and winter demands in megawatts (MW) and megavars (Mvar) for all Interconnection Points connected to the Transmission System at the time of the Transmission Provider’s most recent seasonal system peaks (Transmission Provider must provide the Local Distribution Company the day and hour of such peak no later than September 1); and

(b) no later than February 1 of each year:

(i) annual peak demand forecasts in MW for each Local Distribution Company Interconnection Point to the Transmission System for the next five (5) years, or as determined by the Planning Committee, together with corresponding projected power factors; and

(ii) planned facility (new Interconnection Points) connections to the Transmission System for the next five (5) years, or as determined by the Planning Committee.

ARTICLE 8. Transmission Service Level

8.1 Subject to applicable regulatory approvals, including adherence to Least- Cost planning requirements and principles, adherence to applicable NERC, ECAR or other regional reliability council or successor organization’s reliability requirements, and all other applicable operating reliability criteria and subject to the oversight and direction of the appropriate RTO or ISO, the Transmission Provider shall operate, maintain, plan and construct its Transmission System in accordance with Good Utility Practice to provide the following service levels:

(i)	A minimum Steady-State Voltage of 0.97 Per Unit (PU) at all Interconnection Points with Local Distribution Company with all influential Transmission Provider facilities in service (no contingency conditions);
(ii)	A minimum Steady-State Voltage of 0.92 PU at all Interconnection Points with the Local Distribution Company influenced by one or more Transmission Provider facilities out of service (contingency conditions);
(iii)	A maximum Steady-State Voltage of 1.05 PU at all Interconnection Points with the Local Distribution Company during all operating conditions;
(iv)	An adequate Transmission System that shall not load Local Distribution Company facilities above normal ratings during peak load conditions with all influential Transmission Provider facilities in service (no contingency conditions);
(v)	An adequate Transmission System that shall not load Local Distribution Company facilities above emergency ratings during

	peak load conditions with one or more influential Transmission Provider facilities out of service (contingency conditions);
(vi)	On a three-year rolling average, experience no more than 0.357 Momentary Outage Events per 138 kV line protective zone (system average) and 0.743 Momentary Outage Events per 345 kV line protective zone (system average) per year. As used in this Article 8 the term “year” shall mean calendar year; and the term “line protective zone” is illustrated and defined as follows: Any given electrical fault on a transmission line will trip specific circuit breakers in a normally functioning system. All of the possible line fault locations that will trip these specific circuit breakers constitute the same line protective zone. Physically, a line protective zone consists of the conductors located between the current transformers that provide sensing to trip the circuit breakers for a line fault;
(vii)	Experience no more than three (3) Momentary Outage Events on any given 138 kV line protective zone and two (2) Momentary Outage Events on any given 345 kV line protective zone per year;
(viii)	On a three-year rolling average, experience no more than 0.21 Unplanned Outages per 138 kV line protective zone (system average) and 0.18 Unplanned Outages per 345 kV line protective zone (system average) per year;
(ix)	Experience no more than four (4) Unplanned Outages on any given 138 kV line protective zone and three (3) Unplanned Outages on any given 345 kV line protective zone per year;
(x)	Should the Transmission Provider fail to meet any of the requirements of Section 8.1(vi) or 8.1(viii) by more than 10% two years in a row, the Transmission Provider shall pay, as liquidated damages and not as a penalty, to the Local Distribution Company, an amount equal to one half of one percent (0.5%) of the annual revenue paid by the Local Distribution Company under the applicable transmission tariff; such liquidated damages amount shall be based upon the revenue received in the second year of such failure. Such liquidated damages amount shall be increased by one half of a percent (0.5%) for each additional 10% by which the Transmission Provider fails to meet the any of the given outage targets, up to a maximum of 4.0% of the annual revenue. Outage events affecting 15% or more of transmission line protective zones within a 24-hour period will not be counted toward the requirements of Section 8.1.

If transmission service does not meet the requirements of this Article 8, Transmission Provider shall present an action plan acceptable to the Local Distribution Company within sixty (60) days of non-compliance of this Article 8 to restore transmission service to the minimum standards as described in this Article 8 in a timely manner. Should the Transmission Provider fail to correct the deficiency(s) within one year of notification from the Local Distribution Company, the Local Distribution Company shall have the right to take corrective action at the Transmission Provider’s expense. The Local Distribution Company shall defer taking such actions for corrective measures normally requiring longer than one year to complete, provided the Transmission Provider is diligently pursuing such measures.

8.2 Should the Michigan Public Service Commission (MPSC) adopt service quality standards that the Local Distribution Company must meet that are more stringent than current historical performance; and should the transmission service level provided by the Transmission Provider directly or indirectly influence the Local Distribution Company’s ability to meet such standards, the Local Distribution Company will promptly notify the Transmission Provider of such proposal and the Transmission Provider shall have an opportunity to participate either as a party or in cooperation with the Distribution Company, in any related MPSC hearings or proceedings. Subject to the foregoing and to any required approval by FERC, the Transmission Provider shall be responsible for meeting its proportional share of the adopted service quality standard and for any penalties that might be assessed if the standards are not met.

8.3 Transmission Provider shall be responsible for those compensable disruptions/interruptions caused by the Transmission Provider’s Transmission System to those Local Distribution Company customers under Special Manufacturing Contracts in existence at the time of execution of this document as set forth in Exhibit 3, including any contractual payments due.

ARTICLE 9. New Construction and Modification

9.1 Subject to this Article 9, Transmission Provider may construct additional Transmission System elements or modify the existing Transmission System and Local Distribution Company may construct additional Distribution System elements or modify the existing Distribution System. All such modifications and construction provided for herein, shall be conducted in accordance with Good Utility Practice and all applicable NERC and ECAR Standards. The Party that modifies the system elements or constructs new system elements is obligated to maintain the

transmission, distribution and communications capabilities of the other Party in accordance with Good Utility Practice to avoid or minimize any adverse impact on the other Party. The Parties shall look to the operating history of the Local Distribution Company in the relevant geographic area prior to the Effective Date of this Agreement, where available, in determining what constitutes Good Utility Practice.

9.2 Notwithstanding the foregoing, no modifications to or new construction of facilities or access thereto, including but not limited to rights-of-way, fences, and gates, shall be made by either Party which might reasonably be expected to have a material effect upon the other Party with respect to operations or performance under this Agreement, without providing the other Party with sufficient information regarding the work prior to commencement to enable such Party to evaluate the impact of the proposed work on its operations. The information provided must be of sufficient detail to satisfy reasonable Transmission Provider or Local Distribution Company review and operational requirements. Each Party shall use reasonable efforts to minimize any adverse impact on the other Party.

9.3 If any Party intends to install any new facilities, equipment, systems, or circuits or any modifications to existing or future facilities, equipment, systems or circuits that could reasonably be expected to have a material effect upon the operation of the other Party, the Party desiring to perform said work shall, in addition to the requirements of Section 9.2, provide the other Party with drawings, plans, specifications and other necessary documentation for review at least 60 days prior to the start of the construction of any such installation. This notice period shall not apply to modifications or new installations made to resolve or prevent pending Emergency or Network Security Conditions.

9.4 The Party reviewing any drawings, plans, specifications, or other necessary documentation for review shall promptly review the same and provide any comments to the performing Party no later than 30 days prior to the start of the construction of any installation. Unless system modifications are required in association with the addition of generation to the system (in which case Section 9.8 hereof shall apply) all such reviews shall be performed at no cost to either Party. The performing Party shall incorporate all requested modifications to the extent required in accordance with Good Utility Practice and compliance with this Agreement.

9.5 Within 180 days following placing in-service of any modification or construction subject to this Article 9, the Party initiating the work shall provide “as built” drawings, plans and related technical data to the other Party. Approval or review of any document referenced herein shall not

relieve the initiating Party of its responsibility for the design or construction of any proposed facility, nor shall it subject the other Party to any liability, except with respect to the confidentiality provisions of Article 20.

9.6 Each Party shall, at its own expense, have the right to inspect or observe all maintenance activities, equipment tests, installation work, construction work, and modification work to the facilities of the other Party that could have a material effect upon the facilities or operations of the first Party.

9.7 Construction and installation of any facility shall meet all or exceed all environmental permitting requirements, reviews or approvals as required by Federal, State or local law prior to the installation of such facilities. The Parties agree to coordinate environmental permitting related activities such as site review for regulated resources, permit application and project oversight (e.g. monitoring as applicable).

9.8 Whenever system modifications are required to connect generating facilities to either the Local Distribution Company’s or the Transmission Provider’s system it is expected that the party installing the generating facilities will normally be responsible for much or all of the associated costs. The Parties agree to cooperate in sharing information regarding such projects and to individually make arrangements with the party adding the generation to obtain payment of all related costs as appropriate.

ARTICLE 10. Access to Facilities

10.1 The Parties hereby agree to provide each other reasonable access to their respective property as may be necessary and appropriate to enable each Party to operate and maintain its respective facilities and equipment on such property. Such right of access shall be provided in a manner so as not to unreasonably interfere with either Party’s ongoing business operations, rights, and obligations.

10.2 Each Party shall provide the other Party keys, access codes or other access methods necessary to enter the other Party’s facilities to exercise rights under this Agreement. Access shall only be granted to Qualified Personnel.

ARTICLE 11. Notifications and Reporting

11.1 Unless otherwise provided, any notice required to be given by either Party to the other Party in connection with this Agreement shall be given in writing: (a) personally; (b) by facsimile transmission (if sender thereafter

sends such notice to recipient by any of the other methods provided in this Section 11.1; (c) by registered or certified U.S. mail, return receipt requested, postage prepaid; or (d) by reputable overnight carrier, with acknowledged receipt of delivery; or (e) any other method mutually agreed by the Parties in writing. Notice shall be deemed given on the date of receipt personally. Notice sent by facsimile shall be deemed given on the date the transmission is confirmed by sender’s facsimile machine, so long as the facsimile is sent on a business day during normal business hours of the recipient. Otherwise, the notice shall be deemed given on the next succeeding business day. Notice provided by mail or overnight courier shall be deemed given at the date of acceptance or refusal of acceptance shown on such receipt.

11.2 Notice to the Transmission Provider shall be to the Transmission Provider’s Representative, at the addresses identified in Exhibit 2. Notice to the Local Distribution Company shall be to the Local Distribution Company’s Representative, at the addresses identified in Exhibit 2.

11.3 Each Party shall provide prompt notice describing the nature and extent of the condition, the impact on operations, and all corrective action, to the other Party of any Emergency or Network Security Condition which may be reasonably anticipated to affect the other Party’s equipment, facilities or operations. Either Party may take reasonable and necessary action, both on its own and the other Party’s system, equipment, and facilities, to prevent, avoid or mitigate injury, danger, damage or loss to its own equipment and facilities, or to expedite restoration of service; provided however, that the Party taking such action shall give the other Party prior notice, if at all possible, before taking any action on the other Party’s system, equipment, or facilities.

11.4 In the event of an Emergency or Network Security Condition contemplated by Section 11.3, each Party shall provide the other with such information, documents, and data necessary for operation of the Transmission System and Distribution System, including, without limitation, such information which is to be supplied to any Governmental Authority, NERC, ECAR, or Transmission System Operations Center or Distribution System Control Center.

11.5 In order to continue interconnection of the Distribution System and Transmission System, each Party shall promptly provide the other Party with all relevant information, documents, or data regarding the Distribution System and the Transmission System that would be expected to affect the Distribution System or Transmission System, and which is reasonably requested by NERC, ECAR, or any Governmental Authority.

11.6 For routine maintenance and inspection activities on either Parties system that will require major equipment or system outages, and could impact the other Party’s system, the Party performing the same shall provide the other Party with not less than seventy-two (72) hours prior notice, if practicable; provided that the provisions of Section 3.9 remain applicable to the outages, and said notice is in addition to, and does not substitute for, the requirements of Section 3.9 (maintenance and inspection activities in generating plant substations require 20 working days notification).

11.7 Transmission Provider shall notify Local Distribution Company prior to entering Local Distribution Company’s facilities for routine measurements, inspections and meter reads in accordance with the requirements of Section 11.6. Local Distribution Company shall notify Transmission Provider prior to entering Transmission Provider’s facilities, including switchyards, for routine maintenance, operations, measurements, inspections and meter reads, in accordance with the requirements of Section 11.6.

11.8 Each Party shall provide prompt verbal notice to the other Party of any system alarm that applies to the other Party’s equipment, unless the system alarm is automatically sent to the other Party.

11.9 Each Party shall provide a report or a copy of the data from a system events recorder, SCADA system sequence of events or digital fault recorder that applies to the other Party’s equipment.

11.10 Each Party agrees to immediately notify the other Party verbally, and then in writing, of any labor dispute or anticipated labor dispute of which its management has actual Knowledge that might reasonably be expected to affect the operations of the other Party with respect to this Agreement.

ARTICLE 12. Safety

12.1 Each Party agrees that all work performed by either Party that may reasonably be expected to affect the other Party shall be performed in accordance with Good Utility Practice and all applicable laws, regulations, safety standards, practices and procedures and other requirements pertaining to the safety of Persons or property, (including, but not limited to those of the Occupational Safety and Health Administration, the National Electrical Safety Code and those developed or accepted by Transmission Provider and Local Distribution Company for use on their respective systems) when entering or working in the other Party’s property or facilities or switching area. A Party performing work within the boundaries of the other Party’s facilities must abide by the safety rules applicable to the site.

12.2 Each Party shall be solely responsible for the safety and supervision of its own employees, agents, representatives, and subcontractors.

12.3 Transmission Provider shall immediately report any injuries that occur while working on the Local Distribution Company’s property or facilities or switching area to appropriate agencies and the Local Distribution Company’s Site Representative. Local Distribution Company shall immediately report any injuries that occur while working on the Transmission Provider’s property or facilities or switching area to appropriate agencies and the Transmission Provider’s Site Representative. Each Party will provide the other with its clearing/tagging/lockout procedures. For clearances requested or initiated by the Local Distribution Company on the Local Distribution Company’s equipment that utilizes the Transmission Provider’s equipment as an isolation device, Local Distribution Company procedures shall govern. For clearances requested or initiated by the Transmission Provider on the Transmission Provider’s’ equipment that utilizes the Local Distribution Company’s equipment as an isolation device, Transmission Provider procedures shall govern. Under no circumstances shall either Party remove the other Party’s protective tags without proper authorization.

ARTICLE 13. Environmental Compliance and Procedures

13.1 Release Prevention and Response. Each Party shall notify the other Party, verbally within 24 hours upon discovery of any Release of any Regulated Substance caused by the Party’s operations or equipment that impacts the property or facilities of the other Party, or which may migrate to, or adversely impact the property, facilities or operations of the other Party and shall promptly furnish to the other Party copies of any reports filed with any governmental agencies addressing such events. Such verbal notification shall be followed by written notification within five (5) days. The Party responsible for the Release of any Regulated Substance on the property or facilities of the other Party, or which may migrate to, or adversely impact the property, facilities or operations of the other Party shall be responsible for: (1) the cost and completion of reasonable remediation or abatement activity for that Release, and; (2) required notifications to governmental agencies and submitting of all reports or filings required by environmental laws for that Release. Advance written notification (except in Emergency situations, in which verbal, followed by written notification, shall be provided as soon as practicable) shall be provided to the other Party by the Party responsible for any remediation or abatement activity on the property or facilities of the other Party, or which may adversely impact the property, facilities, or operations of the other Party. Except in Emergency situations such remediation or abatement

activity shall be performed only with the consent of the Party owning the affected property or facilities.

13.2 The Parties agree to coordinate, to the extent necessary, the preparation of site plans, reports, environmental permits, clearances and notifications required by federal and state law or regulation, including but not limited to Spill Prevention, Control and Countermeasures (SPCC), Storm Water Pollution Prevention Plans (SWPP), Act 451 Part 31 Part 5 Rules, CERCLA, EPCRA, TSCA, soil erosion and sedimentation control plans (SESC) or activities, wetland or other water-related permits, threatened or endangered species reviews or management and archeological clearances or notifications required by any regulatory agency or competent jurisdiction. Notification of permits applied for and/or received will occur in a timeframe manner suitable to the interests of both Parties.

ARTICLE 14. Billings and Payment

14.1 Any invoices payable under this Agreement shall be provided to the other Party under this Agreement during the preceding month. Invoices 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 within twenty (20) days of the invoice date, 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 the other Party, or by wire transfer to a bank of the Party being paid, provided that payments expressly required by this Agreement to be mailed shall be mailed in accordance with Section 14.2.

14.2 Any payments required to be made by Local Distribution Company under this Agreement shall be made to Transmission Provider at the following address:

Michigan Electric Transmission Company, LLC
P.O. Box 673971 Detroit,
MI 48267-3971

Any payments required to be made by Transmission Provider under this Agreement shall be made to Local Distribution Company at the following address:

Consumers Energy Company
One Energy Plaza
Jackson, MI 49201
Attention: Treasurer

14.3 The rate of interest on any amount not paid when due shall be equal to the Interest Rate in effect at the time such amount became due. Interest on delinquent amounts shall be calculated from the due date of the invoice to the date of the payment. When payments are made by mail, invoices shall be considered as having been paid on the date of receipt by the other Party. Nothing contained in this article is intended to limit either Party’s remedies under Article 21 of this Agreement.

14.4 Payment of an invoice shall not relieve the paying Party from any responsibilities or obligations it has under this Agreement, nor shall such payment constitute a waiver of any claims arising hereunder.

14.5 If all or part of any bill is disputed by a Party, that Party shall promptly pay the amount that is not disputed and provide the other Party a reasonably detailed written explanation of the basis for the dispute pursuant to Article 26. 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 at the Interest Rate through the date on which payment is made, within ten (10) business days of such resolution.

14.6 Subject to the Confidentiality provisions of Article 20, within two (2) years following a calendar year, during normal business hours, Local Distribution Company and Transmission Provider shall have the right to audit each other’s accounts and records pertaining to transactions under this Agreement that occurred during such calendar year at the offices where such accounts and records are maintained; provided that the audit shall be limited to those portions of such accounts and records that reasonably relate to the services provided to the other Party under this Agreement for said calendar year. The Party being audited shall be entitled to review the audit report and any supporting materials. To the extent that audited information includes Confidential Information, the auditing Party shall keep all such information confidential pursuant to Article 20.

14.7 Neither Party shall be responsible for the other Party’s costs of collecting amounts due under this Agreement, including attorney fees and expenses and the expenses of arbitration.

ARTICLE 15. Applicable Regulations and Interpretation

15.1

Each Party’s performance under this Agreement is subject to the condition that all requisite governmental and regulatory approvals for such performance are obtained in form and substance satisfactory to the other Party in its reasonable judgment. Each Party shall exercise Due Diligence and shall act in good faith to secure all appropriate approvals in a timely fashion.

15.2

This Agreement and all rights, obligations, and performances of the Parties hereunder, are subject to present or future state or federal laws, regulations, or orders properly issued by state or federal bodies having jurisdiction. When not in conflict with or pre-empted by Federal law, this Agreement shall be interpreted pursuant to the laws of the State of Michigan, exclusive of its conflicts of law principles.

ARTICLE 16. Force Majeure

16.1	An 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 equipment, 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.
16.2	If 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 Transmission Provider’s and Local Distribution Company’s obligation under Section 16.3 of this Agreement to provide protection 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.
16.3	Any Party’s obligation to make payments already owing shall not be suspended by Force Majeure.

ARTICLE 17. Indemnification And Limitation on Liability

17.1

Each Party shall at all times assume all liability for, and shall indemnify and save the other Party 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 facilities or facilities controlled by it, unless caused by the sole negligence, or intentional wrongdoing, of the other Party.

17.2

EXCEPT AS SET FORTH IN SECTION 8.3, NEITHER PARTY SHALL BE LIABLE TO THE OTHER FOR ANY SPECIAL, INCIDENTAL, EXEMPLARY, PUNITITIVE 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 18. Insurance

18.1 The 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.

2. A Party may, at its option, [A] be an approved self-insurer by the State of Michigan 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.

3. Within 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 Party 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 19. Several Obligations

19. Except where specifically stated in this Agreement to be otherwise, the duties, obligations and liabilities of the Parties are intended to be several and not joint or collective. Nothing contained in this Agreement shall ever be construed to create an association, trust, partnership, or joint venture or to impose a trust or partnership duty, obligation or liability or agency relationship on or with regard to either Party. Each Party shall be individually and severally liable for its own obligations under this Agreement.

ARTICLE 20. Confidentiality

20.1(a) “Confidential Information” shall mean any confidential, proprietary or trade secret information of a plan, specification, pattern, procedure, design, device, list concept, policy or compilation relating to the present or planned business of a Party, which is designated in good faith as Confidential by the Party supplying the information, whether conveyed orally, electronically, in writing, through inspection or otherwise. Confidential Information shall include, without limitation, all information relating to a Party’s technology, research and development, business affairs, and pricing, customer-specific load data that constitutes a trade secret, and any information supplied by either of the Parties to the other prior to the execution of this Agreement.

(b)	General. Each Party will hold in confidence any and all Confidential Information unless (1) compelled to disclose such information by judicial or administrative process or other provisions of law or as otherwise provided for in this Agreement, or (2) to meet obligations imposed by FERC or by a state or other federal entity or by membership in NERC or ECAR (including other Transmission Providers). Information required to be disclosed under (b)(1) or (b)(2) above, does not, by itself, cause any information provided by Local Distribution Company to Transmission Provider to lose its confidentiality. To the extent it is necessary for either Party to release or disclose such information to a third party in order to perform that Party’s obligations herein, such Party shall advise said third party of the confidentiality provisions of this Agreement and use its best efforts to require said third party to agree in writing to comply with such provisions. Transmission Provider will develop and file with FERC standards of conduct relating to the sharing of a market-related Confidential Information with and by Transmission Provider employees.
(c)	Term: During the term of this Agreement, and for a period of three (3) years after the expiration or termination of this Agreement, except as otherwise provided in this Article 20, each Party shall hold in confidence and shall not disclose to any Person Confidential Information.
(a)	Standard of Care: Each Party shall use at least the same standard of care to protect Confidential Information it receives as that it uses to protect its own Confidential Information from unauthorized disclosure, publication or dissemination.

20.2 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 disclosure by the receiving Party (2) was in the lawful possession of the receiving Party on a non-confidential basis prior to receiving it from the disclosing Party; or (3) was supplied to the receiving Party without restriction by a third 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 Agreement; or (6) is required, in accordance with Section 20.1(b) of this Agreement, to be disclosed by any federal or state government or agency or is otherwise required to be disclosed by law or subpoena, or is necessary in any legal proceeding establishing rights and obligations under this Agreement. Information designated as

	Confidential Information will no longer be deemed confidential if the Party that designated the information as confidential notifies the other Party that it no longer is confidential.
20.3	Order of Disclosure. If a court or a government agency or entity with the right power, and apparent authority to do so requests or requires either Party, by subpoena, oral deposition, interrogatories, requests for production of documents, administrative order, or otherwise, to disclose Confidential Information, that Party shall provide the other Party with prompt notice of such request(s) or requirement(s) so that the other Party may seek an appropriate protective order or waive compliance with the terms of this Agreement. The notifying Party shall have no obligation to oppose or object to any attempt to obtain such production except to the extent requested to do so by the disclosing Party and at the disclosing Party’s expense. If either Party desires to object or oppose such production, it must do so at its own expense. The disclosing Party may request a protective order to prevent any Confidential Information from being made public. 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 effort to obtain reliable assurance that confidential treatment will be accorded any Confidential Information so furnished.
20.4	Use of Information or Documentation. Each Party may utilize information or documentation furnished by the disclosing Party and subject to Section 20.1 in any proceeding under Article 26 or in an administrative agency or court of competent jurisdiction addressing any dispute arising under this Agreement, subject to a confidentiality agreement with all participants (including, if applicable, any arbitrator) or a protective order.
20.5	Remedies Regarding Confidentiality. The Parties agree that monetary damages by themselves will be inadequate to compensate a Party for the other Party’s breach of its obligations under this article. Each Party accordingly agrees that the other Party is entitled to equitable relief, by way of injunction or otherwise, if it breaches or threatens to breach its obligations under this article.

ARTICLE 21. Breach, Default and Remedies

21.1 General. A breach of this Agreement (“Breach”) shall occur upon the failure by a Party to perform or observe a material term or condition of this Agreement. A 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 Section 21.4.
21.2	Events of Breach. A Breach of this Agreement shall include:

(a)	The failure to pay any amount when due;
(b)	The 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;
(c)	A Party’s abandonment of its work or the facilities contemplated in this Agreement;
(d)	If a Party: (1) becomes insolvent; (2) 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; (3) makes a general assignment for the benefit of its creditors; or (4) consents to the appointment of a receiver, trustee or liquidator;
(e)	Failure of either Party to provide information or data to the other Party 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.

21.3

Continued Operation. Except as specifically provided in this Agreement, in the event of a Breach or Default by either Party, the Parties shall continue to operate and maintain, as applicable, facilities and appurtenances that are reasonably necessary for the Transmission Provider to operate and maintain the Transmission System, or the Local Distribution Company to operate and maintain the Distribution System, in a safe and reliable manner.

21.4

Cure and Default. Upon the occurrence of an event of Breach, 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 a Party to this Agreement identifies in writing to the other Party 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. In the event of a Default, the non-Defaulting Party has the right to take whatever action at law or equity as may be permitted under this Agreement.

21.5

Right to Compel Performance. Notwithstanding the foregoing, upon the occurrence of an event of Default, the non-Defaulting Party shall be entitled to 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 exercise such other rights and remedies as it may have in equity or at law.

ARTICLE 22. Term

22.1	Term. This Agreement shall become effective as of the Effective Date and shall continue in full force and effect so long as any Interconnection Point is connected to the Transmission System, except that it may be terminated by mutual agreement of the Parties.
22.2	Material Adverse Change.

(a) In the event of a material change in law or regulation that adversely affects, or may reasonably be expected to adversely affect, either Party’s performance under this Agreement, including but not limited to the following:

(i)	this Agreement is not accepted for filing by the FERC without material modification or condition;
(ii)	NERC or ECAR prevents, in whole or in part, either Party from performing any provision of this Agreement in accordance with its terms; or
(iii)	The FERC, the United States Congress, any state, or any federal or state regulatory agency or commission implements any change in any law, regulation, rule or practice which materially affects or is reasonably expected to materially affect either Party’s ability to perform under this Agreement.

The Parties will negotiate in good faith any amendment or amendments to the Agreement necessary to adapt the terms of this Agreement to such change in law or regulation, and the

Transmission Provider shall file such amendment or amendments with FERC.

(b)

If the Parties are unable to reach agreement on any such amendments, then the Parties shall continue to perform under this Agreement to the maximum extent possible, taking all reasonable steps to mitigate any adverse effect on each other resulting from the Event. If the Parties are unable to reach agreement on any such amendments, Transmission Provider shall have the right to make a unilateral filing with FERC to modify this Agreement pursuant to Section 205 of the Federal Power Act and Local Distribution Company shall have the right to make a unilateral filing with FERC to modify this Agreement pursuant to Section 206 of the Federal Power Act. Each Party shall have the right to protest any such filing by the other Party and to participate fully in any proceeding before FERC.

22.3 Survival. 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 23. Assignment/Change in Corporate Identity

23.1

Transmission Provider Assignment Rights. Transmission Provider may not assign this Agreement or any of its rights, interests, or obligations hereunder without the prior written consent of Local Distribution Company, which consent shall not be unreasonably withheld; provided however, that Transmission Provider may assign this Agreement or any of its rights or obligations hereunder without the prior consent of Local Distribution Company and may assign this Agreement to any entity(ies) in connection with a merger, consolidation, or reorganization, provided that the surviving entity(ies) or assignee owns the Transmission System, agrees in writing to be bound by all the obligations and duties of Transmission Provider provided for in this Agreement and the assignee’s creditworthiness is equal to or higher than that of Transmission Provider.

23.2

Local Distribution Company Assignment Rights. Local Distribution Company may not assign this Agreement or any of its rights, interests or obligations hereunder without the prior written consent of Transmission Provider, which consent shall not be unreasonably withheld; provided however, that Local Distribution Company may, without the consent of Transmission Provider, and by providing prior reasonable notice under the

	circumstances to Transmission Provider, assign, this Agreement to any entity(ies) in connection with a merger, consolidation, or reorganization, provided that the surviving entity(ies) or assignee owns the Local Distribution Company, agrees in writing to be bound by all the obligations and duties of Local Distribution Company provided for in this Agreement and the assignee’s creditworthiness is equal to or higher than that of Local Distribution Company.
23.3	Assigning Party to Remain Responsible. Any assignments authorized as provided for in this article will not operate to relieve the Party assigning this Agreement or any of its rights, interests or obligations hereunder of the responsibility of full compliance with the requirements of this Agreement unless (a) the other Party consents, such consent not to be unreasonably withheld, and (b) the assignee agrees in writing to be bound by all of the obligations and duties of the assigning Party provided for in this Agreement.
23.4	This Agreement and all of the provisions hereof are binding upon, and inure to the benefit of, the Parties and their respective successors and permitted assigns.

ARTICLE 24. Subcontractors

24.1	Nothing in this Agreement shall prevent the Parties from utilizing the services of subcontractors as they deem appropriate; provided, however, the Parties agree that, where applicable, all said subcontractors shall comply with the terms and conditions of this Agreement.
24.2	Except as provided herein, the creation of any subcontract relationship shall not relieve the hiring Party of any of its obligations under this Agreement. Each Party shall be fully responsible to the other Party for the acts and/or omissions of any subcontractor it hires as if no subcontract had been made. Any obligation imposed by this Agreement upon the Parties, where applicable, shall be equally binding upon and shall be construed as having application to any subcontractor.
24.3	No subcontractor is intended to be or shall be deemed a third-party beneficiary of this Agreement.
24.4	The obligations under this Article 26 shall not be limited in any way by any limitation on subcontractor’s insurance.
24.5	Each Party shall require its subcontractors to comply with all federal and state laws regarding insurance requirements and shall maintain standard and ordinary insurance coverages.

ARTICLE 25. Dispute Resolution

Any dispute between the parties arising out of or relating to this Contract or the breach thereof shall be brought to the Administrative Committee. If the Administrative Committee can resolve the dispute, such resolution shall be reported in writing to and shall be binding upon the Parties. If the Administrative Committee cannot resolve the dispute within a reasonable time, the senior officer of Local Distribution Company or the senior officer of Transmission Provider may, by written notice to the senior officer of the other Party and the members of the Administrative Committee, withdraw the matter from consideration by the Administrative Committee and submit the same for resolution to the senior officers of the Parties. If the senior officers of the Parties agree to a resolution of the matter, such resolution shall be reported in writing to, and shall be binding upon, the Parties; but if said senior officers fail to resolve the matter within five (5) Business Days after its submission to them, then the Parties agree to try in good faith to settle the dispute by mediation administered by the American Arbitration Association under its Commercial Mediation Rules before resorting to litigation.

ARTICLE 26. Miscellaneous Provisions

26.1	This Agreement shall constitute the entire Agreement between the Parties hereto relating to the subject matter hereof. In all other respects, special contracts or superseding rate schedules shall govern Transmission Provider’s transmission service to Local Distribution Company.
26.2	No failure or delay on the part of Transmission Provider or Local Distribution Company in exercising any of its rights under this Agreement, no partial exercise by either Party of any of its rights under this Agreement, and no course of dealing between the Parties shall constitute a waiver of the rights of either Party under this Agreement. Any waiver shall be effective only by a written instrument signed by the Party granting such waiver, and such shall not operate as a waiver of, or estoppel with respect to, any subsequent failure to comply therewith.
26.3	Nothing in this Agreement, express or implied, is intended to confer on any other Person except the Parties hereto any rights, interests, obligations or remedies hereunder.
26.4	In the event that any clause or provision of this Agreement or any part hereof shall be held to be invalid, void, or unenforceable by any court or Governmental Authority of competent jurisdiction, said holding or action shall be strictly construed and shall not affect the validity or effect of any other provision hereof, and the Parties shall endeavor in good faith to

	replace such invalid or unenforceable provisions with a valid and enforceable provision which achieves the purposes intended by the Parties to the greatest extent permitted by law.
26.5	The article and section headings herein are inserted for convenience only and are not to be construed as part of the terms hereof or used in the interpretation of this Agreement.
26.6	In the event an ambiguity or question of intent or interpretation arises, this Agreement shall be construed as if drafted jointly by the Parties and no presumption or burden of proof shall arise favoring or disfavoring any Party by virtue of authorship of any of the provisions of this Agreement. Any reference to any federal, state, local, or foreign statute or law shall be deemed also to refer to all rules and regulations promulgated thereunder, unless the context requires otherwise. The word “including” in this Agreement shall mean including without limitation.
26.7	This Agreement may be executed in one or more counterparts, each of which shall be deemed an original.
26.8	Each Party shall act as an independent contractor with respect to the provision of services hereunder.

IN WITNESS WHEREOF, Transmission Provider and Local Distribution Company have caused this instrument to be executed by their duly authorized representatives as of the day and year first above written.

CONSUMERS ENERGY COMPANY
By:	/s/ Richard J. Ford
	Name:	Richard J. Ford
	Title:	VP - Energy Delivery	APVD AS TO FORM
MICHIGAN ELECTRIC TRANSMISSION COMPANY, LLC
By:	/s/ Daniel J. Oginsky
	Name:	Daniel J. Oginsky
	Title:	Secretary

EXHIBIT 1 — Interconnection Points (Substations) Addendum 5, Final 06/10/10

Substation

1	Abbe
2	Acme (CWIP)
3	Alcona
4	Alder Creek
5	Alger
6	Algoma
7	Alma
8	Almeda
9	Alpena
10	Alpine
11	Amber
12	American Bumper
13	Arthur (6/06)
14	Aubil Lake
15	Backus
16	Bagley
17	Bangor
18	Baraga (12/07)
19	Bard Road
20	Barnum Creek
21	Barry
22	Bass Creek
23	Batavia
24	Bay Road
25	Bayberry
26	Beals Road
27	Becker
28	Beecher
29	Begole
30	Bell Road
31	Bennington
32	Beveridge
33	Bilmar
34	Bingham
35	Black River
36	Blackman
37	Blackstone
38	Blinton
39	Blue Water
40	Bluegrass
41	Boardman

42	Boxboard
43	Bricker
44	Brickyard
45	Briggs & Stratton
46	Broadmoor
47	Bronco
48	Broughwell
49	Buck Creek
50	Buick Stewart
51	Bullock
52	Busch Road (02/08)
53	Calhoun
54	Camelot Lake
55	Campbell 138
56	Canal
57	Cannon
58	Carpenter Rd (8/06)
59	Carter
60	Cedar Springs
61	Cement City
62	Chase
63	Cheesman
64	Chicago
65	Churchill
66	Clare
67	Claremont
68	Clearwater
69	Cleveland
70	Club
71	Cobb
72	Cochran
73	Cole Creek
74	Colony Farm
75	Convis
76	Cork Street
77	Cornell
78	Cottage Grove
79	Covert
80	Cowan Lake
81	Crahen (10/07)
82	Croton
83	David
84	Dean Road
85	Deja
86	Delaney
87	Delhi

88	Denso Jackson
89	Derby
90	Dorr Corners
91	Dort
92	Dow Corning
93	Dowling
94	Drake Road
95	Duffield Rd
96	Dupont
97	Duquite
98	Dutton
99	East Paris
100	East Tawas
101	Easton
102	Edenville
103	Ellis
104	Emmet
105	Englishville
106	Eureka
107	Farr Road
108	Felch Road
109	Filer City
110	Fillmore
111	Forty Fourth Street
112	Foundry
113	Four Mile
114	Gaines (5/06)
115	Gallagher
116	Garfield
117	Gaylord
118	Geddes (04/08)
119	Gleaner
120	Grand Blanc BOC
121	Gray Road (CWIP)
122	Greenwood
123	Grey Iron
124	Grodi Road
125	Grout
126	Hackett
127	Hagadorn
128	Hager Park
129	Halsey
130	Haring
131	Harvard Lake (06/09)
132	Hazelwood
133	Hemphill

134	Hendershot
135	Higgins
136	Hillman Cogen
137	Hodenpyl
138	Holland Road
139	Hotchkiss
140	HSC
141	Hubbard Lake (12/07)
142	Hubbardston Road (CWIP)
143	Hudsonville
144	Hughes Road
145	Hull Street
146	Iosco
147	Island Road
148	Jamestown
149	Karn 138
150	Kentwood
151	Keystone
152	Kinderhook (05/07)
153	Kipp Road
154	Kraft
155	Lafayette
156	Laundra (05/07)
157	Lawndale
158	Layton
159	Leoni
160	Letts Road
161	Lewiston
162	Lindbergh
163	Livingston Peaker
164	Lovejoy
165	Ludington
166	Malleable (decomm 10/07)
167	Manlius
168	Marquette
169	McGulpin
170	MCV
171	Meadowbrooke
172	Mecosta
173	Michigan
174	Michigan Power (MPLP)
175	Milham
176	Mio
177	Monitor
178	Moore Road
179	Morrow

180	Mullins
181	Neff Road
182	Nineteen Mile Road
183	North Belding
184	North Corunna
185	Northern Fibre
186	Nugent Sand
187	Oakland
188	Oceana
189	Orr Road (07/09)
190	Packard
191	Palisades
192	Parr Road
193	Parshallville
194	Pasadena
195	Pavilion
196	Pettis Road
197	Pigeon River/Rondo
198	Pingree (10/08)
199	Piston Ring
200	Plaster Creek
201	Plymouth Street
202	Plum (CWIP)
203	Plywood
204	Port Calcite
205	Port Sheldon
206	Porter
207	Portsmouth
208	Price Road (09/07)
209	Progress Street
210	Race Street
211	Raisin
212	Ransom
213	Renaissance
214	Rice Creek
215	Riggsville
216	Rivertown
217	Riverview
218	Rockport/Presque Isle
219	Roedel Road
220	Rogue River (06/07)
221	Saginaw River
222	Samaria
223	Sanderson
224	Savidge
225	Scott Lake

226	Seamless East/Seamless
227	Solar (CWIP)
228	Sonoma (5/06)
229	Spaulding
230	Spruce Road
231	Stacey
232	Stamping Plant
233	Steelcase
234	Stonegate
235	Stover
236	Stronach
237	Summerton
238	Thetford 138
239	Tihart
240	Tinsman
241	Tippy
242	Titus Lake
243	Trillium (06/07)
244	Trowbridge
245	Twelfth Street
246	Twilight
247	Twining
248	Upjohn
249	Van Atta
250	Van Buren (06/08)
251	Vanderbilt
252	Vernon
253	Verona
254	Vevay
255	Viking Lincoln
256	Vrooman
257	Wackerly
258	Warner
259	Warren
260	Washtenaw
261	Wayland
262	Weadock
263	Wealthy Street
264	West Fenton (05/07)
265	Wexford
266	White Lake
267	White Road
268	Whiting
269	Whittemore
270	Willard
271	Withey Lake (5/06)
272	Zeeland

EXHIBIT 2 — Contact Information For Local Distribution Company’s Representatives and Transmission

Provider’s Representatives

Local Distribution Company

Consumers Energy Company
4000 Clay Ave SW, PO Box 201
Grand Rapids, MI 49501-0201

Attn: Executive Manager of System Planning and Control

Transmission Provider

Michigan Electric Transmission Company, LLC:
27175 Energy Way
Novi, MI 48377

Attn:   Legal Department — Contracts

EXHIBIT 3

SPECIAL MANUFACTURING CONTRACTS INFLUENCED BY TRANSMISSON SYSTEM

		PAYMENT PER DISRUPTION EVENT
CUSTOMER	SUBSTATION	INTERRUPTION		VOLTAGE SAG
GM	BUICK STEWART	$	150,000	NOT APPLICABLE
	MALLEABLE	$	150,000	NOT APPLICABLE
	FLORENCE ST.	$	150,000	NOT APPLICABLE
	GRAND BLANC BOC	$	100,000	NOT APPLICABLE
	GREY IRON	$	150,000	NOT APPLICABLE
	STAMPING PLANT	$	100,000	NOT APPLICABLE
DELPHI	HOLLAND RD.	$	150,000	NOT APPLICABLE

NOTES FOR GM & DELPHI:

1.	NO PAYMENTS FOR VOLTAGE SAGS.
2.	CUMULATIVE ANNUAL PAYMENT IS CAPPED AT $3,000,000.
3.	INITIAL TERM OF GM AND DELPHI CONTRACTS EXPIRE IN 2005.
4.	CONTRACTS MAY BE EXTENDED TO 2010 BY MUTUAL AGREEMENT.

								EVENT #
DOW CORNING	CARTER	$	(15,000	)	$	(15,000	)	no events
		$	15,000			0		1st /yr
		$	15,000		$	15,000		2nd/yr
		$	55,000		NOT APPLICABLE			3rd/yr
DOW CORNING	DOW CORNING	$	(25,000	)	$	(25,000	)	no events
		$	25,000			0		1st /yr
		$	35,000		$	25,000		2nd/yr
		$	105,000		NOT APPLICABLE			3rd/yr
HEMLOCK	HSC	$	(40,000	)	$	(20,000	)	no events
SEMICONDUCTOR		$	40,000			0		1st /yr
		$	60,000		$	20,000		2nd/yr
		$	150,000		NOT APPLICABLE			3rd/yr
HEMLOCK	SILICON	NOT APPLICABLE			$	(15,000	)	no events
SEMICONDUCTOR		NOT APPLICABLE				0		1st /yr
		NOT APPLICABLE				0		2nd/yr
		NOT APPLICABLE				0		3rd/yr
		NOT APPLICABLE			$	15,000		4th/yr

NOTES FOR DOW CORNING & HEMLOCK SEMICONDUCTOR:

1.	IF NO EVENTS IN A YEAR, PAYMENT IS MADE TO CONSUMERS.
2.	MAXIMUM # OF PAYABLE EVENTS/YR IS 3 FOR INTERRUPTIONS & 1 FOR SAGS.
3.	WEATHER RELATED EVENTS ARE NOT PAYABLE.

EXHIBIT 4 — Metering Specifications

Performance criteria:

1.	Meters shall meet or exceed the latest version of ANSI C12.16 (Standard for Solid State Electricity Meters) specifications for solid state metering.
2.	Current transformers used for metering shall meet or exceed an accuracy class of 0.3%. Secondary connected burdens shall not exceed rated burden of any current transformer. Current transformers shall comply with most current applicable ANSI Standards including C57.13 (IEEE Standard Requirements for Instrument Transformers) and C12.11 (Instrument Transformers for Revenue Metering 10 kV BIL through 350 kV BIL). Meter installations shall comply with manufacturer’s accuracy and burden class information on the nameplate of each device.
3.	Voltage transformers used for metering shall meet or exceed an accuracy class of 0.3%. Secondary connected burdens shall not exceed rated burden of any voltage transformer. Voltage transformers shall comply with most current applicable ANSI Standards including C57.13 (IEEE Standard Requirements for Instrument Transformers), and C12.11 (Instrument Transformers for Revenue Metering 10 kV BIL through 350 kV BIL). Meter installations shall comply with manufacturer’s accuracy and burden class information on the nameplate of each device.
4.	PT secondary circuits shall have a disconnect switch installed which provides a visible air gap for worker safety, and which allows for attachment of a protective safety tag.

EXHIBIT 5

For ownership changes since August 7, 2007, refer to the drawings in each Party’s Drawing Management System (DMS), as discussed in Section 3.2 of this Agreement.

The WDs of the following substations have been revised since the last update (Addendum 2):

Consumers Energy (CE)	Michigan Electric Transmission Company (METC)
Alma	HSC
Bard Road
Beals Road
Beecher
Black River
Bullock
Claremont
Cobb
Cornell
Croton
Delhi
Dort
Felch Road
Four Mile
Hemphill
Lawndale
Milham
North Belding
Rice Creek
Riggsville
Riverview
Saginaw River
Spaulding
Stover
Verona
Weadock
Wealthy Street
Wexford
Whiting

EXHIBIT 6 - Jointly Owned Assets Ownership by Percent of Major Equipment Addendum 5 — Final 06/10/10

Substations
Jointly Owned Assets
Percentage Split by Major Equipment Count

					Generation
					Owned by
					Local				Last
					Distribution		Third-Party		Revision
Substation Name	Distribution		Transmission		Company		Assets		Date
Alma		66.67		33.33						10/24/03
Bard Road		41.67		58.33						06/10/10
Batavia		63.64		36.36						10/24/03
Beals Road		84.62		15.38						06/10/10
Beecher		82.05		17.95						07/23/04
Bingham		91.67		8.33						06/10/10
Black River1		68.00		24.00				8.00		06/10/10
Blackstone		72.00		28.00						06/10/10
Bullock		76.00		24.00						11/20/08
Claremont		68.00		32.00						05/01/02
Cobb Plant		47.22		25.00		27.78				05/01/02
Cornell		68.42		31.58						06/10/10

Changes, relative to previous revisions (addendums), are shown in bold type.
1	At 120kV and above, third-party related assets will be included as part of the Transmission Provider’s assets for purposes of making this calculation. Also, the third-party may share in the financial responsibility associated with O&M activities.

					Generation
					Owned by
					Local			Last
					Distribution		Third-Party	Revision
Substation Name	Distribution		Transmission		Company		Assets	Date
Croton		54.54		31.82		13.64			06/10/10
Delhi		61.90		38.10					10/24/03
Dort22		69.57		30.43					06/10/10
Emmet		92.31		7.69					05/01/02
Eureka		88.89		11.11					06/10/10
Felch Road		83.33		16.67					03/31/06
Four Mile		73.33		26.67					03/16/06
Gaylord		44.44		44.44		11.12			11/20/08
Halsey		76.92		23.08					10/24/03
Hemphill		65.52		34.48					06/10/10
HSC		40.00		60.00					06/10/10
Iosco		83.33		16.67					05/30/07
Lawndale		82.35		17.65					05/01/02
Marquette		75.00		25.00					05/01/02

Changes, relative to previous revisions (addendums), are shown in bold type.
2	Third-party may share in the financial responsibility associated with O&M activities.

					Generation
					Owned by
					Local				Last
					Distribution		Third-Party		Revision
Substation Name	Distribution		Transmission		Company		Assets		Date
McGulpin3		60.00		40.00						06/10/10
Mecosta		87.50		12.50						06/10/10
Milham		75.00		25.00						06/10/10
Moore Road43		64.65		10.00				25.35		08/07/07
Morrow1,2		66.67		23.33		6.67		3.33		11/20/08
North Belding		66.67		33.33						10/24/03
Oakland		87.50		12.50						10/24/03
Ransom		88.89		11.11						01/05/05
Rice Creek		92.86		7.14						10/24/03
Riggsville		75.00		25.00						11/20/08
Riverview		93.75		6.25						10/24/03
Saginaw River		57.89		42.11						11/20/08
Spaulding		60.00		40.00						03/31/06
Stover		85.71		14.29						11/20/08

Changes, relative to previous revisions (addendums), are shown in bold type.
3	At 120kV and above, third-party related assets will be included as part of the Transmission Provider’s assets for purposes of making this calculation. Also, the third-party may share in the financial responsibility associated with O&M activities.
2	Third-party may share in the financial responsibility associated with O&M activities.
3	Below 120kV the third-party related assets will be included as part of the Local Distribution Company’s assets for purposes of making this calculation. Also, the third-party may share in the financial responsibility associated with O&M activities.

					Generation
					Owned by
					Local			Last
					Distribution		Third-Party	Revision
Substation Name	Distribution		Transmission		Company		Assets	Date
Stronach52		66.67		33.33					05/24/04
Tihart		73.33		26.67					01/31/05
Tippy		33.33		66.67					11/13/02
Twining		76.92		23.08					05/01/02
Verona		60.87		39.13					03/31/06
Weadock		35.14		24.32		40.54			03/16/06
Wealthy Street		86.11		13.89					03/16/06
Wexford		93.75		6.25					06/10/10
White Lake		81.25		18.75					10/24/03
Whiting		31.58		31.58		36.84			08/07/07

Changes, relative to previous revisions (addendums), are shown in bold type.
2	Third-party may share in the financial responsibility associated with O&M activities.

EX-10.92

Exhibit 10.92

Midwest ISO	Fourth Revised Service Agreement No. 1756
FERC Electric Tariff, Fourth Revised Volume No. 1	Superseding Third 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

Issued by: Steven G. Kozey, Issuing Officer	Effective: April 22, 2010
Issued on: April 21, 2010

Original Sheet No. 1

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.

Original Sheet No. 2

Amended and Restated
GENERATOR INTERCONNECTION AGREEMENT
by and among
Michigan Electric Transmission Company, LLC,
Consumers Energy Company
and the
Midwest Independent Transmission System Operator, Inc.

ARTICLE 1 - DEFINITIONS	6
ARTICLE 2 - TERM OF AGREEMENT	10
2.1 Effective Date	10
2.2 Term	10
2.3 Termination	10
2.4 Regulatory Filing	10
2.5 Survival	10
ARTICLE 3 - INTERCONNECTION SERVICE	11
3.1 Scope of Service	11
3.2 Third-Party Actions	12
ARTICLE 4 - INTERCONNECTION ASSETS	12
4.1 Reservation of Rights to Interconnection Assets	12
4.2 Modifications	12
4.3 As-Built Drawings	12
ARTICLE 5 - OPERATIONS	13
5.1 General	13
5.2 Transmission Provider and Transmission Owner Obligations	13
5.3 Consumers Obligations	13
5.4 Jointly Owned Assets	13
5.5 Access Rights	14
5.6 Switching and Tagging Rules	14
5.7 Black Start Participation	14
5.8 Reactive Power	14
5.9 System Security	14
5.10 Consumers Voltage Regulation	15
5.11 Protection and System Quality	15
5.12 Outages, Interruptions, and Disconnection	16
5.13 Operating Expenses	18
ARTICLE 6 - MAINTENANCE	19
6.1 Transmission Owner’s Obligations	19
6.2 Consumers’ Obligations	19
6.3 Jointly Owned Assets	19
6.4 Access Rights	19
6.5 Maintenance Expenses	20
6.6 Coordination	20

Original Sheet No. 3

6.7 Inspections and Testing	20
6.8 Right to Observe Testing	20
6.9 Secondary Systems	20
6.10 Observation of Deficiencies	20
ARTICLE 7 - EMERGENCIES	21
7.1 Obligations	21
7.2 Notice	21
7.3 Immediate Action	21
7.4 Transmission Provider’s and Transmission Owner’s Authority	21
7.5 Consumers’ Authority	22
7.6 Audit Rights	22
ARTICLE 8 - SAFETY	22
8.1 General	22
8.2 Environmental Releases	22
ARTICLE 9 - METERING	22
9.1 General	22
9.2 Costs of Administering Metering Assets	23
9.3 Testing of Metering Assets	23
9.4 Metering Data	23
9.5 Communications	24
ARTICLE 10 - FORCE MAJEURE	24
ARTICLE 11 - INFORMATION REPORTING	25
ARTICLE 12 - PAYMENTS AND BILLING PROCEDURES	25
12.1 Invoices	25
12.2 Payments	25
12.3 Interest Charges	26
12.4 Disputes	26
ARTICLE 13 - ASSIGNMENT	26
ARTICLE 14 - INDEMNITY AND INSURANCE	27
14.1 Indemnity	27
14.2 Insurance	27
ARTICLE 15 - LIMITATION ON LIABILITY	28
ARTICLE 16 - BREACH, CURE AND DEFAULT	28
16.1 General	28
16.2 Events of Breach	28
16.3 Continued Operation	29
16.4 Cure and Default	29
16.5 Right to Compel Performance	30
ARTICLE 17 - CONFIDENTIALITY	30

Original Sheet No. 4

ARTICLE 18 -AUDIT RIGHTS	31
ARTICLE 19 - DISPUTES	31
ARTICLE 20 - NOTICES	31
ARTICLE 21 - MISCELLANEOUS	32
21.1 Amendments	32
21.2 Binding Effect	32
21.3 Counterparts	32
21.4 Entire Agreement	32
21.5 Governing Law	32
21.6 Headings Not To Affect Meaning	33
21.7 Waivers	33
21.8 Termination of Predecessor Interconnection Agreement	33
EXHIBITS
EXHIBIT A Consumers Generation Resources	34
EXHIBIT B Interconnection Assets	37
EXHIBIT B Table 1	38
EXHIBIT C Generator Connections located in Consumers’ Distribution System	65
EXHIBIT C Consumers Energy Generator Connections Covered under Other Interconnection Agreements	65

Original Sheet No. 5

Amended and Restated
GENERATOR INTERCONNECTION AGREEMENT

     THIS Amended AND RESTATED GENERATOR INTERCONNECTION AGREEMENT(the “Agreement”) is made and entered into as of March 18^th, 2010 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 “Midwest ISO” 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 July 24, 2008 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

Original Sheet No. 6

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.

Original Sheet No. 7

     “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.

Original Sheet No. 8

     “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.

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

     “Midwest ISO 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.

Original Sheet No. 9

     “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 the Midwest ISO.

     “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 Midwest ISO Tariff.

     “Transmission Service” shall include both Point-To-Point Transmission Service and Network Integration Transmission Service provided under the Midwest ISO 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

Original Sheet No. 10

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

2.1 Effective Date

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

2.2 Term

     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.

2.3 Termination

     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.

2.4 Regulatory Filing

     Transmission Provider shall file this Agreement with the Commission as a Service Agreement under the Midwest ISO 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.

2.5 Survival

     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.

Original Sheet No. 11

ARTICLE 3
INTERCONNECTION SERVICE

3.1 Scope 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.

     3.1.1 Except 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.

     3.1.2 Except 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.

     3.1.3 Except 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.

     3.1.4 Except 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.

     3.1.5 Transmission 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 Midwest ISO Tariff.

Original Sheet No. 12

3.2 Third-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 Midwest ISO 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 Midwest ISO Tariff.

ARTICLE 4
INTERCONNECTION ASSETS

4.1 Reservation 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.

4.2 Modifications

     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.

4.3 As-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.

Original Sheet No. 13

ARTICLE 5
OPERATIONS

5.1 General

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.

5.3 Consumers 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.

5.4 Jointly 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

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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.

5.5 Access 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.

5.6 Switching 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

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     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.

5.10 Consumers 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.

5.11 Protection 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.

     5.11.1 Requirements 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

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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.

     5.11.2 System 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.

     5.11.3 Inspection. 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.

5.12 Outages, Interruptions, and Disconnection

     5.12.1 Outage 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

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Consumers scheduled maintenance on its Units that may be impacted by maintenance on Transmission Owner’s Interconnection Assets.

     5.12.2 Outage Restoration.

          5.12.2.1 Unplanned 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.

          5.12.2.2 Planned 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.

     5.12.3 Interruption. 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.

     5.12.4 Disconnection.

     5.12.4.1 Disconnection 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.

     5.12.4.2 Disconnection 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

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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.

     5.12.4.3 Disconnection 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.

     5.12.5 Continuity 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.

     5.12.6 Curtailment 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.

5.13 Operating 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

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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

6.1 Transmission 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.

6.2 Consumers’ 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.

6.3 Jointly 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.

6.4 Access 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

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maintenance and/or construction work within the boundaries of the other Party’s assets must abide by the rules applicable to that site.

6.5 Maintenance 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.

6.6 Coordination

     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.

6.7 Inspections 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.

6.8 Right 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.

6.9 Secondary 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.

6.10 Observation of Deficiencies

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     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

7.1 Obligations

     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.

7.2 Notice

     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.

7.3 Immediate 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.

7.4 Transmission 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

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restoration of service. Transmission Provider or Transmission Owner shall use reasonable efforts to minimize the effect of such actions on the Unit.

7.5 Consumers’ 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.

7.6 Audit 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

8.1 General

     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.

8.2 Environmental 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

9.1 General

     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,

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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.

9.2 Costs 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.

9.3 Testing 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.

9.4 Metering Data

     9.4.1 When 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.

     9.4.2 At 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.

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9.5 Communications

     9.5.1 At 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.

     9.5.2 For 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 bidirectional 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

     10.1 An 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.

     10.2 If 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

Original Sheet No. 25

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.

     10.3 Any 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

12.1 Invoices

     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.

12.2 Payments

     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, Ml 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:

Original Sheet No. 26

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.

12.3 Interest 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.

12.4 Disputes

     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

13.1 This 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.

13.2 Notwithstanding 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

Original Sheet No. 27

assigning Transmission Provider or Transmission Owner shall be released and discharged therefrom to the extent provided in the assignment agreement.

13.3 Notwithstanding 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

14.1 Indemnity

     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.

14.2 Insurance

     14.2.1 The 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.

     14.2.2 A 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.

     14.2.3 Within 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

Original Sheet No. 28

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

16.1 General

     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.

16.2 Events of Breach

     A Breach of this Agreement shall include:

     16.2.1 The failure to pay any amount when due;

     16.2.2 The 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;

Original Sheet No. 29

     16.2.3 If 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;

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

     16.2.5 Failure 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

     16.2.6 Failure 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.

16.3 Continued 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.

16.4 Cure 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.

Original Sheet No. 30

16.5 Right 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

17.1 All 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.

     17.1.1 Recipient 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.

     17.1.2 Recipient 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.

     17.1.3 If 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.

Original Sheet No. 31

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 Midwest ISO Tariff shall apply to all disputes arising under this Agreement.

ARTICLE 20
NOTICES

20.1 Any 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, Ml 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

Original Sheet No. 32

20.2 The 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

21.1 Amendments

     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.

21.2 Binding 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.

21.3 Counterparts

     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.

21.4 Entire 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.

21.5 Governing Law

Original Sheet No. 33

     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.

21.6 Headings 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.

21.7 Waivers

     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 July 24, 2008 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	/s/ Daniel J. Oginsky
	Daniel J. Oginsky
Title	Sr. V.P. & General Counsel
CONSUMERS ENERGY COMPANY
By	/s/ James R. Coddington	1-20-2010
	James R. Coddington
Title	V.P. Generation Ops.	APVD AS TO FORM
MIDWEST INDEPENDENT TRANSMISSION SYSTEM OPERATOR, INC.
By	/s/ WILLIAM C. PHILLIPS	9-18-10
	WILLIAM C. PHILLIPS
Title	Vice President
	Standards Compliance & Strategy

EXHIBIT A — CONSUMERS GENERATION RESOURCES Original Sheet No. 34

			Summer		Winter
	Nameplate		Net		Net								AGC		Black
	Rated		Demonstrated		Demonstrated							AGC	Ramp		Start	Synch
Generating Unit	MVA (1)		MW Capability		MW Capability		Kilovolts		RPM		Cooling	Capable	MW/Min		Capable	Breaker(s)		Comments
Campbell 1		312.0		260.0		260.0		16.0		3,600	Hydrogen	Yes		1	No		199
Campbell 2		492.0		355.0		360.0		20.0		3,600	Water/Hydrogen	Yes		1	No		299
Campbell A		21.9		13.0		17.0		13.8		3,600	Air	No		0	Yes		C16
Cobb 1		81.2		61.0		61.0		14.4		3,600	Hydrogen	No		0	No		199	Cobb 1-3 are capable of 68 MW each except that with 3 units running the combined output is boiler limited to 183 MW.
Cobb 2		81.2		61.0		61.0		14.4		3,600	Hydrogen	No		0	No		299	Cobb 1-3 are capable of 68 MW each except that with 3 units running the combined output is boiler limited to 183 MW.
Cobb 3		81.2		61.0		61.0		14.4		3,600	Hydrogen	No		0	No		399	Cobb 1-3 are capable of 68 MW each except that with 3 units running the combined output is boiler limited to 183 MW.
Cobb 4		184.0		158.0		160.0		18.0		3,600	Hydrogen	Yes		1	No		499
Cobb 5		184.0		158.0		160.0		18.0		3,600	Hydrogen	Yes		1	No		599
Gaylord 1		18.8		14.0		17.0		13.8		3,600	Air	No		0	Yes		116
Gaylord 2		18.8		14.0		17.0		13.8		3,600	Air	No		0	Yes		216
Gaylord 3		18.8		14.0		17.0		13.8		3,600	Air	No		0	Yes		316
Gaylord 4		18.8		14.0		17.0		13.8		3,600	Air	No		0	Yes		416
Gaylord 5		21.9		14.0		17.0		13.8		3,600	Air	No		0	No		516
Karn 1		336.0		255.0		255.0		16.0		3,600	Hydrogen	No		0	No		199
Karn 2		320.0		260.0		260.0		16.0		3,600	Hydrogen	No		0	No		299
Karn 3		814.7		638.0		638.0		26.0		3,600	Water/Hydrogen	Yes		6	No		28R8/28H9
Karn 4		835.0		638.0		638.0		26.0		3,600	Water/Hydrogen	Yes		6	No		32F7/32H9
Ludington 1 (gen)		388.0		312.0		312.0		20.0		112.5	Air	Yes		9	No (2)		116	NDC is 312 MW but can operate at 340 MWg (338 MW net) at full pond.
Ludington 2 (gen)		388.0		312.0		312.0		20.0		112.5	Air	Yes		9	Yes		216	NDC is 312 MW but can operate at 340 MWg (338 MW net) at full pond.
Ludington 3 (gen)		388.0		312.0		312.0		20.0		112.5	Air	Yes		9	Yes		316	NDC is 312 MW but can operate at 340 MWg (338 MW net) at full pond.

EXHIBIT A — CONSUMERS GENERATION RESOURCES Original Sheet No. 35

			Summer		Winter
	Nameplate		Net		Net								AGC		Black
	Rated		Demonstrated		Demonstrated							AGC	Ramp		Start	Synch
Generating Unit	MVA(1)		MW Capability		MW Capability		Kilovolts		RPM		Cooling	Capable	MW/Min		Capable	Breaker(s)		Comments
Ludington 4 (gen)		388.0		312.0		312.0		20.0		112.5	Air	Yes		9	No (2)		416	NDC is 312 MW but can operate at 340 MWg (338 MW net) at full pond.
Ludington 5 (gen)		388.0		312.0		312.0		20.0		112.5	Air	Yes		9	Yes		516	NDC is 312 MW but can operate at 340 MWg (338 MW net) at full pond.
Ludington 6 (gen)		388.0		312.0		312.0		20.0		112.5	Air	Yes		9	No (2)		616	NDC is 312 MW but can operate at 340 MWg (338 MW net) at full pond.
Morrow A		20.7		14.0		17.0		13.8		3,600	Air	No		0	Yes		A16
Morrow B		20.7		14.0		17.0		13.8		3,600	Air	No		0	Yes		B16
Straits 1		25.0		16.0		21.0		13.8		3,600	Air	No		0	Yes		S16
Thetford 1		39.5		30.0		37.0		13.8		3,600	Air	No		0	Yes		116
Thetford 2		39.5		29.0		37.0		13.8		3,600	Air	No		0	Yes		216
Thetford 3		39.5		30.0		37.0		13.8		3,600	Air	No		0	Yes		316
Thetford 4		39.5		30.0		37.0		13.8		3,600	Air	No		0	Yes		416
Thetford 5		20.7		15.0		17.0		13.8		3,600	Air	No		0	Yes		516
Thetford 6		20.7		15.0		17.0		13.8		3,600	Air	No		0	Yes		616
Thetford 7		20.7		14.0		17.0		13.8		3,600	Air	No		0	Yes		716
Thetford 8		20.7		15.0		18.0		13.8		3,600	Air	No		0	Yes		816
Thetford 9		20.7		14.0		17.0		13.8		3,600	Air	No		0	Yes		916
Weadock 7		202.0		155.0		155.0		18.0		3,600	Hydrogen	Yes		1	No		799
Weadock 8		184.0		155.0		155.0		18.0		3,600	Hydrogen	Yes		1	No		899
Weadock A		21.9		13.0		17.0		13.8		3,600	Air	No		0	Yes		A16
Whiting 1		125.0		102.0		102.0		14.4		3,600	Hydrogen	Yes		1	No		199
Whiting 2		125.0		102.0		102.0		14.4		3,600	Hydrogen	Yes		1	No		299
Whiting 3		156.3		122.0		124.0		15.5		3,600	Hydrogen	Yes		1	No		399
Whiting A		21.9		13.0		17.0		13.8		3,600	Air	No		0	Yes		46A
Alcona Hydro 1		4.4		4.0		4.0		5.0		90	Air	NA	NA		Yes		116/166
Alcona Hydro 2		4.4		4.0		4.0		5.0		90	Air	NA	NA		Yes		216/166
Calkins Bridge Hydro 1		0.6		0.4		0.4		4.8		180	Air	NA	NA		Yes		116/166	Also known as Allegan Hydro
Calkins Bridge Hydro 2		1.1		0.9		0.9		4.8		120	Air	NA	NA		Yes		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		Yes		116/166
Cooke Hydro 2		3.3		3.0		3.0		2.5		180	Air	NA	NA		Yes		216/166
Cooke Hydro 3		3.3		3.0		3.0		2.5		180	Air	NA	NA		Yes		316/166

EXHIBIT A — CONSUMERS GENERATION RESOURCES Original Sheet No. 36

			Summer		Winter
	Nameplate		Net		Net								AGC	Black
	Rated		Demonstrated		Demonstrated							AGC	Ramp	Start	Synch
Generating Unit	MVA (1)		MW Capability		MW Capability		Kilovolts		RPM		Cooling	Capable	MW/Min	Capable	Breaker(s)		Comments
Croton Hydro 1		3.8		2.9		2.9		7.2		225	Air	NA	NA	Yes		116/246
Croton Hydro 2		3.8		2.9		2.9		7.2		225	Air	NA	NA	Yes		216/246
Croton Hydro 3		1.4		1.3		1.3		7.2		150	Air	NA	NA	Yes		316/246
Croton Hydro 4		1.6		1.3		1.3		7.2		150	Air	NA	NA	Yes		416/246
Five Channels 1		3.3		3.2		3.2		2.5		150	Air	NA	NA	Yes		116/166
Five Channels 2		3.3		3.2		3.2		2.5		150	Air	NA	NA	Yes		216/166
Foote Hydro 1		3.3		3.3		3.3		5.0		90	Air	NA	NA	Yes		116/366
Foote Hydro 2		3.3		3.3		3.3		5.0		90	Air	NA	NA	Yes		216/366
Foote Hydro 3		3.3		3.3		3.3		5.0		90	Air	NA	NA	Yes		316/366
Hodenpyl Hydro 1		8.9		9.2		9.2		7.5		120	Air	NA	NA	Yes		116/266
Hodenpyl Hydro 2		8.9		9.2		9.2		7.5		120	Air	NA	NA	Yes		216/266
Loud Hydro 1		2.2		2.2		2.2		2.5		120	Air	NA	NA	Yes		116/266
Loud Hydro 2		2.2		2.2		2.2		2.5		120	Air	NA	NA	Yes		216/266
Mio Hydro 1		2.7		2.2		2.2		2.5		80	Air	NA	NA	Yes		116/166
Mio Hydro 2		2.7		2.2		2.2		2.5		80	Air	NA	NA	Yes		216/166
Rogers Hydro 1		1.9		1.5		1.5		7.5		150	Air	NA	NA	Yes		116/166
Rogers Hydro 2		1.9		1.5		1.5		7.5		150	Air	NA	NA	Yes		216/166
Rogers Hydro 3		1.9		1.5		1.5		7.5		150	Air	NA	NA	Yes		316/166
Rogers Hydro 4		1.9		1.5		1.5		7.5		150	Air	NA	NA	Yes		416/166
Tippy Hydro 1		7.1		7.0		7.0		7.5		109	Air	NA	NA	Yes		116/266/126
Tippy Hydro 2		7.1		7.0		7.0		7.5		109	Air	NA	NA	Yes		216/266/126
Tippy Hydro 3		7.1		7.0		7.0		7.5		109	Air	NA	NA	Yes		316/266/126
Webber Hydro 1		3.3		2.3		2.3		7.2		164	Air	NA	NA	Yes		116/166
Webber Hydro 2		1.3		1.0		1.0		2.5		200	Air	NA	NA	Yes		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.

Original Sheet No. 37

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.

Original Sheet No. 38

Exhibit B-Table 1

Jointly Owned Asset Ownership by Percent of Major Equipment
Addendum 1 — Final 01-01-10

Substations
Jointly Owned Assets
Percentage Split by Major Equipment Count
(Substations with 100% Ownership by Major Equipment Count Not Included)

					Generation
					Owned by
					Local				Last
					Distribution		Third-Party		Revision
Substation Name	Distribution		Transmission		Company		Assets		Date
Campbell 138 kV		0.00		69.23		30.25		0.51		01/01/10
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 1		66.67		23.33		6.67		3.33		01/01/10
Thetford		0.00		92.00		8.00				04/29/02
Weadock		35.14		24.32		40.54				01/01/10
Whiting		31.58		31.58		36.84				01/01/10

1 At 120kV 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.

Original Sheet No. 39

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 Bank	No. A (located outside of substation; not included in JOA calc)
Circuit Breakers	Nos. 199, 299, 799, 899* 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* 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
Foundations	All 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 Bank	No. 5
Circuit Breakers	Nos. 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, 584, 585, 586,594, 1020 and 1121

Original Sheet No. 40

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

Original Sheet No. 41

CEII MATERIAL

Original Sheet No. 42

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 Banks	Nos. 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. 100,102,104, 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, 8826-2 and 8832-2
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, 1020,1021, 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

Original Sheet No. 43

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

Original Sheet No. 44

CEII MATERIAL

Original Sheet No. 45

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 Banks	Nos. 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

Original Sheet No. 46

Jointly Owned Assets — Percentage Split by Major Equipment Count

Gaylord Generating Substation — See Exhibit B — Table 1

Original Sheet No. 47

CEII MATERIAL

Original Sheet No. 48

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 Breakers	Nos. 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
Foundations	All 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 Breakers	Nos. 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, 2038 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
Foundations	All foundations supporting the Circuit Breakers identified above

Jointly Owned Assets — Percentage Split by Major Equipment Count

Karn Plant Substation - See Exhibit B — Table 1

Original Sheet No. 49

CEII MATERIAL

Original Sheet No. 50

CEII MATERIAL

Original Sheet No. 51

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)
Reactors	Nos. 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):

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

Original Sheet No. 52

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, and 26R4
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 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 = 56.76%; Third Parties = 43.24%

Original Sheet No. 53

CEII MATERIAL

Original Sheet No. 54

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, 288, 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, 208, 209, 252, 262, 264, 265, 282, 284, 285, 286, 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
Capacitors	Nos. 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 Breakers	Nos. 177, 377, 388, 500, 588, 677 and 988
Switches	Nos. 107, 173, 175, 176, 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, 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

Original Sheet No. 55

Third Party Owned Assets

Kalamazoo River Generation Station owns the following assets at the Morrow Substation (Wiring Diagram #190):

Circuit Breaker	No. 888
Switches	Nos. 882, 884, 885 and 886

Jointly Owned Assets — Percentage Split by Major Equipment Count

Morrow Substation — See Exhibit B — Table 1

Original Sheet No. 56

CEII MATERIAL

Original Sheet No. 57

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 Breakers	Nos. 13B7, 13W8, 116, 216, 316, 416, 516, 616, 716, 816 and 916
Switches	Nos. 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, 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

Original Sheet No. 58

CEII MATERIAL

Original Sheet No. 59

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
Capacitors	1 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 Banks	Nos. 5 and 6
Circuit Breakers	Nos. 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.

Original Sheet No. 60

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 Breakers	Nos. 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

Original Sheet No. 61

CEII MATERIAL

Original Sheet No. 62

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 31 attached). 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, 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, 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, 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 Breakers	Nos. 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

Original Sheet No. 63

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

Original Sheet No. 64

CEII MATERIAL

Original Sheet No. 65

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-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, 333-126943 on Forms S-8 and Registration Statement No. 333-163716 on Form S-3 of our reports dated February 23, 2011, 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, 2010.

/s/  DELOITTE & TOUCHE LLP

Detroit, Michigan
February 23, 2011

1

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.

Date: February 23, 2011

/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.

Date: February 23, 2011

/s/ Cameron M. Bready

Cameron M. Bready

Executive Vice President — Treasurer and Chief Financial Officer

2

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, 2010, as filed with the Securities and Exchange Commission on February 23, 2011 (the “Report”), we, Joseph L. Welch, President & Chief Executive Officer of the Registrant, and Cameron M. Bready, Executive Vice President — Treasurer 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, to the best of our knowledge, 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.

Date: February 23, 2011

/s/ Joseph L. Welch

Joseph L. Welch

President and Chief Executive Officer

/s/ Cameron M. Bready

Cameron M. Bready

Executive Vice President — Treasurer and Chief Financial Officer

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