10-K 1 itc2012123110k.htm 10-K ITC 2012.12.31 10K
 
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, 2012
OR
o
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission File Number: 001-32576
ITC HOLDINGS CORP.
(Exact Name of Registrant as Specified in Its Charter)
Michigan
(State or Other Jurisdiction of
Incorporation or Organization)
 
32-0058047
(I.R.S. Employer
Identification No.)
27175 Energy Way
Novi, Michigan 48377
(Address Of Principal Executive Offices, Including Zip Code)
(248) 946-3000
(Registrant’s Telephone Number, Including Area Code)
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class
Common stock, without par value
 
Name of Each Exchange on Which Registered
New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act of 1933. Yes þ No o
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Securities Exchange Act of 1934. Yes o No þ
Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information, statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer þ
 
Accelerated filer o
 
Non-accelerated filer o
 
Smaller Reporting Company o
 
 
 
 
(Do not check if a smaller reporting company)
 
 
Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ
The aggregate market value of the registrant’s common stock held by non-affiliates on June 30, 2012 was approximately $3.5 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 26, 2013 was 52,272,984.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Registrant’s definitive Proxy Statement for the Registrant’s 2013 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, 2012
INDEX

 
 
Page
 
 
 
 
 
 
 
 
 



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DEFINITIONS
Unless otherwise noted or the context requires, all references in this report to:
ITC Holdings Corp. and its subsidiaries
“ITC Great Plains” are references to ITC Great Plains, LLC, a wholly-owned subsidiary of ITC Grid Development, LLC;
“ITC Grid Development” are references to ITC Grid Development, LLC, a wholly-owned subsidiary of ITC Holdings;
“ITC Holdings” are references to ITC Holdings Corp. and not any of its subsidiaries;
“ITC Midwest” are references to ITC Midwest LLC, a wholly-owned subsidiary of ITC Holdings;
“ITCTransmission” are references to International Transmission Company, a wholly-owned subsidiary of ITC Holdings;
“METC” are references to Michigan Electric Transmission Company, LLC, a wholly-owned subsidiary of MTH;
“MISO Regulated Operating Subsidiaries” are references to ITCTransmission, METC and ITC Midwest together;
“MTH” are references to Michigan Transco Holdings, LLC, the sole member of METC and an indirect wholly-owned subsidiary of ITC Holdings;
“Regulated Operating Subsidiaries” are references to ITCTransmission, METC, ITC Midwest and ITC Great Plains together; and
“We,” “our” and “us” are references to ITC Holdings together with all of its subsidiaries.
Other definitions
“Consumers Energy” are references to Consumers Energy Company, a wholly-owned subsidiary of CMS Energy Corporation;
“Detroit Edison” are references to The Detroit Edison Company, a wholly-owned subsidiary of DTE Energy;
“DTE Energy” are references to DTE Energy Company;
“Entergy” are references to Entergy Corporation;
“Entergy Transaction” are references to the transaction whereby the electric transmission business of Entergy will be separated and subsequently merged with a wholly-owned subsidiary of ITC Holdings;
“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);
“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;


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“MOPSC” are references to the Missouri Public Service Commission;
“MPSC” are references to the Michigan Public Service Commission;
“MPUC” are references to the Minnesota Public Utilities Commission;
“MW” are references to megawatts (one megawatt equaling 1,000,000 watts);
“NERC” are references to the North American Electric Reliability Corporation;
“NOLs” are references to net operating loss carryforwards for income taxes;
“OCC” are references to Oklahoma Corporation Commission;
“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 operate high-voltage systems in Michigan’s Lower Peninsula and portions of Iowa, Minnesota, Illinois, Missouri, Kansas and Oklahoma that transmit electricity from generating stations to local distribution facilities connected to our systems.
Our business strategy is to operate, maintain and invest in transmission infrastructure in order to enhance system integrity and reliability, to reduce transmission constraints and to allow new generating resources to interconnect to our transmission systems. We also are pursuing development projects not within our existing systems, which are also intended to improve overall grid reliability, reduce transmission constraints and facilitate interconnections of new generating resources, as well as to enhance competitive wholesale electricity markets.
As electric transmission utilities with rates regulated by the FERC, our Regulated Operating Subsidiaries earn revenues through tariff rates charged for the use of their electric transmission systems by our customers, which include investor-owned utilities, municipalities, cooperatives, power marketers and alternative energy suppliers. As independent transmission companies, our Regulated Operating Subsidiaries are subject to rate regulation only by the FERC. The rates charged by our Regulated Operating Subsidiaries are established using cost-based formula rate templates as discussed in “Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations — Cost-Based Formula Rates with True-Up Mechanism.”
Development of Business
We are actively developing transmission infrastructure required to meet reliability needs and 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 and Operating Results Trends” for additional details about our long-term capital investment program totaling $4.2 billion for the period 2012 through 2016. In addition, we have entered into definitive agreements whereby the electric transmission business of Entergy will be separated and subsequently merged with a wholly-owned subsidiary of ITC Holdings as discussed under “Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations—Capital Project Updates and Other Recent Developments.” Finally, 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 expected revenues and earnings. In addition, we expect to invest in strategic development opportunities to improve the efficiency and reliability of the transmission grid, but we cannot assure you that we will be able to initiate or complete any of these investments.”
Current Transmission Systems
We expect to invest approximately $1.6 billion from 2012 through 2016 at our Regulated Operating Subsidiaries in order to maintain and replace the current transmission infrastructure, enhance system integrity and reliability and accommodate load growth.
Network Upgrades to Support Generator Interconnections
We expect to invest approximately $0.9 billion from 2012 through 2016 to develop and build transmission infrastructure to support generator interconnections.
In 2010, we received MISO approval of the Thumb Loop Project which is primarily located in ITCTransmission’s region. The Thumb Loop Project is a 140-mile, double-circuit 345 kV transmission line and related substations that


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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 generating facilities. The backbone transmission network, transmission for wind interconnection and transmission for interconnection of other generating facilities may provide additional investment opportunities.
Development Projects
We expect to invest approximately $1.7 billion from 2012 through 2016 to construct our portions of various development projects that we are currently advancing in the South Central and North Central regions of the country. We are pursuing strategic development opportunities for transmission investments related to upgrading the existing transmission grid and regional transmission facilities, primarily to improve overall grid reliability, reduce transmission constraints, enhance competitive markets and facilitate interconnections of new generating resources, including wind generation and other renewable resources.
South Central Region
We have pursued the opportunity to invest in certain transmission projects in Kansas and Oklahoma, through ITC Great Plains. Two of these projects, the KETA Project consisting of a transmission line that runs between Spearville, Kansas and Axtell, Nebraska, and the Hugo to Valliant Project in Oklahoma, were completed and placed in-service in 2012.
A third project, known as the Kansas V-Plan Project, which consists of a transmission line running from the Spearville substation to Medicine Lodge, Kansas, is currently under construction.
North Central Region
In 2009, we announced the Green Power Express project, consisting of transmission line segments that would facilitate the movement of power from the Dakotas, Minnesota and Iowa to Midwest load centers that demand energy. Since the announcement of the Green Power Express project, MISO undertook its Regional Generation Outlet Study (“RGOS”) to promote investments in new regional transmission infrastructure and implemented its Multi-Value Project (“MVP”) cost allocation methodology that better aligns the costs of MVPs with the benefits associated with them. MISO’s RGOS and MVP processes provide a channel for the Green Power Express project, or its underlying segments, to move forward through the planning approval process as MVPs. In December 2011, MISO approved the first portfolio of MVPs identified through the RGOS which includes portions of four MVPs that we intend to build, own and operate. The four MVPs are located in south central Minnesota, portions of Iowa, southwest Wisconsin, and northeast Missouri.
We continue to explore other opportunities to advance segments of our Green Power Express project, or similar RGOS projects, through the MISO MVP process.
Segments
We have one reportable segment consisting of our Regulated Operating Subsidiaries. Additionally, we have other subsidiaries focused primarily on business development activities and a holding company whose activities include corporate debt and equity financings and general corporate activities. A more detailed discussion of our reportable segment, including financial information about the segment, is included in Note 18 to the consolidated financial statements.
Operations
As transmission-only companies, our Regulated Operating Subsidiaries function as conduits, allowing for power from generators to be transmitted to local distribution systems either entirely through their own systems or in conjunction with neighboring transmission systems. Third parties then transmit power through these local distribution systems to end-use consumers. The transmission of electricity by our Regulated Operating Subsidiaries is a central function to the provision of electricity to residential, commercial and industrial end-use consumers. The operations performed by our Regulated Operating Subsidiaries fall into the following categories:
asset planning;
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 Services, Inc. (“ULCS”), which is a division of Asplundh Tree Expert Co., to perform the majority of their maintenance. The agreement with ULCS provides us with access to an experienced and scalable workforce with knowledge of our system at an established rate.
Real Time Operations
System Operations. From our operations facility in Novi, Michigan, transmission system operators continuously monitor the performance of the transmission systems of our Regulated Operating Subsidiaries, using software and communication systems to perform analysis to plan for contingencies and maintain security and reliability following any unplanned events on the system. Transmission system operators are also responsible for the switching and protective tagging function, taking equipment in and out of service to ensure capital construction projects and maintenance programs can be completed safely and reliably.
Local Balancing Authority Operator. Under the functional control of MISO, ITCTransmission and METC operate their electric transmission systems as a combined Local Balancing Authority (“LBA”) area, known as the Michigan Electric Coordinated Systems (“MECS”). From our operations facility in Novi, Michigan, our employees perform the LBA functions as outlined in MISO’s Balancing Authority Agreement. These functions include actual interchange data administration and verification and MECS LBA area emergency procedure implementation and coordination. ITC Midwest and ITC Great Plains are not responsible for LBA functions for their respective assets.
Operating Contracts
Our Regulated Operating Subsidiaries have various operating contracts, including numerous interconnection agreements with generation and transmission providers that address terms and conditions of interconnection. The following significant agreements exist at our Regulated Operating Subsidiaries:
ITCTransmission
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


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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 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


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any relocation work until an alternative right-of-way satisfactory to Consumers Energy is obtained at METC’s expense.
The term of the Easement Agreement runs through December 31, 2050 and is subject to 10 automatic 50-year renewals after that time unless METC provides one year’s notice of its election not to renew the term. Consumers Energy may terminate the Easement Agreement 30 days after giving notice of a failure by METC to pay its quarterly installment if METC does not cure the non-payment within the 30-day notice period. At the end of the term or upon any earlier termination of the Easement Agreement, the easement and related rights terminate and the transmission facilities revert to Consumers Energy.
Amended and Restated Operating Agreement. Under the Amended and Restated Operating Agreement (the “Operating Agreement”), dated as of April 29, 2002, METC agrees to operate its transmission system to provide all transmission customers with safe, efficient, reliable and nondiscriminatory transmission service pursuant to its tariff. Among other things, METC is responsible under the Operating Agreement for maintaining and operating its transmission system, providing Consumers Energy with information and access to its transmission system and related books and records, administering and performing the duties of control area operator (that is, the entity exercising operational control over the transmission system) and, if requested by Consumers Energy, building connection facilities necessary to permit interaction with new distribution facilities built by Consumers Energy. Consumers Energy has corresponding obligations to provide METC with access to its books and records and to build distribution facilities necessary to provide adequate and reliable transmission services to wholesale customers. Consumers Energy must cooperate with METC as METC performs its duties as control area operator, including by providing reactive supply and voltage control from generation sources or other ancillary services and reducing load. The Operating Agreement is effective through 2050 and is subject to 10 automatic 50-year renewals after that time, unless METC provides one year’s notice of its election not to renew.
Amended and Restated Purchase and Sale Agreement for Ancillary Services. The Amended and Restated Purchase and Sale Agreement for Ancillary Services (the “Ancillary Services Agreement”) is dated as of April 29, 2002. Since METC does not own any generating facilities, it must procure ancillary services from third party suppliers, such as Consumers Energy. Currently, under the Ancillary Services Agreement, METC pays Consumers Energy for providing certain generation based services necessary to support the reliable operation of the bulk power grid, such as voltage support and generation capability and capacity to balance loads and generation. METC is not precluded from procuring these ancillary services from third party suppliers when available. The Ancillary Services Agreement is subject to rolling one-year renewals starting May 1, 2003, unless terminated by either METC or Consumers Energy with six months prior written notice.
Amended and Restated Distribution-Transmission Interconnection Agreement. The Amended and Restated Distribution-Transmission Interconnection Agreement (the “DT Interconnection Agreement”), dated April 1, 2001 and amended and restated most recently as of June 1, 2012, 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 December 1, 2012, specifies the terms and conditions under which Consumers Energy and METC maintain the interconnection of Consumers Energy’s generation resources and METC’s transmission assets. The Generator Interconnection Agreement is effective either until it is replaced by any MISO-required contract, or until mutually agreed by METC and Consumers Energy to terminate, but not later than the date that all listed generators cease commercial operation.


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ITC Midwest
IP&L operates the electric distribution system to which ITC Midwest’s transmission system connects. ITC Midwest is a party to a number of operating contracts with IP&L that govern the operations and maintenance of its transmission system. These contracts include the following:
Distribution-Transmission Interconnection Agreement. The Distribution-Transmission Interconnection Agreement (the “DTIA”), dated as of December 17, 2007, governs the rights, responsibilities and obligations of ITC Midwest and IP&L, with respect to the use of certain of their own and the other parties’ property, assets and facilities, and the construction of new facilities or modification of existing facilities. Additionally, the DTIA sets forth the terms pursuant to which the equipment and facilities and the interconnection equipment of IP&L will continue to connect ITC Midwest’s facilities through which ITC Midwest provides transmission service under the MISO Transmission and Energy Markets Tariff. The DTIA will remain in effect until terminated by mutual agreement by the parties (subject to any required FERC approvals) or as long as any interconnection point of IP&L is connected to ITC Midwest’s facilities, unless modified by written agreement of the parties.
Large Generator Interconnection Agreement. ITC Midwest, IP&L and MISO entered into the Large Generator Interconnection Agreement (the “LGIA”), dated as of December 20, 2007, in order to establish, re-establish and maintain the direct electricity interconnection of IP&L’s electricity generating assets with ITC Midwest’s transmission system for the purposes of transmitting electric power from and to the electricity generating facilities. The LGIA will remain in effect until terminated by ITC Midwest or until IP&L elects to terminate the agreement if a particular unit ceases commercial operation for three consecutive years.
Operations Services Agreement For 34.5 kV Transmission Facilities. ITC Midwest and IP&L entered into the Operations Services Agreement for 34.5 kV Transmission Facilities (the “OSA”), effective as of January 1, 2011, under which IP&L performs certain operations functions for ITC Midwest’s 34.5 kV transmission system on behalf of ITC Midwest. The OSA provides that when ITC Midwest upgrades 34.5 kV facilities to higher operating voltages it may notify IP&L of the change and the OSA is no longer applicable to those facilities. The OSA will remain in full force and effect until December 31, 2015 and will extend automatically from year to year thereafter until terminated by either party upon not less than one year prior written notice to the other party.
ITC Great Plains
Amended and Restated Maintenance Agreement. Mid-Kansas Electric Company LLC (“Mid-Kansas”) and ITC Great Plains have entered into a Maintenance Agreement (the “Mid-Kansas Agreement”), dated as of August 24, 2010, pursuant to which Mid-Kansas has agreed to perform various field operations and maintenance services related to the ITC Great Plains Elm Creek and Flat Ridge Substations, which ITC Great Plains purchased from Mid-Kansas. The Mid-Kansas Agreement has an initial term of 10 years and automatic 10-year renewals unless terminated (1) due to a breach by the non-terminating party following notice and failure to cure, (2) by mutual consent of the parties, or (3) by ITC Great Plains under certain limited circumstances. Services must continue to be provided for at least six months subsequent to the termination date in any case.
Maintenance Agreement. Midwest Energy, Inc. (“Midwest Energy”) and ITC Great Plains have entered into a maintenance agreement (the “Midwest Energy Agreement”) dated as of June 25, 2012. Pursuant to which Midwest Energy has agreed to perform various field operations and maintenance service related to ITC Great Plains facilities associated with the KETA project. The Midwest Energy Agreement has an initial term of three years with automatic three-year renewals unless terminated (1) due to a material breach by the non-terminating party following notice and failure to cure or (2) by mutual consent of the parties. Services must continue to be provided for at least six months subsequent to the termination date in any case.
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


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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 standards established by the NERC, as well as the standards of applicable regional entities under the NERC that have been delegated certain authority for the purpose of proposing and enforcing reliability standards. Finally, 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.
In July 2011, the FERC issued Order No. 1000 (“Order 1000”) which amends certain existing transmission planning and cost allocation requirements to ensure that FERC-jurisdictional services are provided at just and reasonable rates and on a basis that is just and reasonable and not unduly discriminatory or preferential. With respect to transmission planning, Order 1000: (1) requires that each public utility transmission provider participate in a regional transmission planning process that produces a regional transmission plan; (2) requires that each


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public utility transmission provider amend its Open Access Transmission Tariff (“OATT”) to describe procedures that provide for the consideration of transmission needs driven by public policy requirements in the local and regional transmission planning processes; (3) removes from FERC-approved tariffs and agreements a federal right of first refusal (“ROFR”) for certain new transmission facilities; and (4) improves coordination between neighboring transmission planning regions for new interregional transmission facilities. Order 1000 could potentially lead to greater competition for certain future transmission projects, including within our current operating area. Both MISO and SPP made compliance filings in the last quarter of 2012 to implement the first three requirements of Order 1000 noted above.
Revenue Requirement Calculations and Cost Sharing for Projects with Regional Benefits
The cost based formula rates used by our Regulated Operating Subsidiaries continue to evolve to include revenue requirement calculations for various types of projects. Network revenues continue to be the largest component of revenues recovered through our formula rates. However, regional cost sharing revenues are growing as a result of projects that have been identified by MISO or SPP as having regional benefits, and therefore eligible for regional cost recovery under their tariff. Separate calculations of revenue requirement are performed for projects that have been approved for regional cost sharing and these separate calculations impact only which parties ultimately pay for the transmission services related to these projects and do not impact our financial results.
We have projects that are eligible for regional cost sharing under Attachment FF of the MISO tariff, such as certain network upgrade projects, and the MVPs, including the Thumb Loop Project. The FERC accepted MISO’s Thumb Loop Project 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 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.


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ITC Midwest also is subject to the regulatory oversight of certain state agencies (including the Iowa Department of Natural Resources) and certain local authorities with respect to the issuance of environmental, highway, railroad, and similar permits.
Minnesota
The MPUC has jurisdiction over the construction, siting and routing of new transmission lines or upgrades of existing lines through Minnesota’s Certificate of Need and Route Permit Processes. Transmission companies are also required to participate in the State’s Biennial Transmission Planning Process and are subject to the state’s preventative maintenance requirements. Pursuant to Minnesota law, ITC Midwest has the right as an independent transmission company to condemn property in the State of Minnesota for the purpose of building new transmission facilities.
ITC Midwest is also subject to the regulatory oversight of the Minnesota Pollution Control Agency, the Minnesota Department of Natural Resources, the MPUC in conjunction with the Department of Commerce, and certain local authorities for compliance with applicable environmental standards and regulations.
Illinois
The ICC exercises jurisdiction over siting of new transmission lines through its requirements for Certificates of Public Convenience and Necessity and Right-Of-Way acquisition that apply to construction of new or upgraded facilities.
ITC Midwest also is subject to the regulatory oversight of the Illinois Environmental Protection Agency, the Illinois Department of Natural Resources, the Illinois Pollution Control Board and certain local authorities for compliance with all environmental standards and regulations.
Missouri
Because ITC Midwest is a “public utility” and an “electrical corporation” under Missouri law, the MOPSC has jurisdiction to determine whether ITC Midwest may operate in such capacity. The MOPSC also exercises jurisdiction with regard to other non-rate matters affecting this Missouri asset such as transmission substation construction, general safety and the transfer of the franchise or property.
ITC Midwest is also subject to the regulatory oversight of the Missouri Department of Natural Resources for compliance with all environmental standards and regulations relating to this transmission line.
ITC Great Plains
Kansas
ITC Great Plains is a “public utility” in Kansas and an “electric utility” pursuant to state statutes. The KCC issued an order approving the issuance of a limited certificate of convenience to ITC Great Plains for the purposes of building, owning and operating SPP transmission projects in Kansas. In addition to its certificate of authority, the KCC has jurisdiction over the siting of electric transmission lines.
ITC Great Plains is also subject to the regulatory oversight of the Kansas Department of Health and Environment for compliance with all environmental standards and regulations relating to the construction phase of any transmission line.
Oklahoma
ITC Great Plains has approval from the OCC to operate in Oklahoma, pursuant to Oklahoma Statutes as an electric public utility providing only transmission services. The OCC does not exercise jurisdiction over the siting of any transmission lines.
ITC Great Plains may be subject to the regulatory oversight of Oklahoma Department of Environmental Quality for compliance with environmental standards and regulations relating to construction of proposed transmission lines.
Sources of Revenue
See “Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations — Results of Operations — Operating Revenues” for a discussion of our principal sources of revenue.


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Seasonality
The cost-based formula rates with a true-up mechanism in effect for all our Regulated Operating Subsidiaries, as discussed in “Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations — Cost-Based Formula Rates with True-Up Mechanism,” mitigate the seasonality of net income for our Regulated Operating Subsidiaries. Our Regulated Operating Subsidiaries accrue or defer revenues to the extent that the actual revenue requirement for the reporting period is higher or lower, respectively, than the amounts billed relating to that reporting period. For example, to the extent that amounts billed are less than our revenue requirement for a reporting period, a revenue accrual is recorded for the difference and the difference results in no net income impact.
Operating cash flows are seasonal at our MISO Regulated Operating Subsidiaries, in that cash received for revenues is typically higher in the summer months when peak load is higher.
Principal Customers
Our principal transmission service customers are Detroit Edison, Consumers Energy and IP&L, which accounted for approximately 26.7%, 25.6% and 27.0%, respectively, of our total operating revenues for the year ended December 31, 2012. 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 2012 revenue accruals and deferrals that were included in our 2012 operating revenues, but will not be billed to our customers until 2014. We have assumed that the revenues billed to these customers in 2014 would be in the same proportion of the respective percentages of network and regional cost sharing revenues billed to them in 2012. 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. However, the competitive environment may change due to the implementation of Order 1000. See further discussion of Order 1000 above under “Regulatory Environment — Federal Regulation.” For our subsidiaries focused on development opportunities for transmission investment in other service areas, the incumbent utilities or other entities with transmission development initiatives may compete with us by seeking regulatory approval to be named the party authorized to build new capital projects that we are also pursuing. Because our Regulated Operating Subsidiaries are currently the only transmission companies that are independent from electricity market participants, we believe we are best able to develop these projects in a non-discriminatory manner. However, there are no assurances we will be selected to develop projects that other entities are also pursuing.
Employees
As of December 31, 2012, we had 503 employees. We consider our relations with our employees to be good.


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Environmental Matters
Our operations are subject to federal, state, and local environmental laws and regulations, which impose limitations on the discharge of pollutants into the environment, establish standards for the management, treatment, storage, transportation and disposal of hazardous materials and of solid and hazardous wastes, and impose obligations to investigate and remediate contamination in certain circumstances. Liabilities for failing to investigate or remediate contamination, as well as other liabilities concerning hazardous materials or contamination, such as claims for personal injury or property damage, may arise at many locations, including formerly owned or operated properties and sites where wastes have been treated or disposed of, as well as at properties currently owned or operated by us. Such liabilities may arise even where the contamination does not result from noncompliance with applicable environmental laws. Under a number of environmental laws, such liabilities may also be joint and several, meaning that a party can be held responsible for more than its share of the liability involved, or even the entire share. Environmental requirements generally have become more stringent and compliance with those requirements more expensive. We are not aware of any specific developments that would increase our costs for such compliance in a manner that would be expected to have a material effect on our results of operations, financial position or liquidity.
Our assets and operations also involve the use of materials classified as hazardous, toxic or otherwise dangerous. Many of the properties our Regulated Operating Subsidiaries own or operate have been used for many years, and include older facilities and equipment that may be more likely than newer ones to contain or be made from such materials. Some of these properties include aboveground or underground storage tanks and associated piping. Some of them also include large electrical equipment filled with mineral oil, which may contain or previously have contained polychlorinated biphenyls (commonly known as PCBs). Our facilities and equipment are often situated close to or on property owned by others so that, if they are the source of contamination, the property of others may be affected. For example, aboveground and underground transmission lines sometimes traverse properties that we do not own, and, at some of our transmission stations, transmission assets (owned or operated by us) and distribution assets (owned or operated by our transmission customers) are commingled.
Some properties in which we have an ownership interest or at which we operate are, and others are suspected of being, affected by environmental contamination. We are not aware of any claims pending or threatened against us with respect to environmental contamination, or of any investigation or remediation of contamination at any properties, that entail costs likely to materially affect us. Some facilities and properties are located near environmentally sensitive areas such as wetlands.
Claims have been made or threatened against electric utilities for bodily injury, disease or other damages allegedly related to exposure to electromagnetic fields associated with electric transmission and distribution lines. While we do not believe that a causal link between electromagnetic field exposure and injury has been generally established and accepted in the scientific community, if such a relationship is established or accepted, the liabilities and costs imposed on our business could be significant. We are not aware of any claims pending or threatened against us for bodily injury, disease or other damages allegedly related to exposure to electromagnetic fields and electric transmission and distribution lines that entail costs likely to have a material adverse effect on our results of operations, financial position or liquidity.
Filings Under the Securities Exchange Act of 1934
Our internet address is http://www.itc-holdings.com. You can access free of charge on our web site all of our reports filed pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), including our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to those reports. These reports are available as soon as practicable after they are electronically filed with the Securities and Exchange Commission (the “SEC”). Also on our web site are our:
Corporate Governance Guidelines;
Code of Business Conduct and Ethics; and
Committee Charters for the Audit and Finance Committee, Compensation Committee and Nominating/Corporate Governance Committee.
Our Code of Business Conduct and Ethics applies to all directors, officers and employees, including our Chairman, President and Chief Executive Officer and our Executive Vice President and Chief Financial Officer. We will post any amendments to the Code of Business Conduct and Ethics, and any waivers that are required to


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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 acquisitions that could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Our Regulated Operating Subsidiaries provide transmission service under rates regulated by the FERC. The FERC has approved the cost-based formula rate templates used by our Regulated Operating Subsidiaries, 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.
In the Minnesota regulatory proceeding to approve ITC Midwest’s December 2007 acquisition of the transmission assets of IP&L, ITC Midwest agreed to build two transmission projects intended to improve the reliability and efficiency of our electric transmission system. Specifically, ITC Midwest made commitments to use commercially reasonable best efforts to complete these projects prior to December 31, 2009 and 2011, respectively. In the event ITC Midwest is found to have failed to meet these commitments, the allowed 12.38% rate of return on the actual equity portion of ITC Midwest’s capital structure would be reduced to 10.39% until such time as ITC Midwest completes these projects, and ITC Midwest would refund with interest any amounts collected since the closing date of the transaction that exceeded what would have been collected if the 10.39% return on equity had been used. The project that was required to be completed prior to December 31, 2009 was completed by that deadline. With respect to the second project, the 345 kV Salem-Hazleton line, certain regulatory approvals were needed from the IUB before construction of the project could commence, but due to the IUB’s case schedule, these approvals were not received until the second quarter of 2011. As a result of the delay in the receipt of the necessary regulatory approvals, the project was not completed by December 31, 2011. We believe we used commercially reasonable best efforts to meet the December 31, 2011 deadline.
Any of the events described above could have an adverse effect on our business, financial condition, results of operations and cash flows.
Our Regulated Operating Subsidiaries’ actual capital expenditures may be lower than planned, which would decrease expected rate base and therefore our expected revenues and earnings. 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.


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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 several years which include estimated transmission network upgrades for generator interconnections. The amounts for network upgrades could change significantly due to factors beyond our control, such as changes in the MISO queue for generation projects and whether the generator meets the various criteria of Attachment FF of the MISO Open Access Transmission, Energy, and Operating Reserve Markets Tariff for the project to qualify as a refundable network upgrade, among other factors. If our Regulated Operating Subsidiaries’ capital 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, 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. 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 development projects for construction of transmission facilities and interconnections with generating resources. These projects may require regulatory approval by the FERC, applicable RTOs and state and local regulatory agencies. Failure to secure such regulatory approval for new strategic development projects could adversely affect our ability to grow our business and increase our revenues. If we fail to obtain these approvals when necessary, we may incur liabilities for such failure.
Changes in federal energy laws, regulations or policies could impact our business, financial condition, results of operations and cash flows.
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 formula rates are unjust and unreasonable and that another rate is just and reasonable. Such a determination could result from challenges initiated at the FERC by interested parties, or by the FERC on its own initiative, in a proceeding under Section 206 of the FPA. An existing formula rate also could be replaced 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


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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, or our actual revenue requirements are higher than expected, the timing of collection of our revenues would be delayed.
If amounts billed for transmission service are lower than expected, which could result from lower network load or point-to-point transmission service on our Regulated Operating Subsidiaries’ transmission systems due to a weak economy, changes in the nature or composition of the transmission assets of our Regulated Operating Subsidiaries and surrounding areas, poor transmission quality of neighboring transmission systems, or for any other reason, the timing of the collection of our revenue requirement would likely be delayed until such circumstances are adjusted through the true-up mechanism in our Regulated Operating Subsidiaries’ formula rate templates. In addition, if the revenue requirements of our Regulated Operating Subsidiaries are higher than expected, the timing of the collection of our Regulated Operating Subsidiaries' revenue requirements would likely be delayed until such circumstances are reflected through the true-up mechanism in our Regulated Operating Subsidiaries' expected, formula rate templates. The effect of such under-collection would be to reduce the amount of our available cash resources from what we had expected, until such under-collection is corrected through the true-up mechanism in the formula rate template, which may require us to increase our outstanding indebtedness, thereby reducing our available borrowing capacity, and may require us to pay interest at a rate that exceeds the interest to which we are entitled in connection with the operation of the true-up mechanism.
Each of our MISO Regulated Operating Subsidiaries depends on its primary customer for a substantial portion of its revenues, and any material failure by those primary customers to make payments for transmission services could have a material adverse effect on our business, financial condition, results of operations and cash flows.
ITCTransmission derives a substantial portion of its revenues from the transmission of electricity to Detroit Edison’s local distribution facilities. Detroit Edison accounted for approximately 75.0% of ITCTransmission’s total operating revenues for the year ended December 31, 2012 and is expected to constitute the majority of ITCTransmission’s revenues for the foreseeable future. Detroit Edison is rated BBB+/stable and Baa1/positive by Standard & Poor’s Ratings Services and Moody’s Investors Services, Inc., respectively. Similarly, Consumers Energy accounted for approximately 78.2% of METC’s total operating revenues for the year ended December 31, 2012 and is expected to constitute the majority of METC’s revenues for the foreseeable future. Consumers Energy is rated BBB-/positive and Baa2/positive by Standard & Poor’s Ratings Services and Moody’s Investors Service, Inc., respectively. Further, IP&L accounted for approximately 80.0% of ITC Midwest’s total operating revenues for the year ended December 31, 2012 and is expected to constitute the majority of ITC Midwest’s revenues for the foreseeable future. IP&L is rated A-/stable and A3/stable by Standard & Poor’s Ratings Services and Moody’s Investors Service, Inc., respectively. These percentages of total operating revenues of Detroit Edison, Consumers Energy and IP&L include an estimate for the 2012 revenue accrual and deferrals that were included in our 2012 operating revenues, but will not be billed to our customers until 2014. We have assumed that the revenues billed to these customers in 2014 would be in the same proportion of the respective percentages of network and regional cost sharing revenues billed to them in 2012.
Any material failure by Detroit Edison, Consumers Energy or IP&L to make payments for transmission services could have an adverse effect on our business, financial condition, results of operations and cash flows.
A significant amount of the land on which our Regulated Operating Subsidiaries’ assets are located is subject to easements, mineral rights and other similar encumbrances. As a result, our Regulated Operating Subsidiaries must comply with the provisions of various easements, mineral rights and other


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similar encumbrances, which may adversely impact their ability to complete construction projects in a timely manner.
METC does not own the majority of the land on which its electric transmission assets are located. Instead, under the provisions of an Easement Agreement with Consumers Energy, METC pays annual rent of $10.0 million to Consumers Energy in exchange for rights-of-way, leases, fee interests and licenses which allow METC to use the land on which its transmission lines are located. Under the terms of the Easement Agreement, METC’s easement rights could be eliminated if METC fails to meet certain requirements, such as paying contractual rent to Consumers Energy in a timely manner. Additionally, a significant amount of the land on which ITCTransmission’s, ITC Midwest’s and ITC Great Plains’ assets are located is subject to easements, mineral rights and other similar encumbrances. As a result, they must comply with the provisions of various easements, mineral rights and other similar encumbrances, which may adversely impact their ability to complete their construction projects in a timely manner.
Our Regulated Operating Subsidiaries contract with third parties to provide services for certain aspects of their businesses. If any of these agreements are terminated, our Regulated Operating Subsidiaries may face a shortage of labor or replacement contractors to provide the services formerly provided by these third parties.
Our Regulated Operating Subsidiaries enter into various agreements and arrangements with third parties to provide services for the operation of certain aspects of their businesses, which, if terminated could result in a shortage of a readily available workforce to provide these services. For example, ITC Midwest and IP&L have entered into the Operations Services Agreement For 34.5 kV Transmission Facilities (the “OSA”), under which IP&L performs certain operations functions for ITC Midwest’s 34.5 kV transmission system. The OSA’s term is from January 1, 2011 until December 31, 2015, and by its terms will remain in full force and effect from year to year thereafter until terminated by either party upon not less than one year’s prior written notice to the other party. If the OSA is terminated for any reason 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 an 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 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.


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Our Regulated Operating Subsidiaries’ assets and operations also involve the use of materials classified as hazardous, toxic, or otherwise dangerous. Some of our Regulated Operating Subsidiaries’ facilities and properties are located near environmentally sensitive areas such as wetlands and habitats of endangered or threatened species. In addition, certain properties in which our Regulated Operating Subsidiaries operate are, or are suspected of being, affected by environmental contamination. Compliance with these laws and regulations, and liabilities concerning contamination or hazardous materials, may adversely affect our costs and, therefore, our business, financial condition and results of operations.
In addition, claims have been made or threatened against electric utilities for bodily injury, disease or other damages allegedly related to exposure to electromagnetic fields associated with electric transmission and distribution lines. We cannot assure you that such claims will not be asserted against us or that, if determined in a manner adverse to our interests, such claims would not have a material effect on our business, financial condition and results of operations.
Our Regulated Operating Subsidiaries are subject to various regulatory requirements, including reliability standards; contract filing requirements; reporting, recordkeeping and accounting requirements; and transaction approval requirements. Violations of these requirements, whether intentional or unintentional, may result in penalties that, under some circumstances, could have a material adverse effect on our business, financial condition, results of operations and cash flows.
The various regulatory requirements to which we are subject include reliability standards established by the NERC, which acts as the nation’s Electric Reliability Organization approved by the FERC in accordance with Section 215 of the FPA. These standards address operation, planning and security of the bulk power system, including requirements with respect to real-time transmission operations, emergency operations, vegetation management, critical infrastructure protection and personnel training. Failure to comply with these requirements can result in monetary penalties as well as non-monetary sanctions. Monetary penalties vary based on an assigned risk factor for each potential violation, the severity of the violation and various other circumstances, such as whether the violation was intentional or concealed, whether there are repeated violations, the degree of the violator’s cooperation in investigating and remediating the violation and the presence of a compliance program. Penalty amounts range from $1,000 to a maximum of $1.0 million per day, depending on the severity of the violation. Non-monetary sanctions include potential limitations on the violator’s activities or operation and placing the violator on a watchlist for major violators. Despite our best efforts to comply and the implementation of a compliance program intended to ensure reliability, there can be no assurance that violations will not occur that would result in material penalties or sanctions. If any of our Regulated Operating Subsidiaries were to violate the NERC reliability standards, even unintentionally, in any material way, any penalties or sanctions imposed against us could have a material adverse effect on our business, financial condition, results of operations and cash flows.
The Regulated Operating Subsidiaries are also subject to requirements under Sections 203 and 205 of the FPA for approval of transactions; reporting, recordkeeping and accounting requirements; and for filing contracts related to the provision of jurisdictional services. Under FERC policy, failure to file jurisdictional agreements on a timely basis may result in foregoing the time value of revenues collected under the agreement, but not to the point where a loss would be incurred. The failure to obtain timely approval of transactions subject to FPA Section 203, or to comply with applicable reporting, recordkeeping or accounting requirements under FPA Section 205, could subject us to penalties that could have a material adverse effect on our financial condition, results of operations and cash flows.
Acts of war, terrorist attacks and threats, including cyber attacks or threats, or the escalation of military activity in response to such attacks or otherwise may negatively affect our business, financial condition, results of operations and cash flows.
Acts of war, terrorist attacks and threats, including cyber attacks or 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 or threats, including cyber attacks or threats. In addition to the increased costs associated with heightened security requirements, such events may have a material 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, results of operations and cash flows.


20


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 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. Our Regulated Operating Subsidiaries target a FERC-approved capital structure of 60% equity and 40% debt that may limit the ability of our Regulated Operating Subsidiaries to use net assets for the payment of dividends to ITC Holdings. While we currently intend to continue to pay quarterly dividends on our common stock, we have no obligation to do so. The payment of dividends is within the absolute discretion of our board of directors and will depend on, among other things, our results of operations, working capital requirements, capital expenditure requirements, financial condition, contractual restrictions, anticipated cash needs and other factors that our board of directors deems relevant.
We 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 and term loan 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.
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 working capital, capital expenditures and the payment of dividends on our common stock.
In the event that we are liquidated, our senior or subordinated creditors and the senior or subordinated creditors of our subsidiaries will be entitled to payment in full prior to any distributions to the holders of shares of our common stock.
We currently have debt instruments outstanding with relatively short remaining maturities. Our ability to secure additional financing prior to or after these facilities mature, if needed, may be substantially restricted by the existing level of our indebtedness and the restrictions contained in our debt instruments. Additionally, the interest rates at which we might secure additional financings may be higher than our currently outstanding debt instruments or higher than forecasted at any point in time, which could adversely affect our business, financial condition, results of operations and cash flows.
Market conditions could affect our access to capital markets, restrict our ability to secure financing to make the capital expenditures and investments and pay other expenses planned by us and could affect our interest rate swap obligations which could adversely affect our business, financial condition, cash flows and results of operations.
We may incur substantial indebtedness in the future, including in connection with the Entergy Transaction. The incurrence of additional indebtedness would increase the leverage-related risks described above.


21


Certain provisions in our debt instruments limit our financial flexibility.
Our debt instruments include senior notes, secured notes, first mortgage bonds, and revolving and term loan 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.
Our debt instruments also require us to meet certain financial ratios, such as maintaining certain debt to capitalization ratios. Our ability to comply with these and other requirements and restrictions may be affected by changes in economic or business conditions, results of operations or other events beyond our control. A failure to comply with the obligations contained in any of our debt instruments could result in acceleration of 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 and term loan credit agreements.
Provisions in our Articles of Incorporation and bylaws, Michigan corporate law and our debt agreements may impede efforts by our shareholders to change the direction or management of our company.
Our Articles of Incorporation and bylaws contain provisions that might enable our management to resist a proposed takeover. These provisions could discourage, delay or prevent a change of control or an acquisition at a price that our shareholders may find attractive. These provisions also may discourage proxy contests and make it more difficult for our shareholders to elect directors and take other corporate actions. The existence of these provisions could limit the price that investors are willing to pay in the future for shares of our common stock. These provisions include:
a restriction limiting market participants from voting or owning 5% or more of the outstanding shares of our capital stock;
a requirement that special meetings of our shareholders may be called only by our board of directors, the chairman of our board of directors, our president or the holders of a majority of the shares of our outstanding common stock;
advance notice requirements for shareholder proposals and nominations; and
the authority of our board to issue, without shareholder approval, common or preferred stock, including in connection with our implementation of any shareholders rights plan, or “poison pill.”
In addition, our revolving and term loan credit agreements provide that a change in a majority of ITC Holdings’ board of directors that is not approved by the current ITC Holdings directors or acquiring beneficial ownership of 35% or more of ITC Holdings outstanding common shares will constitute a default under those agreements.


22


Provisions in our Articles of Incorporation restrict market participants from voting or owning 5% or more of the outstanding shares of our capital stock.
Certain of our Regulated Operating Subsidiaries have been granted favorable rate treatment by the FERC based on their independence from market participants. The FERC defines a “market participant” to include any person or entity that, either directly or through an affiliate, sells or brokers electricity, or provides ancillary services to an RTO. An affiliate, for these purposes, includes any person or entity that directly or indirectly owns, controls or holds with the power to vote 5% or more of the outstanding voting securities of a market participant. To help ensure that we and our subsidiaries will remain independent of market participants, our Articles of Incorporation impose certain restrictions on the ownership and voting of shares of our capital stock by market participants. In particular, the Articles of Incorporation provide that we are restricted from issuing any shares of capital stock or recording any transfer of shares if the issuance or transfer would cause any market participant, either individually or together with members of its “group” (as defined in SEC beneficial ownership rules), to beneficially own 5% or more of any class or series of our capital stock. Additionally, if a market participant, together with its group members, acquires beneficial ownership of 5% or more of any series of the outstanding shares of our capital stock, such market participant or any shareholder who is a member of a group including a market participant will not be able to vote or direct or control the votes of shares representing 5% or more of any series of our outstanding capital stock. Finally, to the extent a market participant, together with its group members, acquires beneficial ownership of 5% or more of the outstanding shares of any series of our capital stock, our Articles of Incorporation allow our board of directors to redeem any shares of our capital stock so that, after giving effect to the redemption, the market participant, together with its group members, will cease to beneficially own 5% or more of that series of our outstanding capital stock.
Risks Related to the Entergy Transaction 
We may be unable to satisfy the conditions or obtain the approvals required to complete the Entergy Transaction or such approvals may contain material restrictions or conditions.
The consummation of the Entergy Transaction is subject to numerous conditions, including (i) consummation of certain transactions and financings contemplated by the merger agreement and the separation agreement (such as the separation of Entergy’s transmission business from its distribution business), (ii) the receipt of ITC Holdings shareholder approval, and (iii) the receipt of certain regulatory approvals in a form that will not impose a burdensome condition on us or Entergy (as described in the merger agreement). We can make no assurances that the Entergy Transaction will be consummated on the terms or timeline currently contemplated, or at all. We have and will continue to expend management’s time and resources and incur expenses due to legal, advisory and financial services fees related to the Entergy Transaction. Governmental agencies may not approve the Entergy Transaction or the related transactions necessary to complete it, or may impose conditions to any such approval or require changes to the terms of the Entergy Transaction. Any such conditions or changes could have the effect of delaying completion of the Entergy Transaction, imposing costs on or limiting the revenues of the combined company following the Entergy Transaction or otherwise reducing the anticipated benefits of the Entergy Transaction. Any condition or change which results in a burdensome condition on Entergy’s transmission business and/or us under the merger agreement and might cause Entergy and/or us to restructure or terminate the Entergy Transaction or the related transactions.
If completed, the Entergy Transaction may not be successful or achieve its anticipated benefits.
If the Entergy Transaction is completed, we may not successfully realize anticipated growth opportunities or integrate our business and operations with the acquired transmission business and operations. After the Entergy Transaction, we will have significantly more revenue, expenses, assets and employees than we did prior to the Entergy Transaction. In the Entergy Transaction, we will also be assuming certain liabilities of Entergy's transmission business and taking on other obligations (including collective bargaining agreements and certain pension obligations with respect to transferred employees). We may not successfully or cost-effectively integrate the acquired transmission business and operations into our business and operations. Even if the combined company is able to integrate the transmission businesses and operations successfully, this integration may not result in the realization of the full benefits of the growth opportunities that we currently expect from the Entergy Transaction within the anticipated time frame, or at all.


23


The merger agreement contains provisions that may discourage other companies from trying to acquire us.
The merger agreement contains provisions that may discourage a third party from submitting a business combination proposal to us prior to the closing of the Entergy Transaction that might result in greater value to ITC Holdings shareholders than the Entergy Transaction. The merger agreement generally prohibits us from soliciting any alternative acquisition proposal, although we may terminate the merger agreement in order to accept an unsolicited alternative transaction proposal that our board of directors determines is superior to the Entergy Transaction. In addition, before our board may withdraw or modify its recommendation or we may terminate the merger agreement to enter into a transaction that our board determines is superior to the Entergy Transaction, Entergy has the opportunity to negotiate with us to modify the terms of the Entergy Transaction in response to any competing acquisition proposals that may be made. If the merger agreement is terminated by us or Entergy in certain limited circumstances, we may be obligated to pay a termination fee to Entergy, which would represent an additional cost for a potential third party seeking a business combination with us.
Failure to complete the Entergy Transaction could adversely affect the market price of ITC Holdings common stock as well as our business, financial condition, results of operations and cash flows.
If the Entergy Transaction is not completed for any reason, the price of ITC Holdings common stock may decline to the extent that the market price of ITC Holdings common stock reflects positive market assumptions that the Entergy Transaction will be completed and the related benefits will be realized. In addition, significant expenses such as legal, advisory and financial services, many of which generally will be paid incurred regardless of whether the Entergy Transaction is completed, must be paid. Under the merger agreement, under certain limited circumstances, we must pay Entergy a termination fee.
Investors holding shares of ITC Holdings common stock immediately prior to the completion of the Entergy Transaction will, in the aggregate, have a significantly reduced ownership and voting interest in us after the Entergy Transaction and will exercise less influence over management.
Investors holding shares of ITC Holdings common stock immediately prior to the completion of the Entergy Transaction will, in the aggregate, own a significantly smaller percentage of the combined company immediately after the completion of the Entergy Transaction. Immediately following the completion of the Entergy Transaction, it is expected that Entergy shareholders will hold at least 50.1% of the ITC Holdings common stock on a fully diluted basis and existing ITC Holdings shareholders will hold no more than 49.9% of ITC Holdings common stock on a fully diluted basis (subject to adjustment in limited circumstances as provided in the merger agreement) and excluding any ITC equity awards issued to employees of the acquired business who become employees of our subsidiaries. In no event will Entergy shareholders hold less than 50.1% of our outstanding common stock immediately after the Entergy Transaction. Consequently, ITC Holdings shareholders, collectively, will be able to exercise less influence over the management and policies of the combined company than they are able to exercise over the management and our policies immediately prior to the completion of the Entergy Transaction.
After the completion of the merger, sales of ITC Holdings common stock may negatively affect its market price.
The shares of ITC Holdings common stock to be issued in the merger to Entergy shareholders will generally be eligible for immediate resale. The market price of ITC Holdings common stock could decline as a result of sales of a large number of shares of ITC Holdings common stock in the market after the completion of the merger or the perception in the market that these sales could occur.
Immediately following the completion of the merger, it is expected that former Entergy shareholders will hold approximately 50.1% of ITC Holdings' common stock on a fully diluted basis and existing ITC Holdings shareholders will hold approximately 49.9% of ITC Holdings' common stock on a fully diluted basis (subject to adjustment in limited circumstances as provided in the merger agreement and excluding any ITC Holdings equity awards issued to employees of Entergy's transmission business who become our employees). In no event will Entergy shareholders hold less than 50.1% of the outstanding common stock of ITC Holdings immediately after the merger. Certain former Entergy shareholders (such as certain index funds and institutional investors with specific investment guidelines that do not pertain to the stock of the combined company) who receive shares of ITC Holdings common stock pursuant to the merger agreement may be required to sell their shares of ITC Holdings common stock immediately after the merger, which may negatively affect the price of ITC Holdings' common stock following the merger.


24


We are required to abide by potentially significant restrictions which could limit our ability to undertake certain corporate actions (such as the issuance of ITC Holdings common stock or the undertaking of a merger or consolidation) that otherwise could be advantageous.
The merger agreement and the separation agreement impose certain ongoing restrictions on us to ensure that applicable statutory requirements under the Internal Revenue Code of 1986, as amended, and applicable Treasury regulations are met so that the Entergy Transaction qualifies as tax-free to Entergy and its shareholders. As a result of these restrictions, our ability to engage in certain transactions, such as the redemption of ITC Holdings common stock or the issuance of our equity securities (subject to certain exceptions generally relating to compensation) may be limited until two years and one day following the closing of the Entergy Transaction (excluding the $700 million recapitalization in the form of a one-time special dividend and/or share repurchase to be completed in connection with the Entergy Transaction).
If we take any of an enumerated list of actions and omissions that would cause the Entergy Transaction to become taxable, we generally will be required to bear the cost of any resulting tax liability. If the Entergy Transaction became taxable, Entergy would be expected to recognize a substantial amount of income, which would result in a material amount of taxes. Any such taxes allocated to us would be expected to be material to us, and could cause our business, financial condition and operating results to suffer. These restrictions may reduce our ability to engage in certain business transactions that otherwise might be advantageous to us.
ITEM 1B.     UNRESOLVED STAFF COMMENTS.
None.
ITEM 2.    PROPERTIES.
Our Regulated Operating Subsidiaries’ transmission facilities are located in Michigan’s Lower Peninsula and portions of Iowa, Minnesota, Illinois, Missouri, Kansas and Oklahoma. Our MISO Regulated Operating Subsidiaries have agreements with other utilities for the joint ownership of specific substations and transmission lines. See Note 15 to the consolidated financial statements.
ITCTransmission owns the assets of a transmission system and related assets, including:
approximately 2,800 circuit miles of overhead and underground transmission lines rated at voltages of 120 kV to 345 kV;
approximately 17,700 transmission towers and poles;
station assets, such as transformers and circuit breakers, at 171 stations and substations which either interconnect ITCTransmission’s transmission facilities or connect ITCTransmission’s facilities with generation or distribution facilities owned by others;
other transmission equipment necessary to safely operate the system (e.g., monitoring and metering equipment);
warehouses and related equipment;
associated land held in fee, rights of way and easements;
an approximately 188,000 square-foot corporate headquarters facility and operations control room in Novi, Michigan, including furniture, fixtures and office equipment; and
an approximately 40,000 square-foot facility in Ann Arbor, Michigan that includes a back-up operations control room.
ITCTransmission’s First Mortgage Bonds are issued under ITCTransmission’s First Mortgage and Deed of Trust. As a result, the bondholders have the benefit of a first mortgage lien on substantially all of ITCTransmission’s property.
METC owns the assets of a transmission system and related assets, including:
approximately 5,600 circuit miles of overhead transmission lines rated at voltages of 120 kV to 345 kV;
approximately 36,900 transmission towers and poles;


25


station assets, such as transformers and circuit breakers, at 98 stations and substations which either interconnect METC’s transmission facilities or connect METC’s facilities with generation or distribution facilities owned by others;
other transmission equipment necessary to safely operate the system (e.g., monitoring and metering equipment); and
warehouses and related equipment.

METC's Senior Secured Notes are issued under METC's First Mortgage Indenture. As a result, the noteholders have the benefit of a first mortgage lien on substantially all of METC's property.
METC does not own the majority of the land on which its assets are located, but under the provisions of its Easement Agreement with Consumers Energy, METC has an easement to use the land, rights-of-way, leases and licenses in the land on which its transmission lines are located that are held or controlled by Consumers Energy. See “Item 1 Business — Operating Contracts — METC — Amended and Restated Easement Agreement.”
ITC Midwest owns the assets of a transmission system and related assets, including:
approximately 6,600 circuit miles of transmission lines rated at voltages of 34.5 kV to 345 kV;
transmission towers and poles;
station assets, such as transformers and circuit breakers, at approximately 262 stations and substations which either interconnect ITC Midwest’s transmission facilities or connect ITC Midwest’s facilities with generation or distribution facilities owned by others;
other transmission equipment necessary to safely operate the system (e.g., monitoring and metering equipment);
warehouses and related equipment; and
associated land held in fee, rights of way and easements.
ITC Midwest’s First Mortgage Bonds are issued under ITC Midwest’s First Mortgage and Deed of Trust. As a result, the bondholders have the benefit of a first mortgage lien on substantially all of ITC Midwest’s property.
ITC Great Plains owns the assets of a transmission system and related assets including:
approximately 190 miles of transmission lines rated at a voltage of 345 kV;
approximately 1,168 transmission towers and poles;
station assets, such as transformers and circuit breakers, at 5 stations and substations which either interconnect ITC Great Plains’ transmission facilities or connect ITC Great Plains’ facilities with transmission, generation or distribution facilities owned by others;
other transmission equipment necessary to safely operate the system (e.g., monitoring and metering equipment); and
associated land held in fee, rights of way and easements.
As of December 31, 2012, there were no liens or encumbrances on the assets of ITC Great Plains.
The assets of our Regulated Operating Subsidiaries are suitable for electric transmission and adequate for the electricity demand in our service territory. We prioritize capital spending based in part on meeting reliability standards within the industry. This includes replacing and upgrading existing assets as needed.
ITEM 3.     LEGAL PROCEEDINGS.
We are involved in certain legal proceedings before various courts, governmental agencies, and mediation panels concerning matters arising in the ordinary course of business. These proceedings include certain contract disputes, regulatory matters and pending judicial matters. We cannot predict the final disposition of such proceedings. We regularly review legal matters and record provisions for claims that are considered probable of loss. 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.


26


Refer to Notes 4 and 16 to the consolidated financial statements for a description of pending litigation.
ITEM 4.     MINE SAFETY DISCLOSURES.
Not applicable.
PART II
ITEM 5.
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.
Stock Price and Dividends
Our common stock has traded on the NYSE since July 26, 2005 under the symbol “ITC”. Prior to that time, there was no public market for our stock. As of February 26, 2013, there were approximately 648 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 2012 and 2011, as reported on the NYSE and the cash dividends per share paid during the periods indicated.
Year Ended December 31, 2012
 
      High
 
      Low
 
Dividends
Quarter ended December 31, 2012
 
$79.75
 
$74.28
 
$0.3775
Quarter ended September 30, 2012
 
$75.87
 
$69.10
 
$0.3775
Quarter ended June 30, 2012
 
$78.86
 
$66.30
 
$0.3525
Quarter ended March 31, 2012
 
$78.51
 
$71.65
 
$0.3525
 
 
 
 
 
 
 
Year Ended December 31, 2011
 
      High
 
      Low
 
Dividends
Quarter ended December 31, 2011
 
$81.90
 
$70.00
 
$0.3525
Quarter ended September 30, 2011
 
$78.89
 
$64.88
 
$0.3525
Quarter ended June 30, 2011
 
$74.67
 
$67.46
 
$0.3350
Quarter ended March 31, 2011
 
$70.28
 
$61.76
 
$0.3350
The declaration and payment of dividends is subject to the discretion of ITC Holdings’ board of directors and depends on various factors, including our net income, financial condition, cash requirements, future prospects and other factors deemed relevant by ITC Holdings’ board of directors. As a holding company with no business operations, ITC Holdings’ material assets consist primarily of the common stock or ownership interests in its subsidiaries, deferred tax assets 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 default under our revolving and term loan credit facilities. Further, each of our subsidiaries is legally distinct from ITC Holdings and has no obligation, contingent or otherwise, to make funds available to ITC Holdings.
If and when ITC Holdings pays a dividend on its common stock, pursuant to our special bonus plans for executives and certain non-executive employees, amounts equivalent to the dividend may be paid to the special bonus plan participants, if approved by the compensation committee. We currently expect these amounts to be paid upon the declaration of dividends on ITC Holdings’ common stock.
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.
Prior to closing the Entergy Transaction, we expect to effectuate a $700 million recapitalization, which may take the form of a one-time special dividend to ITC Holdings’ pre-merger shareholders, a repurchase of ITC Holdings common stock from its shareholders, or a combination of a special dividend and share repurchase.


27


See discussion of certain restrictions on our ability to pay dividends related to the Entergy Transaction as discussed under “Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations — Capital Project Updates and Other Recent Developments.”
The transfer agent for the common stock is Computershare Trust Company, N.A., P.O. Box 43078 Providence, RI 02940-3078.
In addition, the information contained in the Equity Compensation table under “Item 12 Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters” of this report is incorporated herein by reference.
Stock Repurchases
The following table sets forth, the repurchases of common stock for the quarter ended December 31, 2012:
Period
 
 Total Number of
Shares Purchased (1)
 
 Average Price
Paid per Share
 
Total Number of
Shares Purchased as
Part of Publicly
Announced Plan or Program (2)
 
Maximum Number or
Approximate Dollar
Value of Shares that May
Yet Be Purchased Under the Plans or Programs (2)
 
 
 
 
October 2012
 

 
$

 

 

November 2012
 
192

 
76.90

 

 

December 2012
 
30,158

 
78.08

 

 

Total
 
30,350

 
$
78.07

 

 

____________________________
(1)
Shares acquired were delivered to us by employees as payment of tax withholding obligations due to us upon the vesting of restricted stock.
(2)
We do not have a publicly announced share repurchase plan.


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ITEM 6.     SELECTED FINANCIAL DATA.
The selected historical financial data presented below should be read together with our consolidated financial statements and the notes to those statements and “Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations,” included elsewhere in this Form 10-K.
 
ITC Holdings and Subsidiaries
 
Year Ended December 31,
(In thousands, except per share data)
2012
 
2011
 
2010
 
2009
 
2008
OPERATING REVENUES
$
830,535

 
$
757,397

 
$
696,843

 
$
621,015

 
$
617,877

OPERATING EXPENSES

 
 
 
 
 
 
 
 
Operation and maintenance (a)
121,941

 
129,288

 
126,528

 
95,730

 
113,818

General and administrative (a) (b) (c)
112,091

 
82,790

 
78,120

 
69,231

 
81,296

Depreciation and amortization (d)
106,512

 
94,981

 
86,976

 
85,949

 
94,769

Taxes other than income taxes
59,701

 
53,430

 
48,195

 
43,905

 
41,180

Other operating (income) and expense — net
(769
)
 
(844
)
 
(297
)
 
(667
)
 
(809
)
Total operating expenses
399,476

 
359,645

 
339,522

 
294,148

 
330,254

OPERATING INCOME
431,059

 
397,752

 
357,321

 
326,867

 
287,623

OTHER EXPENSES (INCOME)
 
 
 
 
 
 
 
 
 
Interest expense
155,734

 
146,936

 
142,553

 
130,209

 
122,234

Allowance for equity funds used during construction
(23,000
)
 
(16,699
)
 
(13,412
)
 
(13,203
)
 
(11,610
)
Loss on extinguishment of debt

 

 

 
1,263

 

Other income
(2,401
)
 
(2,881
)
 
(2,340
)
 
(2,792
)
 
(3,415
)
Other expense
4,218

 
3,962

 
2,588

 
2,918

 
3,944

Total other expenses (income)
134,551

 
131,318

 
129,389

 
118,395

 
111,153

INCOME BEFORE INCOME TAXES
296,508

 
266,434

 
227,932

 
208,472

 
176,470

INCOME TAX PROVISION
108,632

 
94,749

 
82,254

 
77,572

 
67,262

NET INCOME
$
187,876

 
$
171,685

 
$
145,678

 
$
130,900

 
$
109,208

 
 
 
 
 
 
 
 
 
 
Basic earnings per share
$
3.65

 
$
3.36

 
$
2.89

 
$
2.62

 
$
2.22

Diluted earnings per share
$
3.60

 
$
3.31

 
$
2.84

 
$
2.58

 
$
2.18

Dividends declared per share
$
1.460

 
$
1.375

 
$
1.310

 
$
1.250

 
$
1.190

 
ITC Holdings and Subsidiaries
 
As of December 31,
(In thousands)
2012
 
2011
 
2010
 
2009
 
2008
BALANCE SHEET DATA:
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$
26,187

 
$
58,344

 
$
95,109

 
$
74,853

 
$
58,110

Working capital (deficit)
(805,085
)
 
(113,939
)
 
69,338

 
147,335

 
1,095

Property, plant and equipment — net
4,134,579

 
3,415,823

 
2,872,277

 
2,542,064

 
2,304,386

Goodwill
950,163

 
950,163

 
950,163

 
950,163

 
951,319

Total assets
5,564,809

 
4,823,366

 
4,307,873

 
4,029,716

 
3,714,565

Debt:
 
 
 
 
 
 
 
 
 
ITC Holdings
1,689,619

 
1,459,599

 
1,459,178

 
1,458,757

 
1,327,741

Regulated Operating Subsidiaries
1,457,608

 
1,185,423

 
1,037,718

 
975,641

 
920,512

Total debt
3,147,227

 
2,645,022

 
2,496,896

 
2,434,398

 
2,248,253

Total stockholders’ equity
$
1,414,855

 
$
1,258,892

 
$
1,117,433

 
$
1,011,523

 
$
929,063



29


 
ITC Holdings and Subsidiaries
 
Year Ended December 31,
(In thousands)
2012
 
2011
 
2010
 
2009
 
2008
CASH FLOWS DATA:
 
 
 
 
 
 
 
 
 
Capital expenditures
$
802,763

 
$
556,931

 
$
388,401

 
$
404,514

 
$
401,840

____________________________
(a)
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.
(b)
During 2011 and 2009, we recognized $2.1 million and $10.0 million, respectively of regulatory assets associated with the development activities of ITC Great Plains as well as certain pre-construction costs for the Kansas V-Plan and KETA projects. Upon initial establishment of these regulatory assets in 2011 and 2009, $2.1 million and $8.0 million, respectively, of general and administrative expenses were reversed of which $1.4 million and $5.9 million were incurred in periods prior to 2011 and 2009, respectively. No initial establishment of regulatory assets occurred in 2010 that resulted in reversal of expenses.
(c)
During 2012 and 2011, we expensed external legal, advisory and financial services fees of $19.4 million and $7.0 million, respectively relating to the proposed Entergy Transaction recorded within general and administrative expenses of which certain amounts are not expected to be deductible for income tax purposes.
(d)
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.
ITEM 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
Safe Harbor Statement Under The Private Securities Litigation Reform Act of 1995
Our reports, filings and other public announcements contain certain statements that describe our management’s beliefs concerning future business conditions, plans and prospects, growth opportunities and the outlook for our business and the electric transmission industry based upon information currently available. Such statements are “forward-looking” statements within the meaning of the Private Securities Litigation Reform Act of 1995. Wherever possible, we have identified these forward-looking statements by words such as “will,” “may,” “anticipates,” “believes,” “intends,” “estimates,” “expects,” “projects” and similar phrases. These forward-looking statements are based upon assumptions our management believes are reasonable. Such forward-looking statements are subject to risks and uncertainties which could cause our actual results, performance and achievements to differ materially from those expressed in, or implied by, these statements, including, among others, the risks and uncertainties listed in “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. Except as required by law, we undertake no obligation to publicly update any of our forward-looking or other statements, whether as a result of new information, future events, or otherwise.
Overview
Through our Regulated Operating Subsidiaries, we operate high-voltage systems in Michigan’s Lower Peninsula and portions of Iowa, Minnesota, Illinois, Missouri, Kansas and Oklahoma that transmit electricity from generating stations to local distribution facilities connected to our systems. Our business strategy is to operate, maintain and


30


invest in transmission infrastructure in order to enhance system integrity and reliability, to reduce transmission constraints and to upgrade the transmission networks to support new generating resources interconnecting to our transmission systems. We also are pursuing development projects not within our existing systems, which are also intended to improve overall grid reliability, reduce transmission constraints and facilitate interconnections of new generating resources, as well as enhance competitive wholesale electricity markets.
As electric transmission utilities with rates regulated by the FERC, our Regulated Operating Subsidiaries earn revenues through tariff rates charged for the use of their electric transmission systems by our customers, which include investor-owned utilities, municipalities, cooperatives, power marketers and alternative energy suppliers. As independent transmission companies, our Regulated Operating Subsidiaries are subject to rate regulation only by the FERC. The rates charged by our Regulated Operating Subsidiaries are established using cost-based formula rate templates, as discussed in “Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations — Cost-Based Formula Rates with True-Up Mechanism.”
Our Regulated Operating Subsidiaries’ primary operating responsibilities include maintaining, improving and expanding their transmission systems to meet their customers’ ongoing needs, scheduling outages on system elements to allow for maintenance and construction, maintaining appropriate system voltages and monitoring flows over transmission lines and other facilities to ensure physical limits are not exceeded.
We derive nearly all of our revenues from providing electric transmission service over our Regulated Operating Subsidiaries' transmission systems to investor-owned utilities such as Detroit Edison, Consumers Energy and IP&L, and to other entities such as alternative electricity suppliers, power marketers and other wholesale customers that provide electricity to end-use consumers and from transaction-based capacity reservations on our transmission systems.
Significant recent matters that influenced our financial position and results of operations and cash flows for the year ended December 31, 2012 or may affect future results include:
Our capital investment of $819.8 million at our Regulated Operating Subsidiaries ($231.2 million, $149.0 million, $343.3 million and $96.3 million at ITCTransmission, METC, ITC Midwest and ITC Great Plains, respectively) for the year ended December 31, 2012, resulting primarily from our focus on improving system reliability, increasing system capacity and upgrading the transmission network to support new generating resources;
Debt issuances and borrowings under our revolving and term loan credit agreements in 2012 and 2011 to fund capital investment at our Regulated Operating Subsidiaries, resulting in higher interest expense;
Debt maturing within one year and the resulting additional financing required as discussed in Note 8 to the consolidated financial statements;
Final recognition of revenues for the ITCTransmission rate freeze revenue deferral in May 2011, 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 — ITCTransmission’s Rate Freeze Revenue Deferral”;
The Entergy Transaction in which Entergy will divest and merge its electric transmission business with a wholly-owned subsidiary of ITC Holdings as discussed in “Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations — Capital Project Updates and Other Recent Developments.” In 2012, we expensed external legal, advisory and financial services fees of $19.4 million and internal labor costs of approximately $7.1 million related to the Entergy Transaction primarily recorded within general and administrative expenses. Certain amounts of the external costs are not expected to be deductible for income tax purposes. The external and internal costs related to the Entergy Transaction are not included as components of revenue requirement as they were incurred at ITC Holdings. The transaction fees are expected to continue to be significant until the transaction is consummated. Completion of the transaction is anticipated to occur in 2013; and
Recognition of the refund obligation at our MISO Regulated Operating Subsidiaries for the FERC audit of ITC Midwest, as discussed in Note 16 to the consolidated financial statements under “Commitments and Contingent Liabilities — FERC Audit of ITC Midwest.”
These items are discussed in more detail throughout Management’s Discussion and Analysis of Financial Condition and Results of Operations.


31


Cost-Based Formula Rates with True-Up Mechanism
Our Regulated Operating Subsidiaries calculate their revenue requirements using cost-based formula rate templates and are effective without the need to file rate cases with the FERC, although the rates are subject to legal challenge at the FERC. Under these formula rate templates, our Regulated Operating Subsidiaries recover expenses and earn a return on and recover investments in property, plant and equipment on a current rather than a lagging basis. The formula rate templates utilize forecasted expenses, property, plant and equipment, point-to-point revenues, network load at our MISO Regulated Operating Subsidiaries and other items for the upcoming calendar year to establish projected revenue requirements for each of our Regulated Operating Subsidiaries that are used as the basis for billing for service on their systems from January 1 to December 31 of that year. Our cost-based formula rate templates include a true-up mechanism, whereby our Regulated Operating Subsidiaries compare their actual revenue requirements to their billed revenues for each year to determine any over- or under-collection of revenue. The over- or under-collection typically results from differences between the projected revenue requirement used as the basis for billing and actual revenue requirement at each of our Regulated Operating Subsidiaries, or from differences between actual and projected monthly peak loads at our MISO Regulated Operating Subsidiaries. In the event billed revenues in a given year are more or less than actual revenue requirements, which are calculated primarily using information from that year’s FERC Form No. 1, our Regulated Operating Subsidiaries will refund or collect additional revenues, with interest, within a two-year period such that customers pay only the amounts that correspond to actual revenue requirements for that given period. This annual true-up ensures that our Regulated Operating Subsidiaries recover their allowed costs and earn their allowed returns.
ITCTransmission’s Rate Freeze Revenue Deferral
ITCTransmission’s rate freeze 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 for the period from February 28, 2003 through December 31, 2004. The rate freeze revenue deferral was amortized for ratemaking on a straight-line basis for five years from June 2006 through May 2011 and was included in ITCTransmission’s revenue requirement for those periods. Revenues of $5.0 million relating to the rate freeze revenue deferral were recognized in January through May 2011, which resulted in a reduction to after-tax net income of approximately $3.2 million in 2012 compared to 2011.
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 accrue or defer revenues to the extent that their actual revenue requirement for the reporting period is higher or lower, respectively, than the amounts billed relating to that reporting period. For example, to the extent that amounts billed are less than the revenue requirement for a reporting period, a revenue accrual is recorded for the difference. To the extent that amounts billed are more than the revenue requirement for a reporting period, a revenue deferral is recorded for the difference. Although monthly peak loads do not impact operating revenues recognized, network load affects the timing of our cash flows from transmission service. The monthly peak load of our MISO Regulated Operating Subsidiaries is affected by many variables, but is generally impacted by weather and economic conditions and is seasonally shaped with higher load in the summer months when cooling demand is higher.


32


The following table sets forth the monthly peak loads during the last three calendar years.
Monthly Peak Load (in MW) (a)
 
2012
 
2011
 
2010
 
 
 
 
 
ITC
 
 
 
 
 
ITC
 
 
 
 
 
ITC
 
ITCTransmission
 
METC
 
Midwest
 
ITCTransmission
 
METC
 
Midwest
 
ITCTransmission
 
METC
 
Midwest
January
7,264
 
6,145
 
2,789
 
7,326
 
6,045
 
2,777
 
7,255
 
5,947
 
2,838
February
6,919
 
5,754
 
2,592
 
7,261
 
6,058
 
2,854
 
6,998
 
5,800
 
2,782
March
6,941
 
5,708
 
2,443
 
6,946
 
5,715
 
2,520
 
6,620
 
5,376
 
2,517
April
6,403
 
5,259
 
2,296
 
6,483
 
5,416
 
2,458
 
6,501
 
5,112
 
2,425
May
8,947
 
6,459
 
2,700
 
10,119
 
7,239
 
2,773
 
9,412
 
7,240
 
3,052
June
11,652
 
8,738
 
3,388
 
11,488
 
8,231
 
3,403
 
9,722
 
7,128
 
3,207
July
12,222
 
9,358
 
3,643
 
12,321
 
9,389
 
3,621
 
11,451
 
8,498
 
3,422
August
11,087
 
8,520
 
3,477
 
11,158
 
8,538
 
3,614
 
11,082
 
8,422
 
3,399
September
9,094
 
7,308
 
3,411
 
11,288
 
7,966
 
3,466
 
10,817
 
7,353
 
2,804
October
6,626
 
5,428
 
2,487
 
6,642
 
5,479
 
2,559
 
6,725
 
5,414
 
2,447
November
7,024
 
5,953
 
2,680
 
7,101
 
6,061
 
2,556
 
6,930
 
5,734
 
2,674
December
7,226
 
5,891
 
2,682
 
7,206
 
6,071
 
2,734
 
7,824
 
6,526
 
2,928
Total
101,405
 
80,521
 
34,588
 
105,339
 
82,208
 
35,335
 
101,337
 
78,550
 
34,495
____________________________
(a)
Our MISO Regulated Operating Subsidiaries are each part of a joint rate zone. The load data presented is for all transmission owners in the respective joint rate zone and is used for billing network revenues. Each of our MISO Regulated Operating Subsidiaries makes up the most significant portion of the rates or revenue requirement billed to network load within their respective joint rate zone.
The following table presents the network transmission rates (per kW/month) for our MISO Regulated Operating Subsidiaries as posted by MISO that are relevant to our cash flows since January 1, 2010:
Network Transmission Rate
ITCTransmission
 
METC
 
ITC Midwest
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
January 1, 2012 to December 31, 2012
$2.188
 
$2.409
 
$6.797
January 1, 2013 to December 31, 2013
$2.147
 
$2.5263
 
$7.805
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 its annual projected revenue requirement posted annually by SPP.
Revenue Requirement Calculation
Under their cost-based formula rate templates, each of our Regulated Operating Subsidiaries separately calculates a revenue requirement based on financial information specific to each company. The calculation of actual revenue requirements for a historic period is used to calculate the amount of network revenues recognized in that period and to calculate the true-up adjustment for that period. The calculation of projected revenue requirements is used to establish the transmission rate used for billing purposes, and follows the same methodology as the calculation of actual revenue requirement. The following steps illustrate the calculation of revenue requirement and the rate-setting methodology under the formula rate template with a true-up mechanism used by our MISO Regulated Operating Subsidiaries. ITC Great Plains follows a similar methodology and uses a FERC-approved return of 12.16% on the common equity portion of its capital structure.
Step One — Establish Projected Rate Base and Calculate Projected Allowed Return
Rate base is projected using the average of the projected month-end balances for the months beginning with December 31 of the current year and ending with December 31 of the upcoming year and consists primarily of projected in-service property, plant and equipment, net of accumulated depreciation, as well as other items.


33


Projected rate base is multiplied by the projected weighted average cost of capital to determine the projected allowed return on rate base. The weighted average cost of capital is calculated using a projected 13-month average capital structure, the forecasted pre-tax cost of the debt portion of the capital structure and a FERC-approved return of 13.88%, 13.38%, and 12.38% for ITCTransmission, METC, and, ITC Midwest, respectively, on the common equity portion of the capital structure.
Step Two — Calculate Projected Gross Revenue Requirement
The projected gross revenue requirement is calculated beginning with the projected allowed return on rate base, as calculated in Step One above, and adding projected recoverable operating expenses and an allowance for income taxes, depreciation and amortization.
Step Three — Calculate Projected Revenue Requirement
After calculating the projected gross revenue requirement in Step Two above, the 2013 projected gross revenue requirement is adjusted for any 2011 true-up adjustment and is reduced for certain revenues received other than network revenues, such as projected point-to-point, regional cost sharing revenues and rental revenues to arrive at our projected revenue requirement.
Illustration of Formula Rate Setting
Set forth below is a simplified illustration of the calculation of ITCTransmission’s projected 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, 2013 through December 31, 2013, that was based primarily upon projections of ITCTransmission’s 2013 FERC Form No. 1 data. Amounts below are approximations of the amounts used to establish ITCTransmission’s 2013 projected revenue requirement.
Line
Item
Instructions
Amount
1
Projected rate base

 
$
1,162,323,000

2
Multiply by projected 13-month weighted average cost of capital (a)

 
10.25
%
3
Projected allowed return on rate base

(Line 1 x Line 2)
$
119,138,108

4
Projected recoverable operating expenses for 2013

 
$
60,585,000

5
Projected taxes and depreciation and amortization for 2013

 
$
141,022,000

6
Projected gross revenue requirements for 2013

(Line 3 + Line 4 + Line 5)

$
320,745,108

7
Less projected revenue credits for 2013

 
$
(74,481,000
)
8
Plus/(less) 2011 true-up adjustment
 
$
(25,537,000
)
9
Projected revenue requirement for 2013

(Line 6 + Line 7 + Line 8)

$
220,727,108

10
Projected average monthly 2013 network load (in kW)

 
8,567,000

11
Annual component of the joint zone network transmission rate

(Line 9 divided by Line 10)

$
25.765

12
Monthly component of the joint zone network transmission rate ($/kW per month)

(Line 11 divided by
12 months)

$
2.147

____________________________
(a)
The weighted average cost of capital for purposes of this illustration is calculated as follows:
 
 
 
 
 
Weighted
 
Percentage of
 
 
 
Average
 
ITCTransmission’s
 
 
 
Cost of
 
Total Capitalization
 
Cost of Capital
 
Capital
Debt
40.00%
 
4.80% (Pre-tax) =
 
1.92
%
Equity
60.00%
 
13.88% (After tax) =
 
8.33
%
 
100.00%
 
 
 
10.25
%
Capital Investment and Operating Results Trends
We expect a general trend of increases in revenues and earnings for our Regulated Operating Subsidiaries over the long term. The primary factor that is expected to continue to increase our actual revenue requirements in future years is our anticipated capital investment in excess of depreciation as a result of our Regulated Operating Subsidiaries’ long-term capital investment programs to improve reliability, increase system capacity and upgrade the transmission network to support new generating resources, as well as the Entergy Transaction. In addition,


34


our capital investment efforts relating to development initiatives are based on establishing an ongoing pipeline of projects that will position us for long-term growth. Investments in property, plant and equipment, when placed in service upon completion of a capital project, are added to the rate base of our Regulated Operating Subsidiaries.
Our Regulated Operating Subsidiaries strive for high reliability of their systems and to improve system accessibility for all generation resources. 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 standards established by the NERC, as well as the standards of applicable regional entities under the NERC that have been delegated certain authority for the purpose of proposing and enforcing reliability standards. We believe we meet the applicable standards in all material respects, although further investment in our transmission systems and an increase in maintenance activities will likely be needed to maintain compliance, improve reliability and address any new standards that may be promulgated.
We also assess our transmission systems against our own planning criteria that are filed annually with the FERC. Based on our planning studies, we see needs to make capital investments to (1) rebuild existing property, plant and equipment; (2) upgrade the system to address demographic changes that have impacted transmission load and the changing role that transmission plays in meeting the needs of the wholesale market, including accommodating the siting of new generation or to increase import capacity to meet changes in peak electrical demand; (3) relieve congestion in the transmission systems; and (4) achieve state and federal policy goals, such as renewable generation portfolio standards. The following table shows our expected and actual capital investment for each of the Regulated Operating Subsidiaries and our development initiatives:
 
 
 
 
Actual Capital
 
Forecasted Capital
 
 
Long-term Capital
 
Investment for the
 
Investment for the
 
 
Investment Program
 
Year Ended
 
Year Ending
Source of Investment
 
2012-2016 (a)
 
December 31, 2012 (b)
 
December 31, 2013 (a)
(In millions)
 
 
 
 
 
 
ITCTransmission
 
$
739

 
$
231.2

 
$200 — 230
METC
 
581

 
149.0

 
160 — 180
ITC Midwest
 
1,128

 
343.3

 
270 — 300
ITC Great Plains (c)
 
343

 
96.3

 
130 — 150
Development (d)
 
1,390

 

 
Total
 
$
4,181

 
$
819.8

 
$760 — 860
____________________________
(a)
The current long-term capital investment program does not include anticipated expenditures related to the Entergy Transaction. The investments in property, plant and equipment would be expected to increase significantly upon closing of that transaction.
(b)
Capital investment amounts differ from cash expenditures for property, plant and equipment included in our consolidated statements of cash flows due in part to differences in construction costs incurred compared to cash paid during that period, as well as payments for major equipment inventory that are included in cash expenditures but not included in capital investment until transferred to construction work in progress, among other factors.
(c)
ITC Great Plains’ investment program includes the Kansas V-Plan Project that is under construction in addition to the KETA and Hugo-to-Valliant projects which were completed and placed in-service in 2012.
(d)
The long-term capital investment program includes expenditures to construct various development projects such as our portions of the four MISO MVPs.
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 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


35


to meet the various criteria of Attachment FF of the MISO tariff for the project to qualify as a refundable network upgrade, and other factors beyond our control.
Capital Project Updates and Other Recent Developments
Thumb Loop Project
The Thumb Loop Project is located in ITCTransmission’s region and consists of a 140-mile, double-circuit 345 kV transmission line and related substations that will serve as the backbone of the transmission system needed to accommodate future wind development projects in the Michigan counties of Tuscola, Huron, Sanilac and St. Clair. Construction activities commenced for the Thumb Loop Project in 2012. Through December 31, 2012, ITCTransmission has invested $173.5 million in the Thumb Loop Project. We estimate ITCTransmission will invest a total of approximately $510 million to complete construction of the project.
ITC Great Plains
KETA Project
The KETA Project is a 225-mile transmission line that runs between Spearville, Kansas and Axtell, Nebraska. The portion of the transmission line that ITC Great Plains was responsible for constructing runs approximately 174 miles. The KETA Project was placed in-service in 2012.
Kansas V-Plan Project
The Kansas V-Plan Project is a 200-mile transmission line that will run between Spearville and Wichita, Kansas. ITC Great Plains is responsible for constructing an approximately 120 mile portion of the project from Spearville to Medicine Lodge, Kansas. ITC Great Plains commenced construction during 2012, and through December 31, 2012, ITC Great Plains has invested $37.4 million in the Kansas V-Plan Project. We estimate that ITC Great Plains will invest a total of approximately $300 million to complete construction of its portion of the project.
Regulatory Assets
As of December 31, 2012, we have recorded approximately $14.1 million of regulatory assets for start-up and development expenses incurred by ITC Great Plains, which include certain costs incurred for the KETA Project and the Kansas V-Plan Project prior to construction. In March 2011, we recognized a regulatory asset for the Kansas V-Plan Project of $2.0 million and a corresponding reduction to operating expenses, which increased net income by $1.3 million. Subsequent to the initial recognition of the Kansas V-Plan Project regulatory asset in March 2011, we recorded costs incurred for the Kansas V-Plan Project directly to this regulatory asset. Based on ITC Great Plains’ FERC application under which authority to recognize these regulatory assets was sought and the related FERC order, ITC Great Plains will be required to make an additional filing with the FERC under Section 205 of the FPA in order to recover these start-up, development and pre-construction expenses in future rates.
Development Bonuses
During 2012 and 2011, we recognized general and administrative expenses of $2.9 million and $1.2 million, respectively, for bonuses for the successful completion of certain milestones relating to projects at ITC Great Plains. It is reasonably possible that future development-related bonuses would be authorized and awarded for these or other development projects.
North Central Region Development
In 2009, we announced the Green Power Express project, which consisted of transmission line segments that would facilitate the movement of power from the Dakotas, Minnesota and Iowa to Midwest load centers that demand energy. After the announcement of the Green Power Express project, MISO undertook RGOS to promote investments in new regional transmission infrastructure and implemented its MVP cost allocation methodology. MISO’s RGOS and MVP processes provide a channel for the Green Power Express project, or its underlying segments, to move forward through the planning approval process as MVPs. In December 2011, MISO approved the first portfolio of MVPs identified through the RGOS which includes portions of four MVPs that we intend to build, own and operate. The four MVPs are located in south central Minnesota, portions of Iowa, southwest Wisconsin, and northeast Missouri.
We continue to explore other opportunities to advance segments of our Green Power Express project, or similar RGOS projects, through the MISO MVP process.


36


Entergy Transaction
As of December 4, 2011, Entergy and ITC Holdings executed definitive agreements (“transaction agreements”) under which Entergy will divest and then merge its electric transmission business with a wholly-owned subsidiary of ITC Holdings. Entergy’s electric transmission business consists of approximately 15,400 miles of interconnected transmission lines at voltages of 69 kV and above and associated substations across its utility service territory in the Mid-South.
The Entergy Transaction would expand our network across the entire middle of the continental United States from the Great Lakes to the Gulf Coast. It will approximately double our asset base, add sizable new markets to our operating and development portfolio, and diversify and enhance growth prospects through an expanded footprint.
The terms of the transaction agreements call for Entergy to divest its electric transmission business to a newly-formed entity, Mid South TransCo LLC (“Mid South TransCo”), and Mid South TransCo’s subsidiaries, and distribute the equity interests in Mid South TransCo to Entergy’s shareholders in the form of a tax-free spin-off. Mid South TransCo will then merge with a newly-created merger subsidiary of ITC Holdings in an all-stock, Reverse Morris Trust transaction, and will survive the merger as a wholly owned subsidiary of ITC Holdings. Prior to closing the merger, we expect to effectuate a $700 million recapitalization, which may take the form of a one-time special dividend to ITC Holdings’ pre-merger shareholders, a repurchase of ITC Holdings common stock from its shareholders, or a combination of a special dividend and share repurchase. The merger will result in shareholders of Entergy receiving approximately 50.1% of the shares of pro forma ITC Holdings in exchange for their shares of Mid South TransCo, with existing shareholders of ITC Holdings owning the remaining approximately 49.9% of the combined company. In addition, Entergy will receive gross cash proceeds of $1.775 billion from indebtedness that will be incurred by Mid South TransCo and its subsidiaries prior to the merger. This indebtedness will be assumed by us upon completion of the transaction.
Completion of the Entergy Transaction is expected in 2013 and is subject to the satisfaction of certain closing conditions, including receipt of the necessary approvals of Entergy’s retail regulators, the FERC and ITC Holdings’ shareholders. There can be no assurance the Entergy Transaction will be consummated. See “Item 1A Risk Factors — We may be unable to satisfy the conditions or obtain the approvals required to complete the Entergy Transaction or such approvals may contain material restrictions or conditions.”
Per the transaction agreements, prior to completion of the Entergy Transaction, there are certain restrictions on our ability to pay dividends other than those paid in the ordinary course of business with record dates and payment dates consistent with our past practice and, if elected, a one-time special dividend to ITC Holdings’ pre-merger shareholders in accordance with the transaction agreements. Management does not expect the restrictions to have an impact on our ability to pay dividends at the current level for the foreseeable future.
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 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:


37


(1)
multiply the network load measured in kW achieved during the one hour of monthly peak usage for our transmission systems by the appropriate monthly tariff rate by 12 by the number of days in that month; and
(2)
divide the result by 365.
Network revenues from ITC Great Plains include the annual revenue requirements specific to projects that are charged exclusively within one pricing zone within SPP or are classified as direct assigned network upgrades under the SPP tariff and contain a true-up mechanism. Our annual projected project revenue requirements at ITC Great Plains are billed ratably each month and therefore peak usage does not impact its billed network transmission revenues.
Point-to-Point Revenues consist of revenues generated from a type of transmission service for which the customer pays for transmission capacity reserved along a specified path between two points on an hourly, daily, weekly or monthly basis. Point-to-point revenues also include other components pursuant to schedules under the MISO and SPP transmission tariffs. Point-to-point revenues are a reduction to gross revenue requirement when calculating net revenue requirement under our cost-based formula rates.
Regional Cost Sharing Revenues are generated from transmission customers throughout RTO regions for their use of our MISO Regulated Operating Subsidiaries’ network upgrade projects that are eligible for regional cost sharing under provisions of the MISO tariff, including MVP projects such as the Thumb Loop Project. Regional cost sharing revenue also includes revenues collected by transmission customers from other RTOs outside of MISO to allocate costs of certain transmission plant investments. Additionally, the KETA Project and Kansas V-Plan Project at ITC Great Plains are eligible for recovery through a region-wide charge under provisions of the SPP tariff. Regional cost sharing revenues consist of both billed regional cost sharing revenues and accrued or deferred revenues as a result of our accounting under our cost-based formula rates that contain a true-up mechanism. The amount of the regional cost sharing revenue accruals (deferrals) is estimated for each reporting period until such time as the regional cost sharing formula rate templates based on actual costs are completed for each of our Regulated Operating Subsidiaries during the following year. A portion of regional costs sharing revenues are not subject to a direct true-up but instead are treated as reduction to either our regional or network gross revenue requirement when calculating net revenue requirement.
Scheduling, Control and Dispatch Revenues are allocated to our MISO Regulated Operating Subsidiaries by MISO as compensation for the services performed in operating the transmission system. Such services include monitoring of reliability data, current and next day analysis, implementation of emergency procedures and outage coordination and switching. Beginning in 2013, certain scheduling, control and dispatch revenues will include a true-up adjustment at our MISO Regulated Operating Subsidiaries which ensures that our MISO Regulated Operating Subsidiaries recover their allowed costs.
Other Revenues consist of rental revenues, easement revenues, revenues relating to utilization of jointly owned lines under our transmission ownership and operating agreements and amounts from providing ancillary services to customers. The majority of other revenues are a reduction to gross revenue requirement when calculating net revenue requirement under our cost-based formula rates.
Operating Expenses
Operation and Maintenance Expenses consist primarily of the costs of contractors to operate and maintain our transmission systems and costs for our personnel involved in operation and maintenance activities.
Operation expenses include activities related to control area operations, which involve balancing loads and generation and transmission system operations activities, including monitoring the status of our transmission lines and stations. 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 legal, information technology, finance, regulatory and human resources organizations, general office expenses and fees for professional services. Professional services are principally composed of outside legal, audit and information technology services. Professional advisory and consulting services primarily related to external legal, advisory and financial services fees related to the Entergy Transaction are included in general and administrative expenses.


38


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 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 of federal and state income taxes.
Results of Operations
The following table summarizes historical operating results for the periods indicated:
 
Year Ended
 
 
 
Percentage
 
Year ended
 
 
 
Percentage
 
December 31,
 
Increase
 
Increase
 
December 31,
 
Increase
 
Increase
(In thousands)
2012
 
2011
 
(Decrease)
 
(Decrease)
 
2010
 
(Decrease)
 
(Decrease)
OPERATING REVENUES
$
830,535

 
$
757,397

 
$
73,138

 
9.7%
 
$
696,843

 
$
60,554

 
8.7%
OPERATING EXPENSES

 

 
 
 
 
 

 
 
 
 
Operation and maintenance
121,941

 
129,288

 
(7,347
)
 
(5.7)%
 
126,528

 
2,760

 
2.2%
General and administrative
112,091

 
82,790

 
29,301

 
35.4%
 
78,120

 
4,670

 
6.0%
Depreciation and amortization
106,512

 
94,981

 
11,531

 
12.1%
 
86,976

 
8,005

 
9.2%
Taxes other than income taxes
59,701

 
53,430

 
6,271

 
11.7%
 
48,195

 
5,235

 
10.9%
Other operating (income) and expenses — net
(769
)
 
(844
)
 
75

 
(8.9)%
 
(297
)
 
(547
)
 
184.2%
Total operating expenses
399,476

 
359,645

 
39,831

 
11.1%
 
339,522

 
20,123

 
5.9%
OPERATING INCOME
431,059

 
397,752

 
33,307

 
8.4%
 
357,321

 
40,431

 
11.3%
OTHER EXPENSES (INCOME)
 
 
 
 
 
 
 
 
 
 
 
 
 
Interest expense
155,734

 
146,936

 
8,798

 
6.0%
 
142,553

 
4,383

 
3.1%
Allowance for equity funds used during construction
(23,000
)
 
(16,699
)
 
(6,301
)
 
37.7%
 
(13,412
)
 
(3,287
)
 
24.5%
Other income
(2,401
)
 
(2,881
)
 
480

 
(16.7)%
 
(2,340
)
 
(541
)
 
23.1%
Other expense
4,218

 
3,962

 
256

 
6.5%
 
2,588

 
1,374

 
53.1%
Total other expenses (income)
134,551

 
131,318

 
3,233

 
2.5%
 
129,389

 
1,929

 
1.5%
INCOME BEFORE INCOME TAXES
296,508

 
266,434

 
30,074

 
11.3%
 
227,932

 
38,502

 
16.9%
INCOME TAX PROVISION
108,632

 
94,749

 
13,883

 
14.7%
 
82,254

 
12,495

 
15.2%
NET INCOME
$
187,876

 
$
171,685

 
$
16,191

 
9.4%
 
$
145,678

 
$
26,007

 
17.9%


39


Operating Revenues
Year ended December 31, 2012 compared to year ended December 31, 2011
The following table sets forth the components of and changes in operating revenues:
 
 
 
 
 
 
 
 
 
 
 
Percentage
 
2012
 
2011
 
Increase
 
Increase
(In thousands)
Amount
 
Percentage
 
Amount
 
Percentage
 
(Decrease)
 
(Decrease)
Network revenues
$
669,048

 
80.6
%
 
$
637,807

 
84.2
%
 
$
31,241

 
4.9
%
Regional cost sharing revenues
122,626

 
14.8
%
 
87,304

 
11.5
%
 
35,322

 
40.5
%
Point-to-point
17,439

 
2.1
%
 
15,903

 
2.1
%
 
1,536

 
9.7
%
Scheduling, control and dispatch
15,077

 
1.8
%
 
11,583

 
1.5
%
 
3,494

 
30.2
%
Other
6,345

 
0.7
%
 
4,800

 
0.7
%
 
1,545

 
32.2
%
Total
$
830,535

 
100.0
%
 
$
757,397

 
100.0
%
 
$
73,138

 
9.7
%
Network revenues increased due primarily to higher net revenue requirements at our Regulated Operating Subsidiaries during the year ended December 31, 2012 as compared to the same period in 2011. Higher net revenue requirements were due primarily to higher rate base associated with higher balances of property, plant and equipment in-service and higher recoverable expenses due to higher operating expenses, partially offset by the final monthly recognition in January through May 2011 of the ITCTransmission rate freeze revenue deferral described above under “Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations — Cost-Based Formula Rates with True-Up Mechanism — ITCTransmission’s Rate Freeze Revenue Deferral” and the recognition of the FERC refund totaling $11.0 million during the second quarter of 2012 as discussed in Note 16 to the consolidated financial statements under “Commitments and Contingent Liabilities — FERC Audit of ITC Midwest.”
Regional cost sharing revenues increased due primarily to additional capital projects that have been identified by MISO as eligible for regional cost sharing and placing these projects into service. We expect to continue to receive regional cost sharing revenues and these revenues 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 the number of point-to-point reservations.
Scheduling, control and dispatch revenues increased due primarily to a change in MISO's revenue distribution methodology for these types of revenues in 2012 compared to 2011. The new method was implemented by MISO in 2012 to better align the billing rates relating to these services with the projected expenses.
Operating revenues for the year ended December 31, 2012 include the network revenue accruals (deferrals) and regional cost sharing revenue accruals (deferrals) as calculated below:
 
 
 
 
 
 
 
 
 
 
 
 
Total
 
 
 
 
 
 
 
 
 
 
ITC Great
 
Net Revenue
Line
 
Item
 
ITCTransmission
 
METC
 
ITC Midwest
 
Plains
 
Deferrals
 (In thousands)
 
 
 
 
 
 
 
 
 
 
1
 
Estimated net revenue requirement (network revenues recognized) (a)
 
$
239,952

 
$
199,648

 
$
236,938

 
$
3,482

 
 
2
 
Network revenues billed (b)
 
251,501

 
197,662

 
239,637

 
4,630

 
 
3
 
Network revenue accruals (deferrals) (line 1 — line 2)
 
(11,549
)
 
1,986

 
(2,699
)
 
(1,148
)
 
 
4
 
Regional cost sharing revenue accruals (deferrals) (c)
 
(1,393
)
 
(5,766
)
 
957

 
(5,254
)
 
 
5
 
Total net revenue deferrals
  (line 3 + line 4)
 
$
(12,942
)
 
$
(3,780
)
 
$
(1,742
)
 
$
(6,402
)
 
$
(24,866
)
____________________________
(a)
The calculation of the 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.


40


The refund totaling $11.0 million recognized during the second quarter of 2012 as discussed in Note 16 to the consolidated financial statements under “Commitments and Contingent Liabilities — FERC Audit of ITC Midwest” is not included as a reduction in the estimated net revenue requirement above. We have separately recorded a regulatory liability for this refund.
(b)
Network revenues billed at our MISO Regulated Operating Subsidiaries are calculated based on the joint zone monthly network peak load multiplied by their effective monthly network rates for 2012 of $2.188 per kW/month, $2.409 per kW/month and $6.797 per kW/month applicable to ITCTransmission, METC and ITC Midwest, respectively, adjusted for the actual number of days in the month less amounts recovered or refunded associated with our MISO Regulated Operating Subsidiaries 2010 true-up adjustments. The rates for 2012 include amounts for the collection and refund of the 2010 revenue accruals and deferrals and related accrued interest and the revenues billed in 2012 associated with the 2010 revenue accruals and deferrals are not included in these amounts. On August 31, 2012, ITCTransmission’s projected network rate of $2.147 per kW/month, METC’s projected network rate of $2.5263 per kW/month and ITC Midwest’s projected network rate of $7.805 per kW/month, in each case for the period from January 1, 2013 through December 31, 2013, were posted by MISO. Our rates at ITC Great Plains are billed ratably each month based on its annual projected net revenue requirement. ITC Great Plains’ projected revenue requirement of $44.2 million for the period from January 1, 2013 through December 31, 2013 was posted by SPP on August 31, 2012.
(c)
Regional cost sharing revenues are subject to a separate true-up mechanism whereby our Regulated Operating Subsidiaries accrue or defer revenues for any over- or under-recovery. The related revenue accruals or deferrals associated with regional cost sharing revenues are included in the regional cost sharing revenue amounts.
Year ended December 31, 2011 compared to year ended December 31, 2010
The following table sets forth the components of and changes in operating revenues:
 
 
 
 
 
 
 
 
 
 
 
Percentage
 
2011
 
2010
 
Increase
 
Increase
(In thousands)
Amount
 
Percentage
 
Amount
 
Percentage
 
(Decrease)
 
(Decrease)
Network revenues
$
637,807

 
84.2
%
 
$
595,071

 
85.4
%
 
$
42,736

 
7.2
 %
Regional cost sharing revenues
87,304

 
11.5
%
 
55,638

 
8.0
%
 
31,666

 
56.9
 %
Point-to-point
15,903

 
2.1
%
 
26,063

 
3.7
%
 
(10,160
)
 
(39.0
)%
Scheduling, control and dispatch
11,583

 
1.5
%
 
14,525

 
2.1
%
 
(2,942
)
 
(20.3
)%
Other
4,800

 
0.7
%
 
5,546

 
0.8
%
 
(746
)
 
(13.5
)%
Total
$
757,397

 
100.0
%
 
$
696,843

 
100.0
%
 
$
60,554

 
8.7
 %
Network revenues increased due primarily to higher net revenue requirements at our Regulated Operating Subsidiaries during the year ended December 31, 2011 as compared to the same period in 2010. Higher net revenue requirements were due primarily to higher rate base associated with higher balances of property, plant and equipment in-service and higher recoverable expenses due to higher operating expenses, partially offset by the final monthly recognition in May 2011 of the ITCTransmission rate freeze revenue deferral described above under “Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations — Cost-Based Formula Rates with True-Up Mechanism — ITCTransmission’s Rate Freeze Revenue Deferral.”
Regional cost sharing revenues increased due primarily to additional capital projects that have been identified by MISO as eligible for regional cost sharing and placing these projects into service. 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 decreased due primarily to a decline in the number of point-to-point reservations.
Scheduling, control and dispatch revenues decreased due primarily to a change in MISO’s revenue distribution methodology for these types of revenues in 2011 compared to 2010.


41


Operating revenues for the year ended December 31, 2011 include the network revenue accruals (deferrals) and regional cost sharing revenue accruals (deferrals) as calculated below:
 
 
 
 
 
 
 
 
 
 
 
 
Total
 
 
 
 
 
 
 
 
 
 
ITC Great
 
Net Revenue
Line
 
Item
 
ITCTransmission
 
METC
 
ITC Midwest
 
Plains
 
Deferrals
 (In thousands)
 
 
 
 
 
 
 
 
 
 
1
 
Estimated net revenue requirement (network revenues recognized) (a)
 
$
243,917

 
$
188,577

 
$
203,083

 
$
2,230

 
 
2
 
Network revenues billed (b)
 
267,842

 
198,110

 
212,778

 
718

 
 
3
 
Network revenue accruals (deferrals) (line 1 — line 2)
 
(23,925
)
 
(9,533
)
 
(9,695
)
 
1,512

 
 
4
 
Regional cost sharing revenue accruals (deferrals) (c)
 
(1,637
)
 
(1,237
)
 
4,088

 
(3,322
)
 
 
5
 
Total net revenue deferrals
  (line 3 + line 4)
 
$
(25,562
)
 
$
(10,770
)
 
$
(5,607
)
 
$
(1,810
)
 
$
(43,749
)
____________________________
(a)
The calculation of net revenue requirement for our Regulated Operating Subsidiaries is described in “Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations — Cost-Based Formula Rates with True-Up Mechanism — Net Revenue Requirement Calculation.” The amount is estimated for each reporting period until such time as FERC Form No. 1’s are completed for our Regulated Operating Subsidiaries.
(b)
Network revenues billed at our MISO Regulated Operating Subsidiaries are calculated based on the joint zone monthly network peak load multiplied by their effective monthly network rates for 2011 of $2.495 per kW/month, $2.331 per kW/month and $6.694 per kW/month applicable to ITCTransmission, METC and ITC Midwest, respectively, adjusted for the actual number of days in the month less amounts recovered or refunded associated with our MISO Regulated Operating Subsidiaries 2009 true-up adjustments. The rates for 2011 include amounts for the collection and refund of the 2009 revenue accruals and deferrals and related accrued interest and the revenues billed in 2011 associated with the 2009 revenue accruals and deferrals are not included in these amounts. Our rates at ITC Great Plains are billed ratably each month based on its annual projected net revenue requirement.
(c)
Regional cost sharing revenues are subject to a separate true-up mechanism whereby our Regulated Operating Subsidiaries accrue or defer revenues for any over- or under-recovery. The related revenue accruals or deferrals associated with regional cost sharing revenues are included in the regional cost sharing revenue amounts.
Operating Expenses
Operation and maintenance expenses
Year ended December 31, 2012 compared to year ended December 31, 2011
Operation and maintenance expenses decreased by $2.5 million due to increased cost efficiencies associated primarily with substation, breaker and relay maintenance activities, partially offset by higher vegetation management activities, $2.2 million due to a decrease in activities associated with surveying transmission overhead lines and $1.2 million due to lower operating and training expenses.
Year ended December 31, 2011 compared to year ended December 31, 2010
Operation and maintenance expenses increased by $4.8 million due to NERC compliance activities associated with surveying transmission overhead lines, by $3.0 million due to higher vehicles and equipment expenses related to higher fuel costs as well as the age and number of vehicles in the fleet, by $2.6 million due to higher operating and training expenses, and by $2.5 million due to higher costs of helicopter patrolling for infrared and visual inspections of the system and transmission lines. These increases were partially offset by $4.5 million due to lower vegetation management requirements, $3.0 million due to lower substation facility maintenance expenses, and $3.0 million due to reduced structure maintenance primarily caused by reduced tower painting requirement in 2011.


42


General and administrative expenses
Year ended December 31, 2012 compared to year ended December 31, 2011
General and administrative expenses increased due to legal, advisory and financial services fees for the Entergy Transaction of $12.3 million, higher compensation-related expense of $8.7 million primarily due to personnel increases and increases in bonuses earned in 2012 such as those described above under “Capital Project Updates and Other Recent Developments — Development Bonuses”, $2.6 million due to general business expenses primarily due to information technology support, $2.1 million due to the recognition of the Kansas V-Plan Project regulatory asset which reduced expenses in 2011 and did not occur in 2012, $2.1 million due to an increase in other professional services such as legal, advisory and financial services fees and $1.4 million due to increases in general facilities expenses.
Year ended December 31, 2011 compared to year ended December 31, 2010
General and administrative expenses increased by $7.2 million due to higher professional advisory and consulting services primarily related to external legal, advisory and financial services fees related to the Entergy Transaction and by $2.1 million due to higher general business expenses primarily due to increased information technology support. These increases were partially offset by $3.6 million of lower compensation-related expenses and by the reduction of expenses in the first quarter of 2011 of $2.1 million (of which $1.4 million were incurred in periods prior to 2011) in connection with the recognition of the Kansas V-Plan Project regulatory asset.
Depreciation and amortization expenses
Year ended December 31, 2012 compared to year ended December 31, 2011
Depreciation and amortization expenses increased due primarily to a higher depreciable base resulting from property, plant and equipment additions.
Year ended December 31, 2011 compared to year ended December 31, 2010
Depreciation and amortization expenses increased due primarily to a higher depreciable base resulting from property, plant and equipment additions.
Taxes other than income taxes
Year ended December 31, 2012 compared to year ended December 31, 2011
Taxes other than income taxes increased due to higher property tax expenses primarily due to our MISO Regulated Operating Subsidiaries’ 2011 capital additions, which are included in the assessments for 2012 property taxes.
Year ended December 31, 2011 compared to year ended December 31, 2010
Taxes other than income taxes increased due to higher property tax expenses primarily due to our MISO Regulated Operating Subsidiaries’ 2010 capital additions, which are included in the assessments for 2011 property taxes.
Other expenses (income)
Year ended December 31, 2012 compared to year ended December 31, 2011
Interest expense increased due primarily to an increase in borrowing levels under our revolving and term loan credit agreements.
Year ended December 31, 2011 compared to year ended December 31, 2010
Interest expense increased due primarily to an increase in borrowing levels under our revolving credit agreements.
Income Tax Provision
Year ended December 31, 2012 compared to year ended December 31, 2011
Our effective tax rates for the years ended December 31, 2012 and 2011 are 36.6% and 35.6%, respectively. Our effective tax rate differs from our 35% statutory federal income tax rate due primarily to state income taxes as well as the tax effects of AFUDC equity which reduced the effective tax rate. The amount of income tax expense


43


relating to AFUDC equity is recognized as a regulatory asset and not included in the income tax provision. We recorded a state income tax provision of $6.2 million (net of federal deductibility) during the year ended December 31, 2012, compared to a state income tax provision of $3.8 million (net of federal deductibility) for the year ended December 31, 2011. Included in the state income tax provision recorded during the year ended December 31, 2011 is the effect of the Michigan tax law change as discussed in Note 10, which reduced the income tax provision by $4.6 million.
Year ended December 31, 2011 compared to year ended December 31, 2010
Our effective tax rates for the years ended December 31, 2011 and 2010 are 35.6% and 36.1%, respectively. Our effective tax rate differs from our 35% statutory federal income tax rate due primarily to state income taxes as well as the tax effects of AFUDC equity which reduced 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. We recorded a state income tax provision of $3.8 million (net of federal deductibility) during the year ended December 31, 2011, compared to a state income tax provision of $5.9 million (net of federal deductibility) for the year ended December 31, 2010. Included in the state income tax provision recorded during the year ended December 31, 2011 is the effect of the Michigan tax law change as discussed in Note 10, which reduced the income tax provision by $4.6 million.
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 and term loan 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 and, following the close of the Entergy Transaction, capital expenditures at the subsidiaries of Mid South TransCo. Our plans with regard to property, plant and equipment investments are described in detail above under “Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations — Capital Investment and Operating Results Trends.”
Fund business development expenses and related capital expenditures. We are pursuing development activities for transmission projects which will continue to result in the incurrence of development expenses and could result in significant capital expenditures.
Fund working capital requirements.
Fund our debt service requirements, which are described in detail below under “Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations — Contractual Obligations.” We expect our interest payments to increase each year as a result of the additional debt we expect to incur to fund our capital expenditures.
Fund any dividends or any recapitalization associated with the Entergy transaction to holders of our common stock.
Fund contributions to our retirement plans, as described in Note 11 to the consolidated financial statements. We expect to contribute up to $12.4 million to these plans in 2013. The impact of the growth in the number of participants in our retirement benefit plans and changes in the requirements of the Pension Protection Act may require contributions to our retirement plans to be higher than we have experienced in the past.
In addition to the expected capital requirements above, any adverse determinations relating to the contingencies 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 and term loan credit agreements and our cash and cash equivalents as needed to meet our short-term cash requirements. As described in Note 8 to the consolidated financial statements, in 2012, we entered into a new revolving credit agreement at ITC Midwest for $175.0 million and a new term loan credit agreement for $200.0 million at ITC Holdings. The new revolving and term loan credit


44


agreements increased our borrowing capacity by $259.0 million. During 2011, we entered into new revolving credit agreements at ITC Holdings, ITC Great Plains, ITCTransmission and METC in the amount of $200.0 million, $150.0 million, $100.0 million and $100.0 million, respectively. As of December 31, 2012, we had consolidated indebtedness under our revolving and term loan credit agreements of $527.8 million, with unused capacity under the agreements of $397.2 million.
We have approximately $652.0 million of debt maturing during 2013 at ITC Holdings and ITCTransmission. The maturing debt is expected to be refinanced with short and long-term debt. In addition, for our long-term capital requirements and the funding of the anticipated $700 million recapitalization in connection with the Entergy Transaction, we expect that we will need to obtain additional debt financing. Certain of our capital projects could be delayed in the event we experience difficulties in accessing capital. We expect to be able to obtain such additional financing for both our short and long-term requirements as needed, in amounts and upon terms that will be reasonably satisfactory to us due to our strong credit ratings and our historical ability to obtain financing.
Credit Ratings
Credit ratings by nationally recognized statistical rating agencies are an important component of our liquidity profile. Credit ratings relate to our ability to issue debt securities and the cost to borrow money, and should not be viewed as an indication of future stock performance or a recommendation to buy, sell, or hold securities. Ratings are subject to revision or withdrawal at any time and each rating should be evaluated independently of any other rating. Our current credit ratings are displayed in the following table. An explanation of these ratings may be obtained from the respective rating agency.
 
 
 
 
Standard and Poor’s
 
Moody’s Investor
Issuer
 
Issuance
 
Ratings Services (a)
 
Service, Inc. (b)
ITC Holdings
 
Senior Unsecured Notes
 
BBB
 
Baa2
ITCTransmission
 
First Mortgage Bonds
 
A
 
A1
METC
 
Senior Secured Notes
 
A
 
A1
ITC Midwest
 
First Mortgage Bonds
 
A
 
A1
ITC Great Plains
 
Unsecured Credit Facility
 
BBB+
 
Baa1
____________________________
(a)
On December 19, 2012, Standard and Poor’s Financial Services completed their annual review and made no changes to the existing ratings. All of the ratings have a stable outlook.
(b)
Moody’s Investor Service, Inc. updated their credit opinions on April 20, 2012 and made no changes to the credit ratings. All of the ratings have a stable outlook.
Covenants
Our debt instruments include senior notes, secured notes, first mortgage bonds, and revolving and term loan credit agreements containing numerous financial and operating covenants that place significant restrictions, which are described in Note 8 to the consolidated financial statements. 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, although the borrowing costs under our revolving and term loan credit agreements would increase.


45


Cash Flows
The following table summarizes cash flows for the periods indicated:
 
Year Ended December 31,
(In thousands)
2012
 
2011
 
2010
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
 
 
 
Net income
$
187,876

 
$
171,685

 
145,678

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
 
 
Depreciation and amortization expense
106,512

 
94,981

 
86,976

Recognition of and refund and collection of revenue accruals and deferrals — including accrued interest
(13,052
)
 
56,944

 
121,315

Deferred income tax expense
67,285

 
30,797

 
76,746

Tax benefit for excess tax deductions of share-based compensation
(23,022
)
 
(28,114
)
 
(320
)
Other
1,924

 
54,623

 
(7,062
)
Net cash provided by operating activities
327,523

 
380,916

 
423,333

CASH FLOWS FROM INVESTING ACTIVITIES
 
 
 
 
 
Expenditures for property, plant and equipment
(802,763
)
 
(556,931
)
 
(388,401
)
Other
(6,298
)
 
(3,264
)
 
(460
)
Net cash used in investing activities
(809,061
)
 
(560,195
)
 
(388,861
)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
 
 
 
Net issuance/repayment of long-term debt (including revolving and term loan credit agreements)
501,740

 
147,660

 
62,034

Issuance of common stock
14,189

 
18,993

 
8,908

Dividends on common stock
(75,153
)
 
(70,363
)
 
(66,041
)
Refundable deposits from and repayments to generators for transmission network upgrades — net
(4,943
)
 
28,792

 
(18,295
)
Tax benefit for excess tax deductions of share-based compensation
23,022

 
28,114

 
320

Other
(9,474
)
 
(10,682
)
 
(1,142
)
Net cash provided by (used in) financing activities
449,381

 
142,514

 
(14,216
)
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS
(32,157
)
 
(36,765
)
 
20,256

CASH AND CASH EQUIVALENTS — Beginning of period
58,344

 
95,109

 
74,853

CASH AND CASH EQUIVALENTS — End of period
$
26,187

 
$
58,344

 
95,109

Cash Flows From Operating Activities
Year ended December 31, 2012 compared to year ended December 31, 2011
Net cash provided by operating activities decreased $53.4 million in 2012 compared to 2011. The decrease in cash provided by operating activities was due primarily to an increase in payments of operating expenses of $46.2 million, including legal, advisory, consulting and financial services fees for the Entergy Transaction, higher income taxes paid of $7.0 million and $6.5 million of additional interest payments (net of interest capitalized) during 2012 compared to 2011. These decreases were partially offset by an increase in cash received from operating revenues of $10.2 million.
Year ended December 31, 2011 compared to year ended December 31, 2010
Net cash provided by operating activities decreased $42.4 million in 2011 compared to 2010. The decrease in cash provided by operating activities was due primarily to higher income taxes paid of $25.3 million and $6.3 million of additional interest payments (net of interest capitalized) during 2011 compared to 2010. Additionally, there was a decrease of $27.8 million due to recognizing reductions of federal and state income tax liabilities related to tax benefits for excess tax deductions of share-based compensation recognized in 2011 that are reflected as financing cash inflows. These decreases were partially offset by an increase in cash received from operating revenues of $9.3 million.


46


Cash Flows From Investing Activities
Year ended December 31, 2012 compared to year ended December 31, 2011
Net cash used in investing activities increased $248.9 million in 2012 compared to 2011. The increase in cash used in investing activities was due primarily to higher investments in property, plant and equipment during 2012 as we executed our capital investment plan described above under “— Overview — Capital Investment and Operating Results Trends.”
Year ended December 31, 2011 compared to year ended December 31, 2010
Net cash used in investing activities increased $171.3 million in 2011 compared to 2010. The increase in cash used in investing activities was due primarily to higher investments in property, plant and equipment during 2011 as we executed our capital investment plan described above under “— Overview — Capital Investment and Operating Results Trends.”
Cash Flows From Financing Activities
Year ended December 31, 2012 compared to year ended December 31, 2011
Net cash provided by financing activities increased $306.9 million in 2012 compared to 2011. The increase in cash provided by financing activities was due primarily to the proceeds of $175.0 million received from the issuance of METC 3.98% Senior Secured Notes and ITC Midwest's 3.50% First Mortgage Bonds, Series E and the net increase of $179.1 million in amounts outstanding under our revolving and term loan credit agreements. These increases were partially offset by higher net payments of $33.7 million associated with refundable deposits for transmission network upgrades.
Year ended December 31, 2011 compared to year ended December 31, 2010
Net cash from financing activities increased $156.7 million in 2011 compared to 2010. The increase in cash provided by financing activities was due primarily to the net increase of $175.6 million in amounts outstanding under our revolving credit agreements, an increase of $47.1 million in net proceeds associated with refundable deposits for transmission network upgrades as well as an increase of $27.8 million due to the recognition of federal and state income tax liability reductions for the excess tax deduction of share-based compensation during 2011 compared to 2010. This increase was partially offset by no issuances of long-term debt in 2011 as compared to proceeds of $40.0 million from the closing of ITC Midwest’s 4.60% First Mortgage Bonds, Series D, and proceeds of $50.0 million received from the issuance of METC’s 5.64% Senior Secured Notes during 2010.


47


Contractual Obligations
The following table details our contractual obligations as of December 31, 2012:
 
 
 
Less Than
 
1-3
 
4-5
 
More Than
(In thousands)
Total
 
1 Year
 
Years
 
Years
 
5 Years
Debt:
 
 
 
 
 
 
 
 
 
ITC Holdings Senior Notes
1,462,000

 
267,000

 
305,000

 
435,000

 
455,000

ITC Holdings revolving credit agreement
29,600

 

 
29,600

 

 

ITC Holdings term loan credit agreement
200,000

 
200,000

 

 

 

ITCTransmission First Mortgage Bonds
385,000

 
185,000

 

 
100,000

 
100,000

ITCTransmission revolving credit agreement
78,700

 

 
78,700

 

 

METC Senior Secured Notes
350,000

 

 
225,000

 

 
125,000

METC revolving credit agreement
10,500

 

 
10,500

 

 

ITC Midwest First Mortgage Bonds
425,000

 

 

 
40,000

 
385,000

ITC Midwest revolving credit agreement
115,300