UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K

 

 

Commission File Number: 001-32576

 

 

 

 

ITC HOLDINGS CORP.

(Exact Name of Registrant as Specified in Its Charter)

 

 

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:

 

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 o     No o

 

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

 

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

 

 

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

 

The aggregate market value of the registrant’s common stock held by non-affiliates on June 30, 2009 was approximately $2.2 billion, based on the closing sale price as reported on the New York Stock Exchange. For purposes of this computation, all executive officers, directors and 10% beneficial owners of the registrant are assumed to be affiliates. Such determination should not be deemed an admission that such officers, directors and beneficial owners are, in fact, affiliates of the registrant.

 

The number of shares of the Registrant’s Common Stock, without par value, outstanding as of February 19, 2010 was 50,099,808.

 

DOCUMENTS INCORPORATED BY REFERENCE

 

Portions of the Registrant’s definitive Proxy Statement for the Registrant’s 2010 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, 2009

 

INDEX

 

DEFINITIONS

 

Unless otherwise noted or the context requires, all references in this report to:

 

ITC Holdings Corp. and its subsidiaries

 

 

Other definitions

 

 

 

 

Overview

 

Our business consists primarily of the 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.

 

Through our Regulated Operating Subsidiaries, we are engaged in the transmission of electricity in the United States. 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. By pursuing this strategy, we strive for high reliability of our systems and to improve accessibility to generation sources of choice, including renewable sources. We operate high-voltage systems in Michigan’s Lower Peninsula and portions of Iowa, Minnesota, Illinois, Missouri and Kansas that transmit electricity from generating stations to local distribution facilities connected to our systems.

 

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 a cost-based formula rate template. Attachment O of the MISO tariff is used by our MISO 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.” ITC Great Plains uses a formula rate that is included in Attachment H of the SPP tariff as discussed in “Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations — Recent Developments — ITC Great Plains — Formula Rate and Incentives.”

 

Development of Business

 

We are pursuing strategic development opportunities for transmission construction related to building super-regional transmission facilities, primarily to improve overall grid reliability, lower electricity congestion, enhance competitive markets and facilitate interconnections of new generating resources, including wind generation and other renewable resources. For example, we announced a project in 2009, known as the Green Power Express project, consisting of a network of transmission lines that would facilitate the movement of 12,000 megawatts of power from the wind-abundant areas in the Dakotas, Minnesota and Iowa to Midwest load centers that demand clean, renewable energy. The Green Power Express project would traverse portions of North Dakota, South Dakota, Minnesota, Iowa, Wisconsin, Illinois and Indiana and is ultimately expected to include approximately 3,000 miles of extra high-voltage (765 kV) transmission. Portions of the Green Power Express project fall within the service territory of ITC Midwest. ITC Holdings expects to partner with other utilities within the geographical footprint of the Green Power Express and, therefore, expects to invest in only a portion of the total project cost. In addition to the Green Power Express project, based on proposals by RTOs, including MISO and the SPP, we are exploring additional strategic opportunities to upgrade the transmission grid within the MISO and SPP regions and surrounding regions with a backbone transmission network. Based on the anticipated growth of wind generation resources, we also foresee the need to construct additional transmission facilities that will

provide interconnection opportunities for those wind facilities. The backbone transmission network, transmission for wind interconnection and for interconnection of other renewable generating facilities may provide additional investment opportunities. Further, we are pursuing the opportunity to invest in two projects in Kansas, through ITC Great Plains, known as the Spearville-Knoll-Axtell transmission project (the “KETA Project”) and the Kansas V-Plan transmission project running from Spearville substation near Dodge City to Wichita. The capital investment for these two projects is anticipated to be $600 million. ITC Great Plains has established a formula rate for these two projects and other projects within the SPP region. We are also exploring opportunities to build a new 765 kV transmission facility across the southern portion of Michigan’s Lower Peninsula. We cannot predict if or when these investment opportunities will begin, or their duration. Refer to the discussion of risks associated with our strategic development opportunities in “Item 1A Risk Factors — Our Regulated Operating Subsidiaries’ actual capital expenditures may be lower than planned, which would decrease expected rate base and therefore our revenues. In addition, we expect to invest in strategic development opportunities to improve the efficiency and reliability of the transmission grid, but we cannot assure you that we will be able to initiate or complete any of these investments.”

 

Segments

 

We have one reportable segment consisting of our Regulated Operating Subsidiaries. Additionally, we have other subsidiaries focused primarily on business development activities and a holding company whose activities include corporate debt and equity financings and general corporate activities. A more detailed discussion of our reportable segment, including financial information about the segment, is included in Note 17 to the consolidated financial statements.

 

Operations

 

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

 

 

Asset Planning

 

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 review regional system improvement projects 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. This internal expertise allows us to effectively manage outside contractors.

 

Maintenance

 

We develop and track preventive maintenance plans to promote safe and reliable systems. By performing preventive maintenance on our assets, we can minimize the need for reactive maintenance, resulting in improved reliability. Our Regulated Operating Subsidiaries contract with Utility Lines Construction, which is a division of Asplundh Tree Expert Co., to perform the majority of their maintenance. The agreements provide us with access to an experienced and scalable workforce with knowledge of our system at an established rate. The agreements are scheduled to terminate on August 29, 2013, but automatically renew for additional five year terms unless terminated by either party.

 

Real Time Operations

 

System Operations.  From our operations control room facility in Novi, Michigan, transmission system coordinators continuously monitor the performance of the transmission systems of our MISO Regulated Operating Subsidiaries transmission systems, using state of the art computer and communication systems to perform analysis to plan for contingencies and maintain security and reliability following any unplanned events on the system. Transmission system coordinators 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 the operations control room 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.

 

Operating Contracts

 

ITCTransmission

 

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

 

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

 

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

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

 

METC

 

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

 

Amended and Restated Easement Agreement.  Under the Amended and Restated Easement Agreement (the “Easement Agreement”), dated as of April 29, 2002 and as further supplemented, Consumers Energy provides METC with an easement to the land, which we refer to as premises, on which a majority of METC’s transmission towers, poles, lines and other transmission facilities used to transmit electricity at voltages of at least 120 kV are located, which we refer to collectively as the facilities. Consumers Energy retained for itself the rights to, and the value of activities associated with, all other uses of the premises and the facilities covered by the Easement Agreement, such as for distribution of electricity, fiber optics, telecommunications, gas pipelines and agricultural uses. Accordingly, METC is not permitted to use the premises or the facilities covered by the Easement Agreement for any purposes other than to provide electric transmission and related services, to inspect, maintain, repair, replace and remove electric transmission facilities and to alter, improve, relocate and construct additional electric transmission facilities. The easement is further subject to the rights of any third parties that had rights to use or occupy the premises or the facilities prior to April 1, 2001 in a manner not inconsistent with METC’s permitted uses.

 

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

 

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

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

 

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

 

Amended and Restated Purchase and Sale Agreement for Ancillary Services.  The Amended and Restated Purchase and Sale Agreement for Ancillary Services (the “Ancillary Services Agreement”) is dated as of April 29, 2002. Since METC does not own any generating facilities, it must procure ancillary services from third party suppliers, such as Consumers Energy. Currently, under the Ancillary Services Agreement, METC pays Consumers Energy for providing certain generation-based services necessary to support the reliable operation of the bulk power grid, such as voltage support and generation capability and capacity to balance loads and generation. METC is not precluded from procuring these ancillary services from third party suppliers when available. The Ancillary Services Agreement is subject to rolling one-year renewals starting May 1, 2003, unless terminated by either METC or Consumers Energy with six months prior written notice.

 

Amended and Restated Distribution-Transmission Interconnection Agreement.  The Amended and Restated Distribution-Transmission Interconnection Agreement (the “DT Interconnection Agreement”), dated April 29, 2002, 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, specifies the terms and conditions under which Consumers Energy and METC maintain the interconnection of Consumers Energy’s generation resources and METC’s transmission assets. The Generator Interconnection Agreement is effective either until it is replaced by any MISO-required contract, or until mutually agreed by METC and Consumers Energy to terminate, but not later than the date that all listed generators cease commercial operation.

ITC Midwest

 

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

 

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

 

Large Generator Interconnection Agreement.  ITC Midwest, IP&L and MISO entered into the Large Generator Interconnection Agreement (the “LGIA”), dated as of December 20, 2007, in order to establish, re-establish and maintain the direct electricity interconnection of IP&L’s electricity generating assets with ITC Midwest’s transmission system for the purposes of transmitting electric power from and to the electricity generating facilities. The LGIA will remain in effect until terminated by ITC Midwest or until IP&L elects to terminate the agreement if a particular unit ceases commercial operation for three consecutive years.

 

Transition Services Agreement.  ITC Midwest is party to a Transition Services Agreement with IP&L (the “IP&L TSA”), dated as of December 20, 2007, under which IP&L performs operations of the 34.5 kV transmission system on behalf of ITC Midwest. The system operations services related to the 34.5 kV transmission system and the associated detailed billing service have been extended through December 31, 2010. The agreement can also be terminated by mutual agreement of the parties. Subsequent to the termination of the TSA. ITC Midwest expects to perform the activities covered under the TSA or enter into an operating agreement for these services.

 

ITC Great Plains

 

Transition Services Agreement.  Mid-Kansas Electric Company LLC (“Mid-Kansas”) and ITC Great Plains have entered into a Transition Services Agreement (the “Mid-Kansas TSA”), dated as of August 18, 2009. The Mid-Kansas TSA identifies the operations and accounting services Mid-Kansas has agreed to perform related to the ITC Great Plains Elm Creek and Flat Ridge Substations, which ITC Great Plains has purchased from Mid-Kansas. The services will be provided for 12 months from the date of the agreement. The agreement can also be terminated by mutual agreement of the parties. Subsequent to the termination of the Mid-Kansas TSA and any subsequent extensions, ITC Great Plains expects to perform the activities covered under the agreement or enter into an operating agreement for these services.

 

ITC Great Plains also has various interconnection agreements with generation and transmission providers that address terms and conditions of interconnection.

 

Regulatory Environment

 

Many regulators and public policy makers support the need for further investment in the transmission grid. The growth in electricity generation, wholesale power sales and consumption combined with historically inadequate transmission investment have resulted in significant transmission constraints across the United States and increased stress on aging equipment. These problems will continue without increased investment in transmission infrastructure. Transmission system investments can also increase system reliability and reduce the frequency of power outages. Such investments can reduce transmission

constraints and improve access to lower cost generation resources, resulting in a lower overall cost of delivered electricity for end-use consumers. After the 2003 blackout that affected sections of the Northeastern and Midwestern United States and Ontario, Canada, the Department of Energy (the “DOE”) established the Office of Electric Transmission and Distribution, focused on working with reliability experts from the power industry, state governments, and their Canadian counterparts to improve grid reliability and increase investment in the country’s electric infrastructure. In addition, the FERC has signaled its desire for substantial new investment in the transmission sector by implementing financial incentives, such as increasing the return on equity for transmission-only companies to a level that is greater than that of traditional utilities.

 

The FERC has issued orders to promote non-discriminatory transmission access for all transmission customers. In the United States, electric transmission assets are predominantly owned, operated and maintained by utilities that also own electricity generation and distribution assets, known as vertically integrated utilities. The FERC has recognized that the vertically-integrated utility model inhibits the provision of non-discriminatory transmission access and, in order to alleviate this potential discrimination, the FERC has mandated that all transmission systems over which it has jurisdiction must be operated in a comparable, non-discriminatory manner such that any seller of electricity affiliated with a transmission owner or operator is not provided with preferential treatment. The FERC has also indicated that independent transmission companies can play a prominent role in furthering its policy goals and has encouraged the legal and functional separation of transmission operations from generation and distribution operations.

 

On August 8, 2005, the Energy Policy Act was enacted, which requires the FERC to implement mandatory electric transmission reliability standards to be enforced by an Electric Reliability Organization. Effective June 2007, the FERC approved mandatory adoption of certain reliability standards and approved enforcement actions for violators, including fines of up to $1.0 million per day. The NERC was assigned the responsibility of developing and enforcing these mandatory reliability standards. We continually assess our transmission systems against these reliability standards established by the NERC, as well as the standards of applicable regional entities under the NERC that have been delegated certain authority for the purpose of proposing and enforcing reliability standards. In addition, the FERC has finalized rules under which our Regulated Operating Subsidiaries may qualify for rate incentives to invest in transmission infrastructure. Our Regulated Operating Subsidiaries may also be eligible for federal assistance in the siting of such infrastructure. 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.

 

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 do 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

 

ITC Midwest is not a public utility subject to the IUB’s statutory jurisdiction to regulate a public utility’s rates and services pursuant to Iowa Code ch. 476. Iowa Code ch. 478, however, provides that the IUB has the power of supervision over the construction, operation, and maintenance of transmission facilities in Iowa by any entity, which includes the power to issue franchises. Iowa Code ch. 478 further provides that any entity granted a franchise by the IUB is vested with the power of condemnation in Iowa to the extent the IUB approves and deems necessary for public use. A city has the power, pursuant to Iowa Code ch. 364, to grant a franchise to erect, maintain, and operate transmission facilities within the city, which franchise may regulate the conditions required and manner of use of the streets and public grounds of the city and may confer the power to appropriate and condemn private property.

 

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

 

Minnesota

 

The MPUC does not have jurisdiction to regulate ITC Midwest’s rates or terms and conditions of service. However, the MPUC has jurisdiction over the siting and routing of new transmission lines or upgrades of existing lines through Minnesota’s Certificate of Need and Route Permit Processes. Transmission companies are also required to participate in the State’s Biennial Transmission Planning Process and are subject to the state’s preventative maintenance requirements. Pursuant to Minnesota law, ITC

Midwest has the right as an independent transmission company to condemn property in the State of Minnesota for the purpose of building new transmission facilities.

 

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

 

Illinois

 

The ICC does not have jurisdiction to regulate ITC Midwest’s rates or terms and conditions of service, but the ICC does exercise 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

 

The MOPSC does not have jurisdiction to regulate the Company’s rates, terms or conditions of service. However, because ITC Midwest is a “public utility” and an “electrical corporation” under Missouri law, the MOPSC has jurisdiction to determine whether ITC Midwest may operate in such capacity. In this regard, on August 30, 2007, the MOPSC granted ITC Midwest a certificate of public convenience and necessity to own, operate and maintain a 161 kV transmission line of approximately 9.5 miles located in Clark County, Missouri which connects the former IP&L’s transmission substation in Keokuk, Iowa with Ameren Energy Generating Company’s transmission substation near Wayland, Missouri. The MOPSC also exercises jurisdiction with regard to other non-rate matters affecting this Missouri asset such as transmission substation construction, general safety and the transfer of the franchise or property.

 

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

 

ITC Great Plains

 

Kansas

 

ITC Great Plains is a “public utility” in Kansas and an “electric utility” pursuant to state statutes, however, the KCC does not have jurisdiction to regulate the ITC Great Plains’ rates, terms or conditions of service. The KCC issued an order approving the issuance of a limited certificate of convenience to ITC Great Plains for the purposes of building, owning and operating SPP transmission projects in Kansas. In addition to its certificate authority, the KCC has jurisdiction over the siting of electric transmission lines. At this time, ITC Great Plains owns and operates assets in Kansas consisting of the 138 kV Flat Ridge and 230 kV Elm Creek electric substations.

 

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

 

The OCC does not have jurisdiction to regulate ITC Great Plains’ rates, terms or conditions of service, as those processes are preempted by regulation of the FERC. On September 11, 2008, ITC Great Plains received approval from the OCC to operate in Oklahoma, pursuant to Oklahoma Statutes as an electric

public utility providing only transmission services. The OCC does not exercise jurisdiction over the siting of any transmission lines.

 

ITC Great Plains may be subject to the regulatory oversight of Oklahoma Department of Environmental Quality for compliance with environmental standards and regulations relating to construction of proposed transmission lines

 

ITC Great Plains does not currently own or operate transmission facilities in Oklahoma, but is preparing to construct an approximately 19 mile 345 kV transmission line and associated facilities in southeastern Oklahoma, known as the Hugo to Valliant project discussed in “Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations — Recent Developments.”

 

Sources of Revenue

 

See “Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations — Results of Operations — Operating Revenues” for a discussion of our principal sources of revenue.

 

Seasonality

 

The cost-based formula rates with a true-up mechanism in effect for all our Regulated Operating Subsidiaries, as discussed in “Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations — Cost-Based Formula Rates with True- Up Mechanism,” mitigate the seasonality of net income for our Regulated Operating Subsidiaries. Our Regulated Operating Subsidiaries accrue or defer revenues to the extent that their actual net revenue requirement for the reporting period is higher or lower, respectively, than the amounts billed relating to that reporting period. For example, to the extent that amounts billed are less than our net revenue requirement for a reporting period, a revenue accrual is recorded for the difference and this 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 37.7%, 23.6% and 22.5%, respectively, of our total operating revenues for the year ended December 31, 2009. 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 2009 Attachment O revenue accruals and deferrals that were included in our 2009 operating revenues, but will not be billed to our customers until 2011. We have assumed that the Attachment O revenues billed to these customers in 2011 would be in the same proportion of the respective percentages of network revenues billed to them in 2009. 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 have 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. See “Item 7A Quantitative and Qualitative Disclosures about Market Risk — Credit Risk” for discussion of our credit policies.

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.

 

Competition

 

Each of our MISO Regulated Operating Subsidiaries is the only transmission system in its respective service area and, therefore, effectively has no competitors. For our subsidiaries focused on development opportunities for capital projects in other service areas, the incumbent utilities or other entities with transmission development initiatives may compete with us by deciding to pursue capital projects that we are pursuing. Because our 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. Our development expenses are recorded to operating expenses unless and until the FERC allows us recovery of such expenses and they are probable of recovery.

 

Employees

 

As of December 31, 2009, we had 413 employees. We consider our relations with our employees to be good.

 

Environmental Matters

 

Our operations are subject to federal, state, and local environmental laws and regulations, which impose limitations on the discharge of pollutants into the environment, establish standards for the management, treatment, storage, transportation and disposal of hazardous materials and of solid and hazardous wastes, and impose obligations to investigate and remediate contamination in certain circumstances. Liabilities to investigate or remediate contamination, as well as other liabilities concerning hazardous materials or contamination, such as claims for personal injury or property damage, may arise at many locations, including formerly owned or operated properties and sites where wastes have been treated or disposed of, as well as at properties currently owned or operated by us. Such liabilities may arise even where the contamination does not result from noncompliance with applicable environmental laws. Under a number of environmental laws, such liabilities may also be joint and several, meaning that a party can be held responsible for more than its share of the liability involved, or even the entire share. Environmental requirements generally have become more stringent and compliance with those requirements more expensive. We are not aware of any specific developments that would increase our costs for such compliance in a manner that would be expected to have a material adverse effect on our results of operations, financial position or liquidity.

 

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

 

Some properties in which we have an ownership interest or at which we operate are, and others are suspected of being, affected by environmental contamination. We are not aware of any claims pending or threatened against us with respect to environmental contamination, or of any investigation or remediation

of contamination at any properties, that entail costs likely to materially affect us. Some facilities and properties are located near environmentally sensitive areas such as wetlands.

 

Claims have been made or threatened against electric utilities for bodily injury, disease or other damages allegedly related to exposure to electromagnetic fields associated with electric transmission and distribution lines. While we do not believe that a causal link between electromagnetic field exposure and injury has been generally established and accepted in the scientific community, if such a relationship is established or accepted, the liabilities and costs imposed on our business could be significant. We are not aware of any claims pending or threatened against us for bodily injury, disease or other damages allegedly related to exposure to electromagnetic fields and electric transmission and distribution lines that entail costs likely to have a material adverse effect on our results of operations, financial position or liquidity.

 

Filings Under the Securities Exchange Act of 1934

 

Our internet address is 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 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:

 

 

Our Code of Business Conduct and Ethics applies to all directors, officers and employees, including our Chairman, President and Chief Executive Officer and our Senior Vice President, Treasurer and Chief Financial Officer. We will post any amendments to the Code of Business Conduct and Ethics, and any waivers that are required to be disclosed by the rules of either the SEC or the NYSE, on our web site within the required periods. The information on our web site is not incorporated by reference into this report.

 

To learn more about us, please visit our web site at 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 web site 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.

 

 

Risks Related to Our Business

 

Certain elements of our Regulated Operating Subsidiaries’ cost recovery through rates can be challenged, which could result in lowered rates and/or refunds of amounts previously collected and thus have an adverse effect on our business, financial condition, results of operations and cash flows. We have also made certain commitments to federal and state regulators with respect to, among other things, our rates in connection with recent acquisitions (including ITC Midwest’s acquisition of IP&L’s electric transmission assets) that could have an adverse effect on our business, financial condition, results of operations and cash flows.

 

Our Regulated Operating Subsidiaries provide transmission service under rates regulated by the FERC. The FERC has approved our MISO Regulated Operating Subsidiaries’ use of the rate setting

formula under Attachment O. In addition, FERC has approved the formula rate of ITC Great Plains, but it has not expressly approved the amount of actual capital and operating expenditures to be used in either formula rate. All aspects of our Regulated Operating Subsidiaries’ rates approved by the FERC, including the formula rate mechanisms, ITCTransmission’s, METC’s, ITC Midwest’s and ITC Great Plains’ respective allowed 13.88%, 13.38%, 12.38% and 12.16% rates of return on the actual equity portion of their respective capital structures, and the data inputs provided by our Regulated Operating Subsidiaries for calculation of each year’s rate, are subject to challenge by interested parties at the FERC in a proceeding under Section 206 of the FPA. If a challenger can establish that any of these aspects are unjust, unreasonable, unduly discriminatory or preferential, then the FERC will make appropriate prospective adjustments to them and/or disallow any of our Regulated Operating Subsidiaries’ inclusion of those aspects in the rate setting formula. This could result in lowered rates and/or refunds of amounts collected after the date that a Section 206 challenge is filed.

 

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

 

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

 

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

 

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

 

In the Minnesota regulatory proceeding, ITC Midwest also agreed to build two construction projects intended to improve the reliability and efficiency of our electric transmission system. ITC Midwest agreed to

use commercially reasonable efforts to complete these projects prior to December 31, 2009 and 2011, respectively. The project that was required to be completed prior to December 31, 2009 was completed by that deadline. In the event ITC Midwest fails to meet the remaining commitments, the allowed 12.38% rate of return on the actual equity portion of ITC Midwest’s capital structure will be reduced to 10.39% under Attachment O until such time as it completes these projects and ITC Midwest will refund with interest any amounts collected since the close date of the transaction that exceeded what would have been collected if the 10.39% ROE had been used in Attachment O. 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 revenues. In addition, we expect to invest in strategic development opportunities to improve the efficiency and reliability of the transmission grid, but we cannot assure you that we will be able to initiate or complete any of these investments.

 

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 capital investments of approximately $3 billion for the period January 1, 2010 through December 31, 2014. The expected amounts of capital investment over the period beginning January 1, 2010 through December 31, 2014 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.

 

We expect to make significant investments at our Regulated Operating Subsidiaries in 2010, including capital investments for transmission network upgrades. Our expected capital investments in our Regulated Operating Subsidiaries for the year ended December 31, 2010 could change significantly due to the uncertainty around capital investments for transmission network upgrades for generator interconnections as described above. 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 super-regional transmission facilities, interconnections for wind generation and other renewable resources, and other investment opportunities. The incumbent utilities or other entities with transmission development initiatives may compete with us by deciding to pursue capital projects that we are pursuing. These estimates of potential investment opportunities are based primarily on foreseeable transmission needs and general transmission construction costs, not necessarily on particular project cost estimates.

 

Any capital investment at our Regulated Operating Subsidiaries or as a result of our broader strategic development initiatives may be lower than expected due to, among other factors, the impact of actual loads, forecasted loads, regional economic conditions, weather conditions, union strikes, labor shortages, material and equipment prices and availability, our ability to obtain financing for such expenditures, if necessary, limitations on the amount of construction that can be undertaken on our system or transmission systems owned by others at any one time or regulatory approvals for reasons relating to rate construct, environmental, siting, regional planning, cost recovery and other issues or as a result of legal proceedings and variances between estimated and actual costs of construction contracts awarded. Our ability to engage in construction projects resulting from pursuing these initiatives is subject to significant uncertainties, including the factors discussed above, and will depend on obtaining any necessary regulatory and other approvals for the project and for us to initiate construction, our achieving status as the builder of the project in some circumstances and other factors. Therefore, we can provide no assurance as to the actual

level of investment we may achieve at our Regulated Operating Subsidiaries or as a result of the broader strategic development initiatives.

 

The regulations to which we are subject may limit our ability to raise capital and/or pursue acquisitions, development opportunities or other transactions or may subject us to liabilities.

 

Each of our Regulated Operating Subsidiaries is a “public utility” under the FPA and, accordingly, is subject to regulation by the FERC. Approval of the FERC is required under Section 203 of the FPA for a disposition or acquisition of regulated public utility facilities, either directly or indirectly through a holding company. Such approval may also be required to acquire securities in a public utility. Section 203 of the FPA also provides the FERC with explicit authority over utility holding companies’ purchases or acquisitions of, and mergers or consolidations with, a public utility. Finally, each of our Regulated Operating Subsidiaries must also seek approval by the FERC under Section 204 of the FPA for issuances of its securities (including debt securities).

 

We are also pursuing strategic development opportunities for construction of transmission facilities and interconnections with wind generation and other renewable resources. These projects require regulatory approval by the FERC, applicable RTOs and state regulatory agencies. Failure to secure such regulatory approval for new strategic development projects could adversely affect our ability to grow our business and increase our revenues.

 

In addition, we are subject to state and/or local regulations relating to, among other things, facility siting. If we fail to comply with these local regulations, we may incur liabilities for such failure.

 

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

 

The formula rate templates used by our Regulated Operating Subsidiaries to calculate their respective annual revenue requirements will be used by our Regulated Operating Subsidiaries for that purpose until and unless the FERC determines that such rate formula is unjust and unreasonable or that another mechanism is more appropriate. Such determinations could result from challenges initiated at the FERC by interested parties, by the FERC on its own initiative in a proceeding under Section 206 of the FPA or by a successful application initiated by any of our Regulated Operating Subsidiaries under Section 205 of the FPA. End-use consumers and entities supplying electricity to end-use consumers may attempt to influence government and/or regulators to change the rate setting methodologies that apply to our Regulated Operating Subsidiaries, particularly if rates for delivered electricity increase substantially.

 

Each of our Regulated Operating Subsidiaries is regulated by the FERC as a “public utility” under the FPA and is a transmission owner in MISO or SPP. We cannot predict whether the approved rate methodologies for any of our Regulated Operating Subsidiaries will be changed. In addition, the U.S. Congress periodically considers enacting energy legislation that could shift new responsibilities to the FERC, modify provisions of the FPA or provide the FERC or another entity with increased authority to regulate transmission matters. We cannot predict whether, and to what extent, our Regulated Operating Subsidiaries may be affected by any such changes in federal energy laws, regulations or policies in the future.

 

If the network load or point-to-point transmission service on our MISO Regulated Operating Subsidiaries’ transmission systems is lower than expected, the timing of collection of our revenues would be delayed.

 

If the network load or point-to-point transmission service on our MISO Regulated Operating Subsidiaries’ transmission systems is lower than expected due to weather, a weak economy, changes in the nature or composition of the transmission grids of our MISO 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 MISO Regulated Operating Subsidiaries’ formula rate 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 would adversely affect our revenues and our ability to service our debt obligations and affect our ability to pay dividends.

 

ITCTransmission derives a substantial portion of its revenues from the transmission of electricity to Detroit Edison’s local distribution facilities. Detroit Edison accounted for 83.8% of ITCTransmission’s total operating revenues for the year ended December 31, 2009 and is expected to constitute the majority of ITCTransmission’s revenues for the foreseeable future. Detroit Edison is rated BBB/stable and Baa1/stable by Standard & Poor’s Ratings Services and Moody’s Investors Services, Inc., respectively. Similarly, Consumers Energy accounted for 78.0% of METC’s total operating revenues for the year ended December 31, 2009, and is expected to constitute the majority of METC’s revenues for the foreseeable future. Consumers Energy is rated BBB-/stable and Baa2/stable by Standard & Poor’s Ratings Services and Moody’s Investors Service, Inc., respectively. Further, IP&L accounted for 82.6% of ITC Midwest’s total operating revenues for the year ended December 31, 2009 and is expected to constitute the majority of ITC Midwest’s revenues for the foreseeable future. IP&L is rated BBB+/stable and A3/stable by Standard & Poor’s Ratings Services and Moody’s Investors Service, Inc., respectively. These percentages of total operating revenues of Detroit Edison, Consumers Energy and IP&L include an estimate for the 2009 Attachment O revenue accruals and deferrals that were included in our 2009 operating revenues, but will not be billed to our customers until 2011. We have assumed that the Attachment O revenues billed to these customers in 2011 would be in the same proportion of the respective percentages of network revenues billed to them in 2009.

 

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

 

METC does not own the majority of the land on which its transmission assets are located. Additionally, a significant amount of the land on which ITCTransmission’s and ITC Midwest’s assets are located is subject to easements, mineral rights and other similar encumbrances and a significant amount of ITCTransmission’s and ITC Midwest’s other property consists of easements. As a result, ITCTransmission, METC and ITC Midwest must comply with the provisions of various easements, mineral rights and other similar encumbrances, which may adversely impact their ability to complete construction projects in a timely manner.

 

METC does not own the majority of the land on which its electric transmission assets are located. Instead, under the provisions of an Easement Agreement with Consumers Energy, METC pays annual rent of $10.0 million to Consumers Energy in exchange for rights-of-way, leases, fee interests and licenses which allow METC to use the land on which its transmission lines are located. Under the terms of the Easement Agreement, METC’s easement rights could be eliminated if METC fails to meet certain requirements, such as paying contractual rent to Consumers Energy in a timely manner. Additionally, a significant amount of the land on which ITCTransmission’s and ITC Midwest’s assets are located is subject to easements, mineral rights and other similar encumbrances and a significant amount of ITCTransmission’s and ITC Midwest’s other property consists of easements. As a result, they must comply with the provisions of various easements, mineral rights and other similar encumbrances, which may adversely impact their ability to complete their construction projects in a timely manner.

 

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

 

ITC Midwest has an operating service agreement with IP&L, the IP&L TSA, which governs the operation of ITC Midwest’s 34.5 kV transmission system. The IP&L TSA’s initial term expired, but ITC Midwest exercised its option under the IP&L TSA to extend the system operations services and an associated billing service to December 31, 2010. The IP&L TSA can be terminated by mutual agreement of the parties. If the FERC were to terminate this agreement prematurely, or if this agreement is terminated or

fails to be renewed for any other reason at any time when ITC Midwest is unprepared for such termination, ITC Midwest may face difficulty finding a qualified replacement work force to provide such services, which could have a material adverse effect on its ability to carry on its business and on its results of operations.

 

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

 

The operations of our Regulated Operating Subsidiaries are subject to the usual hazards associated with high-voltage electricity transmission, including explosions, fires, inclement weather, natural disasters, mechanical failure, unscheduled downtime, equipment interruptions, remediation, chemical spills, discharges or releases of toxic or hazardous substances or gases and other environmental risks. The hazards can cause personal injury and loss of life, severe damage to or destruction of property and equipment and environmental damage, and may result in suspension of operations and the imposition of civil or criminal penalties. We maintain property and casualty insurance, but we are not fully insured against all potential hazards incident to our business, such as damage to poles, towers and lines or losses caused by outages.

 

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

 

The operations of our Regulated Operating Subsidiaries are subject to federal, state and local environmental laws and regulations, which impose limitations on the discharge of pollutants into the environment, establish standards for the management, treatment, storage, transportation and disposal of hazardous materials and of solid and hazardous wastes, and impose obligations to investigate and remediate contamination in certain circumstances. Liabilities to investigate or remediate contamination, as well as other liabilities concerning hazardous materials or contamination such as claims for personal injury or property damage, may arise at many locations, including formerly owned or operated properties and sites where wastes have been treated or disposed of, as well as at properties currently owned or operated by our Regulated Operating Subsidiaries. Such liabilities may arise even where the contamination does not result from noncompliance with applicable environmental laws. Under a number of environmental laws, such liabilities may also be joint and several, meaning that a party can be held responsible for more than its share of the liability involved, or even the entire share. Environmental requirements generally have become more stringent in recent years, and compliance with those requirements more expensive.

 

Our Regulated Operating Subsidiaries have incurred expenses in connection with environmental compliance, and we anticipate that each will continue to do so in the future. Failure to comply with the extensive environmental laws and regulations applicable to each could result in significant civil or criminal penalties and remediation costs. Our Regulated Operating Subsidiaries’ assets and operations also involve the use of materials classified as hazardous, toxic, or otherwise dangerous. Some of our Regulated Operating Subsidiaries’ facilities and properties are located near environmentally sensitive areas such as wetlands and habitats of endangered or threatened species. In addition, certain properties in which our Regulated Operating Subsidiaries operate are, or are suspected of being, affected by environmental contamination. Compliance with these laws and regulations, and liabilities concerning contamination or hazardous materials, may adversely affect our costs and, therefore, our business, financial condition and results of operations.

 

In addition, claims have been made or threatened against electric utilities for bodily injury, disease or other damages allegedly related to exposure to electromagnetic fields associated with electric transmission and distribution lines. We cannot assure you that such claims will not be asserted against us or that, if determined in a manner adverse to our interests, such claims would not have a material adverse effect on our business, financial condition and results of operations.

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

 

Our Regulated Operating Subsidiaries are required to comply with various regulations, laws, and standards.

 

The various regulatory requirements we are subject to 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 in respect of real-time transmission operations, emergency operations, vegetation management, critical infrastructure protection and personnel training. Failure to comply with these requirements can result in monetary penalties as well as non-monetary sanctions. Monetary penalties vary based on an assigned risk factor for each potential violation, the severity of the violation and various other circumstances, such as whether the violation was intentional or concealed, whether there are repeated violations, the degree of the violator’s cooperation in investigating and remediating the violation and the presence of a compliance program. Penalty amounts range from $1,000 to a maximum of $1.0 million per day, depending on the severity of the violation. Non-monetary sanctions include potential limitations on the violator’s activities or operation and placing the violator on a watchlist for major violators. Despite our best efforts to comply and the implementation of a compliance program intended to ensure reliability, there can be no assurance that violations will not occur that would result in material penalties or sanctions. If any of our Regulated Operating Subsidiaries were to violate the NERC reliability standards, even unintentionally, in any material way, any penalties or sanctions imposed against us could have a material adverse effect on our financial condition, results of operations and cash flows.

 

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

 

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

 

Risks Relating to Our Structure and Financial Leverage

 

ITC Holdings is a holding company with no operations, and unless we receive dividends or other payments from our subsidiaries, we may be unable to pay dividends and fulfill our other cash obligations.

 

As a holding company with no business operations, ITC Holdings’ material assets consist primarily of the stock and membership interests in our Regulated Operating Subsidiaries and our other subsidiaries, deferred tax assets relating primarily to federal income tax NOLs and cash on hand. Our only sources of cash to pay dividends to our stockholders are dividends and other payments received by us from time to time from our Regulated Operating Subsidiaries and our other subsidiaries and the proceeds raised from the sale of our debt and equity securities. Each of our Regulated Operating Subsidiaries, however, is legally distinct from us and has no obligation, contingent or otherwise, to make funds available to us for the payment of dividends to ITC Holdings’ stockholders or otherwise. The ability of each of our Regulated Operating Subsidiaries and our other subsidiaries to pay dividends and make other payments to us is subject to, among other things, the availability of funds, after taking into account capital expenditure

requirements, the terms of its indebtedness, applicable state laws and regulations of the FERC and the FPA. While we currently intend to continue to pay quarterly dividends on our common stock, we have no obligation to do so. The payment of dividends is within the absolute discretion of our board of directors and will depend on, among other things, our results of operations, working capital requirements, capital expenditure requirements, financial condition, contractual restrictions, anticipated cash needs and other factors that our board of directors deems relevant.

 

We are highly leveraged and our dependence on debt may limit our ability to fulfill our debt obligations and/or to obtain additional financing.

 

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

 

 

We may incur substantial indebtedness in the future. The incurrence of additional indebtedness would increase the leverage-related risks described here.

Certain provisions in our debt instruments limit our financial flexibility.

 

Our debt instruments include senior notes, secured notes, first mortgage bonds and revolving credit agreements containing numerous financial and operating covenants that place significant restrictions on, among other things, our ability to:

 

 

The revolving credit agreements, ITC Holdings’ senior notes, ITCTransmission’s first mortgage bonds, ITC Midwest’s first mortgage bonds and METC’s senior secured notes require us to meet certain financial ratios, such as maintaining certain debt to capitalization ratios. Our ability to comply with these and other requirements and restrictions may be affected by changes in economic or business conditions, results of operations or other events beyond our control. A failure to comply with the obligations contained in any of our debt instruments could result in acceleration of the related debt and the acceleration of debt under other instruments evidencing indebtedness that may contain cross-acceleration or cross-default provisions.

 

Adverse changes in our credit ratings may negatively affect us.

 

Our ability to access capital markets is important to our ability to operate our business. Increased scrutiny of the energy industry and the impact of regulation, as well as changes in our financial performance and unfavorable conditions in the capital markets could result in credit agencies reexamining our credit ratings. A downgrade in our credit ratings could restrict or discontinue our ability to access capital markets at attractive rates and increase our borrowing costs. A rating downgrade could also increase the interest we pay under our revolving credit agreements.

 

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

 

As of December 31, 2009, we had estimated federal income tax NOLs of $266.9 million, resulting in part from accelerated depreciation methods for property, plant and equipment for income tax reporting purposes. These federal income tax NOLs may be used to offset future taxable income and thereby reduce our U.S. federal income taxes otherwise payable. Section 382 of the Internal Revenue Code of 1986, as amended imposes an annual limit on the ability of a corporation that undergoes an “ownership change” to use its federal income tax NOLs to reduce its tax liability. We are subject to annual limitations on the use of such federal income tax NOLs as a result of changes in our ownership in 2006. We have not recorded a valuation allowance relating to our federal income tax NOLs. In the event it becomes more likely than not that any portion of the federal income tax NOLs will expire unused, we would be required to recognize an expense to establish a valuation allowance in the period in which the determination is made. If the expense is significant, it could have a material adverse effect on our results of operations.

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

 

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

 

 

In addition, our revolving credit agreements provide that a change in a majority of ITC Holdings’ board of directors that is not approved by the current ITC Holdings directors or acquiring beneficial ownership of 35% or more of ITC Holdings outstanding common shares will constitute a default under those agreements.

 

Provisions in our Articles of Incorporation restrict market participants from voting or owning 5% or more of the outstanding shares of our capital stock.

 

Certain of our Regulated Operating Subsidiaries have been granted favorable rate treatment by the FERC based on their independence from market participants. The FERC defines a “market participant” to include any person or entity that, either directly or through an affiliate, sells or brokers electricity, or provides ancillary services to an RTO. An affiliate, for these purposes, includes any person or entity that directly or indirectly owns, controls or holds with the power to vote 5% or more of the outstanding voting securities of a market participant. To help ensure that we and our subsidiaries will remain independent of market participants, our Articles of Incorporation impose certain restrictions on the ownership and voting of shares of our capital stock by market participants. In particular, the Articles of Incorporation provide that we are restricted from issuing any shares of capital stock or recording any transfer of shares if the issuance or transfer would cause any market participant, either individually or together with members of its “group” (as defined in SEC beneficial ownership rules), to beneficially own 5% or more of any class or series of our capital stock. Additionally, if a market participant, together with its group members, acquires beneficial ownership of 5% or more of any series of the outstanding shares of our capital stock, such market participant or any shareholder who is a member of a group including a market participant will not be able to vote or direct or control the votes of shares representing 5% or more of any series of our outstanding capital stock. Finally, to the extent a market participant, together with its group members, acquires beneficial ownership of 5% or more of the outstanding shares of any series of our capital stock, our Articles of Incorporation allow our board of directors to redeem any shares of our capital stock so that, after giving 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.

 

 

None.

 

 

Our Regulated Operating Subsidiaries’ transmission facilities are located in the lower peninsula of Michigan and portions of Iowa, Minnesota, Illinois, Missouri and Kansas. Our MISO Regulated Operating

Subsidiaries have agreements with other utilities for the joint ownership of specific substations and transmission lines. See Note 15 to the consolidated financial statements.

 

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

 

 

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:

 

 

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

 

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:

 

 

 

ITC Midwest’s First Mortgage Bonds were initially issued in January 2008 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 two electric transmission substations in Kansas.

 

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.

 

 

We are involved in certain legal proceedings from time to time before various courts, governmental agencies, and mediation panels concerning matters arising in the ordinary course of business. These proceedings include certain contract disputes, regulatory matters, and pending judicial matters. We cannot predict the final disposition of such proceedings. We regularly review legal matters and record provisions for claims that are considered probable of loss. The resolution of pending proceedings is not expected to have a material effect on our operations or financial statements in the period they are resolved.

 

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

 

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

 

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

 

 

None.

 

 

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 19, 2010, there were approximately 533 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 2009 and 2008, as reported on the NYSE and the cash dividends per share paid during the periods indicated.

 

 

 

The declaration and payment of dividends is subject to the discretion of ITC Holdings’ board of directors and depends on various factors, including our net income, financial condition, cash requirements, future prospects and other factors deemed relevant by our board of directors. As a holding company with no business operations, ITC Holdings’ material assets consist primarily of the common stock or ownership interests in its subsidiaries, deferred tax assets relating primarily to federal income tax NOLs and cash. ITC Holdings’ material cash inflows are only from dividends and other payments received from time to time from its subsidiaries and the proceeds raised from the sale of debt and equity securities. ITC Holdings may not be able to access cash generated by its subsidiaries in order to pay dividends to shareholders. The ability of ITC Holdings’ subsidiaries to make dividend and other payments to ITC Holdings is subject to the availability of funds after taking into account the subsidiaries’ funding requirements, the terms of the subsidiaries’ indebtedness, the regulations of the FERC under FPA, and applicable state laws. The debt agreements to which we are parties contain numerous financial covenants that could limit ITC Holdings’ ability to pay dividends, as well as covenants that prohibit ITC Holdings from paying dividends if we are in default under our revolving credit facilities. Further, each of our subsidiaries is legally distinct from ITC Holdings and has no obligation, contingent or otherwise, to make funds available to us.

 

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

 

The board of directors intends to increase the dividend rate from time to time as necessary to maintain an appropriate dividend payout ratio, subject to prevailing business conditions, applicable restrictions on dividend payments, the availability of capital resources and our investment opportunities.

 

The transfer agent for the common stock is Computershare Trust Company, N.A., P.O. Box 43078 Providence, RI 02940-3078.

In addition, the information contained in the Equity Compensation table under “Item 12 Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters” of this report is incorporated herein by reference.

 

Stock Repurchases

 

 

 

 

 

The following table sets forth our selected historical financial data for the periods indicated. On July 19, 2005, ITC Holdings affected an approximately 3.34-for-one stock split. All amounts and values of common shares and options and per share data in the accompanying financial information have been retroactively adjusted to give effect to the stock split.

 

The selected 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.

 

 

 

 

 

 

 

Safe Harbor Statement Under The Private Securities Litigation Reform Act of 1995

 

Our reports, filings and other public announcements contain certain statements that describe our management’s beliefs concerning future business conditions, plans and prospects, growth opportunities and the outlook for our business and the electric transmission industry based upon information currently available. Such statements are “forward-looking” statements within the meaning of the Private Securities Litigation Reform Act of 1995. Wherever possible, we have identified these forward-looking statements by words such as “will,” “may,” “anticipates,” “believes,” “intends,” “estimates,” “expects,” “projects” and similar phrases. These forward-looking statements are based upon assumptions our management believes are reasonable. Such forward-looking statements are subject to risks and uncertainties which could cause our actual results, performance and achievements to differ materially from those expressed in, or implied by, these statements, including, among others, the risks and uncertainties disclosed under “Item 1A Risk Factors.”

 

Because our forward-looking statements are based on estimates and assumptions that are subject to significant business, economic and competitive uncertainties, many of which are beyond our control or are subject to change, actual results could be materially different and any or all of our forward-looking statements may turn out to be wrong. Forward-looking statements speak only as of the date made and can be affected by assumptions we might make or by known or unknown risks and uncertainties. Many factors mentioned in our discussion in this report will be important in determining future results. Consequently, we cannot assure you that our expectations or forecasts expressed in such forward-looking statements will be achieved. Actual future results may vary materially. Except as required by law, we undertake no obligation to publicly update any of our forward-looking or other statements, whether as a result of new information, future events, or otherwise.

 

Overview

 

Through our Regulated Operating Subsidiaries, we are engaged in the transmission of electricity in the United States. 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. By pursuing this strategy, we strive for high reliability of our systems and to improve accessibility to generation sources of choice, including renewable sources. We operate high-voltage systems in Michigan’s Lower Peninsula and portions of Iowa, Minnesota, Illinois, Missouri and Kansas that transmit electricity from generating stations to local distribution facilities connected to our systems.

 

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 a cost-based formula rate template, as discussed in “Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations — Cost-Based Formula Rates with True-Up Mechanism.”

 

Our Regulated Operating Subsidiaries’ primary operating responsibilities include maintaining, improving and expanding their transmission systems to meet their customers’ ongoing needs, scheduling outages on system elements to allow for maintenance and construction, balancing electricity generation and demand, 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 network transmission service, point-to-point transmission service and other related services over our Regulated Operating Subsidiaries’ transmission

systems to investor owned utilities such as 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.

 

Significant recent events that influenced our financial position and results of operations and cash flows for the year ended December 31, 2009 or may affect future results include:

 

 

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

 

Recent Developments

 

ITC Great Plains

 

Formula Rate and Incentives

 

As described in Note 4 to the consolidated financial statements, ITC Great Plains’ cost-based formula rate with a true-up mechanism and request for certain incentives for transmission investment have been accepted by the FERC.

 

In October 2009, SPP made a filing with FERC to include ITC Great Plains’ revenue requirement in its tariff. In December 2009, the FERC issued an order which accepted the SPP’s filing to include ITC Great Plains revenue requirement in its tariff. SPP began to bill ITC Great Plains’ 2009 network revenues in January 2010, retroactive to August 18, 2009 (the date of the substation acquisitions described below).

 

Substation Acquisitions

 

In August 2009, ITC Great Plains purchased two electric transmission substations from Mid-Kansas with a net book value of $4.7 million. ITC Great Plains now operates the 138 kV Flat Ridge Substation located in Barber County, Kansas and the 230 kV Elm Creek Substation located in Cloud County, Kansas under a services agreement with Mid-Kansas. As a result of this acquisition, ITC Great Plains participates in SPP as a transmission owner.

 

Regulatory Assets

 

In July 2009, we recorded approximately $8.2 million of regulatory assets for development expenses incurred by ITC Great Plains through June 30, 2009 that became probable of recovery and recorded a corresponding $8.2 million reduction to operating expenses, primarily to general and administrative expense. Subsequent to the initial recognition of these regulatory assets, we recorded an additional $1.8 million of costs incurred during the third and fourth quarters of 2009 directly to regulatory assets. The regulatory asset includes amounts relating to development activities of ITC Great Plains as well as pre-construction costs for the KETA Project. Based on ITC Great Plains’ application and the FERC order, ITC Great Plains will be required to make an additional filing with the FERC under Section 205 of the Federal Power Act in order to recover these start-up, development and pre-construction expenses. The regulatory

assets recorded at ITC Great Plains do not include amounts associated with pre-construction costs for the Kansas V-Plan. In the period in which it becomes probable that future revenues will result from the authorization to recover pre-construction expenses for the Kansas V-Plan, which total $0.9 million at December 31, 2009, we will recognize those expenses as regulatory assets.

 

KETA Project

 

On July 13, 2009, ITC Great Plains received siting approval from the KCC to build the first phase of its 345 kV KETA Project, a 215-mile long transmission line that will run between Spearville, Kansas and Axtell, Nebraska. This first phase of the project involves the construction of an 89-mile transmission line between Spearville and Hays, Kansas. The KCC siting approval is a critical step in allowing ITC Great Plains to pursue construction of the first phase of the KETA Project. The siting permit was conditioned upon ITC Great Plains obtaining the authorization to construct the project from SPP. On January 19, 2010, the FERC issued an order approving the novation agreements required by SPP for the designation to ITC Great Plains by Sunflower Electric Power Corporation and Midwest Energy, Inc. ITC Great Plains is also in the process of securing other remaining regulatory approvals for the second phase of the project, which will run from Hays, Kansas to the Nebraska border. The final segment of the project from the Nebraska border to Axtell, Nebraska will be completed by Nebraska Public Power District. We estimate that the cost for ITC Great Plains’ portion of the KETA project will be approximately $175 million. The first phase of the project represents approximately $105 million of this total and ITC Great Plains has commenced right of way acquisition activities.

 

Kansas V-Plan Project

 

On June 1, 2009, ITC Great Plains entered into a stipulation and an agreement with Prairie Wind Transmission, LLC (“Prairie Wind”) and other interested parties to resolve pending regulatory proceedings about who should be authorized to build the 180-mile long transmission line project known as the Kansas V-Plan. On July 24, 2009, the KCC issued a bench ruling accepting the stipulation and agreement between ITC Great Plains and Prairie Wind, and on October 5, 2009, the KCC issued its final order granting a motion to approve the stipulation and agreement. Under the terms of the settlement agreement, ITC Great Plains and Prairie Wind are each authorized by the KCC to build segments of the Kansas V-Plan, which will run between Spearville and Wichita, Kansas. The agreement stipulates that ITC Great Plains will construct and own two segments of the line, including the first section of line running from Spearville to Comanche County, Kansas and the second section from Comanche County to Medicine Lodge, Kansas. ITC Great Plains will also construct a new substation in Comanche County. Prairie Wind will construct a substation at Medicine Lodge and a third section of line from that substation to a termination point outside of Wichita. Prairie Wind also would be certificated to construct a line from the Kansas V-Plan to the Oklahoma border. The settlement agreement addresses only facilities proposed to be constructed in Kansas. The next steps for this project are expected to include securing siting approvals, resolution of cost allocation issues and project evaluation by the SPP regional planning authority. The stipulation and agreement approved by the KCC has various conditions including approval of regional cost allocation by the SPP. The Kansas V-Plan has been proposed to be constructed at a voltage of 765 kV if deemed appropriate by SPP. ITC Great Plains estimates it will invest approximately $430 million to construct its portions of the project if it is built at this voltage.

 

Hugo to Valliant Project

 

On April 7, 2009, Western Farmers Electric Cooperative, an Oklahoma rural electric cooperative corporation, agreed to designate ITC Great Plains as the exclusive party responsible and authorized to construct, own and operate the Hugo-Valliant transmission line and the Hugo 345 kV Substation, both located in Oklahoma. The project will consist of a 19 mile 345 kV transmission line,and a substation including a new 138/345 kV autotransformer. The project has an estimated cost of approximately $30 million. On April 28, 2009, SPP approved the novation agreement required by the SPP for the designation of ITC Great Plains by Western Farmers Electric Cooperative. On July 10, 2009, the FERC

issued an order accepting the novation agreement and ITC Great Plains has commenced right of way acquisition activities.

 

Development Bonuses

 

During the third quarter of 2009, our board of directors authorized and we paid a total of $0.3 million in bonuses to substantially all employees for the successful completion of certain significant regulatory milestones relating to the Hugo to Valliant transmission line project, which were recorded to general and administrative expenses.

 

In January of 2010, the board of directors authorized and we paid $0.9 million in bonuses to substantially all employees for the successful completion of certain regulatory milestones relating to the KETA Project, which were recorded to general and administrative expenses in 2010. It is reasonably possible that future development-related bonuses would be authorized and awarded for these or other development projects.

 

Green Power Express

 

As described in Note 4 to the consolidated financial statements, in April 2009 the FERC approved Green Power Express’ request for transmission investment incentives and has conditionally accepted Green Power Express’ proposed formula rate tariff sheets, subject to refund, and set them for hearing and Settlement Judge procedures. Drafts of an offer of settlement and supporting documents that would resolve all of the issues set for hearing in the April 10, 2009 order are under review by the parties and are expected to be filed in the first quarter of 2010.

 

The Green Power Express project is a network of transmission lines that would facilitate the movement of 12,000 megawatts of power from the wind-abundant areas in the Dakotas, Minnesota and Iowa to Midwest load centers that demand clean, renewable energy. The Green Power Express project would traverse portions of North Dakota, South Dakota, Minnesota, Iowa, Wisconsin, Illinois and Indiana and is ultimately expected to include approximately 3,000 miles of extra high-voltage (765 kV) transmission. The entire project is currently estimated to cost approximately $10 to $12 billion. Portions of the Green Power Express project fall within the service territory of ITC Midwest. ITC Holdings expects to partner with other utilities within the geographical footprint of the Green Power Express project and, therefore, expects to invest in only a portion of the total project cost.

 

The total development expenses through December 31, 2009 that may be recoverable through regulatory assets were approximately $4.5 million, which have been recorded to expenses in the periods in which they were incurred. In the period in which it becomes probable that future revenues will result from the authorization to recover these pre-construction expenses, we would recognize the regulatory assets and record a reduction to operating expenses for the total amount of these costs incurred through that period.

 

Complaint of IP&L

 

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

 

On April 16, 2009, the FERC issued an order that dismissed the IP&L complaint, citing that IP&L failed to meet its burden as the complainant to establish that the current rate is unjust and unreasonable and to

establish that IP&L’s alternative rate proposal is just and reasonable. Requests for rehearing have been filed with the FERC, so the April 16 order remains subject to rehearing and ultimately to an appeal to a federal Court of Appeals within 30 days of any decision on rehearing.

 

Depreciation Studies

 

During 2009, the FERC accepted depreciation studies filed by ITCTransmission and METC that revised depreciation rates at ITCTransmission and METC and their revenue requirements for 2009, and resulted in a $19.5 million reduction in revenue recognized for the year. This change in accounting estimate results in lower composite depreciation rates for ITCTransmission and METC primarily due to the revision of asset service lives and cost of removal values. The revised estimates resulted in a reduction of depreciation expense of $19.5 million for the year ended December 31, 2009. Because of the inclusion of depreciation expense as a component of net revenue requirement under the cost-based formula rate, the offsetting effect on revenues and expenses from the change in depreciation rates had an immaterial effect on net income and earnings per share amounts for the year ended December 31, 2009.

 

Capitalization of Expenses

 

During 2009, we reviewed the processes and assumptions used to record our estimates for certain expenses to be capitalized, including compensation and benefits, general business expenses and depreciation expense for our vehicles and equipment, given our continued focus on capital investment at our Regulated Operating Subsidiaries and the continuing costs to support these activities. As part of this review, we examined the activities performed by employees to determine which activities were directly and incrementally related to the construction programs at our Regulated Operating Subsidiaries. As a result of this review, the general and administrative expense and operation and maintenance amounts capitalized during 2009 exceed the amounts capitalized during 2008. As a result of the ratemaking model discussed in “Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations — Cost-Based Formula Rates with True-Up Mechanism” and the inclusion of operating expenses in the net revenue requirements of our MISO Regulated Operating Subsidiaries, this capitalization reduced operating expenses and operating revenues by approximately equivalent amounts and therefore did not result in a significant change in net income in 2009 compared to 2008.

 

Michigan Sales and Use Tax Audit

 

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

 

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

 

The amount of use tax liability associated with the exemptions taken by ITCTransmission through December 31, 2009 is estimated to be approximately $5.7 million, which includes approximately $3.3 million assessed for the audit period April 1, 2005 through June 30, 2008, including interest. In the event it becomes appropriate to record additional use tax expense relating to this matter, ITCTransmission would record the additional use tax expense primarily as an increase to the cost of property, plant and equipment, as the majority of purchases for which the exemption was taken relate to equipment purchases associated with capital projects. These higher use tax expenses would be passed on to ITCTransmission’s customers as the amounts are included as components of net revenue requirements and resulting rates. METC has also taken the industrial processing exemption, estimated to be approximately $5.9 million for periods still subject to audit since 2005. The Michigan Department of Treasury initiated a use tax audit of MTH, METC’s sole member, in the first quarter of 2010.

Cost-Based Formula Rates with True-Up Mechanism

 

Our Regulated Operating Subsidiaries’ net revenue requirements are derived 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 using forecasted expenses, property, plant and equipment, point-to-point revenues, network load and other items for the upcoming calendar year to establish their projected net revenue requirement and their component of the billed network rates for service on their systems from January 1 to December 31 of that year. The formula rates include a true-up mechanism, whereby each of our Regulated Operating Subsidiaries will compare its actual net revenue requirements to its billed network revenues for each year after the end of that year. Under our formula rates, in the event billed network revenues in a given year are more or less than actual net 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 net 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. For example, the true-up adjustment relating to 2009 is finalized in 2010 upon completion of the 2009 FERC Form No. 1 and will be included in the projected net revenue requirement that is used to establish the rate that will be effective commencing January 1, 2011.

 

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

 

Monthly peak loads continue to be used for billing network revenues for our MISO Regulated Operating Subsidiaries. Therefore, network load continues to have an impact on cash flows from transmission service, but does not impact operating revenues recognized. 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 following table presents our component of network transmission rates (per kW/month) for our MISO Regulated Operating Subsidiaries that are relevant to our results of operations and cash flows since January 1, 2007:

 

 

 

 

ITC Great Plains does not receive revenue based on a network transmission rate and peak load each month. The SPP tariff applicable to ITC Great Plains is billed ratably each month based on the annual projected net revenue requirement.

 

Net Revenue Requirement Calculation

 

Each of our Regulated Operating Subsidiaries separately calculates a net revenue requirement based on financial information specific to each company. The calculation of actual net revenue requirements for a historic period is used to calculate the amount of network revenues recognized in that period and to calculate the true-up adjustment for that period. The calculation of projected net revenue requirements is used to establish the transmission rate used for billing purposes, and follows the same methodology as the calculation of actual net revenue requirement. The following steps illustrate the calculation of net revenue requirement and the rate-setting methodology under the Attachment O formula rate template with a true-up mechanism used by our MISO Regulated Operating Subsidiaries. ITC Great Plains follows a similar methodology.

 

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

 

Rate base is projected using the average of the 13 projected month-end balances for the months beginning with December 31 of the current year and ending with December 31 of the upcoming year and consists primarily of projected in-service property, plant and equipment, net of accumulated depreciation, as well as other items.

 

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

 

Step Two — Calculate Projected Gross Revenue Requirement

 

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

 

Step Three — Calculate Projected Net Revenue Requirement

 

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

 

Step Four — Calculate True-up Adjustment

 

The actual transmission revenues billed for 2008 were compared to 2008 actual net revenue requirement which is based primarily on amounts from the completed FERC Form No. 1 for 2008. The true-up adjustment that results from the difference between the actual revenue billed and actual net revenue requirement for 2008 was added to the 2010 projected net revenue requirement used to determine the 2010 network transmission rate. Interest is also applied to the true-up adjustment.

 

Illustration of Attachment O Rate Setting.  Set forth below is a simplified illustration of the calculation of ITCTransmission’s projected net revenue requirement as well as its component of the joint zone network transmission rate for billing purposes under the Attachment O rate setting mechanism for the period from January 1, 2010 through December 31, 2010, that was based primarily upon projections of

ITCTransmission’s 2010 FERC Form No. 1 data. Amounts below are approximations of the amounts used to establish our projected net revenue requirement in the 2010 ITCTransmission Attachment O posting.

 

 

 

 

Trends and Seasonality

 

Network Revenues

 

We expect a general trend of increases in network transmission rates and revenues for our Regulated Operating Subsidiaries over the long term. The primary factor that is expected to continue to increase our rates and our actual net revenue requirements in future years is our anticipated capital investment in excess of depreciation levels as a result of our Regulated Operating Subsidiaries long-term capital investment programs. Investments in property, plant and equipment, when placed in service upon completion of a capital project, are added to the rate base of our Regulated Operating Subsidiaries. Our Regulated Operating Subsidiaries strive for high reliability of their systems and to improve accessibility to generation sources of choice, including renewable sources. In addition, the Energy Policy Act requires the FERC to implement mandatory electric transmission reliability standards to be enforced by an Electric Reliability Organization. Effective June 2007, the FERC approved mandatory adoption of certain reliability standards and approved enforcement actions for violators, including fines of up to $1.0 million per day. The 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 will likely be needed to maintain compliance, improve reliability and address any new standards that could 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; and (3) relieve congestion in the transmission systems. The following table shows our expected and actual capital investment for each of the Regulated Operating Subsidiaries:

 

 

 

 

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.

 

Revenue Accruals — Effects of Monthly Peak Loads and Expense Mitigation Efforts

 

Under their formula rates that contain a true-up mechanism, our Regulated Operating Subsidiaries accrue or defer revenues to the extent that their actual net revenue requirement for the reporting period is higher or lower, respectively, than the amounts billed relating to that reporting period. For example, to the

extent that amounts billed are less than our net revenue requirement for a reporting period, a revenue accrual is recorded for the difference. 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. The monthly peak load of our MISO Regulated Operating Subsidiaries is affected by many variables, but is generally reduced as economic activity decreases, and is seasonally shaped with higher load in the summer months when cooling demand is higher. ITCTransmission’s monthly peak loads for the year ended December 31, 2009 decreased 8.3% and 18.0%, respectively, compared to the corresponding totals for 2008 and 2007. METC’s monthly peak loads for the year ended December 31, 2009 decreased 5.5% and 14.0%, respectively, compared to the corresponding totals for 2008 and 2007. Additionally, in 2009, ITCTransmission and METC’s monthly peak loads were 11.6% and 10.4% lower, respectively, than what had been forecasted in developing the transmission network rates applicable for 2009, due in part to the unfavorable economic conditions in Michigan. A challenging economic environment in Michigan that results in lower network loads than what had been forecasted in developing the transmission network rates applicable for 2010 would continue to negatively impact our operating cash flows from network revenues in 2010 and result in an Attachment O revenue accrual for 2010, all other factors being equal. Transmission network rates in 2012 at each of our MISO Regulated Operating Subsidiaries would include any Attachment O revenue accrual for any under-recovered amounts relating to 2010, including interest.

 

To offset the impact of lower network load on cash flows and any potential revenue accrual relating to 2009, we engaged in efforts to mitigate operations and maintenance expenses and general and administrative expenses. These expense mitigation efforts were designed to ensure that we continue to meet our high standards for the reliability and safety of our systems and operations. By minimizing the revenue accrual in 2009 that would have resulted from lower than forecasted load, we collected cash in a manner that more closely corresponded with the revenues that we recorded. This action will also benefit our customers by reducing the significant 2009 revenue accrual that otherwise would have resulted and the impact it would have on network rates in 2011.

 

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

 

Monthly Peak Load (in MW)(a)

 

 

 

 

 

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. MISO and SPP each have credit policies for its tariff customers.

 

Network Revenues are generated from network customers for their use of our electric transmission systems and consist of both billed network revenues and accrued or deferred revenues as a result of our accounting under our cost-based formula rates that contain a true-up mechanism. Refer to “Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Policies — Revenue Recognition under Cost-Based Formula Rates with True-Up Mechanisms” for a discussion of revenue recognition relating to network revenues. The monthly network revenues billed to customers using the transmission facilities of our MISO Regulated Operating Subsidiaries are the result of a calculation which can be simplified into the following:

 

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

 

(2) divide the result by 365.

 

Our rates at ITC Great Plains are billed ratably each month based on its annual projected net revenue requirement and therefore peak usage does not impact its billed network transmission revenues.

 

Point-to-Point Revenues consist of revenues generated from a type of transmission service for which the customer pays for transmission capacity reserved along a specified path between two points on an hourly, daily, weekly or monthly basis. Point-to-point revenues also include other components pursuant to schedules under the MISO transmission tariff.

 

Regional Cost Sharing Revenues consist of revenues received from transmission customers associated with network upgrades to our MISO Regulated Operating Subsidiaries’ transmission systems that are eligible for regional cost sharing under Attachment FF of the MISO Transmission and Energy Market Tariff (Docket No. ER06-18). There is also a true-up mechanism associated with regional cost sharing revenues, whereby our MISO Regulated Operating Subsidiaries accrue or defer revenues for any over- or underrecovery of these revenues. Regional cost sharing revenues became applicable for us during 2008.

 

Scheduling, Control and Dispatch Revenues are allocated to our MISO Regulated Operating Subsidiaries by MISO as compensation for the services performed in operating the transmission system. Such services include, monitoring of reliability data, current and next day analysis, implementation of emergency procedures, and outage coordination and switching. Revenues that are allocated by MISO to our MISO Regulated Operating Subsidiaries relating to these services are not determined based on actual expenses incurred. In any given year, our MISO Regulated Operating Subsidiaries may earn more or less scheduling, control and dispatch revenues than our actual expenses incurred for control room activities.

 

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

Operating Expenses

 

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

 

Operation expenses include activities related to control area operations, which involve balancing loads and generation and transmission system operations activities, including monitoring the status of our transmission lines and stations. The expenses relating to METC’s Easement Agreement are also recorded within operation expenses.

 

Maintenance expenses include preventive or planned maintenance, such as vegetation management, tower painting and equipment inspections, as well as reactive maintenance for equipment failures.

 

General and Administrative Expenses consist primarily of costs for personnel in our finance, human resources, regulatory, information technology and legal organizations, general office expenses and fees for professional services. Professional services are principally composed of outside legal, audit and information technology services. We capitalize to property, plant and equipment portions of certain general and administrative expenses such as compensation, office rent, utilities, and information technology.

 

Depreciation and Amortization Expenses consist primarily of depreciation of property, plant and equipment using the straight-line method of accounting. Additionally, this consists of amortization of various regulatory and intangible assets. We capitalize to property, plant and equipment depreciation expense for vehicles and equipment used in our construction activities

 

Taxes other than Income Taxes consist primarily of property taxes and payroll taxes. Additionally, Michigan Single Business Taxes were recorded here through December 31, 2007, prior to the January 1, 2008 effective date of the Michigan Business Tax which is accounted for as an income tax.

 

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

 

Other items of income or expense

 

Interest Expense consists primarily of interest on long term debt at ITC Holdings and our Regulated Operating Subsidiaries. Additionally, the amortization of debt financing expenses is recorded to interest expense. An allowance for borrowed funds used during construction is included in property, plant and equipment accounts and is a reduction to interest expense.

 

Allowance for Equity Funds Used During Construction (“AFUDC equity”) is recorded as an item of other income and is included in property, plant and equipment accounts. The allowance represents a return on equity at our Regulated Operating Subsidiaries used for construction purposes in accordance with FERC regulations. The capitalization rate applied to the construction work in progress balance is based on the proportion of equity to total capital (which currently includes equity and long-term debt) and the allowed return on equity for our Regulated Operating Subsidiaries.

 

Income tax provision

 

Income tax provision consists primarily of federal income taxes. Additionally, we record income tax provisions for the various state income taxes we are subject to, including the Michigan Business Tax that became effective for us on January 1, 2008.

Results of Operations

 

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

 

 

Operating Revenues

 

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

 

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

 

 

Network revenues decreased due primarily to lower net revenue requirements at our MISO Regulated Operating Subsidiaries during the year ended December 31, 2009 as compared to the same period in 2008. Lower net revenue requirements were due primarily to our expense mitigation efforts discussed under “Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations — Trends and Seasonality — Revenue Accruals — Effects of Monthly Peak Loads and Expense Mitigation Efforts,” other reductions to operating expenses as a result of higher capitalization discussed under “Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations — Recent Developments — Capitalization of Expenses,” the reduction of depreciation expense as a result of the

ITCTransmission and METC depreciation studies discussed in Note 4 to the consolidated financial statements and an increase in regional cost sharing revenues. Partially offsetting these decreases was an increase due to higher rate base primarily associated with higher balances of property, plant and equipment in-service.

 

Network revenues for the year ended December 31, 2009 include the revenue accrual (deferral) as calculated below:

 

 

 

 

Regional cost sharing revenues increased due primarily to capital projects placed in service in 2007, 2008 or 2009 that have been identified by MISO as eligible for regional cost sharing. We expect to continue to receive regional cost sharing revenues and the amounts could become more significant in the near future, including revenues associated with ITC Great Plains’ projects that have or are expected to be approved for regional cost sharing.

 

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

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

 

Year ended December 31, 2008 compared to year ended December 31, 2007

 

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

 

 

Network revenues increased $133.5 million due to ITC Midwest’s asset acquisition in December of 2007. Additionally, ITCTransmission and METC recognized additional network revenues of $18.6 million and $16.5 million, respectively, due to higher net revenue requirements as a result of higher rate base, operating expenses and taxes, among other items during 2008 as compared to 2007.

 

Network revenues for the year ended December 31, 2008 include the revenue accrual (deferral) as calculated below:

 

 

 

 

Point-to-point revenues increased due primarily to ITC Midwest’s asset acquisition resulting in $3.9 million of additional revenues.

 

Scheduling, control and dispatch revenues increased due primarily to ITC Midwest’s asset acquisition resulting in $2.4 million of additional revenues.

 

Regional cost sharing revenues became applicable for us during 2008.

Operating Expenses

 

Operation and maintenance expenses

 

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

 

Operation and maintenance expenses decreased by $13.0 million due to lower field maintenance expenses consisting primarily of reductions in inspections, vegetation management, tower painting, overhead structure maintenance and field operations and training. These items are due in part to the expense mitigation efforts described above under “— Trends and Seasonality — Revenue Accruals — Effects of Monthly Peak Loads and Expense Mitigation Efforts.” Operation and maintenance expenses also decreased by $1.2 million for lower control center expenses and $5.1 million as a result of the expense capitalization process discussed under “— Recent Developments — Capitalization of Expenses.” In addition, operation and maintenance expenses decreased by $1.2 million for lower incentive bonuses related to the ITC Midwest integration activities and by $1.5 million due to lower emergency station expenses at ITC Midwest that resulted from the 2008 floods in Iowa. These decreases were partially offset by higher information technology system maintenance expenses of $3.5 million, due in part to additional operating control room software and expanded financial systems and the expenses to support those systems.

 

Year ended December 31, 2008 compared to year ended December 31, 2007

 

Operation and maintenance expenses increased by $21.5 million due to higher transmission structure maintenance expenses, inspections and other maintenance activities at ITC Midwest. ITC Midwest also incurred transmission system monitoring and control expenses of $4.7 million and incurred $1.2 million for incentive bonuses for ITC Midwest integration activities. In addition, METC incurred additional vegetation management expenses of $6.9 million.

 

General and administrative expenses

 

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

 

General and administrative expenses decreased by $9.6 million as a result of the aforementioned expense capitalization process and $7.4 million due to lower business expenses and professional advisory and consulting services resulting, in part, from our expense mitigation efforts described above. In addition, general and administrative expenses decreased by $8.0 million due to the recognition of regulatory assets relating to start-up and development activities of ITC Great Plains as well as pre-construction costs for the KETA Project. Partially offsetting these decreases was an increase of $6.8 million due to higher compensation and benefits expenses, due in part to personnel additions, stock compensation expense associated with our 2008 and 2009 long term incentive plan grants and net pension cost detailed in Note 11 to the condensed consolidated financial statements. There was an additional $4.7 million increase for salaries, benefits and general business expenses associated with increased development activities at ITC Grid Development and Green Power Express, which are not included in the increases explained above.

 

Year ended December 31, 2008 compared to year ended December 31, 2007

 

General and administrative expenses increased by $6.4 million due to higher professional advisory and consulting services, $6.3 million due to higher business expenses primarily for information technology support and $1.3 million due to higher compensation and benefits expenses primarily resulting from personnel additions and incentive bonuses for ITC Midwest integration activities. In addition, stock compensation expenses increased by $0.9 million due to an executive deferred stock unit bonus. General and administrative expenses also increased by an additional $4.2 million at ITC Grid Development and its subsidiaries for salaries, benefits and general business expenses due to increased development activities, which are not included in the increases explained above.

Depreciation and amortization expenses

 

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

 

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

 

Year ended December 31, 2008 compared to year ended December 31, 2007

 

Depreciation and amortization expenses increased by $18.6 million as a result of ITC Midwest’s asset acquisition in December 2007. Additionally we recognized additional depreciation expense of $5.4 million and $2.8 million at ITCTransmission and METC, respectively, due primarily to a higher depreciable asset base resulting from property, plant and equipment additions.

 

Taxes other than income taxes

 

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

 

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

 

Year ended December 31, 2008 compared to year ended December 31, 2007

 

Taxes other than income taxes increased due to additional property tax expenses at ITC Midwest of $6.2 million as a result of ITC Midwest’s asset acquisition in December 2007. Additionally, property tax expenses at ITCTransmission and METC increased by $3.1 million and $0.8 million due primarily to ITCTransmission’s and METC’s capital additions, which are included in the assessments for 2008 personal property taxes. Partially offsetting these increases was a decrease of $2.7 million as a result of the replacement of the Michigan Single Business Tax discussed in Note 10 to the consolidated financial statements.

 

Other expenses (income)

 

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

 

Interest expense increased due primarily to additional interest expense associated with the $186.1 million of additional indebtedness incurred since December 2008. This increase was partially offset by lower interest expense as a result of lower interest rates under our revolving credit agreements.

 

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

 

Year ended December 31, 2008 compared to year ended December 31, 2007

 

Interest expense increased due primarily to higher borrowing levels to finance capital expenditures and ITC Midwest’s asset acquisition.

 

AFUDC equity increased due to increased property, plant and equipment expenditures and the resulting higher construction work in progress balances during 2008 compared to 2007.

 

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

Income Tax Provision

 

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

 

Our effective tax rate for the years ended December 31, 2009 and 2008 are 37.2% and 38.1%, respectively. Our effective rate differs from our 35% statutory federal income tax rate due primarily to state income tax provision of $8.0 million (net of federal deductibility) recorded during the year ended December 31, 2009 and $9.0 million (net of federal deductibility) recorded during the year ended December 31, 2008, offset by the tax effects of AFUDC equity. The state income tax provision primarily results from the new Michigan Business Tax as discussed in Note 10 to the consolidated financial statements. The amount of income tax expense relating to AFUDC equity is recognized as a regulatory asset and not included in the income tax provision. Our Regulated Operating Subsidiaries include taxes payable relating to AFUDC equity in their actual net revenue requirements.

 

Year ended December 31, 2008 compared to year ended December 31, 2007

 

Our effective tax rate for the year ended December 31, 2008 of 38.1% differed from our 35% statutory federal income tax rate due primarily to the state income tax provision of $9.0 million (net of federal deductibility) recorded during the year ended December 31, 2008, partially offset by the tax effects of AFUDC equity described above. The state income tax provision is primarily a result of the new Michigan Business Tax as discussed in Note 10 to the consolidated financial statements. Our effective tax rate for the year ended December 31, 2007 of 33.3% differed from our 35% statutory federal income tax rate due primarily to our accounting for the tax effects of AFUDC equity.

 

Liquidity and Capital Resources

 

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

 

 

In addition to the expected capital requirements above, an adverse determination in our appeal relating to the recent denial of our ability to use the sales and use tax exemption as described in Note 16 to the consolidated financial statements would result in additional capital requirements.

 

We believe that we have sufficient capital resources to meet our currently anticipated short-term needs. We rely on both internal and external sources of liquidity to provide working capital and to fund capital investments. We expect to continue to utilize our revolving credit agreements and our cash and cash equivalents as needed to meet our other short-term cash requirements. As of December 31, 2009, we had consolidated indebtedness under our revolving credit agreements of $81.4 million, with unused capacity under the agreements of $258.6 million, or $206.4 million of unused capacity if reduced by the undrawn portion of Lehman’s commitment of $52.3 million described below. In addition, as of December 31, 2009, we had $74.9 million of cash and cash equivalents on hand, which exceeds the amounts that we would typically maintain for operating purposes as a result of the recently completed debt issuances discussed in Note 8 to the consolidated financial statements.

 

Lehman, a member of our revolving credit agreement syndication, was included in a bankruptcy filing made by its parent, Lehman Brothers Holdings Inc., on September 14, 2008. Lehman’s aggregate commitment to our various agreements of $55.0 million represented 16.2% of our total revolving credit agreement capacity of $340.0 million and we had $2.7 million outstanding under the agreements at December 31, 2009 relating to Lehman’s participation. We do not expect that we will replace Lehman’s commitments to our existing credit facilities given the favorable terms of our existing agreements compared to current market conditions. However, we believe we have sufficient unused capacity under our revolving credit agreements, even without the Lehman capacity, to meet our short-term capital requirements. Additionally, we believe we will be able to access the financial markets for other short-term capital requirements through term loan agreements, such as the ITC Holdings Term Loan Agreement executed in April 2009 and repaid in December 2009 discussed in Note 8 to the consolidated financial statements.

 

For our long-term capital requirements, we expect that we will need to obtain additional debt and equity financing. Certain of our capital projects could be delayed in the event we experience difficulties in accessing capital. We expect to be able to obtain such additional financing as needed in amounts and upon terms that will be reasonably satisfactory to us.

 

Credit Ratings

 

 

 

 

We believe our investment-grade credit ratings should provide a significant degree of flexibility in obtaining funds on competitive terms. However, these credit ratings reflect the views of the rating agencies only. An explanation of the significance of these ratings may be obtained from each rating agency. Such ratings are not a recommendation to buy, sell or hold debt securities, but rather an indication of creditworthiness. Any rating can be revised upward or downward or withdrawn at any time by a rating agency if it decides that the circumstances warrant the change. Each rating should be evaluated independently of any other rating.

Covenants

 

Our debt instruments include senior notes, secured notes, first mortgage bonds and revolving credit agreements containing numerous financial and operating covenants that place significant restrictions as described in Note 8 to the consolidated financial statements. We are currently in compliance with all debt covenants and in the event of a downgrade in our credit ratings, none of the covenants would be directly impacted.

 

Cash Flows

 

The following table summarizes cash flows for the periods indicated: