EDGAR 10-K Filing

Company CIK: 1317630
Filing Year: 2022
Filename: 1317630_10-K_2022_0001317630-22-000003.json

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ITEM 1. BUSINESS
ITEM 1. BUSINESS.
Overview
ITC Holdings provides safe and reliable electric transmission service to connect consumers to more sustainable and cost-effective energy resources. ITC Holdings continues to make investments in a modernized grid to maintain reliability and accommodate future demands as our economy and lifestyles become increasingly dependent on electricity.
Our business consists primarily of the electric transmission operations of our Regulated Operating Subsidiaries. Through our Regulated Operating Subsidiaries, we own and operate high-voltage electric transmission systems in Michigan’s Lower Peninsula and portions of Iowa, Minnesota, Illinois, Missouri, Kansas and Oklahoma that transmit electricity from generating stations to local distribution facilities connected to our transmission systems.
Our Regulated Operating Subsidiaries’ primary operating responsibilities include maintaining, improving and expanding their transmission systems to meet their customers’ ongoing needs, scheduling outages on system elements to allow for maintenance and construction, maintaining appropriate system voltages and monitoring flows over transmission lines and other facilities to ensure physical limits are not exceeded.
Our Regulated Operating Subsidiaries earn revenues for the use of their electric transmission systems by their 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, and our cost-based rates are discussed in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Cost-Based Formula Rates with True-Up Mechanism” as well as in Note 5 to the consolidated financial statements.
ITC Holdings is a wholly-owned subsidiary of ITC Investment Holdings. Fortis owns a majority indirect equity interest in ITC Investment Holdings, with GIC holding an indirect, passive, non-voting equity interest of 19.9%.
Development of Business
As we move toward a cleaner, sustainable and electrified economy, the power grid will need to be transformed and modernized. Technology deployment and innovation are occurring at an accelerated rate within our industry, so we are actively identifying and investing in infrastructure required to meet evolving system needs and energy policy objectives. Our long-term growth plan includes ongoing investments in our current regulated transmission systems and the identification of incremental strategic projects primarily located in and around our service territories.
We expect to invest approximately $4.0 billion from 2022 through 2026 at our Regulated Operating Subsidiaries. Included in this amount are capital expenditures to: (1) maintain and replace our current transmission infrastructure to enhance system reliability and accommodate load growth; (2) interconnect new renewable generation resources; (3) upgrade physical and technological grid security to protect critical infrastructure; and (4) expand access to electricity markets to reduce the overall cost of delivered energy to customers.
Refer to “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Capital Investment and Operating Results Trends” for additional details about our long-term capital investments. Refer to the discussion of risks associated with our strategic investment opportunities in “Item 1A. Risk Factors.”
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 our Regulated Operating Subsidiaries’ own systems or in conjunction with neighboring transmission systems. Third parties then transmit power through these local distribution systems to end-use consumers. The transmission of electricity by our Regulated Operating Subsidiaries is a central function to the provision of electricity to
residential, commercial and industrial end-use consumers. The operations performed by our Regulated Operating Subsidiaries fall into the following categories:
•asset planning;
•engineering;
•asset protection and performance;
•cyber security operations center; and
•real time operations.
Asset Planning
The Asset Planning group performs the role of detailing the required transmission infrastructure needed to support system changes and economic opportunities. System changes can arise from different points of origin including load growth, load shifts, or new points of interconnection; generation retirements or additions; operational needs; and system dynamic stability needs. Likewise, the Asset Planning group explores opportunities to better utilize the transmission system through economic planning by providing access, via transmission expansion projects, to lower cost energy. However, the core responsibility of the Asset Planning group is proactively anticipating the future demands placed upon the transmission system and developing corrective action plans for any deficiencies. Corrective action plans are developed to ensure compliance with NERC’s reliability standards. Additionally, the Asset Planning group seeks opportunities to further develop a resilient transmission system.
Transmission infrastructure plans are submitted as discrete projects into the MISO and SPP planning processes. As the regional planning authorities, MISO and SPP administer open and transparent processes through which the submitted projects are vetted. MISO and SPP produce transmission expansion plans, which include projects to be constructed by their members, including our MISO Regulated Operating Subsidiaries and ITC Great Plains.
Engineering
The Engineering group is composed of the Design, Capital Projects and Asset Management teams. The Engineering group works with outside contractors to perform various aspects of our design, construction and maintenance, but retains 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.
Design - The Design team is responsible for the design of our transmission systems and setting the standards for equipment used on our systems.
Capital Projects - The Capital Projects team is responsible for project and construction management for capital projects, which includes the construction of new transmission infrastructure as well as asset renewal projects.
Asset Management - The Asset Management team performs the following activities:
•manages our vegetation management program;
•provides engineering technical support to the field;
•specifies, maintains and troubleshoots the protection and controls system that is used to protect and monitor our transmission infrastructure; and
•develops and tracks preventative maintenance to promote safe and reliable systems adhering to mandatory requirements of the NERC and the FERC.
By performing preventive maintenance on our assets, we can minimize the need for reactive maintenance, resulting in improved reliability and cost savings for our customers. Our Regulated Operating Subsidiaries contract with ULCS, which is a division of Asplundh Tree Expert Co., to perform the majority of their maintenance. The agreement with ULCS provides us with access to an experienced and scalable workforce with knowledge of our system at an established rate.
Asset Protection and Performance
The Asset Protection and Performance group is responsible for safety, human performance, security, and emergency preparedness and response. Given the inherent hazardous nature of the utilities industry, we proactively work to ensure that all personnel are free to perform in a safe and secure environment. Our focus is to not compromise the safety of our employees, contractors or the public in the course of providing the most reliable electricity transmission services. We maintain a safety program that includes proactive measures rooted in human performance tools to achieve that focus. Our emergency response plans ensure that we are prepared for a crisis and can maintain continuity of our business and service during said crisis. We operate a security command center from our headquarters facility in Michigan that monitors our most critical assets on a continuous basis. The security command center also gathers intelligence and works with our government and industry partners to prevent threats to our assets.
Cyber Security Operations Center
The Cyber Security Operations Center protects ITC’s reputation and brand by securing critical infrastructure, data, and computing systems from threat actors. We protect vital infrastructure by developing, refining, and continually delivering a comprehensive cyber security program while helping our stakeholders meet their business objectives. As the threat landscape becomes increasingly sophisticated and expansive, we continue to evolve our defensive strategy. We improve this strategy by deploying new technology, continuing education of our user community, and advancing our protections against ongoing cyber threats. We leverage threat intelligence and external industry practices for continuous improvement and refinement of our cyber security program.
Real Time Operations
System Operations - From our operations facilities in Michigan, transmission system operators continuously monitor the performance of the transmission systems of our Regulated Operating Subsidiaries, using software and communication systems to perform analysis to plan for contingencies and maintain security and reliability following any unplanned events on the system. Transmission system operators are also responsible for the switching and protective tagging function, taking equipment in and out of service to ensure capital construction projects and maintenance programs can be completed safely and reliably.
Local Balancing Authority Operator - Under the functional control of MISO, ITCTransmission and METC operate their electric transmission systems as a combined LBA area, known as MECS. From our operations facilities in Michigan, our employees perform the LBA functions as outlined in MISO’s Balancing Authority Agreement. These functions include actual interchange data administration and verification as well as MECS LBA area emergency procedure implementation and coordination. Besides ITCTransmission and METC, our other Regulated Operating Subsidiaries are not responsible for LBA functions for their respective assets.
Operating Contracts
Our Regulated Operating Subsidiaries have various operating contracts, including numerous interconnection agreements with generation and transmission providers that address terms and conditions of interconnection. The following significant agreements exist at our Regulated Operating Subsidiaries:
ITCTransmission
DTE Electric operates an electric distribution system that is interconnected with ITCTransmission’s transmission system. A set of three operating contracts sets forth the terms and conditions related to DTE Electric’s and ITCTransmission’s interconnected systems. These contracts include the following:
Master Operating Agreement. The MOA governs the primary day-to-day operational responsibilities of ITCTransmission and DTE Electric. The MOA identifies control area coordination services that ITCTransmission provides to DTE Electric and certain generation-based support services that DTE Electric is required to provide to ITCTransmission.
Generator Interconnection and Operation Agreement. The GIOA established, re-established and maintains the direct electricity interconnection of DTE Electric’s electricity generating assets with ITCTransmission’s transmission system for the purpose of transmitting electric power from and to the electricity generating facilities.
Coordination and Interconnection Agreement. The CIA outlines the rights, obligations and responsibilities of ITCTransmission and DTE Electric regarding, among other things, the operation and interconnection of DTE Electric’s distribution system and ITCTransmission’s transmission system, and the construction of new facilities or modification of existing facilities. Additionally, the CIA allocates costs for operation of supervisory, communications and metering equipment.
METC
Consumers Energy operates an electric distribution system that is interconnected with METC’s transmission system. 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 Easement Agreement, Consumers Energy provides METC with an easement to the land on which a majority of METC’s transmission towers, poles, lines and other transmission facilities used to transmit electricity for Consumers Energy and others are located. METC pays Consumers Energy an annual rent for the easement and also pays for any rentals, property taxes and other fees related to the property covered by the Easement Agreement.
Amended and Restated Operating Agreement. Under the Operating Agreement, METC is responsible 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.
Amended and Restated Purchase and Sale Agreement for Ancillary Services. 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.
Amended and Restated Distribution-Transmission Interconnection Agreement. The DT Interconnection Agreement 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.
Amended and Restated Generator Interconnection Agreement. The Generator Interconnection Agreement 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.
ITC Midwest
IP&L operates an electric distribution system that interconnects with ITC Midwest’s transmission system. ITC Midwest is a party to a number of operating contracts with IP&L that govern the operations and maintenance of their respective systems. These contracts include the following:
Distribution-Transmission Interconnection Agreement. The DTIA 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 party’s property, assets and facilities and the construction of new facilities or modification of existing facilities.
Large Generator Interconnection Agreement. ITC Midwest, IP&L and MISO entered into the LGIA 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.
Operations Services Agreement For 34.5 kV Transmission Facilities. ITC Midwest and IP&L entered into the OSA under which IP&L performs certain operations functions for ITC Midwest’s 34.5 kV transmission system. The OSA provides that when ITC Midwest upgrades 34.5 kV facilities to higher operating voltages it may notify IP&L of the change and the OSA is no longer applicable to those facilities.
ITC Great Plains
Amended and Restated Maintenance Agreement. Mid-Kansas and ITC Great Plains have entered into the Mid-Kansas Agreement pursuant to which Mid-Kansas has agreed to perform various field operations and maintenance services related to certain ITC Great Plains assets.
ITC Interconnection
ITC Interconnection acquired certain transmission assets from a merchant generating company and placed a 345kV transmission line in service. As a result, ITC Interconnection is a TO in PJM and is subject to rate regulation by the FERC. The revenues earned by ITC Interconnection are based on its facilities reimbursement agreement with the merchant generating company.
Regulatory Environment
Many regulators and public policy makers support the need for further investment in the transmission grid. The growth and changing mix of 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. The DOE has established the Office of Electricity that focuses 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.
The FERC requires TOs to comply with certain reliability standards and may take enforcement actions for violations, including the imposition of substantial fines. NERC is responsible for developing and enforcing these mandatory reliability standards. We continually assess our transmission systems against standards established by NERC, as well as the standards of applicable regional entities under NERC that have been delegated certain authority for the purpose of proposing and enforcing reliability standards.
Finally, utility holding companies are subject to FERC regulations related to access to books and records in addition to the requirement of the FERC to review and approve mergers and consolidations involving utility assets and holding companies in certain circumstances.
Federal Regulation
As electric transmission companies, our Regulated Operating Subsidiaries charge rates that 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 sales of electricity in interstate commerce. The FERC also administers accounting and financial reporting regulations and standards of conduct for the companies it regulates.
Revenue Requirement Calculations and Cost Sharing for Projects with Regional Benefits
The cost-based Formula Rates used by our Regulated Operating Subsidiaries include revenue requirement calculations for various types of projects. Network revenues continue to be the largest component of revenues recovered through our Formula Rates. However, regional cost sharing revenues have experienced long-term growth as a result of projects that have been identified as having regional benefits and are therefore eligible for regional cost recovery. Separate calculations of revenue requirement are performed for projects that have been approved for regional cost sharing.
We have projects that are eligible for regional cost sharing under the MISO tariff, such as certain network upgrade projects, and the MVPs. Additionally, certain projects at ITC Great Plains are eligible for recovery through a region-wide charge in the SPP tariff.
State Regulation
The regulatory agencies in the states where our Regulated Operating Subsidiaries’ assets are located do not have jurisdiction over our rates or terms and conditions of service. However, they typically have jurisdiction over siting of transmission facilities and related matters as described below. Additionally, we are subject to the
regulatory oversight of various state environmental quality departments for compliance with any state environmental standards and regulations.
ITCTransmission, METC and ITC Interconnection
Michigan
The Michigan Public Service Commission has jurisdiction over the siting of certain transmission facilities. Additionally, ITCTransmission, METC and ITC Interconnection 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, METC and ITC Interconnection are also subject to the regulatory oversight of the Michigan Department of Environmental Quality, the Michigan Department of Natural Resources and certain local authorities for compliance with all environmental standards and regulations.
ITC Midwest
Iowa
The Iowa Utilities Board has the power of supervision over the construction, operation and maintenance of transmission facilities in Iowa by any entity, which includes the power to issue franchises. Iowa law further provides that any entity granted a franchise by the Iowa Utilities Board is vested with the power of condemnation in Iowa to the extent the Iowa Utilities Board approves and deems necessary for public use. A city has the power, pursuant to Iowa law, to grant a franchise to erect, maintain and operate transmission facilities within the city, which franchise may regulate the conditions required and manner of use of the streets and public grounds of the city and may confer the power to appropriate and condemn private property.
ITC Midwest also is subject to the regulatory oversight of certain state agencies (including the Iowa Department of Natural Resources) and certain local authorities with respect to the issuance of environmental, highway, railroad and similar permits.
Minnesota
The Minnesota Public Utilities Commission has jurisdiction over the construction, siting and routing of new transmission lines or upgrades of existing lines through Minnesota’s Certificate of Need and Route Permit Processes. Transmission companies are also required to participate in the state’s Biennial Transmission Planning Process and are subject to the state’s preventative maintenance requirements. Pursuant to Minnesota law, ITC Midwest has the right as an independent transmission company to condemn property in the state of Minnesota for the purpose of building new transmission facilities.
ITC Midwest is also subject to the regulatory oversight of the Minnesota Pollution Control Agency, the Minnesota Department of Natural Resources, the Minnesota Public Utilities Commission in conjunction with the Department of Commerce and certain local authorities for compliance with applicable environmental standards and regulations.
Illinois
The Illinois Commerce Commission exercises jurisdiction over the 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 is also subject to the regulatory oversight of the Illinois Environmental Protection Agency, the Illinois Department of Natural Resources, the Illinois Pollution Control Board and certain local authorities for compliance with all environmental standards and regulations.
Missouri
Because ITC Midwest is a “public utility” and an “electrical corporation” under Missouri law, the Missouri Public Service Commission has jurisdiction to determine whether ITC Midwest may operate in such capacity. The Missouri Public Service Commission also exercises jurisdiction with regard to other non-rate matters affecting its sole Missouri asset such as transmission substation construction, general safety and the transfer of the franchise or property.
ITC Midwest is also subject to the regulatory oversight of the Missouri Department of Natural Resources for compliance with all environmental standards and regulations relating to this transmission line.
Wisconsin
ITC Midwest is a “public utility” and independent TO in Wisconsin. The Public Service Commission of Wisconsin granted ITC Midwest a certificate of authority to transact public utility business in the state. The Public Service Commission of Wisconsin also recognized ITC Holdings as a public utility holding company under Wisconsin statutes.
The Public Service Commission of Wisconsin exercises jurisdiction over the siting of new transmission lines through the issuance of certificates of authority and certificates of public convenience and necessity. Upon receipt of such certificates for a transmission project, ITC Midwest has condemnation authority as a foreign transmission provider under Wisconsin law. ITC Midwest is also subject to the jurisdiction of certain local and state agencies, including the Wisconsin Department of Natural Resources, relating to environmental and road permits.
ITC Great Plains
Kansas
ITC Great Plains is a “public utility” and an “electric utility” in Kansas pursuant to state statutes. The KCC issued an order approving the issuance of a limited certificate of convenience to ITC Great Plains for the purposes of building, owning and operating SPP transmission projects in Kansas. In addition to its certificate of authority, the KCC has jurisdiction over the siting of electric transmission lines.
ITC Great Plains is also subject to the regulatory oversight of the Kansas Department of Health and Environment for compliance with all environmental standards and regulations relating to the construction phase of any transmission line.
Oklahoma
ITC Great Plains has approval from the Oklahoma Corporation Commission to operate in Oklahoma, pursuant to Oklahoma statutes as an electric public utility providing only transmission services. The Oklahoma Corporation Commission does not exercise jurisdiction over the siting of any transmission lines.
ITC Great Plains is subject to the regulatory oversight of Oklahoma Department of Environmental Quality for compliance with environmental standards and regulations relating to construction of certain proposed transmission lines.
Sources of Revenue
See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Significant Components of Results of Operations - Revenues” for a discussion of our principal sources of revenue.
Seasonality
The cost-based Formula Rates in effect for our Regulated Operating Subsidiaries, as discussed in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Cost-Based Formula Rates with True-Up Mechanism,” mitigate the seasonality of net income for our Regulated Operating Subsidiaries. Our Regulated Operating Subsidiaries accrue or defer revenues to the extent that the actual revenue requirement for the reporting period is higher or lower, respectively, than the amounts billed relating to that reporting period. For example, to the extent that amounts billed are less than our revenue requirement for a reporting period, a revenue accrual is recorded for the difference and the difference results in no net income impact.
Operating cash flows are seasonal at our MISO Regulated Operating Subsidiaries, in that cash received for revenues is typically higher in the summer months when peak load is higher.
Principal Customers
Our principal transmission service customers are DTE Electric, Consumers Energy and IP&L, which accounted for approximately 21.5%, 23.5% and 24.7%, respectively, of our consolidated billed revenues for the year ended December 31, 2021. One or more of these customers together have consistently represented a significant percentage of our operating revenue. This portion of total billed revenues of DTE Electric, Consumers Energy and IP&L include the collection of 2019 revenue accruals and deferrals and exclude any amounts for the 2021 revenue accruals and deferrals that were included in our 2021 operating revenues but will not be billed to our customers until 2023. Refer to “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Cost-Based Formula Rates with True-Up Mechanism” for a discussion on the difference between billed revenues and operating revenues. Our remaining revenues were generated from providing service to other entities such as alternative energy suppliers, power marketers and other wholesale customers that provide electricity to end-use consumers and from transaction-based capacity reservations. Nearly all of our revenues are from transmission customers in the United States. Although we may recognize allocated revenues from time to time from Canadian entities reserving transmission over the Ontario or Manitoba interface, these revenues have not been and are not expected to be material to us.
Billing
MISO and SPP are responsible for billing and collecting the majority of our transmission service revenues as well as independently administering the transmission tariff in their respective service territory. As the billing agents for our MISO Regulated Operating Subsidiaries and ITC Great Plains, MISO and SPP independently bill DTE Electric, Consumers Energy, IP&L and other customers on a monthly basis and collect 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.
Competition
Each of our MISO Regulated Operating Subsidiaries operates the primary transmission system in its respective service area and has limited competition for certain projects. Other entities with transmission development initiatives may compete with us by seeking approval to be named the party authorized to build new capital projects that we are also pursuing. Our subsidiaries may also compete with other entities on development opportunities for transmission investment in locations outside of our existing service areas.
Human Capital Resources
ITC Holdings places significant emphasis on attracting, developing and retaining individuals who exemplify the values that are the cornerstone of our company. As of December 31, 2021, we had 705 employees, with low employee turnover and no significant change in the number of employees from the prior year. None of our employees are covered by collective bargaining agreements. In addition, we work with many outside firms to provide additional resources to support our business. We utilize human capital resources employed by these firms to assist with construction, maintenance, field operations and other corporate functions of our business. We believe that we have good relationships with our suppliers of contracted services.
Safety is of the utmost importance for our employees, and we consider safety to be a key priority for our company. Our safety policies, procedures and training practices have resulted in safety performance metrics that consistently rank us in the top decile among comparable electric utilities.
We believe that our compensation and benefit programs have been appropriately designed to attract and retain talent. Compensation for employees is made up of a combination of base salary, short-term incentive and long-term incentive pay structures. In addition, we offer a comprehensive package of additional benefits for all of our employees and various professional development opportunities through internal and external programs.
We strive to provide an inclusive and diverse environment for all of our employees. We believe that by recognizing and valuing our employees’ similarities, as well as their differences, we make our shared goals possible. In addition to our internal commitments to inclusion and diversity, we are continuing to enhance our supplier diversity program. This effort will further diversify our supplier base through the recruitment and growth of businesses owned by minorities, women and veterans.
Environmental Matters
See “Environmental Matters” in Note 17 to the consolidated financial statements.
Available Information Under the Securities Exchange Act of 1934
Our Internet address is http://www.itc-holdings.com. Visit our website to learn more about us. Financial and other material information regarding us is routinely posted on our website and is readily accessible. All of our reports filed pursuant to Section 13(a) or 15(d) of the Exchange Act, including our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to those reports, can be accessed free of charge through our website. These reports are available as soon as practicable after they are electronically filed with the SEC. The information on our website is not incorporated by reference into this report.

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ITEM 1A. RISK FACTORS
ITEM 1A. RISK FACTORS.
Risks Related to Our Business
Certain elements of our Regulated Operating Subsidiaries’ Formula Rates have been and can be challenged, which could result in lowered rates and/or refunds of amounts previously collected and thus may have an adverse effect on our business, financial condition, results of operations and cash flows.
Our Regulated Operating Subsidiaries provide transmission service under rates regulated by the FERC. The FERC has approved the cost-based Formula Rates used by our Regulated Operating Subsidiaries to calculate their respective annual revenue requirements, but it has not expressly approved the amount of actual capital and operating expenditures to be used in the Formula Rates. All aspects of our Regulated Operating Subsidiaries’ rates approved by the FERC, including the Formula Rate templates, the rates of return on the actual equity portion of their respective capital structures, ROE adders for independent transmission ownership and RTO participation, the approved capital structures and other aspects of our rates, are subject to challenge by interested parties at the FERC, or by the FERC on its own initiative in a proceeding under Section 206 of the FPA. In addition, interested parties may challenge the annual implementation and calculation by our Regulated Operating Subsidiaries of their projected rates and Formula Rate true up pursuant to their approved Formula Rates under the Regulated Operating Subsidiaries’ Formula Rate implementation protocols. End-use consumers and entities supplying electricity to end-use consumers may also attempt to influence government and/or regulators to change the rate setting methodologies that apply to our Regulated Operating Subsidiaries, particularly if rates for delivered electricity increase substantially. If a challenger can establish that any of these aspects are unjust, unreasonable, unduly discriminatory or preferential, then the FERC will make 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, any of which could have a material adverse effect on our business, financial condition, results of operations and cash flows. See “Rate of Return on Equity Complaints” in Note 17 to the consolidated financial statements for detail on ROE matters.
Our actual capital investment may be lower than planned, which would cause a lower than anticipated rate base and would therefore result in lower revenues, earnings and associated cash flows compared to our current expectations. In addition, we may incur expenses related to the pursuit of strategic investment opportunities, which may be higher than forecasted.
Each of our Regulated Operating Subsidiaries’ rate base, revenues, earnings and associated cash flows are determined in part by additions to property, plant and equipment and when those additions are placed in service. If our operating subsidiaries’ capital investment and the resulting in-service property, plant and equipment are lower than anticipated for any reason, our operating subsidiaries will have a lower than anticipated rate base, thus causing their revenue requirements and future earnings and cash flows to be lower than anticipated.
Any capital investment at our Regulated Operating Subsidiaries may be lower than our published estimates due to, among other factors, the impact of:
•actual or forecasted loads;
•regional economic conditions;
•weather conditions;
•union strikes or labor shortages;
•material and equipment prices and availability;
•variances between estimated and actual costs of construction contracts awarded;
•our ability to obtain financing for such expenditures, if necessary;
•limitations on the amount of construction that can be undertaken on our system or transmission systems owned by others at any one time;
•regulatory requirements relating to our rate construct, including our ability to recover costs;
•the potential for greater competition;
•environmental, siting or regional planning issues; and
•legal proceedings.
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. In addition, projects may be canceled, the scope of planned projects may change, or projects may not be completed on time, any of which may adversely affect our level of investment or cause our projected investments to be inaccurate.
In addition, we may incur expenses to pursue strategic investment opportunities. If these payments or expenses are higher than anticipated, our future results of operations, cash flows and financial condition could be materially and adversely affected.
The regulations to which we are subject may limit our ability to raise capital and/or pursue acquisitions, development opportunities or other transactions or may subject us to liabilities.
Each of our Regulated Operating Subsidiaries is a “public utility” under the FPA and, accordingly, is subject to regulation by the FERC. Approval of the FERC is required under Section 203 of the FPA for a disposition or acquisition of regulated public utility facilities, either directly or indirectly through a holding company. Such approval is also required to acquire a significant interest in securities of a public utility. Section 203 of the FPA also provides the FERC with explicit authority over utility holding companies’ purchases or acquisitions of, and mergers or consolidations with, a public utility. Finally, each of our Regulated Operating Subsidiaries must also seek approval by the FERC under Section 204 of the FPA for issuances of its securities (including debt securities). If we are unable to obtain the necessary FERC approvals for potential acquisitions, dispositions or merger activities, or to raise capital, our strategic and growth opportunities may be limited. This could have an adverse impact on our financial condition, results of operations and cash flows.
We are also pursuing development projects for construction of transmission facilities and interconnections with generating resources. These projects may require regulatory approval by Federal agencies, including the FERC, applicable RTOs and state and local regulatory agencies. Failure to secure such regulatory approval for new strategic development projects could adversely affect our ability to grow our business and increase our revenues. If we fail to obtain these approvals when necessary, we may incur liabilities for such failure.
Changes in energy laws, regulations or policies could impact our business, financial condition, results of operations and cash flows.
Each of our Regulated Operating Subsidiaries is regulated by the FERC as a “public utility” under the FPA and is a TO in MISO, SPP or PJM. We cannot predict whether the approved rate methodologies for any of our Regulated Operating Subsidiaries will be changed. In addition, the U.S. Congress periodically considers enacting energy legislation that could assign new responsibilities to the FERC, modify provisions of the FPA or provide the FERC or another entity with increased authority to regulate transmission matters. Our Regulated Operating Subsidiaries may be affected by any such changes in federal energy laws, regulations or policies in the future. While our Regulated Operating Subsidiaries are subject to the FERC’s exclusive jurisdiction for purposes of rate regulation, changes in state laws affecting other matters, such as transmission siting and construction, could limit investment opportunities available to us.
The widespread outbreak of an illness or other communicable disease, including the COVID-19 pandemic, or any other public health crisis, could have a material adverse impact on our business, financial condition, results of operations, cash flows and credit metrics.
We could be negatively impacted by the widespread outbreak of an illness or any other communicable diseases, or any other public health crisis that results in economic and trade disruptions, including the disruption of global supply chains. COVID-19 is currently impacting the global economy, supply chains and markets. As a result of efforts to limit the spread of COVID-19, public health authorities, OSHA, and/or the states served by our transmission systems may issue orders that can place restrictions on and/or result in the temporary shutdown of operations of businesses that use our transmission systems. The impact of efforts to limit the spread of COVID-19 on our business, financial condition and results of operations is uncertain and will ultimately depend on the duration and severity of the pandemic, the length that the various business restrictions are in effect, the impact of recent resurgences of COVID-19 cases and deaths in the United States, and the efficacy and distribution of COVID-19 vaccines.
We intend to comply with applicable obligations that require broad categories of employees and subcontractors to be vaccinated against COVID-19 or test regularly. Complying with such vaccine and/or testing requirements poses the risk of workforce disruption that could impact business continuity, including the quarantine/isolation of employees, the possibility of resignations by unwilling employees and/or subcontractors, and difficulty in satisfying future labor needs. Significant workforce disruptions could have a material impact on our business, financial condition, results of operations and cash flows.
COVID-19 could disrupt the supply chains that provide services and equipment to us as part of our capital expenditures or maintenance efforts. If our supply chains are disrupted, we may be unable to perform necessary maintenance, which could result in increased costs as we implement contingency plans to allow us to continue to operate. Supply chain interruptions may also increase the cost of capital expenditures or result in the delay or cancellation of planned projects, any of which could have a material adverse impact on our business, financial condition, results of operations and cash flows.
We cannot predict whether, and the extent to which, COVID-19 will have a material impact on our liquidity, financial condition, and results of operations. We require access to the capital markets to fund capital investments. To the extent that our access to the capital markets is adversely affected by COVID-19, we may need to consider alternative sources of funding for our operations and for working capital, any of which may not be available and may increase our cost of capital. The extent to which COVID-19 may impact our liquidity, financial condition, and results of operations will depend on future developments, which are highly uncertain and cannot be predicted; an extended period of global supply chain and economic disruption could materially impact our business, financial condition, results of operations, cash flows and credit metrics.
Each of our MISO Regulated Operating Subsidiaries depends on its primary customer for a substantial portion of its revenues, and any material failure by those primary customers to make payments for transmission services could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Each of ITCTransmission, METC and ITC Midwest derive a substantial portion of their revenues from the transmission of electricity to the local distribution facilities of DTE Electric, Consumers Energy and IP&L, respectively. Each of these customers is expected to constitute the majority of the revenues of the respective MISO Regulated Operating Subsidiary for the foreseeable future. Any material failure by DTE Electric, Consumers Energy or IP&L to make payments for transmission services could have an adverse effect on our business, financial condition, results of operations and cash flows.
A significant amount of the land on which our assets are located is subject to easements, mineral rights and other similar encumbrances. As a result, we must comply with the provisions of various easements, mineral rights and other similar encumbrances, which may adversely impact our 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 the Easement Agreement, METC pays an annual rent to Consumers Energy in exchange for rights-of-way, leases, fee interests and licenses which allow METC to use the land on which its transmission lines are located. Under the terms of the Easement Agreement, METC’s easement rights could be eliminated if METC fails to meet certain requirements, such as paying contractual rent to Consumers Energy in
a timely manner. Additionally, a significant amount of the land on which our other subsidiaries’ assets are located is subject to easements, mineral rights and other similar encumbrances. As a result, they must comply with the provisions of various easements, mineral rights and other similar encumbrances, which may adversely impact their ability to complete their construction projects in a timely manner.
We contract with third parties to provide services for certain aspects of our business. If any of these agreements are terminated, we may face a shortage of labor or replacement contractors to provide the services formerly provided by these third parties.
We enter into various agreements and arrangements with third parties to provide services for construction, maintenance and operations of certain aspects of our business, and we utilize the services of contractors to a significant extent. If any of these agreements or arrangements is terminated for any reason, it could result in a shortage of a readily available workforce to provide such services and we may face difficulty finding a qualified replacement workforce. In such a situation, if we are unable to find adequate replacements for contractors in a timely manner, it could have an adverse effect on our results of operations and the ability to carry on our business.
Hazards associated with high-voltage electricity transmission may result in suspension of our operations, costly litigation or the imposition of civil or criminal penalties.
Our operations are subject to the usual hazards associated with high-voltage electricity transmission, including explosions, fires, mechanical failure, unscheduled downtime, equipment interruptions, remediation, chemical spills, discharges or releases of toxic or hazardous substances or gases and other environmental risks. These 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, litigation by aggrieved parties and the imposition of civil or criminal penalties which may have a material adverse effect on our business, financial condition and results of operations. We maintain property and casualty insurance, but we are not fully insured against all potential hazards incident to our business, such as damage to poles, towers and lines or losses caused by outages.
We are subject to environmental regulations and to laws that can give rise to substantial liabilities from environmental contamination.
We are subject to federal, state and local environmental laws and regulations, which impose limitations on the discharge of pollutants into the environment, establish standards for the management, treatment, storage, transportation and disposal of solid and hazardous wastes and hazardous materials, and impose obligations to investigate and remediate contamination in certain circumstances. Liabilities relating to investigation and remediation of 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 properties we currently own or operate. Such liabilities may arise even where the contamination does not result from noncompliance with applicable environmental laws. Under a number of environmental laws, such liabilities may also be joint and several, meaning that a party can be held responsible for more than its share of the liability involved, or even the entire share.
We have incurred expenses in connection with environmental compliance, and we anticipate that we will continue to do so in the future. Failure to comply with the extensive environmental laws and regulations applicable to us could result in significant civil or criminal penalties and remediation costs. Our assets and operations also involve the use of materials classified as hazardous, toxic or otherwise dangerous. Some of our facilities and properties are located near environmentally sensitive areas such as wetlands and habitats of endangered or threatened species. In addition, certain properties in which we operate are, or are suspected of being, affected by environmental contamination. Compliance with these laws and regulations, and liabilities concerning contamination or hazardous materials, may adversely affect our costs and, therefore, our business, financial condition and results of operations.
If amounts billed for transmission service for our Regulated Operating Subsidiaries’ transmission systems are lower than expected, or our actual revenue requirements are higher than expected, the timing of actual collection of our total revenues would be delayed.
If amounts billed for transmission service are lower than expected, the timing of actual collections of our Regulated Operating Subsidiaries’ total revenue requirement would likely be delayed until such circumstances are adjusted through the true-up mechanism, which would be settled within a two-year period, in our Regulated Operating Subsidiaries’ Formula Rates. Lower than expected amounts collected could result from lower network load or point-to-point transmission service on our Regulated Operating Subsidiaries’ transmission systems due to a weak economy, changes in the nature or composition of the transmission assets of our Regulated Operating Subsidiaries and surrounding areas, poor transmission quality of neighboring transmission systems, or for any other reason. In addition, if the revenue requirements of our Regulated Operating Subsidiaries are higher than expected, the timing of actual collection of our Regulated Operating Subsidiaries' total revenue requirements would likely be delayed until such circumstances are reflected through the true-up mechanism, which would be settled within a two-year period, in our Regulated Operating Subsidiaries' Formula Rates. This could be due to higher actual expenditures compared to the forecasted expenditures used to develop their billing rates or for any other reason. The effect of such under-collection would be to reduce the amount of our available cash resources from what we had expected, until such under-collection is corrected through the true-up mechanism in the Formula Rate template, which may require us to increase our outstanding indebtedness, thereby reducing our available borrowing capacity, and may require us to pay interest at a rate that exceeds the interest to which we are entitled in connection with the operation of the true-up mechanism.
We are subject to various regulatory requirements, including reliability standards; contract filing requirements; reporting, recordkeeping and accounting requirements; and transaction approval requirements. Violations of these requirements, whether intentional or unintentional, may result in penalties that, under some circumstances, could have a material adverse effect on our business, financial condition, results of operations and cash flows.
The various regulatory requirements to which we are subject include reliability standards established by the NERC, which acts as the nation’s Electric Reliability Organization approved by the FERC in accordance with Section 215 of the FPA. These standards address operation, planning and security of the bulk power system, including requirements with respect to real-time transmission operations, emergency operations, vegetation management, critical infrastructure protection and personnel training. Failure to comply with these requirements can result in monetary penalties as well as non-monetary sanctions. Monetary penalties vary based on an assigned risk factor for each potential violation, the severity of the violation and various other circumstances, such as whether the violation was intentional or concealed, whether there are repeated violations, the degree of the violator’s cooperation in investigating and remediating the violation and the presence of a compliance program, and such penalties can be substantial. Non-monetary sanctions include potential limitations on the violator’s activities or operation and placing the violator on a watchlist for major violators. If any of our subsidiaries violate the NERC reliability standards, even unintentionally, in any material way, any penalties or sanctions imposed against us could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Certain of our subsidiaries are also subject to requirements under Sections 203 and 205 of the FPA for approval of transactions; reporting, recordkeeping and accounting requirements; and for filing contracts related to the provision of jurisdictional services. Under the FERC policy, failure to file jurisdictional agreements on a timely basis may result in foregoing the time value of revenues collected under the agreement, but not to the point where a loss would be incurred. The failure to obtain timely approval of transactions subject to FPA Section 203, or to comply with applicable reporting, recordkeeping or accounting requirements under FPA Section 205, could subject us to penalties that could have a material adverse effect on our financial condition, results of operations and cash flows.
Acts of war, terrorist attacks and other catastrophic events may have a material adverse effect on our business, financial condition, results of operations and cash flows.
Acts of war, terrorist attacks and other catastrophic events may negatively affect our business, financial condition and cash flows in unpredictable ways, such as increased security measures and disruptions of markets. Energy related assets, including, for example, our transmission facilities and DTE Electric’s, Consumers Energy’s and IP&L’s generation and distribution facilities that we interconnect with, may be at risk of
acts of war, terrorist attacks and other catastrophic events. Such events or threats may have a material effect on the economy in general and could result in a decline in energy consumption, which may have a material adverse effect on our business, financial condition, results of operations and cash flows.
A cyber-attack or incident could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Various U.S. Government agencies have noted that external threat sources continue to seek to exploit, through cyber-attacks, potential vulnerabilities in the U.S. energy infrastructure, including electric transmission assets. These cyber threats and attacks are becoming more sophisticated and dynamic. Cyber security incidents could harm our business by limiting our transmission capabilities, delay our development and construction of new facilities or capital improvement projects on existing facilities or expose us to liability. Cyber-attacks targeting our information systems could also impair our records, networks, systems and programs, or transmit viruses to other systems. Such events or the threat of such events may increase costs associated with heightened security requirements. In addition, if our major customers or suppliers experience a cyber-attack it may reduce their ability to use our transmission facilities or service our transmission assets. If our business or those of our customers and suppliers are subject to a cyber-attack, it may have a material adverse effect on our business, financial condition, results of operations and cash flows.
Effects of climate change, including natural disasters, severe weather and other related phenomena, and the regulatory and legislative developments related to climate change, may have a material adverse effect on our business, financial condition, results of operations and cash flows.
Natural disasters, severe weather, and other related phenomena due to climate change may negatively affect our business and financial condition through increased costs from repairs to our transmission facilities and implementation of contingency plans for continued operations as repairs are underway. We could also experience disruptions to our supply chain, as our suppliers may face similar challenges to their operations from severe weather-related events due to climate change. Furthermore, prolonged power outages to customers and business interruptions from delays in storm restoration efforts could damage our reputation, which may have a material adverse effect on our business, financial condition, results of operations and cash flows.
Moreover, federal, regional or state legislative or regulatory initiatives may attempt to control or limit the causes of climate change, including greenhouse gas emissions, such as carbon dioxide and methane. Such laws or regulations could impose costs tied to greenhouse gas emissions, operational requirements or restrictions, or additional charges to fund energy efficiency activities. They could also provide a cost advantage to alternative energy sources or result in other costs or requirements, such as costs associated with the adoption of new infrastructure and technology to respond to new mandates. The occurrence of the foregoing events could put upward pressure on costs, adversely affecting our business, financial condition, results of operations and cash flows.
Changes in tax laws or regulations may negatively affect our financial condition, results of operations, net income, cash flows and credit metrics.
We are subject to taxation by various taxing authorities at the federal, state and local levels. Various representatives of the government, corporations, industry groups and the public continue to pursue changes to tax laws and regulations, and corporate tax reform continues to be a priority in many jurisdictions. Due to unique aspects of the treatment of taxes for regulated utilities, the impacts of changes in tax laws for us and our Regulated Operating Subsidiaries may differ from the impacts to other corporations generally. Changes in federal, state or local tax rates or other aspects of tax laws could materially and adversely affect our financial condition, results of operations, net income, cash flows, and credit metrics.
Advances in technology may negatively impact our business, financial condition, results of operations and cash flows.
Research and development efforts continue to seek improvements to existing or new alternative technologies to produce, store and distribute power, including fuel cells, microturbines, distributed generation and battery storage. It is possible that adoption of such alternative technologies could be significant enough to cause a reduction in the demand for electricity from the traditional bulk electric system or could make portions of our transmission systems obsolete before the end of their useful lives. Such advances in alternative technologies could decrease the need for capital investments in our transmission systems over time or increase
cost, and as a result could have an adverse effect on our business, financial condition, results of operations and cash flows.
Risks Relating to Our Corporate and Financial Structure
ITC Holdings is a holding company with no operations, and unless we receive dividends or other payments from our subsidiaries, we may be unable to fulfill our cash obligations.
As a holding company with no business operations, ITC Holdings’ material assets consist primarily of the stock and membership interests in our subsidiaries. Our only sources of cash to meet our obligations are dividends and other payments received by us from time to time from our subsidiaries, the proceeds raised from the sale of our securities and borrowings under our various credit agreements. Each of our subsidiaries, however, is legally distinct from us and has no obligation, contingent or otherwise, to make funds available to us. The ability of each of our Regulated Operating Subsidiaries and our other subsidiaries to pay dividends and make other payments to us is subject to, among other things, the availability of funds, after taking into account capital expenditure requirements, the terms of its indebtedness, applicable state laws and regulations of the FERC and the FPA. Our Regulated Operating Subsidiaries target a FERC-approved capital structure of 60% equity and 40% debt that may limit the ability of our Regulated Operating Subsidiaries to use net assets for the payment of dividends to ITC Holdings. In addition, ITC Holdings’ right to receive any assets of any subsidiary, and therefore the right of its creditors to participate in those assets, will be effectively subordinated to the claims of that subsidiary’s creditors. If ITC Holdings does not receive cash or other assets from our subsidiaries, it may be unable to pay principal and interest on its indebtedness.
We have a considerable amount of debt and our reliance on debt financing may limit our ability to fulfill our debt obligations and/or to obtain additional financing.
We have a considerable amount of debt and our consolidated indebtedness includes various debt securities and borrowings, which utilize indentures, revolving and term loan credit agreements and commercial paper that we rely on as sources of capital and liquidity. Our capital structure can have several important consequences, including, but not limited to, the following:
•If future cash flows are insufficient, we may not be able to make principal or interest payments on our debt obligations, which could result in the occurrence of an event of default under one or more of those debt instruments.
•We may need to increase our indebtedness in order to make the capital expenditures and other expenses or investments planned by us.
•Our indebtedness has the general effect of reducing our flexibility to react to changing business and economic conditions insofar as they affect our financial condition. A substantial portion of the dividends and payments in lieu of taxes we receive from our subsidiaries will be dedicated to the payment of interest on our indebtedness, thereby, reducing our available cash.
•In the event that we are liquidated, the creditors of our subsidiaries will be entitled to payment in full of the subsidiaries’ indebtedness prior to making any payments to ITC Holdings for the payment of its indebtedness.
•We currently have debt instruments outstanding with short-term maturities or relatively short remaining maturities. Our ability to secure additional financing prior to or after these facilities mature, if needed, may be substantially restricted by the existing level of our indebtedness and the restrictions contained in our debt instruments. Additionally, the interest rates at which we might secure additional financings may be higher than our currently outstanding debt instruments or higher than forecasted at any point in time, which could adversely affect our business, financial condition, results of operations and cash flows.
•Market conditions could affect our access to capital markets, restrict our ability to secure financing to make the capital expenditures and investments and pay other expenses planned by us which could adversely affect our business, financial condition, results of operations and cash flows.
We may incur substantial additional indebtedness in the future. The incurrence of additional indebtedness would increase the leverage-related risks described above.
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 and downgrading our credit ratings. In addition, because we are a subsidiary of Fortis, a downgrade in Fortis’ credit rating could cause our credit rating to be downgraded as well, even if our creditworthiness has not otherwise deteriorated. 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 on commercial paper and our revolving and term loan credit agreements.
Certain provisions in our debt instruments limit our financial and operating flexibility.
Our debt instruments on a consolidated basis, including senior notes, secured notes, first mortgage bonds, revolving and term loan credit agreements and commercial paper, contain numerous financial and operating covenants that place significant restrictions on, among other things, our ability to:
•incur additional indebtedness;
•engage in sale and lease-back transactions;
•create liens or other encumbrances;
•enter into mergers, consolidations, liquidations or dissolutions, or sell or otherwise dispose of all or substantially all of our assets;
•create and acquire subsidiaries; and
•pay dividends or make distributions on our stock or on the stock or member capital of our subsidiaries.
In addition, the covenants require us to meet certain financial ratios, such as maintaining certain debt to capitalization ratios and certain funds from operations to debt levels. Our ability to comply with these and other requirements and restrictions may be affected by changes in economic or business conditions, results of operations or other events beyond our control. A failure to comply with the obligations contained in any of our debt instruments could result in acceleration of related debt and the acceleration of debt under other instruments evidencing indebtedness that may contain cross-acceleration or cross-default provisions.

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ITEM 1B. UNRESOLVED STAFF COMMENTS
ITEM 1B. UNRESOLVED STAFF COMMENTS.
None.

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ITEM 2. PROPERTIES
ITEM 2. PROPERTIES.
Our Regulated Operating Subsidiaries’ transmission facilities are located in Michigan, Iowa, Minnesota, Illinois, Missouri, Kansas and Oklahoma. Our MISO Regulated Operating Subsidiaries and ITC Great Plains have agreements with other utilities for the joint ownership of specific substations, transmission lines and other transmission assets. See Note 15 to the consolidated financial statements for more information on the jointly owned assets.
Our Regulated Operating Subsidiaries own the assets of transmission systems and related assets, including:
•approximately 16,000 circuit miles of overhead and underground transmission lines rated at voltages of 34.5 kV to 345 kV, along with related transmission towers and poles;
•station assets, such as transformers and circuit breakers, at approximately 676 stations and substations which either interconnect our Regulated Operating Subsidiaries’ transmission facilities or connect our Regulated Operating Subsidiaries’ facilities with generation or distribution facilities owned by others;
•other transmission equipment necessary to safely operate the system (e.g., monitoring and metering equipment);
•warehouses and related equipment; and
•associated land held in fee, rights-of-way and easements.
ITCTransmission owns a corporate headquarters facility and operations control room in Novi, Michigan and a facility in Ann Arbor, Michigan that includes a back-up operations control room, along with associated furniture, fixtures and office equipment for these facilities.
METC does not own the majority of the land on which its assets are located, but under the provisions of the Easement Agreement, 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.”
Certain of our Regulated Operating Subsidiaries have issued First Mortgage Bonds and Senior Secured Notes. Under the terms of these instruments, the respective bondholders and noteholders have the benefit of a first mortgage lien on substantially all of the assets of the corresponding debt issuer. Refer to Note 9 to the consolidated financial statements for more information on the outstanding debt of our Regulated Operating Subsidiaries. As of December 31, 2021, there were no liens or encumbrances on the assets of ITC Interconnection.
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.

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ITEM 3. LEGAL PROCEEDINGS
ITEM 3. LEGAL PROCEEDINGS.
We are involved in certain legal proceedings before various courts, governmental agencies and mediation panels concerning matters arising in the ordinary course of business. These proceedings include certain contract disputes, regulatory matters and pending judicial matters. We cannot predict the final disposition of such proceedings. We regularly review legal matters and record provisions for claims that are considered probable of loss.
Refer to Notes 5 and 17 to the consolidated financial statements for a description of certain pending legal proceedings, which description is incorporated herein by reference.

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ITEM 4. MINE SAFETY DISCLOSURE
ITEM 4. MINE SAFETY DISCLOSURES.
Not applicable.
PART II

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
ITEM 5.
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.
ITC Holdings is a wholly-owned subsidiary of ITC Investment Holdings and ITC Holdings’ common stock is not publicly traded.
ITC Holdings paid dividends of $232 million and $330 million to our parent, ITC Investment Holdings, during the years ended December 31, 2021 and 2020, respectively. ITC Holdings also paid dividends of $64 million to ITC Investment Holdings in January 2022. The timing and amount of future dividends is subject to an approved dividend declaration from our Board of Directors, and is dependent upon cash flows, capital requirements, legislative and regulatory developments, and financial condition of ITC Holdings, among other factors deemed relevant.

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ITEM 6. SELECTED FINANCIAL DATA
ITEM 6. [Reserved]

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
Safe Harbor Statement Under The Private Securities Litigation Reform Act of 1995
Our reports, filings and other public announcements contain certain statements that describe our management’s beliefs concerning future business conditions, plans and prospects, growth opportunities, the outlook for our business and the electric transmission industry, and expectations with respect to various legal and regulatory proceedings 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,” “forecasted,” “projects,” “likely” and similar phrases. These forward-looking statements are based upon assumptions our management believes are reasonable. Such forward-looking statements are based on estimates and assumptions and are subject to significant risks and uncertainties which could cause our actual results, performance and achievements to differ materially from those expressed in, or implied by, these statements, including, among others, the risks and uncertainties listed in this report under “Item 1A. Risk Factors” and in our other reports filed with the SEC from time to time.
Forward-looking statements speak only as of the date made and can be affected by assumptions we might make or by known or unknown risks and uncertainties. Many factors mentioned in our discussion in this report will be important in determining future results. Consequently, we cannot assure you that our expectations or forecasts expressed in such forward-looking statements will be achieved. Except as required by law, we undertake no obligation to publicly update any of our forward-looking or other statements, whether as a result of new information, future events or otherwise.
Statement on Prior Period Comparisons
This section of this Form 10-K generally discusses the financial condition, changes in financial condition and results of operations for the years ended December 31, 2021 and 2020 and provides year-to-year comparisons between the years ended December 31, 2021 and 2020. Discussions of such information for the year ended December 31, 2019 and year-to-year comparisons between the years ended December 31, 2020 and 2019 that are not included in this Form 10-K can be found in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part II, Item 7. of the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2020.
Overview
ITC Holdings provides safe and reliable electric transmission service to connect consumers to more sustainable and cost-effective energy resources. ITC Holdings continues to make investments in a modernized grid to maintain reliability and accommodate future demands as our economy and lifestyles become increasingly dependent on electricity.
Our business consists primarily of the electric transmission operations of our Regulated Operating Subsidiaries. Through our Regulated Operating Subsidiaries, we own and operate high-voltage electric transmission systems in Michigan’s Lower Peninsula and portions of Iowa, Minnesota, Illinois, Missouri, Kansas and Oklahoma that transmit electricity from generating stations to local distribution facilities connected to our transmission systems.
Our Regulated Operating Subsidiaries’ primary operating responsibilities include maintaining, improving and expanding their transmission systems to meet their customers’ ongoing needs, scheduling outages on system elements to allow for maintenance and construction, maintaining appropriate system voltages and monitoring flows over transmission lines and other facilities to ensure physical limits are not exceeded.
Our Regulated Operating Subsidiaries earn revenues for the use of their electric transmission systems by their 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, and our cost-based rates are discussed below under “- Cost-Based Formula Rates with True-Up Mechanism” as well as in Note 5 to the consolidated financial statements.
Significant recent matters that influenced our financial condition, results of operations and cash flows for the year ended December 31, 2021 or that may affect future results include:
•Our capital expenditures of $834 million at our Regulated Operating Subsidiaries during the year ended December 31, 2021, as described below under “- Capital Investment and Operating Results Trends;”
•Debt issuances, borrowings, repayments, and interest rate swaps as described in Note 9 to the consolidated financial statements;
•The FERC orders related to the MISO ROE Complaints, as described in Note 17 to the consolidated financial statements, that are currently under appeal at the D.C. Circuit Court; and
•Issuance of a NOPR by the FERC on March 20, 2020 and issuance of a supplemental NOPR on April 15, 2021, that include a proposal to update the transmission incentives policy, as described below under “ - Recent Developments.”
These items are discussed in more detail throughout “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 calculate their revenue requirements using cost-based Formula Rates that are effective without the need to file rate cases with the FERC, although the rates are subject to legal challenge at the FERC. Under their cost-based formula, each of our Regulated Operating Subsidiaries separately calculates a revenue requirement based on financial information specific to each company. The calculation of projected revenue requirement for a future period is used to establish the transmission rate used for billing purposes. The calculation of actual revenue requirements for a historic period is used to calculate the amount of revenues recognized in that period and determine the over- or under-collection for that period.
Under these Formula Rates, our Regulated Operating Subsidiaries recover expenses and earn an authorized return on and recover investments in property, plant and equipment on a current basis. The Formula Rates for a given year reflect forecasted expenses, property, plant and equipment, point-to-point revenues, network load at our MISO Regulated Operating Subsidiaries and other items for the upcoming calendar year to establish projected revenue requirements for each of our Regulated Operating Subsidiaries that are used as the basis for billing for service on their systems from January 1 to December 31 of that year. Our Formula Rates include a true-up mechanism, whereby our Regulated Operating Subsidiaries compare their actual revenue requirements to their billed revenues for each year to determine any over- or under-collection of revenue. The over- or under-collection typically results from differences between the projected revenue requirement used as the basis for billing and actual revenue requirement at each of our Regulated Operating Subsidiaries, or from differences between actual and projected monthly network peak loads at our MISO Regulated Operating Subsidiaries. In the event billed revenues in a given year are more or less than actual revenue requirements, which are calculated primarily using information from that year’s FERC Form No. 1, our Regulated Operating Subsidiaries will refund or collect additional revenues, with interest, within a two-year period such that customers pay only the amounts that correspond to actual revenue requirements for that given period. This annual true-up ensures that our Regulated Operating Subsidiaries recover their allowed costs and earn their authorized returns.
See “Cost-Based Formula Rates with True-Up Mechanism” in Note 5 to the consolidated financial statements for further discussion of our Formula Rates and see “Rate of Return on Equity Complaints” in Note 17 to the consolidated financial statements for detail on ROE matters.
Illustrative Example of Formula Rate Setting
The Formula Rate setting example shown below is for illustrative purposes only and is not based on our actual financial data.
Line Item Instructions Amount
1 Rate base (a) $ 1,000,000
2 Multiply by 13-month weighted average cost of capital (b)
8.46 %
3 Authorized return on rate base (Line 1 x Line 2) $ 84,600
4 Recoverable operating expenses (including depreciation and amortization)
$ 150,000
5 Income taxes (c) 37,500
6 Gross revenue requirement (Line 3 + Line 4 + Line 5) $ 272,100
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(a)Consists primarily of in-service property, plant and equipment, net of accumulated depreciation.
(b)The weighted average cost of capital for purposes of this illustration is calculated below. The cost of capital for debt is included at a flat interest rate for purposes of this illustration and is not based on our actual cost of capital. The cost of capital rate for equity represents the current maximum allowed MISO ROE per the May 2020 Order on the Initial Complaint. See Note 17 to the consolidated financial statements for detail on ROE matters.
Weighted
Average
Percentage of
Cost of
Total Capitalization
Cost of Capital
Capital
Debt 40.00% 5.00% =
2.00 %
Equity 60.00% 10.77% =
6.46 %
100.00% 8.46 %
(c)Represents an approximation of the federal and state income tax expense for purposes of this illustration and is not based on our actual tax expense.
Revenue Accruals and Deferrals - Effects of Monthly Network Peak Loads
For our MISO Regulated Operating Subsidiaries, monthly network peak loads are used for billing network revenues, which currently is the largest component of our operating revenues. One of the primary factors that impacts the revenue accruals and deferrals at our MISO Regulated Operating Subsidiaries is actual monthly network peak loads experienced as compared to those forecasted in establishing the annual network transmission rate. Under their cost-based Formula Rates that contain a true-up mechanism, our MISO Regulated Operating Subsidiaries accrue or defer revenues to the extent that their actual revenue requirement for the reporting period is higher or lower, respectively, than the amounts billed relating to that reporting period. Although monthly network peak loads do not impact operating revenues recognized, network load affects the timing of our cash flows from transmission service. The monthly network peak load of our MISO Regulated Operating Subsidiaries is generally impacted by weather, economic conditions and other significant factors, including the effects of COVID-19, and is seasonally shaped with higher load in the summer months when cooling demand is higher. We are unable to predict the possible future impacts of weather, economic conditions, including COVID-19, and other factors on monthly network peak loads at our MISO Regulated Operating Subsidiaries.
ITC Great Plains does not receive revenue based on a peak load or a dollar amount per kW each month. Therefore, peak load does not have a seasonal effect on operating cash flows. The SPP tariff applicable to ITC Great Plains is billed ratably each month based on its annual projected revenue requirement posted annually by SPP.
Capital Investment and Operating Results Trends
We expect a long-term upward trend in rate base resulting from our anticipated capital investment, in excess of depreciation and any acquisition premiums, from our Regulated Operating Subsidiaries’ long-term capital
investment programs to improve reliability, increase system capacity and upgrade the transmission network to support new generating resources. 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. While we expect increases in rate base to result in a corresponding long-term upward trend in revenues and earnings, our revenues and earnings have been impacted by changes in our ROE and required refunds resulting from the resolution of the incentive adders complaints and MISO ROE Complaints, as described in Note 5 and Note 17 to the consolidated financial statements. Our revenues and earnings may be impacted by future increases or decreases to our rates for incentive adders and base ROE.
During 2021, our MISO Regulated Operating Subsidiaries filed revised depreciation rates for their assets which were approved by the FERC in December 2021. The overall depreciation expense at our MISO Regulated Operating Subsidiaries increased beginning on January 1, 2022. This increase is expected to result in higher revenue from customers in the near term due to an overall increase in the rates at which we record depreciation expense. Based on December 31, 2020 asset balances used in the filing, we estimate an increase in 2022 in depreciation expense of approximately $35 million to $40 million resulting from our MISO Regulated Operating Subsidiaries’ new depreciation rates.
Our Regulated Operating Subsidiaries strive for high reliability of their systems and improvement in system accessibility for all generation resources. The FERC requires compliance with certain reliability standards and may take enforcement actions against violators, including the imposition of substantial fines. NERC is responsible for developing and enforcing these mandatory reliability standards. We continually assess our transmission systems against standards established by NERC, as well as the standards of applicable regional entities under NERC that have been delegated certain authority for the purpose of proposing and enforcing reliability standards. We believe that we meet the applicable standards in all material respects, although further investment in our transmission systems and an increase in maintenance activities will likely be needed to maintain compliance, improve reliability and address any new standards that may be promulgated.
We also assess our transmission systems against our own planning criteria that are filed annually with the FERC. Based on our planning studies, we see needs to make capital investments to: (1) maintain and replace our current transmission infrastructure to enhance system reliability and accommodate load growth; (2) interconnect new renewable generation resources; (3) upgrade physical and technological grid security to protect critical infrastructure; and (4) expand access to electricity markets to reduce the overall cost of delivered energy to customers. To date, COVID-19 has not had a material impact on our forecasted capital expenditures. However, we continue to evaluate and monitor the potential impacts of COVID-19, including potential supply chain disruptions, on our forecasted capital expenditures. The following table shows our actual and expected capital expenditures at our Regulated Operating Subsidiaries:
Actual Capital Forecasted
Expenditures for the Capital
year ended Expenditures
(In millions of USD) December 31, 2021 2022 - 2026
Expenditures for property, plant and equipment (a) $ 834 $ 4,004
____________________________
(a)Amounts represent the cash payments to acquire or construct property, plant and equipment, as presented in the consolidated statements of cash flows. These amounts exclude non-cash additions to property, plant and equipment for the AFUDC equity as well as accrued liabilities for construction, labor and materials that have not yet been paid.
Our long-term growth plan includes ongoing investments in our current regulated transmission systems and the identification of incremental strategic projects primarily located in and around our service territories. Refer to “Item 1. Business - Development of Business” for additional information.
A comprehensive effort by MISO is underway to identify and construct the regional transmission required in the MISO region to support the ongoing evolution of the electric industry. MISO is currently requesting FERC authorization for cost allocation and finalizing planning for an initial tranche of long range transmission plan projects.
Investments in property, plant and equipment could be lower than expected due to a variety of factors, as discussed in “Item 1A. Risk Factors.” In addition, investments in transmission network upgrades for generator interconnection projects could change from prior estimates significantly due to changes in the MISO queue for generation projects and other factors beyond our control.
Recent Developments
COVID-19 Pandemic
In March 2020, the World Health Organization declared COVID-19 a pandemic. Efforts to control the outbreak of COVID-19 have resulted in challenges to businesses and facilities in various industries around the world, including our customers, and disruptions to the global economy and supply chains. To date, COVID-19 has not had a material impact on our net income. However, for 2020, we utilized various temporary cost saving measures related to operating expenses, including operation and maintenance expenses and general and administrative expenses, in an attempt to reduce costs for our customers that were collected through our Formula Rates.
We are unable to predict the ultimate effects of COVID-19 on the U.S. or global economy or our operations. We continue to monitor developments affecting our workforce, customers, suppliers, and operations. The extent of the impact of COVID-19 will depend on its duration, actions by government authorities, and impacts on our customers, employees, or vendors. These developments are continuously evolving, and we cannot predict whether COVID-19 will have a material impact on our financial condition, results of operations or cash flows.
Rate of Return on Equity Complaints
Two complaints were filed with the FERC by combinations of consumer advocates, consumer groups, municipal parties and other parties challenging the base ROE in MISO. The FERC has issued multiple orders in these proceedings, and there are appeals to these orders pending in the D.C. Circuit Court. See Rate of Return on Equity Complaints in Note 17 to the consolidated financial statements for a summary of the MISO ROE Complaints. See also the risk factor “Certain elements of our Regulated Operating Subsidiaries’ Formula Rates have been and can be challenged, which could result in lowered rates and/or refunds of amounts previously collected and thus may have an adverse effect on our business, financial condition, results of operations and cash flows.” in Item 1A. Risk Factors.
Challenges to Incentive Adders for Transmission Rates
The FERC issued a NOPR on March 20, 2020, and issued a supplemental NOPR on April 15, 2021, proposing to update its transmission incentives policy. Among other things, the rulemaking proposals would:
•grant incentives to transmission projects based upon benefits to customers ensuring reliability and reducing the cost of delivered power by reducing transmission congestion, and
•eliminate the ROE adders for independent transmission ownership and for RTO participation.
The outcome of this proposal may impact the incentive adders that our Regulated Operating Subsidiaries are authorized to apply to their base ROEs on a prospective basis. As of December 31, 2021, our MISO Regulated Operating Subsidiaries had a total of approximately $5 billion of equity in their collective capital structures for ratemaking purposes. Based on this level of aggregate equity, we estimate that each 10 basis point change in the authorized ROE would impact annual consolidated net income by approximately $5 million. For ITC Great Plains, each 10 basis point change in authorized ROE would impact annual consolidated net income by less than $1 million.
Complaints were previously filed with the FERC under section 206 of the FPA challenging the adders for independent transmission ownership that are in transmission rates charged by our MISO Regulated Operating Subsidiaries and ITC Great Plains. The FERC issued orders in these proceedings, setting revised adders for independent transmission ownership for each of the MISO Regulated Operating Subsidiaries and ITC Great Plains to 25 basis points, and the FERC orders were subsequently appealed in the D.C. Circuit Court. On February 19, 2021, the appeal of the FERC order in the proceedings for the MISO Regulated Operating Subsidiaries was denied. On March 4, 2021, the appeals of the FERC orders in the proceedings for ITC Great Plains were dismissed following a motion for voluntary dismissal by ITC Great Plains. See Note 5 to the consolidated financial statements for a summary of incentive adders for transmission rates and these matters.
See also the risk factor “Certain elements of our Regulated Operating Subsidiaries’ Formula Rates have been and can be challenged, which could result in lowered rates and/or refunds of amounts previously collected and thus may have an adverse effect on our business, financial condition, results of operations and cash flows.” in Item 1A. Risk Factors.
Significant Components of Results of Operations
Revenues
We derive nearly all of our revenues from providing transmission, scheduling, control and dispatch services and other related services over our Regulated Operating Subsidiaries’ transmission systems to DTE Electric, Consumers Energy, IP&L and other entities, such as alternative energy suppliers, power marketers and other wholesale customers that provide electricity to end-use consumers, as well as from transaction-based capacity reservations on our transmission systems. MISO and SPP are responsible for billing and collecting the majority of transmission service revenues. As the billing agents for our MISO Regulated Operating Subsidiaries and ITC Great Plains, MISO and SPP collect fees for the use of our transmission systems, invoicing DTE Electric, Consumers Energy, IP&L and other customers on a monthly basis.
Network Revenues are generated from network customers for their use of our electric transmission systems and are based on the actual revenue requirements as a result of our accounting under our cost-based Formula Rates that contain a true-up mechanism. Refer below under “- Critical Accounting Policies and Estimates - Revenue Recognition under Cost-Based Formula Rates with True-Up Mechanism” for a discussion of revenue recognition relating to network revenues.
Network revenues from ITC Great Plains include the annual revenue requirements specific to projects that are charged exclusively within one pricing zone within SPP or are classified as direct assigned network upgrades under the SPP tariff and contain a true-up mechanism.
Regional Cost Sharing Revenues are generated from transmission customers throughout RTO regions for their use of our MISO Regulated Operating Subsidiaries’ network upgrade projects that are eligible for regional cost sharing under provisions of the MISO tariff, including MVPs. Additionally, certain projects at ITC Great Plains are eligible for recovery through a region-wide charge under provisions of the SPP tariff. Regional cost sharing revenues are treated as a reduction to the net network revenue requirement under our cost-based Formula Rates.
Point-to-Point Revenues consist of revenues generated from a type of transmission service for which the customer pays for transmission capacity reserved along a specified path between two points on an hourly, daily, weekly or monthly basis. Point-to-point revenues also include other components pursuant to schedules under the MISO and SPP transmission tariffs. Point-to-point revenues are treated as a revenue credit to network or regional customers and are a reduction to gross revenue requirement when calculating net revenue requirement under our cost-based Formula Rates.
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.
Other Revenues consist of rental revenues, easement revenues, revenues relating to utilization of jointly owned assets under our transmission ownership and operating agreements and amounts from providing ancillary services to customers. The majority of other revenues are treated as a revenue credit and taken as a reduction to gross revenue requirement when calculating net revenue requirement under our cost-based Formula Rates.
Operating Expenses
Operation and Maintenance Expenses consist primarily of the costs for contractors that operate and maintain our transmission systems as well as our personnel involved in operation and maintenance activities.
Operation expenses include activities related to control area operations, which involve balancing loads and generation and transmission system operations activities, including monitoring the status of our transmission lines and stations. Rental expenses relating to land easements, including METC’s Easement Agreement, are also recorded within operation expenses.
Maintenance expenses include preventive or planned activities, such as vegetation management, tower painting and equipment inspections, as well as reactive maintenance for equipment failures.
General and Administrative Expenses consist primarily of costs for personnel in our legal, information technology, finance, regulatory, human resources, community relations and communication functions, general office expenses and fees for professional services. Professional services are principally composed of outside legal, consulting, audit and information technology services.
Depreciation and Amortization Expenses consist primarily of depreciation of property, plant and equipment using the straight-line method of accounting. Additionally, this consists of amortization of various regulatory and intangible assets.
Taxes Other than Income Taxes consist primarily of property taxes and payroll taxes.
Other Items of Income or Expense
Interest Expense consists primarily of interest on debt at ITC Holdings and our Regulated Operating Subsidiaries. Additionally, the amortization of debt financing expenses and loss on extinguishment of debt are recorded to interest expense. An allowance for borrowed funds used during construction is included in property, plant and equipment accounts and treated as a reduction to interest expense. The amortization of gains and losses on settled and terminated derivative financial instruments is recorded to interest expense. The interest portion of the refunds relating to the MISO ROE Complaints is also recorded to interest expense.
Allowance for Equity Funds Used During Construction (“AFUDC equity”) is recorded as an item of other income and is included in property, plant and equipment accounts. The allowance represents a return on equity at our Regulated Operating Subsidiaries used for construction purposes in accordance with the 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 authorized return on equity for our Regulated Operating Subsidiaries.
Income Tax Provision
Income tax provision consists of current and deferred federal and state income taxes.
Results of Operations
The following table summarizes historical operating results for the periods indicated:
Year Ended Percentage Year Ended Percentage
December 31, Increase Increase December 31, Increase Increase
(In millions of USD) 2021 2020 (Decrease) (Decrease) 2019 (Decrease) (Decrease)
OPERATING REVENUES
Transmission and other services $ 1,358 $ 1,290 $ 68 5 % $ 1,286 $ 4 - %
Formula Rate true-up (9) 8 (17) (213) % 41 (33) (80) %
Total operating revenue 1,349 1,298 51 4 % 1,327 (29) (2) %
OPERATING EXPENSES
Operation and maintenance 108 87 21 24 % 113 (26) (23) %
General and administrative 128 115 13 11 % 138 (23) (17) %
Depreciation and amortization 232 219 13 6 % 203 16 8 %
Taxes other than income taxes 133 124 9 7 % 118 6 5 %
Other operating (income) and expenses, net
(1) - (1) n/a - - n/a
Total operating expenses 600 545 55 10 % 572 (27) (5) %
OPERATING INCOME 749 753 (4) (1) % 755 (2) - %
OTHER EXPENSES (INCOME)
Interest expense, net 251 240 11 5 % 224 16 7 %
Allowance for equity funds used during construction
(30) (27) (3) 11 % (29) 2 (7) %
Other (income) and expenses, net (5) (3) (2) 67 % - (3) n/a
Total other expenses (income) 216 210 6 3 % 195 15 8 %
INCOME BEFORE INCOME TAXES
533 543 (10) (2) % 560 (17) (3) %
INCOME TAX PROVISION 127 136 (9) (7) % 132 4 3 %
NET INCOME $ 406 $ 407 $ (1) - % $ 428 $ (21) (5) %
Operating Revenues
Year ended December 31, 2021 compared to year ended December 31, 2020
The following table sets forth the components of and changes in operating revenues for the years ended December 31, 2021 and 2020 which included revenue accruals and deferrals as described in Note 5 to the consolidated financial statements:
Percentage
2021 2020 Increase Increase
(In millions of USD) Amount Percentage Amount Percentage (Decrease) (Decrease)
Network revenues (a) $ 929 69 % $ 852 66 % $ 77 9 %
Regional cost sharing revenues (a) 358 27 % 362 28 % (4) (1) %
Point-to-point 17 1 % 13 1 % 4 31 %
Scheduling, control and dispatch (a) 19 1 % 20 2 % (1) (5) %
Other
26 2 % 19 1 % 7 37 %
Remeasurement of liabilities for ROE Complaints - - % 32 2 % (32) (100) %
Total $ 1,349 100 % $ 1,298 100 % $ 51 4 %
____________________________
(a)Includes a portion of the Formula Rate true-up of $(9) million and $8 million for the years ended December 31, 2021 and 2020, respectively.
Operating revenues increased primarily due to a higher rate base associated with higher balances of property, plant and equipment in-service and increased recoverable operating expenses in 2021 due to temporary cost saving measures utilized in 2020, which was partially offset by a favorable base ROE adjustment in 2020 related to prior periods as a result of the May 2020 Order.
Operating Expenses
Operation and maintenance expenses
Year ended December 31, 2021 compared to year ended December 31, 2020
Operation and maintenance expense increased primarily due to higher expenses associated with substation and overhead line maintenance activities, as well as higher vegetation management requirements, primarily due to temporary cost saving measures that were utilized in 2020 as a result of the COVID-19 pandemic.
General and administrative expenses
Year ended December 31, 2021 compared to year ended December 31, 2020
General and administrative expenses increased due to higher compensation-related expenses, primarily due to an increase in share-based compensation expense.
Depreciation and amortization expenses
Year ended December 31, 2021 compared to year ended December 31, 2020
Depreciation and amortization expenses increased primarily due to a higher depreciable base resulting from property, plant and equipment in-service additions.
Taxes other than income taxes
Year ended December 31, 2021 compared to year ended December 31, 2020
Taxes other than income taxes increased due to higher property tax expenses primarily due to our Regulated Operating Subsidiaries’ 2020 capital additions and higher millage rates, which are included in the assessments for 2021 property taxes.
Other Expenses (Income)
Interest Expense, Net
Year ended December 31, 2021 compared to year ended December 31, 2020
Interest expense, net increased due to higher debt balances and higher amortization of interest as a result of losses on interest rate swaps terminated in 2020. Additionally, the May 2020 Order resulted in a reduction in our previously recorded refund obligations, as well as a corresponding reduction in interest expense in 2020. See Note 17 to the consolidated financial statements for information regarding the May 2020 Order and the associated impacts of MISO ROE Complaints.
Income Tax Provision
Year ended December 31, 2021 compared to year ended December 31, 2020
Our effective tax rates for the years ended December 31, 2021 and 2020 were 23.8% and 25.0%, respectively. Our effective tax rate as of December 31, 2021 exceeded our 21% statutory federal income tax rate primarily due to state income taxes, partially offset by AFUDC equity and a change in our amortization method associated with excess deferred tax liabilities. The amount of income tax expense relating to AFUDC equity and excess deferred tax was recognized as a regulatory asset and regulatory liability, respectively, and is not included in the income tax provision. See Note 10 to the consolidated financial statements for further discussion regarding our income tax provision.
Liquidity and Capital Resources
We expect to maintain our approach of funding our future capital requirements with cash from operations at our Regulated Operating Subsidiaries, our existing cash and cash equivalents, future issuances under our commercial paper program and amounts available under our revolving credit agreements (the terms of which are described in Note 9 to the consolidated financial statements). In addition, we may from time to time secure debt funding (including debt to finance or refinance portfolios of eligible projects based on the green bond framework established by ITC Holdings) in the capital markets, although we can provide no assurance that we will be able to obtain financing on favorable terms or at all. As market conditions warrant, we may also from time
to time repurchase debt securities issued by us, in the open market, in privately negotiated transactions, by tender offer or otherwise. We expect that our capital requirements will arise principally from our need to:
•Fund capital expenditures (including purchase commitments as described in Note 17 to the consolidated financial statements) at our Regulated Operating Subsidiaries. Our plans with regard to property, plant and equipment investments are described in detail above under “- Capital Investment and Operating Results Trends.”
•Fund our debt service requirements, including principal repayments and periodic interest payments, which are further described below.
•Fund working capital requirements.
In addition to the expected capital requirements above, any adverse determinations or settlements relating to the regulatory matters or contingencies described in Notes 5 and 17 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 (within twelve months) needs. However, we rely on both internal and external sources of liquidity to provide working capital and fund capital investments. The COVID-19 pandemic has impacted the global economy and capital markets in various ways, including negative impacts which have varied in duration and magnitude. An extended period of economic disruption could impact our ability to access the capital markets requiring us to seek alternative forms of financing which could negatively impact our liquidity and capital resources. ITC Holdings’ sources of cash are dividends and other payments received by us from our Regulated Operating Subsidiaries and any of our other subsidiaries as well as the proceeds raised from the sale of our debt securities. Each of our Regulated Operating Subsidiaries, while wholly-owned by ITC Holdings, is legally distinct from ITC Holdings and has no obligation, contingent or otherwise, to make funds available to us.
We expect to continue to utilize our commercial paper program and revolving credit agreements as well as our cash and cash equivalents as needed to meet our short-term (within twelve months) cash requirements. As of December 31, 2021, we had consolidated indebtedness under our revolving credit agreements of $329 million, with unused capacity under our revolving credit agreements of $571 million. ITC Holdings had $155 million of commercial paper issued and outstanding, net of discount, as of December 31, 2021, with the ability to issue an additional $245 million under the commercial paper program. In 2021, we paid $4 million of interest and commitment fees under our revolving credit agreements and commercial paper program.
To address our future capital requirements, we expect that we will need to obtain additional long-term debt financing. As of December 31, 2021, we had various notes and bonds outstanding with terms, including fixed interest rate and principal payment terms, specific to each borrowing. Maturity dates for these long-term debt issuances range from 2022 to 2055. Total future interest payment obligations associated with these existing fixed-rate, long-term debt obligations were $3.9 billion as of December 31, 2021, with expected interest payment obligations of $240 million due within the next twelve months. Certain of our capital projects could be delayed if we experience difficulties in accessing capital pursuant to complications from COVID-19, or otherwise. We expect to be able to obtain such additional financing as needed, in amounts and upon terms that will be acceptable to us due to our strong credit ratings and our historical ability to obtain financing. See Note 9 to the consolidated financial statements for a detailed discussion of our debt activity, including the commercial paper program and our term loan and revolving credit agreements, during the years ended December 31, 2021 and 2020.
METC has a contractual obligation through December 31, 2050 for an Easement Agreement for transmission purposes and rights-of-way, leasehold interests, fee interests and licenses associated with the land over which the transmission lines cross. The cost for use of the rights-of-way is $10 million per year. See Note 17 to the consolidated financial statements for additional details related to the easement.
We have certain obligations including contingent liabilities and other current and long-term liabilities, that have uncertainty regarding the timing and any amount of future cash flows necessary to settle these obligations. Such items include:
•long-term incentive awards;
•pension and other postretirement obligations;
•regulatory liabilities related to asset removal costs and refundable income taxes; and
•liabilities to refund deposits from generators for transmission network upgrades.
We have exposure to LIBOR through the revolving credit agreements of ITC Holdings and certain of our Regulated Operating Subsidiaries. Certain tenors of LIBOR began being phased out in late 2021, with full discontinuation planned for mid-2023. We believe the rate selected as the preferred alternative to LIBOR will be an acceptable replacement rate when LIBOR is fully discontinued. However, we plan to continue using the available LIBOR tenors until 2023 and as such cannot reasonably estimate the expected impact of the planned discontinuation of LIBOR at this time.
Credit Ratings
Credit ratings by nationally recognized statistical rating agencies are an important component of our liquidity profile. Credit ratings relate to our ability to issue debt securities and the cost to borrow money and should not be viewed as a recommendation to buy, sell or hold securities. Ratings are subject to revision or withdrawal at any time and each rating should be evaluated independently of any other rating. Our current credit ratings are displayed in the following table. An explanation of these ratings may be obtained from the respective rating agency.
S&P Moody’s
Rating Outlook (a) Rating Outlook
ITC Holdings
Senior Unsecured Notes BBB+ Stable Baa2 Stable
Commercial Paper A-2 Stable Prime-2 Stable
ITCTransmission
First Mortgage Bonds A Stable A1 Stable
METC
Senior Secured Notes A Stable A1 Stable
ITC Midwest
First Mortgage Bonds A Stable A1 Stable
ITC Great Plains
First Mortgage Bonds A Stable A1 Stable
_____________________
(a)On April 1, 2021, S&P reaffirmed the ratings of ITC Holdings and certain of our Regulated Operating Subsidiaries and revised all outlooks from negative to stable.
Covenants
Our debt instruments contain numerous financial and operating covenants that place significant restrictions on certain transactions, such as incurring additional indebtedness, engaging in sale and lease-back transactions, creating liens or other encumbrances, entering into mergers, consolidations, liquidations or dissolutions, creating or acquiring subsidiaries and selling or otherwise disposing of all or substantially all of our assets. In addition, the covenants require us to meet certain financial ratios, such as maintaining certain debt to capitalization ratios and certain funds from operations to debt levels. As of December 31, 2021, we were not in violation of any debt covenant. In the event of a downgrade in our credit ratings, none of the covenants would be directly impacted, although the borrowing costs under our revolving credit agreements may increase.
Cash Flows
The following table summarizes cash flows for the periods indicated:
Year Ended December 31,
(In millions of USD) 2021 2020 2019
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 406 $ 407 $ 428
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense 232 219 203
Recognition, refund and collection of revenue accruals and deferrals - including accrued interest
52 (47) (55)
Deferred income tax expense 127 138 135
Other (32) (85) (82)
Net cash provided by operating activities 785 632 629
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment (834) (885) (865)
Contributions in aid of construction 15 2 10
Other (5) 5 1
Net cash used in investing activities (824) (878) (854)
CASH FLOWS FROM FINANCING ACTIVITIES
Net issuance/repayment of debt (including commercial paper and revolving and term loan credit agreements)
294 561 463
Dividends to ITC Investment Holdings (232) (330) (250)
Refundable deposits from and repayments to generators for transmission network upgrades, net
(21) 50 11
Settlement of interest rate swaps - (23) -
Other (1) (12) (3)
Net cash provided by financing activities 40 246 221
NET INCREASE (DECREASE) IN CASH, CASH EQUIVALENTS AND RESTRICTED CASH 1 - (4)
CASH, CASH EQUIVALENTS AND RESTRICTED CASH - Beginning of period 6 6 10
CASH, CASH EQUIVALENTS AND RESTRICTED CASH - End of period $ 7 $ 6 $ 6
Cash Flows From Operating Activities
Year ended December 31, 2021 compared to year ended December 31, 2020
Net cash provided by operating activities was $785 million and $632 million for the years ended December 31, 2021 and 2020, respectively. The increase in cash provided by operating activities was due primarily to an increase in cash received from operating revenues of $162 million compared to the year ended December 31, 2020 and lower net payments related to the MISO ROE Complaints of $26 million, including interest, refunded to customers. This increase was partially offset by higher operation and maintenance expenses and general and administrative expenses during the year ended December 31, 2021 compared to the year ended December 31, 2020.
Cash Flows From Investing Activities
Year ended December 31, 2021 compared to year ended December 31, 2020
Net cash used in investing activities was $824 million and $878 million for the years ended December 31, 2021 and 2020, respectively. The decrease in cash used in investing activities was primarily due to a decrease in capital expenditures of $51 million and an increase in contributions in aid of construction of $13 million received during the year ended December 31, 2021 compared to the year ended December 31, 2020.
Cash Flows From Financing Activities
Year ended December 31, 2021 compared to year ended December 31, 2020
Net cash provided by financing activities was $40 million and $246 million for the years ended December 31, 2021 and 2020, respectively. The decrease in cash provided by financing activities was due primarily to a decrease in issuances of long-term debt of $955 million and an increase in net repayments of refundable deposits for transmission network upgrades of $71 million during the year ended December 31, 2021 compared to the year ended December 31, 2020. This decrease was partially offset by a decrease in retirement of long-term debt of $35 million, an increase in net borrowings under our revolving credit agreements of $232 million, a decrease in net repayments under our term loan credit agreements of $200 million, an increase in net issuances of commercial paper of $221 million, a decrease in dividend payments of $98 million and a decrease in settlement of interest rate swaps of $23 million during the year ended December 31, 2021 compared to the year ended December 31, 2020. See Note 9 to the consolidated financial statements for additional discussion on debt and interest rate swaps.
Critical Accounting Policies and Estimates
Our consolidated financial statements are prepared in accordance with GAAP. The preparation of these consolidated financial statements requires the application of appropriate technical accounting rules and guidance, as well as the use of estimates. The application of these policies requires judgments regarding future events.
These estimates and judgments, in and of themselves, could materially impact the consolidated financial statements and disclosures based on varying assumptions, as future events rarely develop exactly as forecasted, and even the best estimates routinely require adjustment.
The following accounting policies are the most significant to the portrayal of our financial condition and results of operations and/or that require management’s most difficult, subjective or complex judgments.
Regulation
Our Regulated Operating Subsidiaries are subject to rate regulation by the FERC. As a result, we apply accounting principles in accordance with the standards set forth by the FASB for accounting for the effects of certain types of regulation. Use of this accounting guidance results in differences in the application of GAAP between regulated and non-regulated businesses and requires the recording of regulatory assets and liabilities for certain transactions that would have been treated as expense or revenue in non-regulated businesses. As described in Note 6 to the consolidated financial statements, we had regulatory assets and liabilities of $211 million and $633 million, respectively, as of December 31, 2021. Future changes in the regulatory and competitive environments could result in discontinuing the application of the accounting standards for the effects of certain types of regulations. If we were to discontinue the application of this guidance on the operations of our Regulated Operating Subsidiaries, we may be required to record losses relating to certain regulatory assets or gains relating to certain regulatory liabilities. We also may be required to record losses of $26 million relating to intangible assets at December 31, 2021 that are described in Note 8 to the consolidated financial statements.
We believe that currently available facts support the continued applicability of the standards for accounting for the effects of certain types of regulation and that all regulatory assets and liabilities are recoverable or refundable under our current rate environment.
Revenue Recognition under Cost-Based Formula Rates with True-Up Mechanism
Our Regulated Operating Subsidiaries recover expenses and earn an authorized return on and recover investments in property, plant and equipment on a current basis, under their forward-looking cost-based Formula Rates with a true-up mechanism.
Under their Formula Rates, our Regulated Operating Subsidiaries use forecasted expenses, property, plant and equipment, point-to-point revenues and other items for the upcoming calendar year to establish their projected revenue requirement and for the MISO Regulated Operating Subsidiaries, their component of the billed network rates for service on their systems from January 1 to December 31 of that year. Our Formula Rates include a true-up mechanism, whereby our Regulated Operating Subsidiaries compare their actual revenue requirements to their billed revenues for each year to determine any over- or under-collection of revenue. The over- or under-collection typically results from differences between the projected revenue
requirement used as the basis for billing and actual revenue requirement at each of our Regulated Operating Subsidiaries, or from differences between actual and projected monthly network peak loads at our MISO Regulated Operating Subsidiaries.
The true-up mechanisms under our Formula Rates meet the GAAP requirements for accounting for rate-regulated utilities and the effects of certain alternative revenue programs. Accordingly, revenue is recognized during each reporting period based on actual revenue requirements calculated using the cost-based Formula Rates. Our Regulated Operating Subsidiaries accrue or defer revenues to the extent that their actual revenue requirement for the reporting period is higher or lower, respectively, than the amounts billed relating to that reporting period. The true-up amount is automatically reflected in customer bills within two years under the provisions of the Formula Rates. See Note 6 to the consolidated financial statements for the regulatory assets and liabilities recorded at our Regulated Operating Subsidiaries’ as a result of the Formula Rate revenue accruals and deferrals.
Contingent Obligations
See Note 2 to the consolidated financial statements for a description of the policy for estimating contingent obligations. The adequacy of liabilities recorded for contingent obligations can be significantly affected by external events or conditions that can be unpredictable; thus, the ultimate outcome of such matters could materially affect our consolidated financial statements. These events or conditions include, without limitation, the following:
•Changes in existing state or federal regulation by governmental authorities having jurisdiction over air quality, water quality, control of toxic substances, hazardous and solid wastes and other environmental matters.
•Changes in existing federal income tax laws or IRS regulations.
•Identification and evaluation of lawsuits or complaints in which we may be or have been named as a defendant.
•Resolution or progression of existing matters through the legislative process, the courts, the FERC, the NERC, the IRS or the Environmental Protection Agency.
Refer to Note 17 to the consolidated financial statements for discussion on contingencies, including the MISO ROE Complaints.
Pension and Postretirement Benefit Plan Assumptions
We sponsor certain retirement benefits for our employees, which include retirement pension plans and certain postretirement health care, dental and life insurance benefits. Our periodic costs and obligations associated with these plans are developed from actuarial valuations derived from a number of assumptions. Key assumptions include:
•Discount rates used to determine obligations,
•Expected long-term returns on plan assets,
•Rate of salary increases,
•Mortality, and
•Rate of increase in health care costs.
Discount Rates
Benefit obligations, service cost and interest cost are determined by separately discounting projected benefit payments using a yield curve of high-quality corporate bonds. As of December 31, 2021, the weighted-average single equivalent discount rate for the benefit obligation was 2.86% and 3.14% for our pension and postretirement benefit plans, respectively.
Expected Long-Term Rate of Return on Plan Assets
In determining our long-term rate of return on plan assets, we consider the current and expected asset allocations, as well as historical and expected long-term rates of return on those types of asset classes. For the
year ended December 31, 2021, we assumed that our pension and postretirement benefit plans’ assets would generate weighted-average long-term rates of return of 5.70% and 4.30%, respectively.
Salary Increases
As of December 31, 2021, we used an annual rate of salary increases of 4.00% to determine our pension and postretirement plan obligations.
Mortality
The Pri-2012 mortality table projected forward generationally from 2012 with the MP-2020 mortality improvement scale was used to determine pension and postretirement plan obligations as of December 31, 2021.
Rate of Increase in Healthcare Costs
We used a current year healthcare cost trend rate of 6.00% for 2021 grading down to a 5.00% ultimate rate in 2025 in valuing our postretirement benefit obligation as of December 31, 2021. These rates are based on a review of recent and expected future experience.
Sensitivity Analysis
The below table displays the effect on our costs and obligation of a 1% change to our assumptions as of December 31, 2021:
Effect on Costs Effect on Obligation
(in millions of USD) 1% Increase 1% Decrease 1% Increase 1% Decrease
Change to Pension Plans
Discount Rate $- $2 $(17) $21
Long-Term Rate of Return on Plan Assets (1) 1 N/A N/A
Change to Postretirement Plan
Discount Rate (4) 2 (22) 28
Long-Term Rate of Return on Plan Assets (1) 1 N/A N/A
Healthcare Cost Trend Rate $4 $(5) $24 $(19)
See Note 11 to the consolidated financial statements for further details regarding our pension and postretirement benefit plan costs and obligations.
Off-Balance Sheet Arrangements
We have no off-balance sheet arrangements that have or are reasonably likely to have a material effect on our financial condition.
Recent Accounting Pronouncements
We have considered all new accounting pronouncements issued by the FASB and determined that it is not likely that any of the recently issued accounting guidance will have a material impact on our consolidated financial statements.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
Commodity Price Risk
We have commodity price risk at our Regulated Operating Subsidiaries arising from market price fluctuations for materials such as copper, aluminum, steel, oil and gas and other goods used in construction and maintenance activities. Higher costs of these materials are passed on to us by the contractors for these activities. These items affect only cash flows, as the amounts are included as components of net revenue requirement and any higher costs are included in rates under their cost-based Formula Rates.
Interest Rate Risk
Fixed Rate Debt
Based on the borrowing rates currently available for bank loans with similar terms and average maturities, the fair value of our consolidated long-term debt and debt maturing within one year, excluding revolving credit agreements and commercial paper, was $6,995 million and $7,119 million at December 31, 2021 and 2020, respectively. The total book value of our consolidated long-term debt and debt maturing within one year, net of discount and deferred financing fees and excluding revolving credit agreements and commercial paper, was $6,179 million and $6,097 million at December 31, 2021 and 2020, respectively. We performed an analysis calculating the impact of changes in interest rates on the fair value of long-term debt and debt maturing within one year, excluding revolving credit agreements and commercial paper at December 31, 2021 and 2020. An increase in interest rates of 10% (from 5.0% to 5.5%, for example) at December 31, 2021 and 2020 would decrease the fair value of debt by $217 million and $213 million, respectively, and a decrease in interest rates of 10% at December 31, 2021 and 2020 would increase the fair value of debt by $231 million and $227 million, respectively, at that date.
Revolving Credit Agreements
At December 31, 2021 and 2020, we had a consolidated total of $329 million and $198 million, respectively, outstanding under our revolving credit agreements, which are variable rate loans and fair value approximates book value. A 10% increase or decrease in borrowing rates under the revolving credit agreements compared to the weighted average rates in effect at December 31, 2021 and 2020 would increase or decrease interest expense by less than $1 million for an annual period with a constant borrowing level of $329 million and $198 million, respectively.
Commercial Paper
At December 31, 2021 and 2020, ITC Holdings had $155 million and $67 million, respectively, of commercial paper issued and outstanding, net of discount, under the commercial paper program. Due to the short-term nature of these financial instruments, the carrying value approximates fair value. A 10% increase or decrease in interest rates for commercial paper would increase or decrease interest expense by less than $1 million for an annual period with a continuous level of commercial paper outstanding of $155 million and $67 million at December 31, 2021 and 2020, respectively.
Derivative Instruments and Hedging Activities
We use derivative financial instruments, including interest rate swap contracts, to manage our exposure to fluctuations in interest rates. The use of these financial instruments mitigates exposure to these risks and the variability of our operating results. We are not a party to leveraged derivatives and do not enter into derivative financial instruments for trading or speculative purposes.
As of December 31, 2021, we held 5-year interest rate swap contracts with a notional amount of $375 million, which manages interest rate risk associated with the forecasted future issuance of fixed-rate debt at ITC Holdings, the proceeds of which will be used for the expected repayment of the ITC Holdings 2.70% Senior Notes, due November 15, 2022. See Note 9 to the consolidated financial statements for further discussion on these interest rate swaps. At December 31, 2020, ITC Holdings did not have any interest rate swaps outstanding.
Credit Risk
Our credit risk is primarily with DTE Electric, Consumers Energy and IP&L, which were responsible for approximately 21.5%, 23.5% and 24.7%, respectively, or $300 million, $327 million and $344 million, respectively, of our consolidated billed revenues for the year ended December 31, 2021. This portion of total billed revenues of DTE Electric, Consumers Energy and IP&L include the collection of 2019 revenue accruals and deferrals and exclude any amounts for the 2021 revenue accruals and deferrals that were included in our 2021 operating revenues but will not be billed to our customers until 2023.
For the year ended December 31, 2020, our credit risk was primarily with DTE Electric, Consumers Energy and IP&L, which were responsible for approximately 21.6%, 23.9% and 23.9%, respectively, or $265 million, $292 million and $292 million, respectively, of our consolidated billed revenues. These percentages and amounts of total billed revenues of DTE Electric, Consumers Energy and IP&L include the collection of 2018
revenue accruals and deferrals and exclude any amounts for the 2020 revenue accruals and deferrals that were included in our 2020 operating revenues but will not be billed to our customers until 2022.
Refer to “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Cost-Based Formula Rates with True-Up Mechanism” for a discussion on the difference between billed revenues and operating revenues. Under DTE Electric’s and Consumers Energy’s current rate structure, DTE Electric and Consumers Energy include in their retail rates the actual cost of transmission services provided by ITCTransmission and METC, respectively, in their billings to their customers, effectively passing through to end-use consumers the total cost of transmission service. IP&L currently includes in their retail rates an allowance for transmission services provided by ITC Midwest in their billings to their customers. However, any financial difficulties experienced by DTE Electric, Consumers Energy or IP&L may affect their ability to make payments for transmission service to ITCTransmission, METC, and ITC Midwest, which could negatively impact our business. MISO, as our MISO Regulated Operating Subsidiaries’ billing agent, bills DTE Electric, Consumers Energy, IP&L and other customers on a monthly basis and collects fees for the use of the MISO Regulated Operating Subsidiaries’ transmission systems. SPP is the billing agent for ITC Great Plains and bills transmission customers for the use of ITC Great Plains transmission systems. MISO and SPP have implemented strict credit policies for its members’ customers, which include customers using our transmission systems. Specifically, MISO and SPP require a letter of credit or cash deposit equal to the credit exposure, which is determined by a credit scoring model and other factors, from any customer using a member’s transmission system.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
The following financial statements and schedules are included herein:
Page
Management’s Report on Internal Control over Financial Reporting 42
Report of Independent Registered Public Accounting Firm (PCAOB ID No. 34)
Consolidated Statements of Financial Position as of December 31, 2021 and 2020 45
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2021, 2020 and 2019 46
Consolidated Statements of Changes in Stockholder’s Equity for the Years Ended December 31, 2021, 2020 and 2019 47
Consolidated Statements of Cash Flows for the Years Ended December 31, 2021, 2020 and 2019 48
Notes to Consolidated Financial Statements 49
Schedule I - Condensed Financial Information of Registrant 126
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Management is responsible for establishing and maintaining adequate internal control over financial reporting. Our internal control over financial reporting is designed to provide reasonable, not absolute, assurance as to the reliability of our financial reporting and the preparation of consolidated financial statements in accordance with generally accepted accounting principles. Internal control over financial reporting, no matter how well designed, has inherent limitations. Therefore, internal control over financial reporting determined to be effective can provide only reasonable assurance with respect to financial statement preparation and may not prevent or detect all misstatements.
Under management’s supervision, an evaluation of the design and effectiveness of our internal control over financial reporting was conducted based on the criteria set forth in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Our assessment included documenting, evaluating and testing of the design and operating effectiveness of our internal control over financial reporting. Based on this evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2021.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
ITC Holdings Corp.
Novi, Michigan
Opinion on the Financial Statements
We have audited the accompanying consolidated statements of financial position of ITC Holdings Corp. and subsidiaries (the "Company") as of December 31, 2021 and 2020, the related consolidated statements of comprehensive income, shareholders' equity, and cash flows for each of the three years in the period ended December 31, 2021, and the related notes and the schedule listed in the Index at Item 15 (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB and in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Regulatory Matters - Impact of rate regulation on the financial statements - Refer to Notes 2, 5, and 6 to the financial statements
Critical Audit Matter Description
The Company’s regulated operating subsidiaries are subject to rate regulation by the Federal Energy Regulatory Commission (the “regulatory agency”). Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial
statements applying the specialized rules to account for the effects of cost-based rate regulation. The Company’s rates are subject to regulatory rate-setting processes through a formula rate with a true-up mechanism, including an authorized return on equity. Regulatory decisions can have an impact on rates, recovery of certain costs, including the costs of transmission assets and regulatory assets, conditions of service, accounting, financing authorization and operating-related matters, the timely recovery of costs and the return on equity. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures, such as property, plant, and equipment; regulatory assets and liabilities; operating revenues and expenses; and income taxes.
We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the potential impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of recovery of costs incurred or potential refunds to customers. While the Company has indicated they expect to recover costs from customers through regulated rates, there is a risk that the formula inputs remain subject to legal challenge at the regulatory agency. The Company uses the formula to calculate annual revenue requirements unless the regulatory agency determines the resulting rates to be unjust and unreasonable. Auditing these judgments required especially subjective judgment and specialized knowledge of accounting for rate regulation and the rate-setting process due to their inherent complexities.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the regulatory agency included the following, among others:
•We evaluated the effectiveness of controls over the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.
•We assessed relevant regulatory orders, regulatory statutes and interpretations, as well as procedural memorandums, utility and intervener filings, and other publicly available information to evaluate the likelihood of recovery in future rates or of future reduction in rates and the ability to earn a reasonable return on equity.
•For regulatory matters in process, we inspected the annual formula rate filings and open complaints for any evidence that might contradict management’s assertions. We obtained and evaluated an analysis from management, regarding cost recoveries or potential future reduction in rates.
•We evaluated the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
/s/ DELOITTE & TOUCHE LLP
Detroit, Michigan
February 10, 2022
We have served as the Company's auditor since 2001.
ITC HOLDINGS CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF FINANCIAL POSITION
December 31,
(In millions of USD, except share data) 2021 2020
ASSETS
Current assets
Cash and cash equivalents $ 5 $ 4
Accounts receivable 128 114
Inventory 45 42
Regulatory assets 21 52
Prepaid and other current assets 18 12
Total current assets 217 224
Property, plant and equipment (net of accumulated depreciation and amortization of $2,199 and $2,055, respectively)
9,961 9,327
Other assets
Goodwill 950 950
Intangible assets (net of accumulated amortization of $49 and $46, respectively) 26 29
Regulatory assets 190 212
Other assets 101 83
Total other assets 1,267 1,274
TOTAL ASSETS $ 11,445 $ 10,825
LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities
Accounts payable $ 127 $ 130
Accrued compensation 72 55
Accrued interest 56 55
Accrued taxes 64 61
Regulatory liabilities 14 14
Refundable deposits and advances for construction 44 37
Debt maturing within one year 654 67
Other current liabilities 16 18
Total current liabilities 1,047 437
Accrued pension and postretirement liabilities 52 59
Deferred income taxes 1,161 1,013
Regulatory liabilities 619 612
Refundable deposits 28 65
Other liabilities 55 50
Long-term debt 6,009 6,295
Commitments and contingent liabilities (Notes 5 and 17)
TOTAL LIABILITIES 8,971 8,531
STOCKHOLDER’S EQUITY
Common stock, without par value, 235,000,000 shares authorized, 224,203,112 shares issued and outstanding at December 31, 2021 and 2020 892 892
Retained earnings 1,584 1,410
Accumulated other comprehensive loss (2) (8)
Total stockholder’s equity 2,474 2,294
TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY $ 11,445 $ 10,825
See notes to consolidated financial statements.
ITC HOLDINGS CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Year Ended December 31,
(In millions of USD) 2021 2020 2019
OPERATING REVENUES
Transmission and other services $ 1,358 $ 1,290 $ 1,286
Formula Rate true-up (9) 8 41
Total operating revenue 1,349 1,298 1,327
OPERATING EXPENSES
Operation and maintenance 108 87 113
General and administrative 128 115 138
Depreciation and amortization 232 219 203
Taxes other than income taxes 133 124 118
Other operating (income) and expense, net (1) - -
Total operating expenses 600 545 572
OPERATING INCOME 749 753 755
OTHER EXPENSES (INCOME)
Interest expense, net 251 240 224
Allowance for equity funds used during construction (30) (27) (29)
Other (income) and expenses, net (5) (3) -
Total other expenses (income) 216 210 195
INCOME BEFORE INCOME TAXES 533 543 560
INCOME TAX PROVISION 127 136 132
NET INCOME 406 407 428
OTHER COMPREHENSIVE INCOME (LOSS)
Derivative instruments, net of tax (Note 13) 6 (15) 3
TOTAL OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX 6 (15) 3
TOTAL COMPREHENSIVE INCOME $ 412 $ 392 $ 431
See notes to consolidated financial statements.
ITC HOLDINGS CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN
STOCKHOLDER’S EQUITY
Accumulated
Other Total
Retained Comprehensive Stockholder’s
Common Stock Earnings Income (Loss) Equity
(In millions of USD)
BALANCE, DECEMBER 31, 2018 $ 892 $ 1,155 $ 4 $ 2,051
Net income - 428 - 428
Dividends to ITC Investment Holdings
- (250) - (250)
Other comprehensive income, net of tax (Note 13) - - 3 3
BALANCE, DECEMBER 31, 2019 $ 892 $ 1,333 $ 7 $ 2,232
Net income - 407 - 407
Dividends to ITC Investment Holdings - (330) - (330)
Other comprehensive loss, net of tax (Note 13) - - (15) (15)
BALANCE, DECEMBER 31, 2020 $ 892 $ 1,410 $ (8) $ 2,294
Net income - 406 - 406
Dividends to ITC Investment Holdings - (232) - (232)
Other comprehensive income, net of tax (Note 13) - - 6 6
BALANCE, DECEMBER 31, 2021 $ 892 $ 1,584 $ (2) $ 2,474
See notes to consolidated financial statements.
ITC HOLDINGS CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31,
(In millions of USD) 2021 2020 2019
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 406 $ 407 $ 428
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense 232 219 203
Recognition, refund and collection of revenue accruals and deferrals - including accrued interest
52 (47) (55)
Deferred income tax expense 127 138 135
Allowance for equity funds used during construction (30) (27) (29)
Share-based compensation 34 25 32
Other 6 4 10
Changes in assets and liabilities, exclusive of changes shown separately:
Accounts receivable (18) - (10)
Accounts payable (3) 4 (11)
Accrued interest 1 7 (2)
Accrued compensation (3) (14) 10
Accrued taxes 3 (3) 3
Net refund settlements and adjustments related to return on equity complaints (5) (65) (82)
Other current and non-current assets and liabilities, net (17) (16) (3)
Net cash provided by operating activities 785 632 629
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment (834) (885) (865)
Contributions in aid of construction 15 2 10
Other (5) 5 1
Net cash used in investing activities (824) (878) (854)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt 75 1,030 175
Borrowings under revolving credit agreements 1,175 1,495 1,090
Borrowings under term loan credit agreements - 275 200
Net issuance (repayment) of commercial paper 88 (133) 200
Retirement of long-term debt - including extinguishment of debt costs - (35) (203)
Repayments of revolving credit agreements (1,044) (1,596) (999)
Repayments of term loan credit agreements - (475) -
Dividends to ITC Investment Holdings (232) (330) (250)
Refundable deposits from generators for transmission network upgrades 18 60 19
Repayment of refundable deposits from generators for transmission network upgrades
(39) (10) (8)
Settlement of interest rate swaps - (23) -
Other (1) (12) (3)
Net cash provided by financing activities 40 246 221
NET INCREASE (DECREASE) IN CASH, CASH EQUIVALENTS AND RESTRICTED CASH 1 - (4)
CASH, CASH EQUIVALENTS AND RESTRICTED CASH - Beginning of period 6 6 10
CASH, CASH EQUIVALENTS AND RESTRICTED CASH - End of period $ 7 $ 6 $ 6
See notes to consolidated financial statements.
ITC HOLDINGS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. GENERAL
ITC Holdings and its subsidiaries are engaged in the transmission of electricity in the United States. ITC Holdings is a wholly-owned subsidiary of ITC Investment Holdings. Fortis owns a majority indirect equity interest in ITC Investment Holdings, with GIC holding an indirect, passive, non-voting equity interest of 19.9%. Through our Regulated Operating Subsidiaries, we own, operate, maintain and invest in high-voltage electric transmission systems in Michigan’s Lower Peninsula and portions of Iowa, Minnesota, Illinois, Missouri, Kansas, and Oklahoma that transmit electricity from generating stations to local distribution facilities connected to our transmission systems.
Our Regulated Operating Subsidiaries are independent electric transmission utilities, with cost-based rates regulated by the FERC. ITCTransmission’s service area is located in southeastern Michigan, while METC’s service area covers approximately two-thirds of Michigan’s Lower Peninsula and is contiguous with ITCTransmission’s service area. ITC Midwest’s service area is located in portions of Iowa, Minnesota, Illinois and Missouri and ITC Great Plains currently owns assets located in Kansas and Oklahoma. MISO bills and collects revenues from the MISO Regulated Operating Subsidiaries’ customers. SPP bills and collects revenue from ITC Great Plains’ customers. ITC Interconnection currently owns assets in Michigan and earns revenues based on its facilities reimbursement agreement with a merchant generating company.
Recent Developments Regarding the COVID-19 Pandemic
In March 2020, the World Health Organization declared COVID-19 a pandemic. Efforts to control the outbreak of COVID-19 have resulted in challenges to businesses and facilities in various industries around the world, including our customers, and disruptions to the global economy and supply chains. To date, COVID-19 has not had a material impact on our net income. However, for 2020, we utilized various temporary cost saving measures related to operating expenses, including operation and maintenance expenses and general and administrative expenses, in an attempt to reduce costs for our customers that were collected through our Formula Rates.
We are unable to predict the ultimate effects of COVID-19 on the U.S. or global economy or our operations. We continue to monitor developments affecting our workforce, customers, suppliers, and operations. The extent of the impact of COVID-19 will depend on its duration, actions by government authorities, and impacts on our customers, employees, or vendors. These developments are continuously evolving, and we cannot predict whether COVID-19 will have a material impact on our financial condition, results of operations or cash flows.
2. SIGNIFICANT ACCOUNTING POLICIES
A summary of the major accounting policies followed in the preparation of the accompanying consolidated financial statements, which conform to GAAP, is presented below:
Principles of Consolidation - ITC Holdings consolidates its majority owned subsidiaries. We eliminate all intercompany balances and transactions.
Use of Estimates - The preparation of the consolidated financial statements requires us to use estimates and assumptions that impact the reported amounts of assets, liabilities, revenues and expenses, and the disclosure of contingent assets and liabilities. Actual results may differ from our estimates.
Regulation - Our Regulated Operating Subsidiaries are subject to the regulatory jurisdiction of the FERC, which issues orders pertaining to rates, recovery of certain costs, including the costs of transmission assets and regulatory assets, conditions of service, accounting, financing authorization and operating-related matters. The utility operations of our Regulated Operating Subsidiaries meet the accounting standards set forth by the FASB for the accounting effects of certain types of regulation. These accounting standards recognize the cost-based rate setting process, which results in differences in the application of GAAP between regulated and non-regulated businesses. These standards require the recording of regulatory assets and liabilities for certain transactions that would have been recorded as revenue and expense in non-regulated businesses. Regulatory assets represent costs that will be
included as a component of future tariff rates and regulatory liabilities represent amounts provided in the current tariff rates that are intended to recover costs expected to be incurred in the future or amounts to be refunded to customers.
Cash and Cash Equivalents - We consider all unrestricted highly-liquid temporary investments with an original maturity of three months or less at the date of purchase to be cash equivalents.
Restricted Cash and Restricted Cash Equivalents - Restricted cash and restricted cash equivalents include cash and cash equivalents that are legally or contractually restricted for use or withdrawal or are formally set aside for a specific purpose.
Accounts Receivable Reserve - We recognize losses for uncollectible accounts based on the current expected credit loss model. As of December 31, 2021, 2020 and 2019 we did not have an accounts receivable reserve.
Inventories - Materials and supplies inventories are valued at average cost. Additionally, the costs of warehousing activities are recorded here and included in the cost of materials when requisitioned.
Property, Plant and Equipment - Depreciation and amortization expense on property, plant and equipment was $223 million, $209 million and $194 million for 2021, 2020 and 2019, respectively.
Property, plant and equipment in service at our Regulated Operating Subsidiaries is stated at its original cost when first devoted to utility service. The gross book value of assets retired less salvage proceeds is charged to accumulated depreciation. The provision for depreciation of transmission assets is a significant component of our Regulated Operating Subsidiaries’ cost of service under FERC-approved rates. Periodically we perform depreciation studies of the assets at our Regulated Operating Subsidiaries. The results of these studies are submitted to, and require approval from the FERC prior to changing our depreciation rates. Depreciation is computed over the estimated useful lives of the assets using the straight-line method for financial reporting purposes and accelerated methods for income tax reporting purposes. The composite depreciation rate for our Regulated Operating Subsidiaries included in our consolidated statements of comprehensive income was 2.0% for 2021, 2020 and 2019. The composite depreciation rates include depreciation primarily on transmission station equipment, towers, poles and overhead and underground lines that have a useful life ranging from 45 to 60 years. The portion of depreciation expense related to asset removal costs is added to regulatory liabilities or deducted from regulatory assets and removal costs incurred are deducted from regulatory liabilities or added to regulatory assets. Certain of our Regulated Operating Subsidiaries capitalize to property, plant and equipment AFUDC in accordance with FERC regulations. AFUDC represents the composite cost incurred to fund the construction of assets, including interest expense and a return on equity capital devoted to construction of assets. The interest component of AFUDC was a reduction to interest expense of $8 million, $7 million and $8 million for 2021, 2020 and 2019, respectively.
For acquisitions of property, plant and equipment greater than the net book value (other than asset acquisitions accounted for under the purchase method of accounting that result in goodwill), the acquisition premium is recorded to property, plant and equipment and amortized over the estimated remaining useful lives of the assets using the straight-line method for financial reporting purposes and accelerated methods for income tax reporting purposes.
Property, plant and equipment includes capital equipment inventory stated at original cost consisting of items that are expected to be used exclusively for capital projects.
Property, plant and equipment at our non-regulated subsidiaries is stated at its acquired cost. Proceeds from salvage less the net book value of the disposed assets is recognized as a gain or loss on disposal. Depreciation is computed based on the acquired cost less expected residual value and is recognized over the estimated useful lives of the assets on a straight-line method for financial reporting purposes and accelerated methods for income tax reporting purposes.
Generator Interconnection Projects and Contributions in Aid of Construction - Certain capital investment at our Regulated Operating Subsidiaries relates to investments made under GIAs. The GIAs typically consist of both transmission network upgrades, which are a category of upgrades deemed by the FERC to benefit the transmission system as a whole, as well as direct connection facilities, which are necessary to interconnect the generating facility to the transmission system and primarily benefit the
generating facility. As a result, GIAs typically require the generator to make a contribution in aid of construction to our Regulated Operating Subsidiaries to cover the cost of certain investments made by us as part of the agreement.
Our investments in transmission facilities are recorded to property, plant and equipment, and are recorded net of any contribution in aid of construction. We also receive refundable deposits from the generator for certain investment in network upgrade facilities in advance of construction, which are recorded to current or non-current liabilities depending on the expected refund date.
Jointly Owned Utility Plant/Coordinated Services - Certain of our Regulated Operating Subsidiaries have agreements with other utilities for the joint ownership of substation assets and transmission lines as described in Note 15. We account for these jointly owned assets by recording property, plant and equipment for the percentage of our undivided ownership interest. Various agreements provide the authority for construction of capital improvements and the operating costs associated with the substations and lines. Generally, each party is responsible for the capital, operation and maintenance and other costs of these jointly owned facilities based upon each participant’s undivided ownership interest, and each participant is responsible for providing its own financing. Our participating share of expenses associated with these jointly held assets are primarily recorded within operation and maintenance expenses on our consolidated statements of comprehensive income.
Fair Value Through Net Income - We have certain investments in mutual funds, including fixed income securities and equity securities that are classified as fair value through net income. The fixed income security investments primarily fund our two supplemental nonqualified, noncontributory, retirement benefit plans for selected management employees as described in Note 11. Gains and losses associated with our mutual funds as described in Note 12 are recorded in earnings.
Impairment of Long-Lived Assets - Other than goodwill, our long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate the carrying amount of an asset may not be recoverable. If the carrying amount of the asset exceeds the expected undiscounted future cash flows generated by the asset, the asset is written down to its estimated fair value and an impairment loss is recognized in our consolidated statements of comprehensive income.
Goodwill and Other Intangible Assets - Goodwill is not subject to amortization; however, goodwill is required to be assessed for impairment, and a resulting write-down, if any, is to be reflected in operating expense. We have goodwill recorded relating to our acquisitions of ITCTransmission and METC, and ITC Midwest’s acquisition of the IP&L transmission assets. Goodwill is reviewed at the reporting unit level at least annually for impairment and whenever facts or circumstances indicate that the value of goodwill may be impaired. Our reporting units are ITCTransmission, METC and ITC Midwest as each entity represents an individual operating segment to which goodwill has been assigned. At December 31, 2021 and 2020, we had goodwill balances recorded at ITCTransmission, METC and ITC Midwest of $173 million, $454 million and $323 million, respectively.
In order to perform an impairment analysis, we have the option of performing a qualitative assessment to determine whether the existence of events or circumstances leads to a determination that it is more likely than not that the fair value of a reporting unit is greater than its carrying amount, in which case no further testing is required. If an entity bypasses the qualitative assessment or performs a qualitative assessment but determines that it is more likely than not that a reporting unit’s fair value is less than its carrying amount, a quantitative, fair value-based test is performed to assess and measure goodwill impairment, if any. If a quantitative assessment is performed, we determine the fair value of our reporting units using valuation techniques based on discounted future cash flows under various scenarios and consider estimates of market-based valuation multiples for companies within the peer group of our reporting units.
We completed our annual goodwill impairment test for our reporting units as of October 1, 2021 and determined that no impairment exists. There were no events subsequent to October 1, 2021 that indicated impairment of our goodwill. Our intangible assets other than goodwill have finite lives and are amortized over their useful lives. Refer to Note 8 for additional discussion on our intangible assets.
Deferred Financing Fees and Discount or Premium on Debt - Costs related to the issuance of long-term debt are generally recorded as a direct deduction from the carrying amount of the related debt and
amortized over the life of the debt. Debt issuance costs incurred prior to the associated debt funding are presented as an asset. Unamortized debt issuance costs associated with the revolving credit agreements, commercial paper and other similar arrangements are presented as an asset (regardless of whether there are any amounts outstanding under those credit facilities) and amortized over the life of the particular arrangement. The debt discount or premium related to the issuance of long-term debt is recorded to long-term debt and amortized over the life of the debt. We recorded $5 million during the years ended December 31, 2021, 2020 and 2019 to interest expense for the amortization of deferred financing fees and debt discounts.
Asset Retirement Obligations - A conditional asset retirement obligation is a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within our control. We have identified conditional asset retirement obligations primarily associated with the removal of equipment containing PCBs and asbestos. We record a liability at fair value for a legal asset retirement obligation in the period in which it is incurred. When a new legal obligation is recorded, we capitalize the costs of the liability by increasing the carrying amount of the related long-lived asset. We accrete the liability to its present value each period and depreciate the capitalized cost over the useful life of the related asset. At the end of the asset’s useful life, we settle the obligation for its recorded amount. We recognize regulatory assets for the timing differences between the incurred costs to settle our legal asset retirement obligations and the recognition of such obligations as applicable for our Regulated Operating Subsidiaries. Our asset retirement obligations as of December 31, 2021 and 2020 of $6 million are included in other liabilities.
Derivatives and Hedging - We may use derivative financial instruments, including interest rate swap contracts, to manage our exposure to fluctuations in interest rates. For derivative instruments that have been designated and qualify as cash flow hedges of the exposure to variability in expected future cash flows, the unrealized gain or loss on the derivative is initially reported, net of tax, as a component of other comprehensive income (loss) and reclassified to the consolidated statements of comprehensive income when the underlying hedged transaction affects net income. Cash flows related to interest rate swaps that are designated in hedging relationships are generally classified on the consolidated statements of cash flows within cash flows from financing activities. The fair values of derivatives are recognized as current or long-term assets and liabilities depending on the timing of settlements and resulting cash flows. Refer to Note 9 for additional discussion regarding derivative instruments.
Contingent Obligations - We are subject to a number of federal and state laws and regulations, as well as other factors and conditions that potentially subject us to environmental, litigation, income tax and other contingencies. We periodically evaluate our exposure to such contingencies and record liabilities for those matters where a loss is considered probable and reasonably estimable. We reverse the liabilities recorded for those matters when a loss is no longer considered probable or the liabilities are otherwise settled. Our liabilities exclude any estimates for legal costs not yet incurred associated with handling these matters, which could be material. The adequacy of liabilities recorded can be significantly affected by external events or conditions that can be unpredictable; thus, the ultimate outcome of such matters could materially affect our consolidated financial statements.
Revenues - Substantially all of our revenue from contracts with customers is generated from providing transmission services to customers based on tariff rates, as approved by the FERC. Revenues from the transmission of electricity are recognized as services are provided based on our FERC-approved cost-based Formula Rates. We record a reserve for revenue subject to refund when such refund is probable and can be reasonably estimated. This reserve is recorded as a reduction to operating revenues.
The cost-based Formula Rates at our Regulated Operating Subsidiaries include a true-up mechanism that compares the actual revenue requirements of our Regulated Operating Subsidiaries to their billed revenues for each year to determine any over- or under-collection of revenue requirements and we record a revenue deferral or accrual for the difference. The true-up mechanisms under our Formula Rates are considered alternative revenue programs of rate-regulated utilities. Operating revenues arising from these alternative revenue programs are presented on our consolidated statements of comprehensive income in the line “Formula Rate true-up”, which is separate from the reporting of our tariff revenues, which are presented in the line “Transmission and other services.” Only the initial origination of our alternative
revenue program revenue is reported in the Formula Rate true-up line on our consolidated statements of comprehensive income. When those amounts are subsequently included in the price of utility service and billed or refunded to customers, we account for that event as the recovery or settlement of the associated regulatory asset or regulatory liability, respectively. Refer to Note 5 under “Cost-Based Formula Rates with True-Up Mechanism” and Note 3 under “Formula Rate True-Up” for a discussion of our revenue accounting under our cost-based Formula Rates.
Share-Based Payment and Employee Share Purchase Plan - Under our long-term incentive plans, we grant long-term incentive awards consisting of PBUs and SBUs. Generally, each PBU and SBU granted is valued based on one share of Fortis common stock traded on the Toronto Stock Exchange, converted to U.S. dollars and settled only in cash. However, certain SBUs granted to the executives may settle in cash, 100% Fortis common stock, or 50% cash and 50% Fortis common stock depending on executives’ settlement elections and whether certain share ownership requirements are met. The awards are classified as liability awards and vest on the date specified in the applicable grant agreements, provided the service and performance criteria, as applicable, are satisfied. The PBUs and SBUs earn dividend equivalents which are also re-measured and settled consistent with the target award at the end of the vesting period.
Compensation cost is recognized over the expected vesting period and remeasured each reporting period based on Fortis’ stock price. The PBUs are also remeasured each reporting period based on the applicable market and performance conditions in the awards. Compensation cost is adjusted for forfeitures in the period in which they occur and the final measure of compensation cost for the awards is based on the cash settlement amount.
Refer to Note 14 for additional discussion of the plans.
Comprehensive Income (Loss) - Comprehensive income (loss) is the change in stockholder’s equity during a period arising from transactions and events from non-owner sources, including net income and any gain or loss arising from our interest rate swaps.
Income Taxes - Deferred income taxes are recognized for the expected future tax consequences of events that have been recognized in the consolidated financial statements or tax returns. Deferred income tax assets and liabilities are determined based on the differences between the financial statements and the tax bases of various assets and liabilities, using the tax rates expected to be in effect for the year in which the differences are expected to reverse, and classified as non-current in our consolidated statements of financial position.
The accounting standards for uncertainty in income taxes prescribe a recognition threshold and a measurement attribute for tax positions taken, or expected to be taken, in a tax return that may not be sustainable. As of December 31, 2021, we have not recognized any uncertain income tax positions.
We file our federal and Michigan income tax returns as part of the FortisUS consolidated tax returns and we are a party to an intercompany tax sharing agreement that establishes the method for determining tax liabilities that are due and allocating tax attributes that are utilized on the consolidated income tax returns. We continue to file with various other state and city jurisdictions where we have a separate return filing obligation. Our prior consolidated federal tax returns are no longer subject to U.S. federal tax examinations for tax years 2017 and earlier. State and city jurisdictions that remain subject to examination range from tax years 2017 to 2020. In the event we are assessed interest or penalties by any income tax jurisdictions, interest and penalties would be recorded as interest expense and other expense, respectively, in our consolidated statements of comprehensive income. Refer to Notes 6 and 10 for additional discussion on income taxes.
3. REVENUE
Our total revenues are comprised of revenues which arise from three classifications including transmission services, other services, and Formula Rate true-up. As other services revenue is immaterial, it is presented in combination with transmission services on the consolidated statements of comprehensive income.
Transmission Services
Through our Regulated Operating Subsidiaries, we generate nearly all our revenue from providing electric transmission services over our transmission systems. As independent transmission companies, our transmission services are provided and revenues are received based on our tariffs, as approved by the FERC. The transmission revenue requirements at our Regulated Operating Subsidiaries are set annually using Formula Rates and remain in effect for a one-year period. By updating the inputs to the formula and resulting rates on an annual basis, the revenues at our Regulated Operating Subsidiaries reflect changing operational data and financial performance, including the amount of network load on their transmission systems (for our MISO Regulated Operating Subsidiaries), operating expenses and additions to property, plant and equipment when placed in service, among other items.
We recognize revenue for transmission services over time as transmission services are provided to customers (generally using an output measure of progress based on transmission load delivered). Customers simultaneously receive and consume the benefits provided by the Regulated Operating Subsidiaries’ services. We recognize revenue in the amount to which we have the right to invoice because we have a right to consideration in an amount that corresponds directly with the value to the customer of performance completed to date. As billing agents, MISO and SPP independently bill our customers on a monthly basis and collects fees for the use of our transmission systems. No component of the transaction price is allocated to unsatisfied performance obligations.
Transmission service revenue includes an estimate for unbilled revenues from service that has been provided but not billed by the end of an accounting period. Unbilled revenues are dependent upon a number of factors that require management’s judgment including estimates of transmission network load (for the MISO Regulated Operating Subsidiaries) and preliminary information provided by billing agents. Due to the seasonal fluctuations of actual load, the unbilled revenue amount generally increases during the spring and summer and decreases during the fall and winter. See Note 4 for information on changes in unbilled accounts receivable.
Other Services
Other services revenue consists of rental revenues, easement revenues, and amounts from providing ancillary services. A portion of other services revenue is treated as a revenue credit and reduces gross revenue requirement when calculating net revenue requirement under our Formula Rates. Total other services revenue was $6 million, $5 million and $7 million for the years ended December 31, 2021, 2020 and 2019, respectively.
Formula Rate True-Up
The true-up mechanism under our Formula Rates is considered an alternative revenue program of a rate-regulated utility given it permits our Regulated Operating Subsidiaries to adjust future rates in response to past activities or completed events in order to collect our actual revenue requirements under our Formula Rates. In accordance with our accounting policy, only the current year origination of the true-up is reported as a Formula Rate true-up. See “Cost-Based Formula Rates with True-Up Mechanism” in Note 5 for more information on our Formula Rates.
4. ACCOUNTS RECEIVABLE
The following table presents the components of accounts receivable on the consolidated statements of financial position:
December 31,
(In millions of USD) 2021 2020 2019 2018
Trade accounts receivable $ 3 $ 2 $ 2 $ 2
Unbilled accounts receivable 116 102 102 92
Other 9 10 13 8
Total accounts receivable $ 128 $ 114 $ 117 $ 102
5. REGULATORY MATTERS
Cost-Based Formula Rates with True-Up Mechanism
The transmission revenue requirements at our Regulated Operating Subsidiaries are set annually using Formula Rates and remain in effect for a one-year period. By updating the inputs to the formula and resulting rates on an annual basis, the revenues at our Regulated Operating Subsidiaries reflect changing operational data and financial performance, including the amount of network load on their transmission systems (for our MISO Regulated Operating Subsidiaries), operating expenses and additions to property, plant and equipment when placed in service, among other items. The formula used to derive the rates does not require further action or FERC filings each year, although the formula inputs remain subject to legal challenge at the FERC. Our Regulated Operating Subsidiaries will continue to use the formula to calculate their respective annual revenue requirements unless the FERC determines the resulting rates to be unjust and unreasonable and another mechanism is determined by the FERC to be just and reasonable. See “Rate of Return on Equity Complaints” in Note 17 for detail on ROE matters for our MISO Regulated Operating Subsidiaries and "Incentive Adders for Transmission Rates" discussed herein.
The cost-based Formula Rates at our Regulated Operating Subsidiaries include a true-up mechanism that compares the actual revenue requirements of our Regulated Operating Subsidiaries to their billed revenues for each year to determine any over- or under-collection of revenue requirements. Revenue is recognized for services provided during each reporting period based on actual revenue requirements calculated using the formula. Our Regulated Operating Subsidiaries accrue or defer revenues to the extent that the actual revenue requirement for the reporting period is higher or lower, respectively, than the amounts billed relating to that reporting period. The amount of accrued or deferred revenues is reflected in future revenue requirements and thus flows through to customer bills within two years under the provisions of our Formula Rates.
The net changes in regulatory assets and liabilities associated with our Regulated Operating Subsidiaries’ Formula Rate revenue accruals and deferrals, including accrued interest, were as follows during the year ended December 31, 2021:
(In millions of USD) Total
Net regulatory assets as of December 31, 2020 $ 50
Net collection of 2019 revenue deferrals and accruals, including accrued interest (43)
Net revenue deferral for the year ended December 31, 2021 (9)
Net regulatory liabilities as of December 31, 2021 $ (2)
Regulatory assets and liabilities associated with our Regulated Operating Subsidiaries’ Formula Rate revenue accruals and deferrals, including accrued interest, are recorded in the consolidated statements of financial position as follows:
December 31,
(In millions of USD) 2021 2020
Current regulatory assets $ 20 $ 44
Non-current regulatory assets 10 19
Current regulatory liabilities (13) (1)
Non-current regulatory liabilities (19) (12)
Net regulatory (liabilities) assets $ (2) $ 50
Incentive Adders for Transmission Rates
The FERC has authorized the use of ROE incentives, or adders, that can be applied to the rates of TOs when certain conditions are met. Our MISO Regulated Operating Subsidiaries and ITC Great Plains utilize ROE adders related to independent transmission ownership and RTO participation. On March 20, 2020, the FERC issued a NOPR and on April 15, 2021, the FERC issued a supplemental NOPR that was a proposal to update the transmission incentives policy. As of December 31, 2021, no final determination had been made on these NOPRs and we cannot predict whether this will have a material impact on us.
MISO Regulated Operating Subsidiaries
On April 20, 2018, Consumers Energy, IP&L, Midwest Municipal Transmission Group, Missouri River Energy Services, Southern Minnesota Municipal Power Agency and WPPI Energy filed a complaint with the FERC under section 206 of the FPA, challenging the adders for independent transmission ownership that are included in transmission rates charged by the MISO Regulated Operating Subsidiaries. At the time of the complaint, the adders for independent transmission ownership allowed up to 50 basis points or 100 basis points to be added to the MISO Regulated Operating Subsidiaries’ authorized ROE, subject to any ROE cap established by the FERC. On October 18, 2018, the FERC issued an order granting the complaint in part, setting revised adders for independent transmission ownership for each of the MISO Regulated Operating Subsidiaries to 25 basis points, and requiring the MISO Regulated Operating Subsidiaries to include the revised adders, effective April 20, 2018, in their Formula Rates. On September 11, 2019, the MISO Regulated Operating Subsidiaries filed an appeal of the FERC’s order in the D.C. Circuit Court and on February 19, 2021, the appeal was denied. As a result, the FERC’s October 18, 2018 order was upheld without further impact on our financial condition, consolidated results of operations or cash flows.
For each of the years ended December 31, 2021, 2020 and 2019, the authorized incentive adders for the MISO Regulated Operating Subsidiaries included a 25 basis point adder for independent transmission ownership and a 50 basis point adder for RTO participation. See Note 17 for information regarding the MISO ROE Complaints and the associated impact to the base ROE of our MISO Regulated Operating Subsidiaries.
ITC Great Plains
On June 11, 2019, KCC filed a complaint with the FERC under section 206 of the FPA, challenging the adder for independent transmission ownership that is included in the transmission rate charged by ITC Great Plains. The adder for independent transmission ownership allowed up to 100 basis points to be added to the ITC Great Plains authorized ROE, subject to any ROE cap established by the FERC. On July 16, 2020, the FERC issued an order granting the complaint, setting the revised adder for independent transmission ownership for ITC Great Plains to 25 basis points, and requiring ITC Great Plains to include the revised adder, effective June 11, 2019, in their Formula Rate. In addition, the order directed ITC Great Plains to provide refunds, with interest, for the period from June 11, 2019 through July 16, 2020. During the fourth quarter of 2020, refunds of $4 million were made to settle the refund liability. ITC Great Plains filed appeals in the D.C. Circuit Court for the various FERC orders in the proceedings for ITC Great Plains. On March 4, 2021, these appeals were dismissed following a motion for voluntary dismissal by ITC Great Plains in response to the denial of the appeal of the FERC’s order to reduce the adder for independent transmission ownership for each of the MISO Regulated Operating Subsidiaries. The dismissal of the appeals did not result in additional impacts to our consolidated results of operations, cash flows or financial condition.
Prior to the issuance of the FERC order on July 16, 2020, the authorized ROE used by ITC Great Plains was 12.16% and was composed of a base ROE of 10.66% with a 100 basis point adder for independent transmission ownership and a 50 basis point adder for RTO participation. Based on the July 16, 2020 order, the authorized ROE used by ITC Great Plains was revised to 11.41% and is currently composed of a base ROE of 10.66% with a 25 basis point adder for independent transmission ownership and a 50 basis point adder for RTO participation.
Rate of Return on Equity Complaints
See “Rate of Return on Equity Complaints” in Note 17 for a discussion of the MISO ROE Complaints.
6. REGULATORY ASSETS AND LIABILITIES
Regulatory Assets
The following table summarizes the regulatory asset balances:
December 31,
(In millions of USD) 2021 2020
Regulatory Assets:
Current:
Revenue accruals (including accrued interest of less than $1 and $2 as of December 31, 2021 and 2020, respectively) (a) $ 20 $ 44
Amounts recoverable related to the Initial Complaint (including accrued interest of less than $1 and $2 as of December 31, 2021 and 2020, respectively) (b) 1 8
Total current 21 52
Non-current:
Revenue accruals (including accrued interest of less than $1 as of December 31, 2021 and 2020) (a) 10 19
ITCTransmission ADIT deferral (net of accumulated amortization of $57 and $54 as of December 31, 2021 and 2020, respectively) 4 7
METC ADIT deferral (net of accumulated amortization of $35 and $33 as of December 31, 2021 and 2020, respectively) 8 10
METC regulatory deferrals (net of accumulated amortization of $12 and $11 as of December 31, 2021 and 2020, respectively) 3 4
Income taxes recoverable related to AFUDC equity 114 106
ITC Great Plains start-up, development and pre-construction (net of accumulated amortization of $9 and $7 as of December 31, 2021 and 2020, respectively) 4 6
Pensions and postretirement 20 30
Income taxes recoverable related to implementation of the Michigan Corporate Income Tax 6 6
Accrued asset removal costs 21 24
Total non-current 190 212
Total $ 211 $ 264
____________________________
(a)Refer to discussion of revenue accruals in Note 5 under “Cost-Based Formula Rates with True-Up Mechanism.” Our Regulated Operating Subsidiaries do not earn a return on the balance of these regulatory assets, but do accrue interest carrying costs, which are subject to rate recovery along with the principal amount of the revenue accrual.
(b)Refer to discussion of the refund in Note 17 under “Rate of Return on Equity Complaints.”
ITCTransmission ADIT Deferral
The carrying amount of the ITCTransmission ADIT Deferral is the remaining unamortized balance of the portion of ITCTransmission’s purchase price in excess of fair value of net assets acquired from DTE Energy approved for inclusion in future rates by the FERC. The original amount recorded for this regulatory asset of $61 million is recognized in rates and amortized on a straight-line basis over 20 years beginning March 1, 2003. ITCTransmission includes the remaining unamortized balance of this regulatory asset in rate base. ITCTransmission recorded amortization expense of $3 million annually during 2021, 2020 and 2019, which is included in depreciation and amortization in our consolidated statements of comprehensive income and recovered through ITCTransmission’s cost-based Formula Rate template.
METC ADIT Deferral
The carrying amount of the METC ADIT Deferral is the remaining unamortized balance of the portion of METC’s purchase price in excess of the fair value of net assets acquired at the time MTH acquired METC from
Consumers Energy approved for inclusion in future rates by the FERC. The original amount approved for recovery recorded for this regulatory asset of $43 million is recognized in rates and amortized on a straight-line basis over 18 years beginning January 1, 2007. METC includes the remaining unamortized balance of this regulatory asset in rate base. METC recorded amortization expense of $2 million annually during 2021, 2020 and 2019, which is included in depreciation and amortization in our consolidated statements of comprehensive income and recovered through METC’s cost-based Formula Rate template.
METC Regulatory Deferrals
The carrying amount of the METC Regulatory Deferrals is the amount METC has deferred, as a regulatory asset, of depreciation and related interest expense associated with new transmission assets placed in service from January 1, 2001 through December 31, 2005 that were included on METC’s balance sheet at the time MTH acquired METC from Consumers Energy. The original amount recorded for this regulatory asset of $15 million, and approved for inclusion in future rates by the FERC, is recognized in rates and amortized over 20 years beginning January 1, 2007. METC includes the remaining unamortized balance of this regulatory asset in rate base. METC recorded amortization expense of $1 million annually during 2021, 2020 and 2019, which is included in depreciation and amortization in our consolidated statements of comprehensive income and recovered through METC’s cost-based Formula Rate template.
Income Taxes Recoverable Related to AFUDC Equity
Accounting standards for income taxes provide that a regulatory asset be recorded if it is probable that a future increase in taxes payable, relating to the book depreciation of AFUDC equity that has been capitalized to property, plant and equipment, will be recovered from customers through future rates. The regulatory asset for the tax effects of AFUDC equity is recovered over the life of the underlying book asset in a manner that is consistent with the depreciation of the AFUDC equity that has been capitalized to property, plant and equipment. This regulatory asset and the related offsetting deferred income tax liabilities do not affect rate base.
ITC Great Plains Start-Up, Development and Pre-Construction
In 2013, ITC Great Plains made a filing with the FERC, under Section 205 of the FPA, to recover start-up, development and pre-construction expenses in future rates. These expenses included certain costs incurred by ITC Great Plains for two regional cost sharing projects in Kansas prior to construction. In March 2015, the FERC accepted ITC Great Plains’ request to commence amortization of the authorized regulatory assets, subject to refund. In December 2015, the FERC issued an order accepting an uncontested settlement agreement establishing the amounts of the regulatory assets and associated carrying charges to be recovered. ITC Great Plains includes the unamortized balance of these regulatory assets in rate base and amortizes them over a 10-year period, that began in the second quarter of 2015. The amortization expense is recorded to general and administrative expenses in our consolidated statements of comprehensive income and is recovered through ITC Great Plains’ cost-based Formula Rate.
Pensions and Postretirement
Accounting standards for defined benefit pension and other postretirement plans for rate-regulated entities allow for amounts that otherwise would have been charged to AOCI to be recorded as a regulatory asset. As the unrecognized amounts recorded to this regulatory asset are recognized, expenses will be recovered from customers in future rates under our cost-based Formula Rates. This regulatory asset is not included when determining rate base.
Income Taxes Recoverable Related to Implementation of the Michigan Corporate Income Tax
Under the Michigan Corporate Income Tax, we are taxed at a rate of 6.0% on federal taxable income attributable to our operations in the state of Michigan, subject to certain adjustments. In 2011, due to certain Michigan tax law changes we were required to establish new deferred income tax balances under the Michigan Corporate Income Tax, and the net result was incremental deferred state income tax liabilities at both ITCTransmission and METC. Under our cost-based Formula Rate, the future tax receivable as a result of the tax law change has resulted in the recognition of a regulatory asset, which will be collected from customers for the 23-year period and the 32-year period for ITCTransmission and METC, respectively, beginning in 2016. ITCTransmission and METC include this regulatory asset within deferred taxes for rate-making purposes when determining rate base.
Accrued Asset Removal Costs
The carrying amount of the accrued asset removal costs represents the difference between incurred costs to remove property, plant and equipment and the estimated removal costs included and collected in rates. The portion of depreciation expense included in our depreciation rates related to asset removal costs reduces this regulatory asset and removal costs incurred are added to this regulatory asset. In addition, this regulatory asset has also been adjusted for timing differences between incurred costs to settle legal asset retirement obligations and the recognition of such obligations under the standards set forth by the FASB. Our Regulated Operating Subsidiaries include this item, excluding the cost component related to the recognition of our legal asset retirement obligations under the standards set forth by the FASB, as a reduction to accumulated depreciation for rate-making purposes, when determining rate base.
Regulatory Liabilities
The following table summarizes the regulatory liability balances:
December 31,
(In millions of USD) 2021 2020
Regulatory Liabilities:
Current:
Revenue deferrals (including accrued interest of $1 and less than $1 as of December 31, 2021 and 2020, respectively) (a) $ 13 $ 1
Refund related to the Initial Complaint (including accrued interest of $1 as of December 31, 2020) (b) - 13
Other 1 -
Total current 14 14
Non-current:
Revenue deferrals (including accrued interest of less than $1 as of December 31, 2021 and 2020) (a) 19 12
Accrued asset removal costs 70 73
Excess state income tax deductions 3 3
Income taxes refundable related to implementation of the TCJA 495 507
Pensions and postretirement 31 16
Other 1 1
Total non-current 619 612
Total $ 633 $ 626
____________________________
(a)Refer to discussion of revenue deferrals in Note 5 under “Cost-Based Formula Rates with True-Up Mechanism.” Our Regulated Operating Subsidiaries accrue interest on the true-up amounts which will be refunded through rates along with the principal amount of revenue deferrals in future periods.
(b)Refer to discussion of the refund in Note 17 under “Rate of Return on Equity Complaints.”
Accrued Asset Removal Costs
The carrying amount of the accrued asset removal costs represents the difference between incurred costs to remove property, plant and equipment and the estimated removal costs included and collected in rates. The portion of depreciation expense included in our depreciation rates related to asset removal costs is added to this regulatory liability and removal expenditures incurred are charged to this regulatory liability. Our Regulated Operating Subsidiaries include this item within accumulated depreciation for rate-making purposes and determining rate base.
Excess State Income Tax Deductions
Our Regulated Operating Subsidiaries have taken state income tax deductions associated with property additions that exceed the tax basis of property, and the unrealized income tax benefits resulting from these
deductions are expected to be refunded to customers through future rates when the income tax benefits are realized. This regulatory liability is included within deferred taxes for rate-making purposes when determining rate base.
Income Taxes Refundable Related to Implementation of the TCJA
Under the TCJA, we were required to revalue our deferred tax assets and liabilities at the new federal corporate income tax rate as of the date of the enactment of the TCJA, which resulted in lower net deferred tax liabilities and the establishment of a net regulatory liability for excess deferred taxes at our Regulated Operating Subsidiaries. For our Regulated Operating Subsidiaries, our deferred taxes are subject to a normalization method of accounting for the excess tax reserves resulting from the change in the federal statutory tax rate which requires the use of either the ARAM or the alternative method, RSGM, for assets related to public utility property. Prior to 2021, the ARAM method was used for the return of excess deferred taxes to customers associated with public utility property. Beginning in 2021, we began using RSGM for the return of all remaining categories of excess deferred taxes to customers, pursuant to the interpretation of recent released revenue procedures and private letter rulings. During the years ended December 31, 2021 and 2020, we recorded $8 million and $2 million, respectively, of amortization related to the excess deferred taxes under RSGM and ARAM. The net regulatory liability is included within deferred taxes for rate-making purposes when determining rate base.
Pensions and Postretirement
Accounting standards for defined benefit pension and other postretirement plans for rate-regulated entities allow for amounts that otherwise would have been credited to AOCI to be recorded as a regulatory liability. As the unrecognized amounts recorded to this regulatory liability are recognized, amounts will be returned to customers in future rates under our cost-based Formula Rates. This regulatory liability is not included when determining rate base.
7. PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment - net consisted of the following:
December 31,
(In millions of USD) 2021 2020
Property, plant and equipment
Regulated Operating Subsidiaries:
Property, plant and equipment in service $ 11,434 $ 10,661
Construction work in progress 529 523
Capital equipment inventory 96 103
Other 87 81
ITC Holdings and other 14 14
Total 12,160 11,382
Less: Accumulated depreciation and amortization (2,199) (2,055)
Property, plant and equipment, net $ 9,961 $ 9,327
Additions to property, plant and equipment in-service and construction work in progress during 2021 and 2020 were due primarily to projects to upgrade or replace existing transmission plant and update grid security to improve the reliability of our transmission systems as well as transmission infrastructure to support generator interconnections and investments that provide regional benefits such as our MVPs. Additionally, in 2020, we made asset acquisitions which added to our in-service property, plant and equipment.
8. INTANGIBLE ASSETS
METC has recorded intangible assets with finite lives derived from the portion of regulatory assets recorded on METC’s historical FERC financial statements that were not recorded on METC’s historical GAAP financial statements. These intangible assets are associated with the METC Regulatory Deferrals and the METC ADIT Deferral as described in Note 6. The carrying amounts of the intangible asset for the METC Regulatory Deferrals and the METC ADIT Deferral were $10 million and $3 million (net of accumulated amortization of $30 million and $16 million), respectively, as of December 31, 2021, and $12 million and $4 million (net of accumulated amortization of $28 million and $15 million), respectively, as of December 31, 2020. The amortization periods for the METC Regulatory Deferrals and the METC ADIT Deferral are 20 and 18 years, respectively, beginning January 1, 2007. METC earns an equity return on the remaining unamortized balance of both intangible assets and recovers the amortization expense through METC’s cost-based Formula Rate template.
ITC Great Plains has recorded intangible assets for payments made by and obligations of ITC Great Plains to certain TOs to acquire rights, which are required under the SPP tariff to designate ITC Great Plains to build, own and operate projects within the SPP region, including three regional cost sharing projects in Kansas. The carrying amount of these intangible assets was $13 million (net of accumulated amortization of $3 million) as of both December 31, 2021 and 2020. The amortization period for these intangible assets is 50 years, beginning March 31, 2011.
We recognized $3 million, $4 million, and $3 million of amortization expense for our intangible assets during the years ended December 31, 2021, 2020 and 2019, respectively, recorded in depreciation and amortization on the consolidated statements of comprehensive income. We expect the annual amortization of our intangible assets that have been recorded as of December 31, 2021 to be as follows:
(In millions of USD)
2022 $ 3
2023 4
2024 3
2025 2
2026 2
2027 and thereafter 12
Total $ 26
9. DEBT
Amounts of outstanding debt were classified as debt maturing within one year and long-term debt in the consolidated statements of financial position as follows:
December 31,
(In millions of USD) 2021 2020
ITC Holdings 6.375% Senior Notes, due September 30, 2036
$ 200 $ 200
ITC Holdings 4.05% Senior Notes, due July 1, 2023 250 250
ITC Holdings 3.65% Senior Notes, due June 15, 2024
400 400
ITC Holdings 5.30% Senior Notes, due July 1, 2043
300 300
ITC Holdings 3.25% Notes, due June 30, 2026
400 400
ITC Holdings 2.70% Senior Notes, due November 15, 2022 (a) 500 500
ITC Holdings 3.35% Senior Notes, due November 15, 2027 500 500
ITC Holdings 2.95% Senior Notes, due May 14, 2030 700 700
ITC Holdings Revolving Credit Agreement, due October 18, 2024 39 37
ITC Holdings Commercial Paper Program (a)
155 67
ITCTransmission 6.125% First Mortgage Bonds, Series C, due March 31, 2036
100 100
ITCTransmission 4.625% First Mortgage Bonds, Series E, due August 15, 2043
285 285
ITCTransmission 4.27% First Mortgage Bonds, Series F, due June 10, 2044
100 100
ITCTransmission 4.00% First Mortgage Bonds, Series G, due March 30, 2053
225 225
ITCTransmission 3.30% First Mortgage Bonds, Series H, due August 28, 2049
75 75
ITCTransmission Revolving Credit Agreement, due October 18, 2024 88 33
METC 5.64% Senior Secured Notes, due May 6, 2040
50 50
METC 3.98% Senior Secured Notes, due October 26, 2042
75 75
METC 4.19% Senior Secured Notes, due December 15, 2044
150 150
METC 3.90% Senior Secured Notes, due April 26, 2046
200 200
METC 4.55% Senior Secured Notes, due January 15, 2049
50 50
METC 4.65% Senior Secured Notes, due July 10, 2049 50 50
METC 2.90% Senior Secured Notes, Series A, due August 3, 2051 75 -
METC 3.02% Senior Secured Notes, due October 14, 2055 150 150
METC Revolving Credit Agreement, due October 18, 2024 30 20
ITC Midwest 6.15% First Mortgage Bonds, Series A, due January 31, 2038
175 175
ITC Midwest 4.60% First Mortgage Bonds, Series D, due December 17, 2024
75 75
ITC Midwest 3.50% First Mortgage Bonds, Series E, due January 19, 2027
100 100
ITC Midwest 4.09% First Mortgage Bonds, Series F, due April 30, 2043
100 100
ITC Midwest 3.83% First Mortgage Bonds, Series G, due April 7, 2055
225 225
ITC Midwest 4.16% First Mortgage Bonds, Series H, due April 18, 2047
200 200
ITC Midwest 4.32% First Mortgage Bonds, Series I, due November 1, 2051
175 175
ITC Midwest 3.13% First Mortgage Bonds, Series J, due July 15, 2051 180 180
ITC Midwest Revolving Credit Agreement, due October 18, 2024 139 75
ITC Great Plains 4.16% First Mortgage Bonds, Series A, due November 26, 2044
150 150
ITC Great Plains Revolving Credit Agreement, due October 18, 2024 33 33
Other 3 -
Total principal 6,702 6,405
Unamortized deferred financing fees and discount
(39) (43)
Total debt
$ 6,663 $ 6,362
____________________________
(a)As of December 31, 2021 and 2020 there was $654 million and $67 million, respectively, net of unamortized deferred financing fees and discount, of debt included within debt maturing within one year in the consolidated statements of financial position.
The annual maturities of debt as of December 31, 2021 are as follows:
(In millions of USD)
2022 $ 655
2023 250
2024 804
2025 -
2026 400
2027 and thereafter 4,593
Total $ 6,702
ITC Holdings
Senior Unsecured Notes
On May 14, 2020, ITC Holdings completed the private offering of $700 million aggregate principal amount of unsecured 2.95% Senior Notes, due May 14, 2030. The net proceeds from this offering were used to repay the amount outstanding under ITC Holdings’ $400 million term loan credit agreement, to repay $122 million under ITC Holdings’ revolving credit agreement, and to repay $92 million under ITC Holdings’ commercial paper program, with remaining proceeds to be used for general corporate purposes. These Senior Notes were issued under ITC Holdings’ indenture, dated April 18, 2013.
Commercial Paper Program
ITC Holdings has an ongoing commercial paper program for the issuance and sale of unsecured commercial paper in an aggregate amount not to exceed $400 million outstanding at any one time. As of December 31, 2021, ITC Holdings had $155 million of commercial paper, net of discount, issued and outstanding under the program, with a weighted-average interest rate of 0.2% and weighted average remaining days to maturity of 32 days. The amount outstanding as of December 31, 2021 was classified as debt maturing within one year in the consolidated statements of financial position. As of December 31, 2020, ITC Holdings had $67 million of commercial paper issued and outstanding.
ITCTransmission
First Mortgage Bonds
On January 14, 2022, ITCTransmission issued $130 million of aggregate principal amount of 2.93% First Mortgage Bonds, Series J due January 14, 2052. The proceeds were used to repay existing indebtedness under the revolving credit agreement and intercompany loan agreement and will also be used to partially fund capital expenditures and for general corporate purposes. ITCTransmission also issued an additional $20 million of aggregate principal amount of 2.93% First Mortgage Bonds, Series I due January 14, 2052, the proceeds of which are expected to fund or refinance a portfolio of eligible renewable energy projects based on the green bond framework established by ITC Holdings. All of ITCTransmission’s First Mortgage Bonds are issued under its First Mortgage and Deed of Trust and secured by a first mortgage lien on substantially all of its real property and tangible personal property.
METC
Senior Secured Notes
On August 3, 2021, METC issued $75 million of 2.90% Series A Senior Secured Notes, due August 3, 2051. The proceeds from the Series A Senior Secured Notes are expected to fund or refinance a portfolio of eligible renewable energy projects based on the green bond framework established by ITC Holdings. METC has an additional $75 million delayed draw of 3.05% Series B Senior Secured Notes in May 2022 with a due date 30 years from the date of issuance. The proceeds from the Series B Senior Secured Notes are expected to be used to repay borrowings under the METC revolving credit agreement, to partially fund capital expenditures and for general corporate purposes. All of METC’s Senior Secured Notes are issued under its first mortgage indenture and secured by a first mortgage lien on substantially all of its real property and tangible personal property.
On October 14, 2020, METC issued $150 million of 3.02% Senior Secured Notes, due October 14, 2055. The proceeds from the issuance were used to repay amounts outstanding under METC’s term loan credit agreement, to repay borrowings under its revolving credit agreement, to partially fund capital expenditures and for general corporate purposes.
Term Loan Credit Agreement
On January 23, 2020, METC entered into an unsecured, unguaranteed term loan credit agreement, due January 23, 2021, under which METC borrowed the maximum of $75 million available under the agreement. The proceeds were used for general corporate purposes, primarily the repayment of borrowings under the METC revolving credit agreement. This borrowing was repaid in full on October 14, 2020 from the proceeds of the METC Senior Secured Notes issued on October 14, 2020. The weighted-average interest rate throughout the life of the loan was 1.08%.
ITC Midwest
First Mortgage Bonds
On July 15, 2020, ITC Midwest issued an aggregate of $180 million of 3.13% First Mortgage Bonds due July 15, 2051. The proceeds were used to partially repay existing indebtedness under the ITC Midwest revolving credit agreement, partially fund capital expenditures and for general corporate purposes. ITC Midwest’s First Mortgage Bonds were issued under its first mortgage and deed of trust and secured by a first mortgage lien on substantially all of its real property and tangible personal property.
Derivative Instruments and Hedging Activities
We have entered into interest rate swaps to manage interest rate risk associated with the forecasted future issuance of fixed-rate debt at ITC Holdings, the proceeds of which will be used for the expected repayment of the ITC Holdings 2.70% Senior Notes, due November 15, 2022. At December 31, 2021, ITC Holdings had the following interest rate swaps:
Interest Rate Swaps
(in millions of USD, except percentages) Notional Amount Weighted Average Fixed Rate Original Term Effective Date
July 2021 swap $ 45 1.113% 5 years November 2022
November 2021 swap 45 1.581% 5 years November 2022
November 2021 swap 45 1.492% 5 years November 2022
November 2021 swap 45 1.497% 5 years November 2022
November 2021 swap 50 1.544% 5 years November 2022
December 2021 swap 50 1.560% 5 years November 2022
December 2021 swap 50 1.489% 5 years November 2022
December 2021 swap 45 1.475% 5 years November 2022
Total $ 375 1.471%
The 5-year term interest rate swaps call for ITC Holdings to receive interest quarterly at a variable rate equal to LIBOR and to pay interest semi-annually at various fixed rates effective for the 5-year period beginning November 15, 2022. The weighted-average interest rate of the interest rate swaps was 1.471% at December 31, 2021. The agreements include a mandatory early termination provision and will be terminated no later than the effective date of the interest rate swaps of November 15, 2022. The interest rate swaps have been determined to be highly effective at offsetting changes in the fair value of the forecasted interest cash flows associated with the debt issuance, resulting from changes in benchmark interest rates from the trade date of the interest rate swaps to the issuance date of the debt obligation.
The interest rate swaps qualify for cash flow hedge accounting treatment, whereby any gain or loss recognized from the trade date to the effective date is recorded net of tax in AOCI. This amount will be accumulated and amortized as a component of interest expense over the life of the forecasted debt. As of December 31, 2021, the fair value of the derivative instruments of $2 million was recorded in other current assets in the consolidated statements of financial position. The interest rate swaps do not contain credit-risk-related contingent features. Refer to Note 12 for additional fair value information. As of December 31, 2020, ITC Holdings did not have any interest rate swaps outstanding.
Revolving Credit Agreements
On May 17, 2021, ITC Holdings, ITCTransmission, METC, ITC Midwest and ITC Great Plains amended their respective revolving credit agreements each dated October 23, 2017, as previously amended and restated on January 10, 2020. The amendments extend the maturity date of the revolving credit agreements from October 2023 to October 2024. The determination of the applicable interest rates and commitment fee rates in the new agreements is consistent with the previous agreements and remains subject to adjustment based on the borrower’s credit rating. At December 31, 2021, ITC Holdings and certain of its Regulated Operating Subsidiaries had the following unsecured revolving credit facilities available:
(In millions of USD, except percentages) Total
Available
Capacity Outstanding
Balance (a) Unused
Capacity Weighted Average
Interest Rate on
Outstanding Balance (b) Commitment
Fee Rate (c)
ITC Holdings $ 400 $ 39 $ 361 (d) 1.4% 0.175 %
ITCTransmission 100 88 12 1.1% 0.10 %
METC 100 30 70 1.1% 0.10 %
ITC Midwest 225 139 86 1.1% 0.10 %
ITC Great Plains 75 33 42 1.1% 0.10 %
Total $ 900 $ 329 $ 571
____________________________
(a)Included within long-term debt in the consolidated statements of financial position.
(b)Interest charged on borrowings depends on the variable rate structure we elected at the time of each borrowing.
(c)Calculation based on the average daily unused commitments, subject to adjustment based on the borrower’s credit rating.
(d)ITC Holdings’ revolving credit agreement may be used for general corporate purposes, including to repay commercial paper issued pursuant to the commercial paper program described above, if necessary. While outstanding commercial paper does not reduce available capacity under ITC Holdings’ revolving credit agreement, the unused capacity under this agreement adjusted for the commercial paper outstanding was $206 million as of December 31, 2021.
10. INCOME TAXES
Our effective tax rate varied from the statutory federal income tax rate due to differences between the book and tax treatment of various transactions as follows:
Year Ended December 31,
(In millions of USD) 2021 2020 2019
Income tax expense at 21% federal statutory rate $ 112 $ 114 $ 118
State income taxes (net of federal benefit) 24 28 22
AFUDC equity (5) (4) (5)
Revaluation of deferred federal income taxes (a) (9) (2) (2)
Valuation allowance 4 - -
Other, net 1 - (1)
Total income tax provision $ 127 $ 136 $ 132
____________________________
(a)Amount for the year ended December 31, 2021 is related to the change in our amortization method associated with excess deferred tax liabilities. Refer to discussion in Note 6 under “Income Taxes Refundable Related to Implementation of the TCJA”.
Components of the income tax provision were as follows:
Year Ended December 31,
(In millions of USD) 2021 2020 2019
Current income tax benefit $ - $ (2) $ (3)
Deferred income tax expense 127 138 135
Total income tax provision $ 127 $ 136 $ 132
For the years ended December 31, 2021, 2020 and 2019, our effective tax rates were 23.8%, 25.0% and 23.6%, respectively.
Deferred income tax assets (liabilities) consisted of the following:
December 31,
(In millions of USD) 2021 2020
Property, plant and equipment $ (1,274) $ (1,156)
Federal income tax NOLs and other credits 49 85
METC regulatory deferral (a) (3) (4)
Acquisition adjustments - ADIT deferrals (a) (3) (5)
Goodwill (145) (139)
Regulatory liability gross up - TCJA 131 134
Pension and postretirement liabilities 22 20
State income tax NOLs (net of federal benefit) 57 58
True-up adjustment principal & interest - (14)
Valuation allowance (4) -
Other, net 9 8
Net deferred tax liabilities $ (1,161) $ (1,013)
Gross deferred income tax liabilities $ (1,434) $ (1,333)
Gross deferred income tax assets 277 320
Valuation allowance (4) -
Net deferred tax liabilities $ (1,161) $ (1,013)
____________________________
(a)Described in Note 6
We had federal income tax NOLs as of December 31, 2021. We expect to use our NOLs prior to their expirations starting in 2036. We also had state income tax NOLs as of December 31, 2021. While we expect to utilize the majority of these state NOLs prior to their expiration, we believe that it is more likely than not that the benefit from certain state NOL carryforwards will not be realized. In recognition of this risk, we have provided a valuation allowance of $4 million on the deferred tax assets related to these state NOL carryforwards.
11. RETIREMENT BENEFITS AND ASSETS HELD IN TRUST
Pension and Postretirement Plan Benefits
We have a qualified defined benefit pension plan (“retirement plan”) for eligible employees, comprised of a traditional final average pay plan and a cash balance plan. The traditional final average pay plan is noncontributory, covers select employees, and provides retirement benefits based on years of benefit service, average final compensation, and age at retirement. The cash balance plan is also noncontributory, covers substantially all employees, and provides retirement benefits based on eligible compensation and interest credits. Our funding practice for the retirement plan is generally to fund the annual net pension cost, though we may contribute additional amounts as necessary to meet the minimum funding requirements of the Employee Retirement Income Security Act of 1974, or as we deem appropriate. We made contributions of $4 million to the retirement plan in each of 2021, 2020, and 2019. We expect to contribute $3 million to the retirement plan in 2022.
We also have two supplemental nonqualified, noncontributory, defined benefit pension plans for selected management employees (the “supplemental benefit plans” and collectively with the retirement plan, the “pension plans”). The supplemental benefit plans provide for benefits that supplement those provided by the retirement plan. The obligations under these supplemental benefit plans are included in the pension benefit obligation calculations below. The investments held in trust for the supplemental benefit plans of $54 million and $56 million at December 31, 2021 and 2020, respectively, are not included in the plan asset amounts presented throughout this footnote, but are included in other assets on our consolidated statements of financial position. For the years ended December 31, 2021, 2020, and 2019, we contributed $3 million, $3 million, and $1 million, respectively, to these supplemental benefit plans.
We provide certain postretirement health care, dental, and life insurance benefits for eligible employees (the “postretirement benefit plan”). We contributed $8 million, $10 million, and $9 million to the postretirement benefit plan in 2021, 2020, and 2019, respectively. We expect to contribute $8 million to the postretirement benefit plan in 2022.
Net periodic benefit costs by component for the pension plans and postretirement benefit plan were as follows:
Pension Plans Postretirement Benefit Plan
Years Ended December 31, Years Ended December 31,
(In millions of USD) 2021 2020 2019 2021 2020 2019
Service cost $ 9 $ 8 $ 7 $ 11 $ 11 $ 9
Interest cost 3 4 5 3 4 4
Expected return on plan assets (6) (6) (5) (6) (5) (4)
Amortization of unrecognized loss 1 1 1 - - -
Net benefit cost $ 7 $ 7 $ 8 $ 8 $ 10 $ 9
The following table reconciles the obligations, assets, and funded status of the pension plans and postretirement benefit plan as well as the presentation of the funded status of the plans in the consolidated statements of financial position:
Pension Plans Postretirement Benefit Plan
December 31, December 31,
(In millions of USD) 2021 2020 2021 2020
Change in Benefit Obligation:
Beginning projected benefit obligation $ (162) $ (141) $ (122) $ (113)
Service cost (9) (8) (11) (11)
Interest cost (3) (4) (3) (4)
Plan amendments - - - 2
Actuarial net gain/(loss) 5 (16) 8 3
Benefits paid 7 7 1 1
Settlements 2 - - -
Ending projected benefit obligation (160) (162) (127) (122)
Change in Plan Assets:
Beginning plan assets at fair value 107 91 120 95
Actual return on plan assets 10 15 13 16
Employer contributions 4 4 8 10
Benefits paid (4) (3) (1) (1)
Ending plan assets at fair value 117 107 140 120
Funded status, (underfunded)/overfunded $ (43) $ (55) $ 13 $ (2)
Accumulated benefit obligation:
Retirement plan $ (99) $ (95) N/A N/A
Supplemental benefit plans (54) (60) N/A N/A
Total accumulated benefit obligation $ (153) $ (155) $ - $ -
Amounts recorded as:
Funded Status:
Accrued pension and postretirement liabilities $ (52) $ (57) $ - $ (2)
Other non-current assets 13 6 13 -
Other current liabilities (4) (4) - -
Total $ (43) $ (55) $ 13 $ (2)
Unrecognized Amounts in Non-current Regulatory Assets/(Liabilities):
Net actuarial loss/(gain) $ 19 $ 30 $ (29) $ (14)
Net prior service cost/(credit) 1 - (2) (2)
Total $ 20 $ 30 $ (31) $ (16)
The unrecognized amounts that otherwise would have been charged and/or credited to AOCI in accordance with the GAAP guidance on accounting for retirement benefits are recorded as a regulatory asset or regulatory liability on our consolidated statements of financial position, as discussed in Note 6. The amounts recorded as a regulatory asset or regulatory liability represent a net periodic benefit cost or credit to be recognized in our operating income in future periods. Our measurement of the accumulated benefit obligation for the postretirement benefit plan as of December 31, 2021 and 2020 does not reflect the potential receipt of any subsidies under the Medicare Prescription Drug, Improvement and Modernization Act of 2003.
The net actuarial gains for the year ended December 31, 2021 within the change in benefit obligation for both the pension plans and postretirement benefit plan are primarily the result of increases in the discount rates and actual returns on plan assets greater than expected.
The net actuarial loss for the year ended December 31, 2020 within the change in benefit obligation for the pension plans is primarily the result of decreases in the discount rates. The net actuarial gain for the year ended December 31, 2020 within the change in benefit obligation for the postretirement benefit plan was driven primarily by per capita experience gains as well as other actuarial gains, partially offset by a decrease in the discount rate.
The combined projected benefit obligation and fair value of plan assets for those plans in which the projected benefit obligation is in excess of the fair value of plan assets are as follows:
Pension Plans
December 31,
(In millions of USD) 2021 2020
Projected benefit obligation $ (56) $ (61)
Fair value of plan assets (a) - -
____________________________
(a)The investments held in trust for our supplemental benefit plans are not included in the plan asset amounts presented herein, but are included in other assets on our consolidated statements of financial position.
The combined accumulated benefit obligation and fair value of plan assets for those plans in which the accumulated benefit obligation is in excess of the fair value of plan assets are as follows:
Pension Plans
December 31,
(In millions of USD) 2021 2020
Accumulated benefit obligation $ (54) $ (60)
Fair value of plan assets (a) - -
____________________________
(a)The investments held in trust for our supplemental benefit plans are not included in the plan asset amounts presented herein, but are included in other assets on our consolidated statements of financial position.
Actuarial assumptions used to determine the benefit obligations for the pension plans and postretirement benefit plan are as follows:
Pension Plans Postretirement Benefit Plan
December 31, December 31,
2021 2020 2019 2021 2020 2019
Weighted average discount rate 2.86% 2.49% 3.27% 3.14% 2.94% 3.61%
Weighted average interest crediting rate 4.00% 4.00% 4.00% N/A N/A N/A
Annual rate of salary increases 4.00% 4.00% 4.00% 4.00% 4.00% 4.00%
Health care cost trend rate N/A N/A N/A 5.75% 6.00% 6.25%
Ultimate health care cost trend rate N/A N/A N/A 5.00% 5.00% 5.00%
Year that the ultimate trend rate is reached N/A N/A N/A 2025 2025 2025
Annual rate of increase in dental benefit costs N/A N/A N/A 4.50% 4.50% 4.50%
Actuarial assumptions used to determine the benefit cost for the pension plans and postretirement benefit plan are as follows:
Pension Plans Postretirement Benefit Plan
Years Ended December 31, Years Ended December 31,
2021 2020 2019 2021 2020 2019
Weighted average discount rate - service cost 2.77% 3.47% 4.42% 3.20% 3.80% 4.58%
Weighted average discount rate - interest cost 1.93% 2.91% 3.99% 2.50% 3.30% 4.28%
Weighted average interest crediting rate 4.00% 4.00% 4.50% N/A N/A N/A
Annual rate of salary increases 4.00% 4.00% 4.00% 4.00% 4.00% 4.00%
Health care cost trend rate N/A N/A N/A 6.00% 6.25% 6.50%
Ultimate health care cost trend rate N/A N/A N/A 5.00% 5.00% 5.00%
Year that the ultimate trend rate is reached N/A N/A N/A 2025 2025 2025
Expected long-term rate of return on plan assets 5.70% 6.00% 6.60% 4.30% 4.50% 5.00%
At December 31, 2021, the projected benefit payments for the pension plans and postretirement benefit plan calculated using the same assumptions as those used to calculate the benefit obligations described above are as follows:
(In millions of USD) Pension Plans Postretirement Benefit Plan
2022 $ 8 $ 2
2023 9 2
2024 9 2
2025 10 3
2026 10 3
2027 through 2031 63 22
Investment Objectives and Fair Value Measurement
The general investment objectives of the retirement plan and postretirement benefit plan include maximizing the return within reasonable and prudent levels of risk and controlling administrative and management costs. Investment decisions are made by our retirement benefits board as delegated by our board of directors. Equity investments may include various types of U.S. and international equity securities, such as large-cap, mid-cap, and small-cap stocks. Fixed income investments may include cash and short-term instruments, U.S. Government securities, corporate bonds, mortgages, and other fixed income investments. No investments are prohibited for use in the retirement plan or postretirement benefit plan, including derivatives, but our exposure to derivatives currently is not material. We intend that the long-term capital growth of the retirement and postretirement benefit plans, together with employer contributions, will provide for the payment of the benefit obligations.
As of December 31, 2021 and 2020, the plan assets of the retirement plan and postretirement benefit plan consisted of the following assets by category:
Target Allocation Pension Plans Postretirement Benefit Plan
Asset Category 2021 2021 2020 2021 2020
Fixed income securities 50 % 50 % 50 % 50 % 50 %
Equity securities 50 % 50 % 50 % 50 % 50 %
Total 100 % 100 % 100 % 100 % 100 %
We determine our expected long-term rate of return on plan assets based on the current and expected target allocations of the retirement plan and postretirement benefit plan investments and considering historical and expected long-term rates of return on comparable fixed income investments and equity investments.
The measurement of fair value is based on a three-tier hierarchy, which prioritizes the inputs used in measuring fair value. These tiers include: Level 1, defined as observable inputs, such as quoted prices in active markets; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs in which little or no market data exists, therefore, requiring an entity to develop its own assumptions. Changes in economic conditions or model-based valuation techniques may require the transfer of financial instruments from one fair value level to another. In such instances, the transfer is reported at the beginning of the reporting period. For the years ended December 31, 2021 and 2020, there were no transfers between levels.
For the years ended December 31, 2021 and 2020, the fair value of retirement plan and postretirement benefit plan assets measured on a recurring basis at the Level 1 tier were as follows:
Pension Plans Postretirement Benefit Plan
December 31, December 31,
(In millions of USD) 2021 2020 2021 2020
Mutual funds - U.S. equity securities $ 47 $ 43 $ 67 $ 57
Mutual funds - international equity securities 12 11 3 3
Mutual funds - fixed income securities 58 53 70 60
Total $ 117 $ 107 $ 140 $ 120
The mutual funds consist primarily of publicly traded mutual funds and are recorded at fair value based on observable trades for identical securities in an active market.
Defined Contribution Plan
We also sponsor a defined contribution retirement savings plan. Participation in this plan is available to substantially all employees. We match employee contributions up to certain predefined limits based upon eligible compensation and the employee’s contribution rate. The cost of this plan was $6 million in 2021, $6 million in 2020, and $5 million in 2019.
12. FAIR VALUE MEASUREMENTS
The measurement of fair value is based on a three-tier hierarchy, which prioritizes the inputs used in measuring fair value. These tiers include: Level 1, defined as observable inputs such as quoted prices in active markets; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions. Changes in economic conditions or model-based valuation techniques may require the transfer of financial instruments from one fair value level to another. In such instances, the transfer is reported at the beginning of the reporting period. For the years ended December 31, 2021 and 2020, there were no transfers between levels.
Our assets measured at fair value subject to the three-tier hierarchy at December 31, 2021, were as follows:
Fair Value Measurements at Reporting Date Using
Quoted Prices in
Active Markets for
Identical Assets Significant
Other Observable
Inputs Significant
Unobservable
Inputs
(in millions of USD) (Level 1) (Level 2) (Level 3)
Financial assets measured on a recurring basis:
Mutual funds - fixed income securities $ 51 $ - $ -
Mutual funds - equity securities 12 - -
Interest rate swap derivatives - 2 -
Total $ 63 $ 2 $ -
Our assets measured at fair value subject to the three-tier hierarchy at December 31, 2020, were as follows:
Fair Value Measurements at Reporting Date Using
Quoted Prices in
Active Markets for
Identical Assets Significant
Other Observable
Inputs Significant
Unobservable
Inputs
(in millions of USD) (Level 1) (Level 2) (Level 3)
Financial assets measured on a recurring basis:
Cash equivalents $ 1 $ - $ -
Mutual funds - fixed income securities 52 - -
Mutual funds - equity securities 10 - -
Total $ 63 $ - $ -
As of December 31, 2021 and 2020, we held certain assets that are required to be measured at fair value on a recurring basis. The assets included in the table consist of investments recorded within cash and cash equivalents and other long-term assets, including investments held in a trust associated with our supplemental benefit plans described in Note 11. The mutual funds we own are publicly traded and are recorded at fair value based on observable trades for identical securities in an active market. Changes in the observed trading prices and liquidity of money market funds are monitored as additional support for determining fair value. Gains and losses for all mutual fund investments are recorded in other operating income and expense.
As of December 31, 2021, the assets related to derivatives consist of interest rate swaps as discussed in Note 9. The fair value of our interest rate swap derivatives is determined based on a DCF method using LIBOR swap rates, which are observable at commonly quoted intervals.
We also held non-financial assets that are required to be measured at fair value on a non-recurring basis. These consist of goodwill and intangible assets. We did not record any impairment charges on long-lived assets and no other significant events occurred requiring non-financial assets and liabilities to be measured at fair value (subsequent to initial recognition) during the years ended December 31, 2021 and 2020. Refer to Note 8 for additional information on our intangible assets.
Fair Value of Financial Assets and Liabilities
Fixed Rate Debt
Based on the borrowing rates obtained from third party lending institutions currently available for bank loans with similar terms and average maturities from active markets, the fair value of our consolidated long-term debt and debt maturing within one year, excluding revolving credit agreements and commercial paper, was $6,995 million and $7,119 million at December 31, 2021 and 2020, respectively. These fair values represent Level 2 under the three-tier hierarchy described above. The total book value of our consolidated long-term debt and debt maturing within one year, net of discount and deferred financing fees and excluding revolving credit agreements and commercial paper, was $6,179 million and $6,097 million at December 31, 2021 and 2020, respectively.
Revolving Credit Agreements
At December 31, 2021 and 2020, we had a consolidated total of $329 million and $198 million, respectively, outstanding under our revolving credit agreements, which are variable rate loans. The fair value of these loans approximates book value based on the borrowing rates currently available for variable rate loans obtained from third party lending institutions. These fair values represent Level 2 under the three-tier hierarchy described above.
Other Financial Instruments
The carrying value of other financial instruments included in current assets and current liabilities, including cash and cash equivalents, special deposits and commercial paper, approximates their fair value due to the short-term nature of these instruments.
13. STOCKHOLDER'S EQUITY
Accumulated Other Comprehensive Income
The following table provides the components of changes in AOCI:
Year Ended December 31,
(In millions of USD) 2021 2020 2019
Balance at the beginning of period $ (8) $ 7 $ 4
Derivative Instruments
Reclassification of net loss relating to interest rate cash flow hedges from AOCI to earnings (net of tax of $2 for the year ended December 31, 2021, $1 for the year ended December 31, 2020 and less than $1 for the year ended December 31, 2019) (a) 4 3 1
Gain (loss) on interest rate swaps relating to interest rate cash flow hedges (net of tax of $1 for the year ended December 31, 2021, $8 for the year ended December 31, 2020 and $1 for the year ended December 31, 2019) 2 (18) 2
Total other comprehensive income (loss), net of tax 6 (15) 3
Balance at the end of period $ (2) $ (8) $ 7
____________________________
(a)The reclassification of the net loss relating to interest rate cash flow hedges is reported in interest expense on a pre-tax basis.
The amount of net loss relating to interest rate cash flow hedges to be reclassified from AOCI to earnings for the 12-month period ending December 31, 2022 is expected to be approximately $4 million (net of tax of less than $2 million). The reclassification is reported in interest expense on a pre-tax basis.
14. SHARE-BASED COMPENSATION AND EMPLOYEE SHARE PURCHASE PLAN
We recorded share-based compensation costs as follows:
Year Ended December 31,
(In millions of USD) 2021 2020 2019
Operation and maintenance expenses $ 2 $ 2 $ 2
General and administrative expenses 32 23 30
Amounts capitalized to property, plant and equipment 9 7 8
Total share-based compensation costs $ 43 $ 32 $ 40
Total tax benefit recognized in the consolidated statements of comprehensive income
$ 9 $ 8 $ 8
Long-Term Incentive Plans
Under our long-term incentive plans, we may grant long-term incentive awards of PBUs and SBUs to employees, including executive officers, of ITC Holdings and its subsidiaries. Generally, each PBU and SBU granted will be valued based on one share of Fortis common stock traded on the Toronto Stock Exchange, converted to U.S. dollars and settled only in cash. However, certain SBUs granted to the executives may settle in cash, 100% Fortis common stock, or 50% cash and 50% Fortis common stock depending on executives’ settlement elections and whether certain share ownership requirements are met. PBUs and SBUs that are granted pursuant to our long-term incentive plans generally vest on either the third December 31st or January 1st following the grant date, provided the service and performance criteria, as applicable, are satisfied, and will be settled during the subsequent quarter. However, certain awards may vest over a shorter period or on the grant date if certain retirement eligibility criteria are met. The granted awards and related dividend equivalents have no shareholder rights.
Performance-Based Units
The PBUs are classified as liability awards based on the cash settlement feature. The PBUs are measured at fair value at the end of each reporting period, which will fluctuate based on the price of Fortis common stock and the level of achievement of the financial performance criteria, including a market condition and a performance condition. The payout may range from 0% - 200% of the target award, depending on actual performance relative to the performance criteria. The PBUs earn dividend equivalents which are also re-measured consistent with the target award and settled in cash at the end of the vesting period.
The following table shows the changes in PBUs during the year ended December 31, 2021:
Number of
Performance
Based Units
PBUs at December 31, 2020 900,951
Granted 314,940
Vested and paid out (291,325)
Forfeited (25,474)
PBUs at December 31, 2021 899,092
The following table presents the classification in the consolidated statements of financial position of obligations related to outstanding PBUs not yet settled:
December 31,
(In millions of USD) 2021 2020
Accrued compensation $ 28 $ 20
Other long-term liabilities 25 22
Total $ 53 $ 42
The aggregate fair value of PBUs as of December 31, 2021 and 2020 was $72 million and $59 million, respectively. At December 31, 2021, $19 million of total unrecognized compensation cost related to PBUs not yet vested is expected to be recognized over the remaining weighted-average period of 1.7 years.
Service-Based Units
The SBUs are classified as liability awards based on the possibility of cash settlement. The SBUs are measured at fair value at the end of each reporting period, which will fluctuate based on the price of Fortis common stock. The SBUs earn dividend equivalents which are also re-measured based on the price of Fortis common stock and settled in cash at the end of the vesting period.
The following table shows the changes in SBUs during the year ended December 31, 2021:
Number of
Service
Based Units
SBUs at December 31, 2020 687,710
Granted 247,181
Vested and paid out (219,605)
Forfeited (25,474)
SBUs at December 31, 2021 689,812
The following table presents the classification in the consolidated statements of financial position of obligations related to outstanding SBUs not yet settled:
December 31,
(In millions of USD) 2021 2020
Accrued compensation $ 11 $ 9
Other long-term liabilities 11 10
Total $ 22 $ 19
The aggregate fair value of SBUs as of December 31, 2021 and 2020 was $32 million and $28 million, respectively. At December 31, 2021, $10 million of the total unrecognized compensation cost related to SBUs not yet vested is expected to be recognized over the remaining weighted-average period of 1.7 years.
Employee Share Purchase Plan
ITC employees are permitted to purchase common shares of Fortis stock under the Fortis ESPP. ITC Holdings also makes contributions as additional compensation to participating employees’ ESPP accounts. The cost of ITC Holdings’ contribution for the years ended December 31, 2021, 2020, and 2019 was less than $1 million, respectively.
15. JOINTLY OWNED UTILITY PLANT/COORDINATED SERVICES
Certain of our Regulated Operating Subsidiaries have agreements with other utilities for the joint ownership of substation assets and transmission lines as discussed in Note 2. We have investments in jointly owned utility assets as shown in the table below as of December 31, 2021:
Net Investments (a)
(In millions of USD) Substations Lines
ITCTransmission (b) $ - $ 29
METC (c) 17 41
ITC Midwest (d) 49 103
ITC Great Plains (e) 10 23
Total $ 76 $ 196
____________________________
(a)Amount represents our investment in jointly held plant in-service, which has been reduced by the ownership interest amounts of other parties.
(b)ITCTransmission has a 49.6% joint ownership in 345 kV transmission lines with a municipal power agency.
(c)METC has joint ownership in several assets within various substations and several 345 kV transmission lines with various parties including Consumers Energy. As of December 31, 2021, METC’s ownership percentages for jointly owned substation facilities and lines ranged from less than 1.0% to 92.0% and 1.0% to 41.9%, respectively.
(d)ITC Midwest has joint ownership in several substations and transmission lines with various parties. ITC Midwest’s ownership percentages for jointly owned substation facilities and lines ranged from 28.0% to 80.0% and 11.0% to 80.0%, respectively, as of December 31, 2021. In addition to the jointly held plant in-service, ITC Midwest has $71 million of construction work in progress for jointly held plant in the consolidated statements of financial position as of December 31, 2021.
(e)ITC Great Plains has a 51.0% joint ownership in a transmission project with an electric cooperative.
16. RELATED PARTY TRANSACTIONS
Intercompany Receivables and Payables
ITC Holdings may incur charges from Fortis and other subsidiaries of Fortis that are not subsidiaries of ITC Holdings for general corporate expenses incurred. In addition, ITC Holdings may perform additional services for, or receive additional services from, Fortis and such subsidiaries. These transactions are in the normal course of
business and payments for these services are settled through accounts receivable and accounts payable, as necessary. We had intercompany receivables from Fortis and such subsidiaries of $2 million and less than $1 million at December 31, 2021 and December 31, 2020, respectively, and intercompany payables to Fortis and such subsidiaries of less than $1 million at December 31, 2021 and December 31, 2020.
Related party charges for corporate expenses from Fortis and such subsidiaries are recorded in general and administrative expense. ITC Holdings had such expense for the years ended December 31, 2021, 2020 and 2019 of $10 million. Related party billings for services to Fortis and other subsidiaries recorded as an offset to general and administrative expenses for ITC Holdings were $2 million for each of the years ended December 31, 2021 and 2020, and less than $1 million for the year ended December 31, 2019.
Dividends
We paid dividends of $232 million, $330 million and $250 million during the years ended December 31, 2021, 2020 and 2019, respectively, to ITC Investment Holdings. ITC Holdings also paid dividends of $64 million to ITC Investment Holdings in January 2022.
Transfer of Membership Interests
In February 2021, we transferred our membership interests in certain wholly-owned development entities to our parent company, ITC Investment Holdings. The transfer was accounted for at book value as a non-reciprocal transfer of value. There was no gain or loss recognized on the transfer. The transfer did not have a material impact on our consolidated financial condition, results of operations or cash flows.
Intercompany Tax Sharing Agreement
We are organized as a corporation for tax purposes and subject to a tax sharing agreement as a wholly-owned subsidiary of ITC Investment Holdings. Additionally, we record income taxes based on our separate company tax position and make or receive tax-related payments with ITC Investment Holdings. During the year ended December 31, 2021, we did not make or receive any tax-related payments with ITC Investment Holdings. During year ended December 31, 2020, we paid $2 million to ITC Investment Holdings for matters related to the State of Michigan income taxes. During the year ended December 31, 2019 we did not make or receive any tax-related payments with ITC Investment Holdings.
During each of the years ended December 31, 2020 and 2019, we received a payment of $2 million from FortisUS for a tax refund that originated prior to establishing the tax sharing agreement.
17. COMMITMENTS AND CONTINGENT LIABILITIES
Environmental Matters
We are subject to federal, state and local environmental laws and regulations, which impose limitations on the discharge of pollutants into the environment, require reporting of emissions from certain equipment, 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 relating to investigation and remediation of 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 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 some environmental laws, such liabilities may also be joint and several, meaning that a party can be held responsible for more than its share of the liability involved, or even the entire share. Although environmental requirements generally have become more stringent and compliance with those requirements more expensive, we are not aware of any specific developments that would increase our costs for such compliance in a manner that would be expected to have a material adverse effect on our financial condition, results of operations or liquidity.
Our assets and operations also involve the use of materials classified as hazardous, toxic or otherwise dangerous. Some of the properties that we 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 above ground or underground storage tanks and associated piping. Some of them also include large electrical equipment filled with mineral oil, which may contain or previously have
contained PCBs. Some of our facilities and electrical equipment may also contain asbestos containing materials. 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, above ground and underground transmission lines sometimes traverse properties that we do not own and transmission assets that we own or operate are sometimes commingled at our transmission stations with distribution assets owned or operated by our transmission customers.
Some properties in which we have an ownership interest or at which we operate are, or are suspected of being, affected by environmental contamination. We are not aware of any pending or threatened claims against us with respect to environmental contamination relating to these properties, or of any investigation or remediation of contamination at these properties, that entail costs likely to materially affect us. Some facilities and properties are located near environmentally sensitive areas, including wetlands and habitat for threatened and endangered species.
Litigation
We are involved in certain legal proceedings before various courts, governmental agencies and mediation panels concerning matters arising in the ordinary course of business. These proceedings include certain contract disputes, eminent domain and vegetation management activities, 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.
Rate of Return on Equity Complaints
Two complaints were filed with the FERC by combinations of consumer advocates, consumer groups, municipal parties and other parties challenging the base ROE in MISO. The complaints were filed with the FERC under Section 206 of the FPA requesting that the FERC find the MISO regional base ROE rate (the “base ROE”) for all MISO TO’s, including our MISO Regulated Operating Subsidiaries, to no longer be just and reasonable.
Initial Complaint
On November 12, 2013, the Association of Businesses Advocating Tariff Equity, Coalition of MISO Transmission Customers, Illinois Industrial Energy Consumers, Indiana Industrial Energy Consumers, Inc., Minnesota Large Industrial Group and Wisconsin Industrial Energy Group (collectively, the “complainants”) filed the Initial Complaint with the FERC. The complainants sought a FERC order to reduce the base ROE used in the formula transmission rates for our MISO Regulated Operating Subsidiaries to 9.15%, reducing the equity component of our capital structure and terminating the ROE adders approved for certain Regulated Operating Subsidiaries. The FERC set the base ROE for hearing and settlement procedures, while denying all other aspects of the Initial Complaint. The ROE collected through the MISO Regulated Operating Subsidiaries’ rates during the period November 12, 2013 through September 27, 2016 consisted of a base ROE of 12.38% plus applicable incentive adders.
On September 28, 2016, the FERC issued the September 2016 Order that set the base ROE at 10.32%, with a maximum ROE of 11.35%, effective for the period from November 12, 2013 through February 11, 2015 based on a two-step DCF methodology adopted in previous complaint matters for other utilities. The September 2016 Order required our MISO Regulated Operating Subsidiaries to provide refunds, including interest, which were completed in 2017. Additionally, the base ROE established by the September 2016 Order was to be used prospectively from the date of that order until a new approved base ROE was established by the FERC. On October 28, 2016, the MISO TOs, including our MISO Regulated Operating Subsidiaries, filed a request with the FERC for rehearing of the September 2016 Order regarding the short-term growth projections in the two-step DCF analysis. Additional impacts to the base ROE for the period of the Initial Complaint and the related accrued refund liabilities resulted from the November 2019 Order and May 2020 Order issued by the FERC, as discussed below.
Second Complaint
On February 12, 2015, the Second Complaint was filed with the FERC by Arkansas Electric Cooperative Corporation, Mississippi Delta Energy Agency, Clarksdale Public Utilities Commission, Public Service Commission of Yazoo City and Hoosier Energy Rural Electric Cooperative, Inc., seeking a FERC order to
reduce the base ROE used in the formula transmission rates of our MISO Regulated Operating Subsidiaries to 8.67%, with an effective date of February 12, 2015.
On June 30, 2016, the presiding ALJ issued an initial decision that recommended a base ROE of 9.70% for the refund period from February 12, 2015 through May 11, 2016, with a maximum ROE of 10.68%, which also would be applicable going forward from the date of a final FERC order. The Second Complaint was dismissed as a result of the November 2019 Order and the dismissal of the complaint was reaffirmed in the May 2020 Order, as discussed below.
November 2019 Order
On November 21, 2019, the FERC issued an order in the MISO ROE Complaints which applied a methodology to the Initial Complaint period that used two financial models to determine the base ROE. The FERC determined that the base ROE for the Initial Complaint should be 9.88% and the top of the range of reasonableness for that period should be 12.24% and that this base ROE should apply during the first refund period of November 12, 2013 to February 11, 2015 and from the date of the September 2016 Order prospectively. In the November 2019 Order, the FERC also dismissed the Second Complaint. Therefore, based on the November 2019 Order, for the Second Complaint refund period from February 12, 2015 to May 11, 2016, no refund is due. As a result, in 2019, we reversed the aggregate estimated current liability we had previously recorded for the Second Complaint. In addition, for the period from May 12, 2016 to September 27, 2016, no refund is due because no complaint had been filed for that period. The FERC ordered refunds to be made in accordance with the November 2019 Order. The MISO TOs, including our MISO Regulated Operating Subsidiaries, and several other parties filed requests for rehearing of the November 2019 Order. The MISO TOs asserted that the methodology applied by the FERC in the November 2019 Order does not allow the MISO TOs to earn a reasonable rate of return on their investment, as required by precedent. On January 21, 2020, the FERC issued an order granting rehearing of the November 2019 Order for further consideration.
May 2020 Order
On May 21, 2020, the FERC issued an order on rehearing of the November 2019 Order. In this order, the FERC revised its November 2019 Order methodology, finding that three financial models should be used to determine the base ROE, among other revisions. By applying the new methodology, the FERC determined that the base ROE for the Initial Complaint should be 10.02% and the top of the range of reasonableness for that period should be 12.62%. The FERC determined that this base ROE should apply during the first refund period of November 12, 2013 to February 11, 2015 and from the date of the September 2016 Order prospectively. The FERC ordered refunds to be made in accordance with the May 2020 Order by December 23, 2020. On October 8, 2020, the FERC granted an extension to September 23, 2021 and on August 2, 2021 the FERC granted a second extension to February 28, 2022. On December 16, 2021, MISO requested a third extension to May 31, 2022, and that remains pending. In the May 2020 Order, the FERC also reaffirmed its decision to dismiss the Second Complaint and its finding that no refunds would be ordered on the Second Complaint. Our MISO Regulated Operating Subsidiaries are parties to multiple appeals of the September 2016 Order, November 2019 Order and May 2020 Order at the D.C. Circuit Court.
Financial Statement Impacts
As of December 31, 2021, we had recorded an aggregate current regulatory asset and liability of $1 million and less than $1 million, respectively, and as of December 31, 2020, we had recorded an aggregate current regulatory asset and liability of $8 million and $13 million, respectively, in the consolidated statements of financial position. These impacts reflect amounts owed from or due to customers under the terms outlined in the May 2020 Order and the November 2019 Order on the Initial Complaint and the periods subsequent to the September 2016 Order. During the year ended December 31, 2021, we refunded net settlement payments of $5 million due to customers related to this ROE matter and during the year ended December 31, 2020, we refunded net settlement payments of $31 million due to customers related to this ROE matter.
Although the November 2019 Order and May 2020 Order dismissed the Second Complaint with no refunds required, it is possible upon resolution of the pending appeals that our MISO Regulated Operating Subsidiaries could be required to provide material refunds related to the Second Complaint.
Our MISO Regulated Operating Subsidiaries currently record revenues at the base ROE of 10.02% established in the May 2020 Order plus applicable incentive adders. See Note 5 for a summary of incentive adders for transmission rates.
The recognition of the obligations associated with the MISO ROE Complaints resulted in the following impacts to the consolidated statements of comprehensive income:
Year Ended December 31,
(In millions of USD) 2021 2020 2019
Revenue increase $ - $ 32 $ 69
Interest expense decrease - (3) (12)
Estimated net income increase - 25 61
As of December 31, 2021, our MISO Regulated Operating Subsidiaries had a total of approximately $5 billion of equity in their collective capital structures for ratemaking purposes. Based on this level of aggregate equity, we estimate that each 10 basis point change in the authorized ROE would impact annual consolidated net income by approximately $5 million.
Purchase Obligations
At December 31, 2021, we had purchase obligations of $126 million representing commitments for materials, services and equipment that had not been received as of December 31, 2021, primarily for construction and maintenance projects for which we have an executed contract. Of these purchase obligations, $107 million is expected to be paid in 2022, with the majority of the items related to materials and equipment that have long production lead times.
Other Commitments
METC
Amended and Restated Purchase and Sale Agreement for Ancillary Services. 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.
Amended and Restated Easement Agreement. Under the Easement Agreement, Consumers Energy provides METC with an easement to the land on which a majority of METC’s transmission towers, poles, lines and other transmission facilities used to transmit electricity for Consumers Energy and others are located. The term of the Easement Agreement runs through December 31, 2050 and is subject to 10 automatic 50-year renewals thereafter unless METC gives notice of nonrenewal at least one year in advance. METC pays Consumers Energy $10 million in annual rent per year for the easement and also pays for any rentals, property, taxes, and other fees related to the property covered by the Easement Agreement. Payments to Consumers Energy under the Easement Agreement are charged to operation and maintenance expenses.
ITC Midwest
Operations Services Agreement For 34.5 kV Transmission Facilities. ITC Midwest and IP&L entered into the OSA under which IP&L performs certain operations functions for ITC Midwest’s 34.5 kV transmission system. The OSA provides that when ITC Midwest upgrades 34.5 kV facilities to higher operating voltages it may notify IP&L of the change and the OSA is no longer applicable to those facilities.
ITC Great Plains
Amended and Restated Maintenance Agreement. Mid-Kansas and ITC Great Plains have entered into the Mid-Kansas Agreement pursuant to which Mid-Kansas has agreed to perform various field operations and maintenance services related to certain ITC Great Plains assets.
Concentration of Credit Risk
Our credit risk is primarily with DTE Electric, Consumers Energy and IP&L, which were responsible for approximately 21.5%, 23.5% and 24.7%, respectively, or $300 million, $327 million and $344 million,
respectively, of our consolidated billed revenues for the year ended December 31, 2021. This portion of total billed revenues of DTE Electric, Consumers Energy and IP&L include the collection of 2019 revenue accruals and deferrals and exclude any amounts for the 2021 revenue accruals and deferrals that were included in our 2021 operating revenues but will not be billed to our customers until 2023. Under DTE Electric’s and Consumers Energy’s current rate structure, DTE Electric and Consumers Energy include in their retail rates the actual cost of transmission services provided by ITCTransmission and METC, respectively, in their billings to their customers, effectively passing through to end-use consumers the total cost of transmission service. IP&L currently includes in their retail rates an allowance for transmission services provided by ITC Midwest in their billings to their customers. However, any financial difficulties experienced by DTE Electric, Consumers Energy or IP&L may affect their ability to make payments for transmission service to ITCTransmission, METC, and ITC Midwest, which could negatively impact our business. MISO, as our MISO Regulated Operating Subsidiaries’ billing agent, bills DTE Electric, Consumers Energy, IP&L and other customers on a monthly basis and collects fees for the use of the MISO Regulated Operating Subsidiaries’ transmission systems. SPP is the billing agent for ITC Great Plains and bills transmission customers for the use of ITC Great Plains transmission systems. MISO and SPP have implemented strict credit policies for its members’ customers, which include customers using our transmission systems. Specifically, MISO and SPP require a letter of credit or cash deposit equal to the credit exposure, which is determined by a credit scoring model and other factors, from any customer using a member’s transmission system.
The financial results of ITC Interconnection are currently not material to our consolidated financial statements, including billed revenues.
18. SUPPLEMENTAL FINANCIAL INFORMATION
Reconciliation of Cash, Cash Equivalents and Restricted Cash
The following table provides a reconciliation of cash, cash equivalents and restricted cash reported on the consolidated statements of financial position that sum to the total of the same such amounts shown in the consolidated statements of cash flows:
December 31,
(In millions of USD) 2021 2020 2019 2018
Cash and cash equivalents $ 5 $ 4 $ 4 $ 6
Restricted cash included in:
Other non-current assets 2 2 2 4
Total cash, cash equivalents and restricted cash $ 7 $ 6 $ 6 $ 10
Restricted cash included in other non-current assets primarily represents cash on deposit to pay for vegetation management, land easements and land purchases for the purpose of transmission line construction as well as amounts liquidated to make benefit payments related to our supplemental benefit plans.
Supplementary Cash Flow Information
Year Ended December 31,
(In millions of USD) 2021 2020 2019
Supplementary cash flows information:
Interest paid (net of interest capitalized) $ 237 $ 236 $ 228
Income taxes paid - 2 -
Income tax refunds received - 2 3
Supplementary non-cash investing and financing activities:
Additions to property, plant and equipment and other long-lived assets (a) 140 135 92
Allowance for equity funds used during construction 30 27 29
Right-of-use assets obtained in exchange for new operating lease liabilities - - 5
Other 3 - -
____________________________
(a)Amounts consist of current and accrued liabilities for construction, labor, materials and other costs that have not been included in investing activities. These amounts have not been paid for as of December 31, 2021, 2020 or 2019, respectively, but will be or have been included as a cash outflow from investing activities for expenditures for property, plant and equipment or repayments of contributions in aid of construction when paid.
19. SEGMENT INFORMATION
We identify reportable segments based on the criteria set forth by the FASB regarding disclosures about segments of an enterprise, including the regulatory environment of our subsidiaries and the business activities performed to earn revenues and incur expenses.
Regulated Operating Subsidiaries
We aggregate ITCTransmission, METC, ITC Midwest, ITC Great Plains and ITC Interconnection into one reportable operating segment based on their similar regulatory environment and economic characteristics, among other factors. They are engaged in the transmission of electricity within the United States, earn revenues from the same types of customers and are regulated by the FERC.
ITC Holdings and Other
Information below for ITC Holdings and Other consists primarily of a holding company whose activities include debt financings and general corporate activities. The other subsidiaries of ITC Holdings, excluding the Regulated Operating Subsidiaries, do not have significant operations.
Regulated
Operating ITC Holdings Reconciliations/
2021 Subsidiaries and Other Eliminations Total
(In millions of USD)
Operating revenues $ 1,386 $ 1 $ (38) $ 1,349
Depreciation and amortization 231 1 - 232
Interest expense, net 123 129 (1) 251
Income (loss) before income taxes 691 (158) - 533
Income tax provision (benefit) 173 (46) - 127
Net income 518 406 (518) 406
Property, plant and equipment, net 9,954 7 - 9,961
Goodwill 950 - - 950
Total assets (a) 11,317 6,134 (6,006) 11,445
Capital expenditures 841 - (7) 834
Regulated
Operating ITC Holdings Reconciliations/
2020 Subsidiaries and Other Eliminations Total
(In millions of USD)
Operating revenues $ 1,333 $ 1 $ (36) $ 1,298
Depreciation and amortization 218 1 - 219
Interest expense, net 118 122 - 240
Income (loss) before income taxes 683 (140) - 543
Income tax provision (benefit) 179 (43) - 136
Net income 504 407 (504) 407
Property, plant and equipment, net 9,319 8 - 9,327
Goodwill 950 - - 950
Total assets (a) 10,710 5,830 (5,715) 10,825
Capital expenditures 886 - (1) 885
Regulated
Operating ITC Holdings Reconciliations/
2019 Subsidiaries and Other Eliminations Total
(In millions of USD)
Operating revenues $ 1,358 $ - $ (31) $ 1,327
Depreciation and amortization 201 2 - 203
Interest expense, net 105 119 - 224
Income (loss) before income taxes 710 (150) - 560
Income tax provision (benefit) 179 (47) - 132
Net income 531 428 (531) 428
Property, plant and equipment, net 8,573 9 - 8,582
Goodwill 950 - - 950
Total assets (a) 9,946 5,402 (5,290) 10,058
Capital expenditures 874 - (9) 865
____________________________
(a)Reconciliation of total assets results primarily from differences in the netting of deferred tax assets and liabilities in our segments as compared to the classification in our consolidated statements of financial position.

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
None.

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ITEM 9A. CONTROLS AND PROCEDURES
ITEM 9A. CONTROLS AND PROCEDURES.
Management’s Report on Internal Control Over Financial Reporting is included in Item 8. of this Form 10-K.
Disclosure Controls and Procedures
We maintain disclosure controls and procedures that are designed to provide reasonable assurance that material information required to be disclosed in our reports that we file or submit under the Exchange Act, is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required financial disclosure. In designing and evaluating the disclosure controls and procedures, management recognized that a control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, with a company have been detected.
As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15 of the Exchange Act. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures are effective, at the reasonable assurance level.
Changes in Internal Control over Financial Reporting
There have been no changes in our internal control over financial reporting during the quarter ended December 31, 2021 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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ITEM 9B. OTHER INFORMATION
ITEM 9B. OTHER INFORMATION.
None.

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ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.
DIRECTORS
Our Bylaws provide for the election of directors at each annual meeting of shareholders. Each director serves until the next annual meeting and until his or her successor is elected and qualified, or until his or her resignation or removal.
The Board must consist of the Chief Executive Officer of the Company (Ms. Apsey), a minority of representatives of Fortis (Mr. Hutchens and Ms. Perry) and a majority of directors who are independent of Fortis. Mr. Laurito previously served as a Fortis representative until his retirement from Fortis on December 31, 2021. Due to Mr. Laurito’s affiliation with Fortis, he will remain a non-independent director for at least 3 years from his retirement from Fortis. All directors must be independent of any “market participant” in MISO and SPP and a majority of the directors must be “independent” as defined in the Shareholders Agreement. See “Item 13. Certain Relationships And Related Transactions, And Director Independence - Director Independence.”
Linda H. Apsey, 52. Ms. Apsey became President and Chief Executive Officer of the Company in November 2016 and was elected a director of the Company in January 2017. From May 2016 through January 2017, Ms. Apsey served as the Company’s Executive Vice President and Chief Business Unit Officer, where she was
responsible for leading all aspects of the financial and operational performance of our five Regulated Operating Subsidiaries and the Company’s development. She had previously served as the Company’s Executive Vice President, Chief Business Unit Officer and President, ITC Michigan since February 2015 where she was responsible for leading all aspects of the financial and operational performance of the Company’s five Regulated Operating Subsidiaries and acting as the business unit head and president of the ITCTransmission and METC operating companies. Ms. Apsey currently serves as a director of the Fortis utility subsidiary, FortisAlberta Inc. The Board selected Ms. Apsey to serve as a director due to her position as President and Chief Executive Officer of the Company.
Leanne M. Bell, 61. Ms. Bell became a director of the Company in February 2022. Ms. Bell is a retired financial and power infrastructure expert with a portfolio of board work spanning the infrastructure space in both the United States and Europe. She has overseen the investment of more than $6 billion in global power infrastructure projects and companies. Before committing full time to non-executive board roles in 2014, Ms. Bell was Chief Financial Officer of Synergy Renewables LLC, Managing Director of Tiger Infrastructure Partners (formerly Lehman Brothers Global Infrastructure Partners) and Managing Director of GE Energy Financial Services. She currently sits on the boards of Ventient Energy Services Limited, Nassau Financial Group and Third Coast Midstream, LLC. She previously served on the board of Onward Energy Services from 2018 to 2020 and John Laing Group from 2020 to 2021. The Board selected Ms. Bell to serve as a director due to her expansive career in the financial and energy industries. Ms. Bell serves on the Audit and Risk Committee.
Robert A. Elliott, 66. Mr. Elliott became a director of the Company in January 2017. Mr. Elliott has served as President and Owner of Elliott Accounting, an accounting, income tax and management advisory services organization in Tucson, Arizona, since 1983. He also serves as an Investment Advisor Representative for Greenberg Financial Group, a brokerage firm, a position in which he has served since 2001. Mr. Elliott has been a board member of UNS Energy Corporation, a subsidiary of Fortis, since 2014, serving as the Chair of the Board until 2021 . Mr. Elliott currently serves on the board of directors of AAA Mountain West Group and has served since 2016. He is the Chair of the board of directors of AAA Auto Club Partners. He previously served on the board of directors of AAA Arizona Inc. from 2007 to 2016. The Board selected Mr. Elliott to serve as a director because of his accounting experience, his familiarity with Fortis subsidiary operations and his experience serving as a leader on other boards of directors. Mr. Elliott serves as Chairperson of the Audit and Risk Committee, and the Board has determined that Mr. Elliott is an “audit committee financial expert,” as that term is defined under applicable SEC rules.
Debora M. Frodl, 56. Ms. Frodl became a director of the Company in August 2020. Ms. Frodl is the founder of DF Strategies, a strategic consultancy firm in Minneapolis, MN, since 2018. She previously enjoyed a 28-year career at General Electric, where she most recently was Global Executive Director, Ecomagination from December 2012 to December 2017. Ms. Frodl gained over twenty years of senior executive experience at GE Capital, serving in roles including Senior Vice President and CEO and President. Ms. Frodl currently serves as a member of the Board of Directors for Renewable Energy Group, Inc., XL Fleet Corporation, and Spring Valley Acquisition Corporation. Since 2014, Ms. Frodl has served as an ambassador for the US Department of Energy’s Clean Energy, Education & Empowerment for Women Initiative. She also serves on the Advisory Board for the National Renewable Energy Lab, Joint Institute of Strategic Energy Analysis and University of Minnesota, Institute on the Environment. The Board selected Ms. Frodl to serve as a director due to her career in the energy industry, and her leadership experience and familiarity within the geographic region in which the Company operates and conducts its business. Ms. Frodl serves on the Governance and Human Resources Committee.
Lt. Gen. Ronnie Hawkins, Jr., USAF, Retired, 66. Lt. Gen. Hawkins, Jr. became a director of the Company in June 2020. Lt. Gen. Hawkins Jr. was appointed as President of Angelo State University, which is part of the Texas Tech University System, in 2020. Lt. Gen. Hawkins Jr. is also the President and CEO of the Hawkins Group, a consultancy focusing on digital, information technology and cybersecurity challenges for Fortune 500 clients and the U.S. Government. He founded the Hawkins Group in 2015 after serving more than a 37-year decorated career in the United States Air Force, which included leadership roles in critical infrastructure and key information systems used by the Department of Defense and its coalition partners. The Board selected Lt. Gen. Hawkins Jr. due to his vast knowledge of cybersecurity and information systems as well as his leadership experience. Mr. Hawkins serves on the Governance and Human Resources Committee.
David G. Hutchens, 55. Mr. Hutchens became a director of the Company in January 2021. Mr. Hutchens is the President and Chief Executive Officer of Fortis and has served as such since January 2021. Prior to his current position, Mr. Hutchens was appointed to Chief Operating Officer of Fortis in January 2020 while concurrently serving as the Chief Executive Officer of UNS Energy Corporation, a position in which he held since May 2014. Mr. Hutchens also served as Executive Vice President, Western Utility Operations with Fortis from 2018 to 2020. His career in the energy sector spans more than 25 years, having held a variety of positions at electric and gas utilities in Arizona. He currently serves as a director of the Fortis utility subsidiaries, FortisBC, Fortis Alberta and UNS Energy Corporation. The Board selected Mr. Hutchens to serve based on his relevant business and leadership experience and because he is a director representative of Fortis. Mr. Hutchens serves on the Governance and Human Resources Committee.
James P. Laurito, 65. Mr. Laurito became a director of the Company in October 2016. Mr. Laurito retired from Fortis in December 2021. He previously served as Fortis’ Executive Vice President, Business Development since April 2016 and as Chief Technology Officer from 2018 until his retirement. Previously, Mr. Laurito served as the President and Chief Executive Officer of Fortis’ Central Hudson Gas & Electric Corporation subsidiary from January 2010 to November 2014. Prior to joining Central Hudson, Mr. Laurito served as the President and Chief Executive Officer of both New York State Electric and Gas Corporation and Rochester Gas and Electric Corporation, subsidiaries of Avangrid, Inc. Mr. Laurito served as a board member of Fortis’ Central Hudson Gas & Electric Corporation subsidiary from 2014 to 2021. He has been Chairman of the Hudson Valley Economic Development Corporation since January 2015 and currently serves on the board of Belize Electricity Co. Ltd. and Bowman Consulting Group, also serving as the Chair of the Compensation Committee of Bowman Consulting Group. The Board selected Mr. Laurito to serve due to his expansive background in the utility industry and his regulatory knowledge. Mr. Laurito serves on the Governance and Human Resources Committee.
Jocelyn H. Perry, 51. Ms. Perry became a director of the Company in January 2022. Ms. Perry has served as Fortis’ Executive Vice President and Chief Financial Officer since 2018. Previously, Ms. Perry was the President and Chief Executive Officer of Fortis’ Newfoundland Power subsidiary from 2017 to 2018 and as its Chief Operating Officer from 2016 to 2017. Ms. Perry currently serves on the boards of Fortis’ subsidiaries FortisBC and UNS Energy Corporation. The Board selected Ms. Perry to serve based on her relevant business and leadership experience and because she is a director representative of Fortis. Ms. Perry serves on the Audit and Risk Committee.
Sandra E. Pierce, 63. Ms. Pierce was appointed as Chair of the Board of Directors of the Company in May 2020 and has served as a director of the Company since January 2017. Ms. Pierce is Senior Executive Vice President, Private Client Group & Regional Banking Director and Chair of Michigan for Huntington National Bank. Ms. Pierce joined Huntington in 2016 after its merger with FirstMerit Corporation in 2016. While at FirstMerit, Ms. Pierce served as Vice Chairman of FirstMerit Corporation and Chairman and CEO of FirstMerit Michigan, from 2013 to 2016. Ms. Pierce currently serves as a board member of Barton Malow Enterprises, Penske Automotive Group and American Axle & Manufacturing, Inc. She also serves as the vice chair of Business Leaders of Michigan, chair of the Detroit Financial Advisory Board and the chair of the Henry Ford Health System. The Board selected Ms. Pierce to serve as a director due to her leadership experience and familiarity with the geographic region in which the Company operates and conducts business.
Kevin L. Prust, 66. Mr. Prust became a director of the Company in January 2017. Mr. Prust retired in 2014 as Executive Vice President and Chief Financial Officer of The Weitz Company, LLC, a large national and international construction firm, a position he held since joining the company in 2009. Prior to that, Mr. Prust was with McGladrey & Pullen LLP, a national CPA firm, from 1978 through 2008 serving in various positions and becoming partner in 1985. Mr. Prust previously served on the board of Mercy Medical Center, in Des Moines, Iowa from 2009 to 2018. In 2015 Mr. Prust served on the board of Stock Building Supply Holdings, Inc. until the company was acquired. The Board selected Mr. Prust to serve as a director because of the expansive financial and accounting experience he obtained as a chief financial officer as well as his familiarity with the geographic region in which the Company operates and conducts business. Mr. Prust serves on the Audit and Risk Committee and the Board has determined that Mr. Prust is an “audit committee financial expert,” as that term is defined under applicable SEC rules.
A. Douglas Rothwell, 65. Mr. Rothwell became a director of the Company in October 2017. Mr. Rothwell served as President and CEO of Business Leaders for Michigan - a business roundtable of the state’s top 100
CEOs from 2005 through 2020. Mr. Rothwell currently chairs the University of North Carolina at Chapel Hill’s (“UNC”) Ackland Museum board in addition to serving as an Executive Residence for Economic Development at UNC. He previously chaired the Michigan Economic Development Corporation, the American Center for Mobility and the UNC Board of Visitors. The Board selected Mr. Rothwell to serve as a director because of his vast experience working with business leaders in various industries to foster business development and growth and his familiarity and business contacts within the geographic region in which the Company operates and conducts business. Mr. Rothwell serves as the Chair of the Governance and Human Resources Committee.
EXECUTIVE OFFICERS
Set forth below are the names, ages and titles of our current executive officers and a description of their business experience. Our executive officers serve as executive officers at the pleasure of the Board of Directors.
Linda H. Apsey, 52. Ms. Apsey’s background is described above under “Directors.”
Gretchen L. Holloway, 47. Ms. Holloway was named Senior Vice President and Chief Financial Officer in July 2017. Prior to this role, Ms. Holloway served as Vice President, Interim Chief Financial Officer and Treasurer, a position in which she served since October 2016. In her role, Ms. Holloway is responsible for the Company’s accounting, internal audit, treasury, financial planning and analysis, management reporting, risk management and tax functions. From May 2016 to October 2016, Ms. Holloway was Vice President and Treasurer and from November 2015 until May 2016, Ms. Holloway served as Vice President, Finance and Treasurer of the Company. In this role and her immediate past role, she was responsible for all treasury and corporate planning activities including cash management and as the Company’s liaison with the investment banking community and rating agencies. Ms. Holloway served from February 2015 to November 2015 as Vice President, Finance of the Company, where she was responsible for corporate finance activities including oversight of the budget and forecast processes and other financial analysis. Ms. Holloway currently serves as a member of the Finance & Audit Committee for the Children’s Hospital of Michigan Foundation and as a member of the Board of Directors of Inforum.
Jon E. Jipping, 55. Jon E. Jipping has served as Executive Vice President and Chief Operating Officer since June 2007. Mr. Jipping is responsible for transmission system planning, system operations, engineering, supply chain, field construction and maintenance, and information technology. Prior to this appointment, Mr. Jipping served as Senior Vice President - Engineering and was responsible for transmission system design, project engineering and asset management. Mr. Jipping joined the Company as Director of Engineering in March 2003, was appointed Vice President - Engineering in 2005 and was named Senior Vice President in February 2006. Mr. Jipping currently serves on the board of Wataynikaneyap Power PM Inc., an entity owned by FortisOntario, Inc., a subsidiary of Fortis, which was created to develop and operate transmission to connect remote First Nation communities to the electrical grid in northwestern Ontario, Canada. He was appointed to the Michigan Technological University Board of Trustees as a Board Member in 2020.
Christine Mason Soneral, 49. Christine Mason Soneral has served as Senior Vice President, General Counsel, Secretary and Chief Compliance Officer since October 2020. She was named Senior Vice President and General Counsel in April 2015 and served as Vice President and General Counsel from February 2015 through this appointment. She is responsible for all corporate legal affairs and the leadership of our legal department, which includes the legal, real estate, contract administration and corporate compliance functions. Prior to this role, Ms. Mason Soneral was Vice President and General Counsel-Utility Operations since 2007 and was responsible for legal matters connected with the operations, capital projects, contract, regulatory, property and litigation matters of the Company’s Regulated Operating Subsidiaries. Ms. Mason Soneral served on the board of Citizens Research Council, a privately funded, not-for-profit public affairs research organization from 2014 to 2020. Ms. Mason Soneral also currently serves as a member of the Michigan State University College of Social Science's External Advisory Board and is a Co-Founder and Director of Michigan State University’s Women’s Leadership Institute.
Krista K. Tanner, 47. Ms. Tanner has served as our Senior Vice President and Chief Business Officer since February 2019. Ms. Tanner is responsible for strategic direction, customer service, local government and community affairs and financial performance for four of the Company’s operating subsidiaries: ITC Midwest, ITC Great Plains, ITCTransmission and METC. In addition, she is responsible for federal regulatory and legislative affairs and marketing and communications. Ms. Tanner joined the Company in November 2014 where she
served as Vice President, ITC Holdings and President, ITC Midwest. In this role she served as the business unit head, providing leadership and strategic direction for ITC Midwest. Ms. Tanner joined the Company from Alliant Energy, where she served as director of regulatory policy from 2011 to 2014. While at Alliant Energy she directed Alliant Energy’s regional and federal regulatory policy group and led Alliant Energy’s legal strategy across regulatory jurisdictions. Prior to working at Alliant Energy, Ms. Tanner was a state regulatory commissioner on the Iowa Utilities Board from 2007 - 2011. Ms. Tanner previously served as a member of the Board of Directors of the Midwest Reliability Organization from 2017 to 2019. Ms. Tanner currently serves as a member of the Board of Directors of Delta Dental of Iowa.
Code of Conduct and Ethics
We have adopted a Code of Conduct and Ethics that applies to all of our directors, employees and executive officers, including our chief executive officer, chief financial officer and principal accounting officer. The Code of Conduct and Ethics, as currently in effect (together with any amendments that may be adopted from time to time), is available on our website at www.itc-holdings.com. To the extent required by the Code of Conduct and Ethics or by applicable law, we will post any amendments to the Code of Conduct and Ethics and any waivers that are required to be disclosed by the rules of the SEC on our website, within the required periods.

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ITEM 11. EXECUTIVE COMPENSATION
ITEM 11. EXECUTIVE COMPENSATION.
COMPENSATION OF EXECUTIVE OFFICERS AND DIRECTORS
Compensation Discussion and Analysis
The following Compensation Discussion and Analysis describes the elements of compensation for our Chief Executive Officer (or “CEO”), our Chief Financial Officer and the three other most highly compensated executive officers who were serving as such at December 31, 2021. We refer to these individuals collectively as the “named executive officers” or “NEOs.”
The Company’s named executive officers for 2021 were:
Name
Position
Linda H. Apsey President and Chief Executive Officer
Gretchen L. Holloway Senior Vice President and Chief Financial Officer
Jon E. Jipping Executive Vice President and Chief Operating Officer
Christine Mason Soneral Senior Vice President, General Counsel, Secretary and Chief Compliance Officer
Krista Tanner Senior Vice Present and Chief Business Unit Officer
Executive Summary
The Governance and Human Resources Committee (the “Committee”) is responsible for determining the compensation of our NEOs and administering the plans in which the NEOs participate. The goals of our compensation system are to attract first-class executive talent in a competitive environment and to motivate and retain key employees who are crucial to our success by rewarding Company and individual performance that promotes long-term sustainable growth and increases shareholder value. The key components of our NEOs' compensation package include base salary, annual cash incentive bonuses, long-term equity incentives, as well as certain perquisites and other benefits. In determining the amount of NEO compensation, we consider competitive compensation practices of other utilities and similarly sized organizations, the executive's individual performance against objectives, the executive's responsibilities and expertise, and our performance in relation to annual goals that are designed to strengthen and enhance our value.
The Committee made the following decisions with regard to executive compensation in 2021:
•Base salary increases. Base salary increases were provided to each of our NEOs in 2021 to reward individual performance and to remain competitive and aligned with market.
•Annual cash incentive bonuses. The NEOs earned cash incentive bonuses for 2021 performance of approximately 163% of target. This was based on achieving 100% of the performance targets established under the annual corporate performance bonus plan in early 2021 and achievement of certain performance factors which resulted in a bonus multiplier of 1.63. See “Compensation Discussion and
Analysis - Key Components of Our NEO Compensation Program - Annual Corporate Performance Bonus.”
•Long-term equity incentives. We granted long-term equity incentive awards to our NEOs in January 2021. Total award opportunities were set as a percentage of base salary and delivered one-third in the form of SBUs and two-thirds in the form of PBUs.
Overview and Philosophy
The objectives of our compensation program are to attract first-class executive talent in a competitive environment and to motivate and retain key employees who are crucial to our success by rewarding Company and individual performance that promotes long-term sustainable growth and increases shareholder value by:
•Performing best-in-class utility operations;
•Improving reliability, reducing congestion, and facilitating access to generation resources; and
•Utilizing our experience and skills to seek and identify opportunities to invest in needed transmission and to optimize the value of those investments.
Our compensation program is designed to motivate and reward individual and corporate performance. Our compensation philosophy is to:
•Provide for flexibility in pay practices to recognize our unique position and growth proposition;
•Use a market-based pay program aligned with pay-for-performance objectives;
•Leverage incentives, where possible, and align long-term equity incentive awards with improvements in our financial performance and shareholder value;
•Provide benefits through flexible, cost-effective plans while taking into account business needs and affordability; and
•Provide other non-monetary awards to recognize and incentivize performance.
Risk and Reward Balance
When reviewing the compensation program, the Committee considers the impact of the program on the Company’s risk profile. The Committee believes that the compensation program has been structured with the appropriate mix and design of elements to provide strong incentives for executives to balance risk and reward, without excessive risk taking.
The Committee engaged FW Cook, its independent compensation consultant, to conduct an annual comprehensive compensation program risk assessment. In July 2021, FW Cook reviewed the attributes and structure of our executive compensation programs for the purpose of identifying potential sources of risk within the program design. The review covered compensation plan design and administration/governance risk.
Based on its own analysis and a report from FW Cook concluding that the Company’s compensation programs do not create risks that are reasonably likely to have a material adverse impact on the Company, the Committee concluded that none of our compensation programs and features contain elements that create material risk to the Company. Risk mitigating factors with respect to the Company’s compensation programs included a market competitive pay mix, the linking of pay to performance through annual cash bonus and long-term equity incentive plans, caps on annual cash bonus and long-term equity incentive plan payouts, various performance measures that are both financially and operationally focused, stock ownership guidelines, prohibition on hedging and pledging, oversight by an independent committee of directors, regular review of NEO tally sheets and engagement of an independent compensation consultant.
Benchmarking and Relationship of Compensation Elements
Benchmarking. We reviewed market competitive target pay levels from two distinct market samples, utility and general industry data, as reflected in published surveys. FW Cook compiled data for the following components of compensation - base salary, target annual cash bonus incentive and target long-term incentive, as well as target total cash compensation and target total direct compensation. Position-specific market target pay levels are reviewed for utility-specific data from the Willis Towers Watson Energy Services Executive Compensation Survey and general industry data from the Willis Towers Watson General Industry Executive
Compensation Survey. The energy services data is used as our primary source with the general industry data provided as an additional reference point for positions other than those specific to the utility industry. The market data were aged and size-adjusted to correspond to our adjusted revenue scope. The adjusted revenue scope accounts for our unique business model and reflects the competitive incremental revenue that would normally be embedded in rates to reflect a typical cost of goods sold factor.
Our compensation strategy is to target compensation at the median (50th percentile) of the energy services benchmark data, plus or minus 20%, based on consideration of individual characteristics (performance, experience, etc.), internal equity and other factors. The Committee adopted this strategy in October 2019. In November 2020, the Committee reviewed the benchmarking study conducted by its independent consultant comparing NEO target total direct compensation, which is the sum of base salary, target annual incentives and target long-term incentives, to the 25th, 50th and 75th percentile survey data to assess the market competitiveness of our compensation opportunities. Overall, the study found target total direct compensation provided to our NEOs is at the high end of, and in some cases exceeds, the targeted competitive position. Current positioning reflects median base salaries and above median target bonus and long-term equity incentive opportunities. The Committee continues to monitor and balance competitive practices, talent needs and cost considerations when setting compensation.
Use of Tally Sheets. The Committee reviews tally sheets, every other year, as prepared by management to facilitate its assessment of the total annual compensation of our NEOs. The tally sheets contain annual cash compensation (salary and bonuses), long-term equity incentives, benefit contributions and perquisites. In addition, the tally sheets include retirement program balances, outstanding vested and unvested equity values and potential severance and termination scenario values.
Pay Review Process. In addition to the Committee’s benchmarking analysis, our CEO reviewed and examined market survey compensation levels and practices, as well as individual responsibilities and performance, our compensation philosophy and other related information to develop proposed compensation for each of our NEOs, other than herself. Ms. Apsey evaluated the performance of the NEOs, other than herself, and made recommendations on their salaries, target cash bonus incentive levels and long-term equity incentive awards. The Committee considered these recommendations in its decision making and conferred with FW Cook to understand the impact and result of any such recommendations. The Committee uses market data from FW Cook and makes recommendations on Ms. Apsey’s salary, cash bonus incentive targets and long-term equity incentive awards to the Board of Directors. The Board of Directors (other than Ms. Apsey) evaluates Ms. Apsey’s performance and considers the Committee’s recommendations in its decision making.
The Committee reviewed and considered each element of compensation and the resulting target total direct compensation, along with the objectives of our compensation program, the input of the CEO and the market data to set the 2021 target pay levels. The Committee did not determine the mix of compensation elements using a pre-set formula. In setting executive compensation levels, the Committee retained full discretion to consider or disregard data collected through benchmarking studies. In addition to the market data, compensation decisions also considered individual and Company performance, retention concerns, the importance of the position, internal equity and other factors.
Key Components of Our NEO Compensation Program
The key components of our executive compensation program are discussed below.
•Base Salary - provides sufficient competitive pay to attract and retain experienced and successful executives.
•Cash Bonus Incentive - encourages and rewards contributions to our annual corporate performance goals.
•Long Term Equity Incentives - encourages a multi-year focus on performance, rewards building long-term shareholder value and helps retain NEOs.
The other elements of our executive compensation program are discussed below under the heading “Other Components of Our Executive Compensation Program” which summarize the benefit programs that are available to our NEOs.
Base Salary
The Committee annually reviews and approves the base salaries, and any adjustments thereto, of the NEOs. In making these determinations, the Committee considers the executive’s job responsibilities, individual performance, leadership and years of experience, the performance of the Company, the recommendation of the CEO (except for the base salary of the CEO) and the target total direct compensation package as well as the benchmarking analysis conducted by its advisor.
The 2021 base salaries for the NEOs, including any year-over-year change, were:
NEO 2020 Base Salary 2021 Base Salary Percent Increase
Linda H. Apsey $ 816,000 $ 840,500 3.0 %
Gretchen L. Holloway 397,800 411,700 3.5 %
Jon E. Jipping 585,800 597,500 2.0 %
Christine Mason Soneral 393,900 399,800 1.5 %
Krista Tanner 339,600 354,900 4.5 %
Ms. Tanner’s higher percentage increase reflects her expanding role and responsibilities.
Annual Corporate Performance Bonus
Early each year, the Committee approves our annual corporate performance bonus plan goals and targets, which are based on key Company objectives relating to operational excellence and superior financial performance. The corporate performance goals and targets were designed to align the interests of customers, the shareholder and management, and encourage teamwork and coordination among all of our executives and employees with a common focus on the growth and success of the Company.
The annual corporate performance bonus plan goals were individually weighted. Weights were assigned to each goal based on areas of focus during the year and difficulty in achieving target performance. Weights were also assigned so that there was a balance between operational and financial goals. Each goal operated independently, and, for most goals, there was not a range of acceptable performance; if a goal was not achieved, there was no payout for that goal. Where performance goals were stated in a range, the threshold goals were generally expected to be achieved while the maximum goals were considered “stretch” goals with lower expectation of achievement. The bonus goal targets were designed to be challenging to meet, while remaining achievable.
For 2021, the ACBP consisted of four primary measurement categories: Financial, Safety & Compliance, System Performance and Capital Project Plan. Financial goals, representing 20%, plus Safety & Compliance, representing 20%, determined 40% of the target bonus opportunity, while System Performance, representing 30%, and Capital Project Plan, representing 30%, determined the remaining 60% of the target bonus opportunity. This reflected the inherent importance of driving operational performance, reliability and needed investment in our transmission system for the benefit of our customers.
Target levels for the corporate performance goals were determined based on our annual and long-term strategic plans, historical performance, expectations for future growth and desired improvement over time. Our safety, operations and security goals were established to deliver high performance in core company operations. Benchmarks and metrics were used in connection with these goals to establish a level of performance in the top decile or quartile within our industry. Likewise, our infrastructure protection goals led to the deployment of industry leading practices resulting in a generally enhanced security posture.
Corporate performance goal criteria approved by the Committee for 2021, the rationale for the target goal (in some cases in relation to the prior year target) and actual bonus results, were as set forth below.
Financial goals represented 20% of the total maximum annual bonus target and included specific measures for Non-Field Operation and Maintenance Expense and Net Income.
Category Goal Rationale for Goal Rationale for Target Goal Potential Payout 2021 Results Actual Payout
Financial
20% Maximum Potential Payout Non-field Operation and Maintenance Expense and General and Administrative Expenses Controlling general and administrative expenses is an important part of controlling rates charged to transmission customers. Target is consistent with the approach used in 2020 and based on the 2021 Board-approved budget.
Non-Field O&M and G&A expense at or under budget of $168M. 10 % $142M 10%
Adjusted Net Income (1) Represents the Company’s financial performance as it reflects a true measure of earnings contributions from our Regulated Operating Subsidiaries. Target based on the 2021 Board-approved budget.
Adjusted Net Income at or above $504M to achieve 10%;
Adjusted Net Income at or above $479M to achieve 5%. 5% - 10% $518M 10%
Total 20 % 20%
Safety & Compliance goals represented 20% of the total maximum annual bonus target and included specific measures for Lost Time, Recordable Incidents and Infrastructure Protection.
Category Goal Rationale for Goal Rationale for Target Potential Payout 2021 Results Actual Payout
Safety & Compliance
20% Maximum Potential Payout Safety as measured by lost time Maintaining the safety of our employees and contractors is a core value and is at the foundation of our success. Target number of incidents remained the same as prior years and was based on industry top decile performance, which reflects an aggressive view and philosophy on the importance of safety.
2 or fewer lost work day cases for injuries to Company employees and specified contract employees. 5 % 0 5%
Safety as measured by recordable incidents Maintaining the safety of our employees and contractors is a core value and is at the foundation of our success. Target number of incidents unchanged from prior year and was based on industry top decile performance, which reflects an aggressive view and philosophy on the importance of safety.
8 or fewer recordable incidents for injuries to Company employees and specified contract employees. 5 % 1 5%
Infrastructure Protection Maintaining cyber and physical security is critical to ensuring system reliability and ongoing operations. Goal focused on implementing updated security objectives. Emphasized securing our information systems and physical space, helping protect our most important assets.
Implementation of the 2021 Cyber Plan and Physical Security Plan, as presented to and approved by the Board of Directors, implementation of each Plan worth 5%. 10 % Completed 10%
Total 20 % 20 %
System Performance goals represented 60% of the total maximum annual bonus target and included specific measures for System Outages, Maintenance Plans and Capital Project Plan.
Category Goal Rationale for Goal Rationale for Target Potential Payout 2021 Results Actual Payout
System Performance and Capital Project Plan
60% Maximum Potential Payout Outage frequency Reducing and limiting system outages are critical to ensuring system reliability. Target unchanged from prior year for ITCTransmission, reduced from prior year for METC and ITC Midwest; all targets aligned with industry benchmark data. Number of Forced, Sustained Line Outages, excluding the "External" cause classification, for:
ITCTransmission (13 or fewer, representing top decile performance);
METC (23 or fewer, representing top decile performance);
ITC Midwest (59 or fewer, representing top decile performance, no more than 48 at the 69kV level representing top quartile performance.);
Each target is worth 5%. 15 % ITCTransmission - 12
METC - 15
ITC Midwest - 47/36
15%
Field Operation and Maintenance Plan Performing necessary preventive maintenance is critical to ensuring system reliability. Target is reflective of goal to complete the normal maintenance schedule of high priority maintenance activities. Complete high priority 2021 Field O&M Initiatives for:
ITCTransmission (15)
METC (13)
ITC Midwest (10)
Each target worth 5%.
Payout reduced by 5% if not at or under Field O&M overall maintenance budget of $92M. 15 % All high priority Field O&M initiatives completed under budget at $89M 15%
Capital Project Plan Performing necessary system upgrades is critical to ensuring system reliability, providing a robust transmission grid and delivering financial performance. Target is based on accrued capital investment.
The maximum payout represents the risk-adjusted capital investment plan for 2021, with a threshold level also established.
Complete $751M of the 2021 Capital Project Plan to achieve 30%; Complete $711M to achieve 15%.
15 - 30% $876M 30%
60 % 60%
Total Bonus (as a percent of target bonus level) 100 % 100%
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(1)We utilize adjusted net income as a criterion in measuring achievement of financial goals for our annual corporate performance bonus. This non-GAAP financial measure reconciles to net income of our Regulated Operating Subsidiaries with adjustments under $1 million.
Additionally, our executives, including the NEOs, are eligible for an executive bonus multiplier. To further motivate management to provide value to the shareholder, we include a performance factor under which their ACPB payouts may be increased for outperformance by as much as 100% based on multiple measures, as follows:
Measure Threshold Maximum Achievement Multiplier Weight Result
Capital Project Plan $790M $853M $876M 2.00x 30% 0.60x
Adjusted Consolidated Net Income (1) $398M $418M $407M 1.50x 30% 0.45x
Strategic Plan Objectives Create 6 Objectives Achieve 4 Objectives Achieved 1 Objective 1.25x 30% 0.38x
Inclusion & Diversity Plan Create Plan Achieve 5 Goals Achieved 5 Goals 2.00x 10% 0.20x
Bonus Multiplier 1.63x
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(1)We utilize adjusted consolidated net income as a criterion in measuring achievement of financial goals for the executive bonus multiplier. This non-GAAP financial measure reconciles to consolidated net income of ITC Holdings as follows:
(In millions of USD) 2021
Net Income $ 406
Adjustments 1
Adjusted Consolidated Net Income $ 407
Each measure has an established scale, which includes a threshold level and below equating to a 1.00x multiplier, having no impact on the bonus award, to a maximum of 2.00x, which would increase the bonus by 100% to a maximum of 200% of target. Achievement against performance scales related to each of the above metrics produced an executive bonus multiplier of 1.63x. This performance factor was applied to each executive’s ACPB factor of 100% to produce a final payment of approximately 163% of target.
Bonuses are based on a target bonus, which for each executive is a percentage of his or her base salary. The Committee considers each individual’s job responsibilities and the results of its benchmarking analysis when determining the base bonus percentage for the executive officers, including the NEOs, which we refer to as the “target bonus levels.” Target bonus levels for 2021 were 100% of base salary for each NEO.
Long-Term Incentive
The Committee provides and maintains a long-term equity incentive program under the 2017 Omnibus Plan, the Executive Omnibus Plan and the Fortis Inc. 2020 Restricted Share Unit Plan. In February 2021, the Committee approved grants of SBUs and PBUs to the NEOs, based on our CEO’s recommendation (except for grants to the CEO), and also on the Committee’s assessment of the performance of the Company and the executive. Award opportunities for the NEOs were provided in a mix of PBUs (weighted 67%) and SBUs (weighted 33%). The PBUs can be earned for results in two equally-weighted measures, Total Shareholder Return (relative to Fortis’ peer group) and ITC cumulative consolidated net income, over the three-year performance period. The PBU metrics were selected as Total Shareholder Return aligns with the Fortis shareholder experience and cumulative consolidated net income measures our sustained growth (organic and development), cost management and efficiency. Each unit is generally equivalent to one share of Fortis stock (as traded on the Toronto Stock Exchange) and earned PBU units are payable in cash and earned SBU units are payable in cash or Fortis common stock. Awards to the CEO were also presented to the Board of Directors by the Committee and ratified by the Board of Directors (other than the CEO). The amounts and more detailed terms of the 2021 SBU and PBU grants made under the Fortis Inc. 2020 Restricted Share Unit Plan and the Executive Omnibus Plan are described in the narrative following the Grants of Plan-Based Awards Table. The awards were designed to reward, motivate and encourage long-term performance, act as a retention mechanism, and further align the interests of the NEOs with the interests of the Fortis shareholders. Total value for the award for each grantee was determined based on a percentage of salary. For the NEOs, when the 2021 awards were made, the award values were targeted to be:
NEO Grant Value Percent of Salary
Ms. Apsey 250 %
Ms. Holloway 175 %
Mr. Jipping 175 %
Ms. Mason Soneral 175 %
Ms. Tanner 175 %
In determining the size of grants under the long-term incentive program and the award mix, the Committee considered market practice, the recommendation of the CEO (with respect to grants other than to the CEO) in light of comparisons to benchmarking data, expense to the Company and the practice of other U.S. Fortis subsidiary companies.
Other Components of Our Executive Compensation Program
Pension Benefits. As is common in our industry and as established pursuant to our initial formation requirements included in the acquisition agreement with DTE Energy for ITCTransmission, we maintain a tax-qualified defined benefit retirement plan for eligible employees, comprised of a traditional pension component and a cash balance component. All employees, including the NEOs, participate in either the traditional component or the cash balance component. We have also established a supplemental nonqualified, noncontributory retirement benefit plan for selected management employees: the Executive Supplemental Retirement Plan, or ESRP, in which all of the NEOs participate. This plan provides for benefits that supplement those provided by our qualified defined benefit retirement plan. Benefits payable to the NEOs pursuant to the retirement plans are set by the terms of those plans. The Committee exercises no regular discretionary authority in the determination of benefits. The retirement plans may be modified, amended or terminated at any time, although no such action may reduce a NEO’s earned benefits. See “Pension Benefits” for information regarding participation by the NEOs in our retirement plans as well as a description of the terms of the plans.
Benefits and Perquisites. The NEOs participate in a variety of benefit programs, which are designed to enable us to attract and retain our workforce in a competitive marketplace. These programs include our Savings and Investment Plan, which consists of an employee deferral contribution component and an employer safe-harbor matching contribution component.
Our NEOs are provided a limited number of perquisites in addition to benefits provided to our other employees. The purpose of these perquisites is to minimize distractions from the NEOs’ attention to important Company initiatives, to facilitate their access to work functions and personnel, and to encourage interactions among NEOs and others within professional, business and local communities. NEOs are provided perquisites such as auto allowance, financial, estate and legal planning, income tax return preparation, annual physical, club memberships, and personal liability insurance. Additionally, we own aircraft to facilitate the business travel schedules of our executives and other employees, particularly to locations that do not provide efficient commercial flight schedules. Ms. Apsey and guests who travel with her are permitted to travel for personal business on our aircraft, with an annual maximum of 50 flight hours for such personal travel. Ms. Apsey incurs imputed income for all guests and herself for personal travel in the amount of the incremental cost to the Company of such travel.
We purchase tickets to various sporting, civic, cultural, charity and entertainment events. We use these tickets for business development, partnership building, charitable donations and community involvement. If not used for business purposes, we may make these tickets available to employees, including the NEOs, as a form of recognition and reward for their efforts. Because such tickets have already been purchased, we do not believe that there is any aggregate incremental cost to the Company if a NEO uses a ticket for personal purposes.
None of the NEOs are reimbursed for income taxes associated with the value of the perquisites. The Committee continues to monitor and review the Company’s perquisite program. Perquisites are further discussed in footnote 4 to the “Summary Compensation Table.”
Potential Severance Compensation. Pursuant to their employment agreements, each NEO is entitled to certain benefits and payments upon a termination of his or her employment. Benefits and payments to be
provided vary based on the circumstances of the termination. We believe it is important to provide these protections in order to ensure our NEOs will remain engaged and committed to us during an acquisition of the Company or other transition in management. See “Employment Agreements and Potential Payments Upon Termination or Change in Control” for further detail on these employment agreements, including a discussion of the compensation to be provided upon termination or a change in control.
Stock Ownership Policy
The Board believes that having a share ownership policy is a key element of strong corporate governance and aligns the interests of management with the interests of Fortis shareholders. Under these guidelines, which became effective January 1, 2020, officers, including NEOs, must achieve and maintain the applicable level of Fortis stock ownership by the fifth anniversary of when the guidelines first became applicable to the individual. The current levels are as follows:
Position Ownership Level
Chief Executive Officer 2x annual base salary
Executive and Senior Vice Presidents 1.5x annual base salary
Vice Presidents 1x annual base salary
The securities that qualify for the purpose of determining compliance with the policy are common shares of Fortis stock and the executive’s outstanding SBU awards. Share ownership levels include Fortis securities beneficially owned: (i) in a trust; (ii) by the executive’s spouse; and (iii) by the executive’s minor children. Any executive that fails to maintain minimum stock ownership under these guidelines will not be eligible for future equity-based compensation awards until the later of (i) the end of the one-year period commencing on the date of such failure or (ii) such time as the executive is again in compliance with the guidelines. As of December 31, 2021, each of the NEOs was in compliance with this policy.
Governance and Human Resources Committee Report
The Governance and Human Resources Committee has reviewed and discussed this Compensation Discussion and Analysis with management and, based on the review and discussions with management, has recommended to the Board of Directors that the Compensation Discussion and Analysis be included in this report.
DEBORA M. FRODL
RONNIE D. HAWKINS, JR.
DAVID G. HUTCHENS
JAMES P. LAURITO
A. DOUGLAS ROTHWELL
Summary Compensation
The following table provides a summary of compensation paid or accrued by the Company and its subsidiaries to or on behalf of the NEOs for services rendered by them during each of the last three calendar years, as required by applicable SEC rules and regulations. The material terms of plans and agreements pursuant to which certain items set forth below were paid are discussed elsewhere in Compensation of Executive Officers and Directors.
Summary Compensation Table
Name Year Salary ($) Stock Awards ($) (1) Non-Equity Incentive Plan Compensation ($) (2) Change in Pension Value & Non-qualified Deferred Compensation Earnings
($)(3) All Other Compensation ($) (4) Total ($)
(a) (b) (c) (e) (f) (g) (h) (i)
Linda H. Apsey,
President & CEO 2021 $ 843,732 $ 2,086,868 $ 1,370,015 $ 184,341 $ 100,652 $ 4,585,608
2020 819,630 2,036,614 1,151,376 359,039 84,625 4,451,284
2019 794,692 2,061,860 1,352,000 322,636 55,516 4,586,704
Gretchen L. Holloway
SVP & CFO 2021 413,284 715,560 671,071 101,514 36,871 1,938,300
2020 399,570 695,003 561,296 181,670 36,936 1,874,475
2019 388,115 703,598 659,100 147,032 36,362 1,934,207
Jon E. Jipping,
EVP & COO 2021 599,799 1,038,492 973,925 211,095 38,499 2,861,810
2020 589,347 1,023,422 826,564 522,326 38,199 2,999,858
2019 578,000 1,046,405 980,200 568,493 38,169 3,211,267
Christine Mason Soneral, SVP, General Counsel, Secretary & CCO 2021 401,377 694,865 651,674 94,802 38,746 1,881,464
2020 396,285 688,169 555,793 200,948 35,950 1,877,145
2019 389,469 703,598 659,100 170,742 36,500 1,959,409
Krista Tanner,
SVP & CBUO 2021 356,265 616,837 578,487 94,877 36,113 1,682,579
2020 339,797 593,288 479,176 123,653 34,620 1,570,534
____________________________
(1) The amounts reported in this column represent the grant date fair value of PBU awards and SBU awards granted to the NEOs under the 2017 Omnibus Plan, the Executive Omnibus Plan and the Fortis Inc. 2020 Restricted Share Unit Plan in accordance with FASB Accounting Standards Codification Topic 718, or ASC 718.
The grant date fair value of the SBU awards is based on the applicable share price on the grant date. The grant date fair value of the PBU awards is based on the applicable share price on the grant date and the payout of the performance (which approximates target achievement), and market conditions. The SBU awards and PBU awards are liability awards, subject to remeasurement through the vesting date, and settled in cash, see “Grants of Plan-Based Awards.” The value of the 2021 PBU awards at the grant date assuming that the highest level of performance conditions will be achieved are as follows:
Ms. Apsey $ 2,782,565
Ms. Holloway 954,115
Mr. Jipping 1,384,709
Ms. Mason Soneral 926,514
Ms. Tanner 822,480
(2) The amounts reported in this column include cash awards tied to the achievement of annual Company performance goals under our annual corporate performance bonus plan in effect for each of 2021, 2020 and 2019. For information regarding the corporate goals for 2021, see “Compensation Discussion and Analysis - Key Components of Our NEO Compensation Program - Annual Corporate Performance Bonus."
(3) All amounts reported in this column pertain to the tax-qualified defined benefit pension plan and the supplemental nonqualified, noncontributory retirement plan maintained by the Company. None of the income on nonqualified deferred compensation was above-market or preferential. Variations in the amounts
from year to year reflect an additional year of service and pay changes used in the accrued benefit, as well as changes in assumptions on which the benefits are calculated, for which the formula has not been materially revised. The discount rate used for the present value of accumulated benefits was 3.44% in 2019, 2.74% for 2020 and 3.01% for 2021. In 2020, the mortality assumption was changed at year-end 2020 from the Adjusted RP-2014 table projected for future mortality improvements with MP-2017 generational scale to the Pri-2012 tables with MP-2020 mortality improvement scale.
(4) All Other Compensation includes amounts for auto allowance, financial, estate and legal planning, income tax return preparation, annual physical, club memberships, event tickets, personal liability insurance, personal use of company aircraft and for other benefits such as Company contributions on behalf of the NEOs pursuant to the matching component of the Savings and Investment Plan. Perquisites have been valued for purposes of these tables on the basis of the aggregate incremental cost to the Company. The incremental cost of the personal use of the Company aircraft was determined based upon the Company’s expenses incurred in connection with the actual costs of maintenance, landing, parking, crew and catering and estimated fuel costs relating to Ms. Apsey’s hours of use of the aircraft. Fuel expense was determined by calculating the average fuel cost for the month and the average amount of fuel used per hour. These benefits and perquisites for 2021, 2020 and 2019 are itemized in the table below as required by applicable SEC rules.
Name Year 401(k) Match Personal Use of Company Aircraft Other Benefits Total
Linda H. Apsey 2021 $ 17,400 $ 54,461 $ 28,791 $ 100,652
2020 17,100 40,440 27,085 84,625
2019 16,800 19,777 18,939 55,516
Gretchen L. Holloway 2021 15,550 - 21,321 36,871
2020 15,450 - 21,486 36,936
2019 15,100 - 21,262 36,362
Jon E. Jipping 2021 17,400 - 21,099 38,499
2020 17,100 - 21,099 38,199
2019 16,800 - 21,369 38,169
Christine Mason Soneral 2021 15,550 - 23,196 38,746
2020 15,450 - 20,500 35,950
2019 15,100 - 21,400 36,500
Krista Tanner 2021 14,659 - 21,454 36,113
2020 14,120 - 20,500 34,620
We purchase tickets to various sporting, civic, cultural, charity and entertainment events. We use these tickets for business development, partnership building, charitable donations and community involvement. If not used for business purposes, we may make these tickets available to employees, including the NEOs, as a form of recognition and reward for their efforts. Because such tickets have already been purchased, we do not believe that there is any aggregate incremental cost to the Company, if a NEO uses a ticket for personal purposes.
Grants of Plan-Based Awards
The following table sets forth information concerning each grant of an award made to a NEO during 2021.
Name Grant Date Award Type Estimated Future Payouts Under Non-Equity Incentive Plan Awards Estimated Future Payouts Under Equity Incentive Plan Awards All Other Stock Awards: Number of Shares of Stock or Units (#) Grant Date Fair Value of Stock and Option Awards ($)(3)
Threshold ($) Target ($)(1) Maximum ($)(1) Threshold (#) Target (#)(2) Maximum (#)(2)
(a) (b) (c) (d) (e) (f) (g) (h) (i) (j)
Linda H. Apsey 1/1/2021 SBU $ - $ - $ - - - - 17,036 $ 695,586
1/1/2021 PBU - - - 17,038 34,075 68,150 - 1,391,282
ACPB - 840,000 1,680,000 - - - - -
Gretchen L. Holloway 1/1/2021 SBU - - - - - - 5,841 238,502
1/1/2021 PBU - - - 5,842 11,684 23,368 - 477,058
ACPB - 411,700 823,400 - - - - -
Jon E. Jipping 1/1/2021 SBU - - - - - - 8,478 346,138
1/1/2021 PBU - - - 8,479 16,957 33,914 - 692,354
ACPB - 597,500 1,195,000 - - - - -
Christine Mason Soneral 1/1/2021 SBU - - - - - - 5,673 231,608
1/1/2021 PBU - - - 5,673 11,346 22,692 - 463,257
ACPB - 399,800 799,600 - - - - -
Krista Tanner 1/1/2021 SBU - - - - - - 5,035 205,597
1/1/2021 PBU - - - 5,036 10,072 20,144 - 411,240
ACPB - 354,900 709,800 - - - - -
____________________________
(1) The amount shown in Column (d) represents the potential payout for the ACPB based on “target bonus levels.” The amount payable assuming maximum achievement of all bonus goals, including the bonus multiplier, is set forth in column (e). Actual dollar amounts paid are disclosed and reported in the “Summary Compensation Table” as Non-Equity Incentive Plan Compensation. For more information regarding the ACPBs, see “Compensation Discussion and Analysis - Key Components of Our NEO Compensation Program - Annual Corporate Performance Bonus.”
(2) Payment of each PBU award is contingent on meeting performance targets based on (1) Fortis Total Shareholder Return in comparison to the Total Shareholder Return during the performance period for each of the companies that comprise the 2021 Fortis peer group and (2) cumulative consolidated net income for each fiscal year during the performance period. The performance measures are independent of each other. If threshold, target or maximum performance goals are attained in the performance period, 50%, 100% or 200% of the target amount, respectively, may be earned. If actual performance falls between threshold, target and maximum, the awards would be prorated between levels based on performance outcome. For more information regarding performance share awards, see “Grant of Plan-Based Awards - Performance-Based Unit Award Agreements.”
(3) Grant Date Fair Value consists of SBUs and PBUs awarded under the Fortis Inc. 2020 Restricted Share Unit Plan and Executive Omnibus Plan, respectively, with a grant date of January 1, 2021. The SBUs and PBUs reflected here are recorded at fair value at the date of grant, which was $40.83 per share. Share fair values were converted from Canadian Dollars to US Dollars using the “Award Conversion Rate” defined in the plans.
The Committee has established long-term incentive targets as a percentage of the base salary for each NEO in consideration of benchmarking data on total direct compensation, the importance of the NEO’s position to the success of the Company, our need to create meaningful incentives to enhance performance and the culture of teamwork that makes our company successful. The Committee did not have a pre-established targeted allocation of total direct compensation.
The Committee had the power to award SBUs in the form of equity or cash under the Fortis Inc. 2020 Restricted Share Unit Plan and PBUs in the form of equity or cash under the Executive Omnibus Plan with the terms of each award set forth in a written agreement with the recipient. Grants made in 2021 to the NEOs were made under their respective plans pursuant to terms stated in the SBU and PBU award agreements.
Performance-Based Unit Award Agreements
The PBU award agreements entered into with each NEO on January 1, 2021 (the “PBU Grant Date”) (each a “PBU Agreement”) provide generally that the award will vest on January 1, 2024 (the “PBU Vesting Date”) to the extent one or more of the performance goals are met and if the grantee continues to be employed by the Company through the PBU Vesting Date. One-half of the Target Number of PBUs shall be related to the Fortis Total Shareholder Return goal (the “TSR goal”) and one-half of the Target Number of PBUs shall be related to the Cumulative Consolidated Net Income goal (the “CCNI goal”). The PBUs will become earned as set forth in the following table:
Measurement Category Goal at Threshold Shares at Threshold Goal at Target Shares at Target Goal at Maximum Shares at Maximum
Fortis Total Shareholder Return 30th percentile
50% of TSR Target Units 50th percentile
100% of TSR Target Units 85th percentile
200% of TSR Target Units
Cumulative Consolidated Net Income 99% of Target 50% of CCNI Target Units 100% of Target 100% of CCNI Target Units 103% of Target 200% of CCNI Target Units
The performance period for the award is January 1, 2021 through December 31, 2023 (the “Payment Criteria Period”). The performance measures are independent of each other; that is, if the threshold level of one performance measure is attained, units relating to that measure will be “earned” (subject to vesting as otherwise provided in the PBU Agreement) even if the threshold level of the other performance measure is not attained. The number of PBUs that are “earned” with respect to each performance measure will be prorated between levels based on performance. The Committee will have discretion to reduce the number of PBUs earned under certain circumstances.
Total Shareholder Return of Fortis will be compared to each of the companies (the “Peer Companies”) listed in the Fortis Peer Group 2021 Report excluding any company that is no longer traded on the Toronto Stock Exchange or a “national securities exchange” at the end of the Payment Criteria Period. The Peer Companies currently consist of the following 25 U.S. and Canadian public utility companies:
Alliant Energy Corporation Emera Incorporated PG&E Corporation
Ameren Corporation Entergy Corporation Pinnacle West Capital Corporation
Atmos Energy Corporation Evergy, Inc. PPL Corporation
Canadian Utilities Limited Eversource Energy Public Service Enterprise Group Inc.
CenterPoint Energy Inc. FirstEnergy Corp. Sempra Energy
CMS Energy Corporation Hydro One Limited UGI Corporation
Consolidated Edison Inc. NiSource Inc. WEC Energy Group, Inc.
DTE Energy Company OGE Energy Corp. Xcel Energy Inc.
Edison International
The Total Shareholder Return of Fortis and the Peer Companies shall be computed in U.S. dollars as follows:
A: Calculate the Market Price as of the first day of the Payment Criteria Period (if necessary, converted into U.S. dollars based on the Award Conversion Rate as defined in the Executive Omnibus Plan)
B: Calculate the Market Price as of the last day of the Payment Criteria Period (if necessary, converted into U.S. dollars based on the Award Conversion Rate)
C: Calculate the total dividends paid per share of its common stock (or equivalent security) during the Payment Criteria Period (if necessary, converted into U.S. dollars based on the Award Conversion Rate)
Total Shareholder Return = ((B - A) + C)/A
Adjusted Consolidated Net Income for the Company for each calendar year in the Payment Criteria Period shall be equal to net income as set forth in the Company’s audited consolidated financial statements contained in its annual report on Form 10-K for such year, as adjusted for extraordinary items and changes in Return on Equity, in each case at the Committee’s discretion. Cumulative Consolidated Net Income for the Company during the Payment Criteria Period shall be the sum of the Adjusted Consolidated Net Income for each of the three years in the Payment Criteria Period. See “Compensation Discussion and Analysis - Key Components of Our NEO Compensation Program - Annual Corporate Performance Bonus" for a reconciliation of Adjusted Consolidated Net Income to Net Income.
If the grantee ceases to be employed before the PBU Vesting Date due to death, disability or “Retirement” (as defined below), and the grantee has been employed with the Company for 15 years or more, the grantee will receive, following the PBU Vesting Date, the number of PBUs to which the grantee would have otherwise been entitled if the grantee had remained employed through the PBU Vesting Date. If the grantee ceases to be employed before the PBU Vesting Date due to death, disability or Retirement, and the grantee has been employed with the Company for less than 15 years, the grantee will receive, following the PBU Vesting Date, (i) one-third of the number of PBUs to which the grantee would have otherwise been entitled if the grantee had remained an employee through the PBU Vesting Date shall be deemed to have vested on the PBU Vesting Date if termination occurred on or after the one-year anniversary of the PBU Grant Date and before the two-year anniversary of the PBU Grant Date, and (ii) two-thirds of the number of PBUs to which the grantee would have otherwise been entitled if the grantee had remained an employee through the PBU Vesting Date shall be deemed to have vested on the PBU Vesting Date if termination occurred on or after the two-year anniversary of the PBU Grant Date but before the PBU Vesting Date. If termination occurs prior to the PBU Vesting Date other than as a result of death, disability or Retirement, grantee will forfeit the award.
“Retirement” is defined to mean termination of grantee’s employment with the Company upon or after completing 10 years of service with the Company after attaining the age of 45 if the grantee has provided the Company with at least six months’ written notice of such retirement.
Upon a “Change of Control,” as defined in the Executive Omnibus Plan, all outstanding PBUs become redeemable on the effective date of the consummation of the event resulting in the Change of Control (the “Change of Control Redemption Date”). In the event of a Change of Control, the payout percentage for outstanding PBUs is the product of (i) the higher of (A) 100% of the target number of PBUs in the award or (B) the actual payout percentage based on the Committee’s assessment of performance of the payment criteria from the beginning of the Payment Criteria Period for the award through the date of the Change of Control, multiplied by (ii) a fraction, the numerator of which is the number of days elapsed in the Payment Criteria Period for the award through the date on which the Change of Control occurred and the denominator of which is the total number of days in the payment criteria period for the award.
Grantees are entitled to receive additional PBUs equal to the “dividend equivalent” when a cash dividend is paid on common shares of Fortis stock (each a “Common Share”). Such “dividend equivalent” shall be equal to a fraction where the numerator is the product of (a) the number of PBUs in the grantee’s account on the date that the dividends are paid, including PBUs previously credited as “dividend equivalents,” multiplied by (b) the dividend paid per Common Share and the denominator of which is the “Market Price” of one Common Share calculated on the date that dividends are paid, converted to U.S. dollars based on the Award Conversion Rate. All “dividend equivalent” PBUs shall have a PBU Vesting Date which is the same as the PBU Vesting Date for the PBUs in respect of which such additional PBUs are credited.
Service-Based Unit Award Agreements
The SBU award agreements entered into with each NEO on January 1, 2021 (the “SBU Grant Date”) (each a “SBU Agreement”) provide generally that, so long as the grantee remains employed by the Company, the SBUs fully vest upon the earlier of (i) January 1, 2024 (the “SBU Vesting Date”) or (ii) the grantee's death, disability or “Retirement.” If the grantee ceases to be employed before the SBU Vesting Date due to death, disability or Retirement, and the grantee has been employed with the Company for 15 years or more, the grantee will receive, the number of SBUs to which the grantee would have otherwise been entitled if the grantee had remained employed through the SBU Vesting Date. If the grantee ceases to be employed before the SBU Vesting Date due to death, disability or Retirement, and the grantee has been employed with the Company for less than 15 years, the grantee will receive a prorated number of SBUs to reflect the actual period between the
SBU Grant Date and the date of the grantee’s death, disability or Retirement. If termination occurs prior to the SBU Vesting Date other than as a result of death, disability or Retirement, the grantee will forfeit the award.
Upon a “Change of Control,” all outstanding SBUs become redeemable on the date that is immediately prior to the Change of Control Redemption Date.
“Retirement” and “Change of Control” are defined in the same manner as defined in the description of the PBU Agreement disclosed above. Grantees are entitled to receive additional dividend equivalent SBUs in the same manner as defined in the description of the PBU Agreement disclosed above.
The SBU Agreement provides that the grantee may elect to have their SBU awards vest as common shares of Fortis Inc. stock or cash payment. If the grantee does not satisfy their share holding requirement stated in the Stock Ownership Policy, 50% of the SBU awards must settle in common shares of Fortis Inc. stock.
Outstanding Equity Awards at Fiscal Year-End
The following table provides information with respect to SBUs and PBUs that have not vested as of the end of 2021 held by the NEOs.
Name Number of Shares or Units of Stock That Have Not Vested (#) (SBUs) Market Value of Shares or Units of Stock That Have Not Vested ($) (SBUs) (1) Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested (#) (PBUs) Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested ($) (PBUs) (1)
(a) (b) (c) (d) (e)
Linda H. Apsey 17,617 (2) $ 850,365 70,464 (3) $ 3,401,317
17,688 (4) 853,796 70,757(5) 3,415,454
Gretchen L. Holloway 6,012 (2) 290,187 24,046 (3) 1,160,721
6,065 (4) 292,749 24,262 (5) 1,171,128
Jon E. Jipping 8,853 (2) 427,329 35,409 (3) 1,709,180
8,802 (4) 424,866 35,211 (5) 1,699,658
Christine Mason Soneral 5,953 (2) 287,342 23,810 (3) 1,149,290
5,890 (4) 284,287 23,560 (5) 1,137,249
Krista Tanner 5,132 (2) 247,731 20,527 (3) 990,821
5,228 (4) 252,360 20,915 (5) 1,009,551
____________________________
(1)Value was determined by multiplying the number of units that have not vested by the closing price of Fortis common stock on the NYSE as of December 31, 2021 ($48.27).
(2)These unvested SBUs were granted in 2020 and generally vest on January 1, 2023. These SBU numbers include the original SBU grant plus dividend equivalent units earned.
(3)These unvested PBUs were granted in 2020 and generally vest on January 1, 2023. These PBU numbers include the original PBU grant plus dividend equivalent units earned. The award contains performance conditions established by the Committee. In order for PBUs to vest such performance conditions must be achieved. Amounts reported reflect PBU payouts as if the maximum performance goals have been achieved.
(4)These unvested SBUs were granted in 2021 and generally vest on January 1, 2024. These SBU numbers include the original SBU grant plus dividend equivalent units earned.
(5)These unvested PBUs were granted in 2021 and generally vest on January 1, 2024. These PBU numbers include the original PBU grant plus dividend equivalent units earned. The award contains performance conditions established by the Committee. In order for PBUs to vest such performance conditions must be achieved. Amounts reported reflect PBU payouts as if the maximum performance goals have been achieved.
The PBU grants made to NEOs were made pursuant to the Executive Omnibus Plan and the SBU grants
made to NEOs were made pursuant to the Fortis Inc. Restricted Share Unit Plan. The terms of the grants are described above in the narrative discussion accompanying the “Grants of Plan-Based Awards” Table.
Stock Vested
The following table provides information with respect to SBUs and PBUs held by the NEOs that vested during 2021:
Stock Awards
Name Number of Shares or Units of Stock Acquired on Vesting (#) Value of Shares or Units of Stock Realized on Vesting ($) (1)
(a) (b) (c)
Linda H. Apsey 22,252 (2) $ 994,825
83,223 (3) 3,720,645
Gretchen L. Holloway 7,593 (2) 339,478
28,399 (3) 1,269,649
Jon E. Jipping 11,293 (2) 504,896
42,236 (3) 1,888,217
Christine Mason Soneral 7,593 (2) 339,478
28,399 (3) 1,269,649
Krista Tanner 4,520 (2) 202,068
16,904 (3) 755,729
____________________________
(1)Value is based on the 5-day volume weighted average price of common stock on the Toronto Stock Exchange on the vesting date, converted from Canadian Dollars to US Dollars using the “Award Conversion Rate” defined in the 2017 Omnibus Plan, which is $44.7608.
(2)Amounts reported reflect the vesting of SBUs granted March 6, 2019 and associated dividend equivalent units.
(3)Amounts reported reflect the vesting of PBUs granted March 6, 2019 and associated dividend equivalent units. The award contains performance conditions established by the Committee. The performance period ended on December 31, 2021. The Committee certified the achievement of 187% of the applicable performance goals on February 1, 2022.
Pension Benefits
The following table provides information with respect to each pension benefit plan that provides for payments or other benefits at, following or in connection with retirement. Those plans are the International Transmission Company Retirement Plan (the “Qualified Plan”) and the ESRP.
Pension Benefits Table
Name Plan Name Number of Years Credited Service (#)(1) Present Value of Accumulated Benefit ($)(2) Payments During Last Fiscal Year ($)
(a) (b) (c) (d) (e)
Linda H. Apsey Cash Balance Component 27.58 $ 484,463 N/A
ESRP Shift N/A 39,019 N/A
Total Qualified Plan 523,482 N/A
ESRP 18.83 2,299,303 N/A
Gretchen Holloway Cash Balance Component 17.95 342,794 N/A
Total Qualified Plan 342,794 N/A
ESRP 6.91 504,904 N/A
Jon E. Jipping Traditional Component 31.03 2,155,602 N/A
Total Qualified Plan 2,155,602 N/A
ESRP 16.92 1,824,457 N/A
Christine Mason Soneral Cash Balance Component 14.29 336,173 N/A
Total Qualified Plan 336,173 N/A
ESRP 14.28 903,985 N/A
Krista Tanner Cash Balance Component 7.14 156,244 N/A
Total Qualified Plan 156,244 N/A
ESRP 7.14 356,793 N/A
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(1) Credited service is estimated as of December 31, 2021 and represents the service reflected in the determination of benefits. For determining vesting, service with DTE Energy is counted for the Qualified Plan only.
For Ms. Apsey and Mr. Jipping, the credited service for the cash balance and traditional components of the Qualified Plan, respectively, includes service with DTE Energy. The Company began operations on February 28, 2003, following its acquisition of ITCTransmission from DTE Energy. As of that date, the benefits from DTE Energy’s qualified plan that had accrued, as well as the associated assets from DTE Energy’s pension trust, were transferred to the Qualified Plan. Therefore, even though DTE Energy service is included in determining the benefits under the traditional and cash balance components of the Qualified Plan, the benefits associated with this additional service do not represent a benefit augmentation, but rather a transfer of benefit liability and associated assets from DTE Energy’s qualified plan to the Qualified Plan. With respect to the ESRP, credited service includes Company service only for the period during which the NEO was an ESRP participant.
(2) The “Present Value of Accumulated Benefit” is the estimated lump-sum equivalent value measured as of December 31, 2021 (the “measurement date” used for financial accounting purposes) of the benefit that was earned as of that date. Certain benefits are payable as an annuity only, not as a lump sum, and/or may not be payable for several years in the future. The values reflected are based on several assumptions. The date at which the present values were estimated was December 31, 2021. The rate at which future expected benefit payments were discounted in calculating present values was 3.01%, the same rate used for fiscal year-end 2021 financial accounting disclosure of the Qualified Plan. The future annual earnings rate on account balances under the cash balance and ESRP shift components of the Qualified Plan, and for ESRP benefits, was assumed to be 1.94% for 2022 and 4.00% thereafter.
We assumed no NEOs would die or become disabled prior to retirement or terminate employment with us prior to becoming eligible for benefits unreduced for early retirement. The assumed retirement age for each executive was generally the earliest age at which benefits unreduced for early retirement were available under the respective plans. For the traditional component of the defined benefit plan, that age is the earlier of (1) age 58 with 30 years of service (including service with DTE Energy), or (2) age 60 with 15 years of service. For consistency, we generally use the same assumed retirement commencement age for other benefits, including benefits expressed as an account value where the concept of benefit reductions for early retirement is not meaningful. The assumed retirement benefit commencement ages were 58 for each NEO.
Post-retirement mortality was assumed to be in accordance with the Pri-2012 mortality table projected for future mortality improvements with MP-2020 generational scale. Benefits under the traditional component of the Qualified Plan were assumed to be paid as a monthly annuity payable for the lifetime of the employee. For all other benefits, payment was assumed to be as a single lump sum, although other actuarially equivalent forms are available.
We maintain one tax-qualified noncontributory defined benefit pension plan and one supplemental nonqualified, noncontributory defined benefit retirement plan. First, we maintain the Qualified Plan, which provides funded, tax-qualified benefits up to the limits on compensation and benefits under the Internal Revenue Code. Generally, all of our salaried employees, including the NEOs, are eligible to participate.
We maintain the ESRP, in which all of our NEOs participate. The ESRP provides additional retirement benefits which are not tax qualified.
The following describes the Qualified Plan and the ESRP, and pension benefits provided to the NEOs under those plans.
Qualified Plan
There are two primary retirement benefit components of the Qualified Plan. Each NEO earns benefits from the Company under only one of these primary components.
Because our first operating utility subsidiary was acquired from DTE Energy, a component of the Qualified Plan bears relation to the DTE Energy Corporation Retirement Plan (the “DTE Plan”). Generally, persons who were participants in the “traditional component” of the DTE Plan as of February 28, 2003 (the date ITCTransmission was acquired from DTE Energy) earn benefits under the traditional component of our Qualified Plan. All other participants earn benefits under the cash balance component. Ms. Apsey also has benefits under the ESRP shift described below.
Benefits under the Qualified Plan are funded by an irrevocable tax-exempt trust. A NEO’s benefit under the Qualified Plan is payable from the assets held by the tax-exempt trust.
NEOs become fully vested in their normal retirement benefits described below with 3 years of service, including service with DTE Energy, or upon attainment of the plan’s normal retirement age of 65. If a NEO terminates employment with less than 3 years of service, the NEO is not vested in any portion of his or her benefit.
Traditional Component of Qualified Plan
Mr. Jipping participates in the traditional component of the Qualified Plan. The benefits are determined under the following formula, stated as an annual single life annuity payable in equal monthly installments at the normal retirement age of 65: 1.5% times average final compensation times credited service up to 30 years, plus 1.4% times average final compensation times credited service in excess of 30 years. Credited service includes service with DTE Energy. Although benefits under the formula are defined in terms of a single life annuity, other annuity forms (e.g., joint and survivor benefits) are available that have the same actuarial value as the single life annuity benefit. The benefits are not payable in the form of a lump sum.
Average final compensation is equal to one-fifth of the NEO’s salary (excluding any bonuses or special pay) during the 260 weeks of credited service, not necessarily consecutive, at any time during the NEO’s employment that results in the highest average.
Benefits provided under the Qualified Plan are based on compensation up to a compensation limit under the Internal Revenue Code (which was $290,000 in 2021 and is indexed in future years). In addition, benefits provided under the Qualified Plan may not exceed a benefit limit under the Internal Revenue Code (which was $230,000 payable as a single life annuity beginning at normal retirement age in 2021).
NEOs may retire with a reduced benefit as early as age 45 after 15 years of credited service. If a NEO has 30 years of credited service at retirement, the benefit that would be payable at normal retirement age is reduced for commencement ages below 58. The percentage of the normal retirement benefit payable at sample commencement ages is as follows:
Age 58 and older: 100%
Age 55: 85%
Age 50: 40%
If a NEO has less than 30 years but more than 15 years of credited service at retirement, the benefit that would be payable at normal retirement age is reduced for commencement ages below age 60. The percentage of the normal retirement benefit payable at sample commencement ages is as follows:
Age 60 and older: 100%
Age 55: 71%
Age 50: 40%
If a NEO terminates employment prior to earning 15 years of credited service, the annuity benefit may not commence prior to attaining age 65. If the NEO terminates employment after earning 15 years of credited service but below age 45, the benefit may commence as early as age 45. The percentage of the normal retirement benefit payable at sample commencement ages is as follows:
Age 65 and older: 100%
Age 60: 58%
Age 55: 36%
Age 50: 23%
Mr. Jipping’s annual accrued benefit payable in monthly installments as an annuity for his lifetime, beginning at age 60, is approximately $130,000. He is fully vested.
Cash Balance Component of Qualified Plan
Mses. Apsey, Holloway, Mason Soneral and Tanner participate in the cash balance component of the Qualified Plan. The benefits are stated as a notional account value.
Each year, a NEO’s account is increased by a “contribution credit” equal to 7% of pay. For this purpose, pay is equal to base salary plus bonuses and overtime up to the same compensation limit as applied under the traditional component of the Qualified Plan ($290,000 in 2021). Each year, a NEO’s account is also increased by an “interest credit” based on 30-year Treasury rates.
Upon termination of employment, a vested NEO may elect full payment of his or her account. Alternate forms of benefit (e.g., various forms of annuities) are available as well that have the same actuarial value as the account.
Mses. Apsey, Holloway, Mason Soneral and Tanner are entitled to immediate payment of their account value on termination of employment, even if before normal retirement age. Ms. Apsey’s estimated account value as of year-end 2021 is approximately $467,000, Ms. Holloway’s is approximately $315,000, Ms. Mason Soneral’s is approximately $315,000, Ms. Tanner is approximately $145,000.
The ESRP provides notional account accruals similar to the cash balance component of the Qualified Plan. The “compensation credit” to the NEO’s notional account, analogous to the contribution credit in the cash balance component of the Qualified Plan, is equal to 9% of base salary plus actual bonus earned under the Company’s ACPB. The “investment credit,” analogous to the interest credit in the cash balance component of the Qualified Plan, is similarly based on 30-year Treasury rates.
The ESRP shift benefit is an amount that would otherwise be payable from the ESRP, but is instead being paid from the Qualified Plan, subject to applicable qualified plan legal limits on the ability to discriminate in favor of highly paid employees. The NEO’s cash balance account is increased by any amounts shifted from the
ESRP. The purpose of the benefit is to provide the NEO and the Company the tax advantages of providing benefits through a tax qualified plan.
Ms. Apsey has received ESRP shift additions to her Qualified Plan cash balance account. There was no shift of compensation credits for 2021, although previous shifts have continued to earn interest credits. As of year-end 2021, her ESRP shift balance was approximately $38,000.
Executive Supplemental Retirement Plan
The ESRP is a nonqualified retirement plan. Only selected executives participate, including all our NEOs. The purpose of the ESRP is to promote the success of the Company and its subsidiaries by providing the ability to attract and retain talented executives by providing such designated executives with additional retirement benefits.
The ESRP resembles the cash balance component of the Qualified Plan in that benefits are expressed as a notional account value and the vested account balance is payable as a lump sum on termination of employment, although an installment option of equivalent value is also available.
Each year, a NEO’s account is increased by a “compensation credit” equal to 9% of pay. For this purpose, pay is equal to base salary plus any bonus under the Company’s ACPB. There is no limit on compensation that may be taken into account as in the Qualified Plan. Each year, a NEO’s account is also increased by an “investment credit” equal to the same earnings rate as the interest credit in the cash balance component of the Qualified Plan, based on 30-year Treasury rates.
The plan has been in effect since March 1, 2003. Vesting occurs at 20% for each year of participation. All of our NEOs are fully vested.
As noted above in the description of the Qualified Plan, a portion of the ESRP account balance may be shifted to the cash balance component of the Qualified Plan each year, as permitted under the rules for qualified plans. Such a shift allows the NEOs to become immediately vested in the account values shifted and confers certain tax advantages to the NEOs and us. As of December 31, 2021, the ESRP account values, net of the amounts shifted to the Qualified Plan, are as follows:
Ms. Apsey $ 2,214,807
Ms. Holloway 464,356
Mr. Jipping 1,823,110
Ms. Mason Soneral 846,109
Ms. Tanner 329,977
The ESRP is funded with a Rabbi Trust, which we cannot use for any purpose other than to satisfy the benefit obligations under the ESRP, except in the event of the Company’s bankruptcy, in which case the assets are available to general creditors.
Nonqualified Deferred Compensation
We maintain the Executive Deferred Compensation Plan under which nonqualified deferred compensation is permissible. Only selected officers of the Company, including the NEOs, are eligible to participate in this plan. NEOs are allowed to defer up to 100% of their salary and bonus. Investment earnings are based on the various investment options available under the plan and are selected by the individual NEOs. Distributions will generally be made at the NEO’s termination of employment for any reason. Mr. Jipping elected to participate in 2020 and his deferral was withheld in 2021. Mr. Jipping also elected to participate in 2021, and his deferral will be made in 2022 due to his 2021 bonus payment occurring in 2022. Mr. Jipping is the only NEO that participated in the Executive Deferred Compensation Plan in 2021. The following table reports amounts contributed in 2021, together with aggregate earnings on contributions and withdrawals or distributions on contributions in 2021, under the plan.
Name (in millions of USD) Executive Contributions in Last Fiscal Year (1) Registrant Contributions in Last Fiscal Year Aggregate Earnings in Last Fiscal Year Aggregate Withdrawals/Distributions Aggregate Balance at Last Fiscal Year End (2)
Jon E. Jipping $ 800,226 $ - $ 412,880 $ - $ 3,214,206
____________________________
(1) The amounts reported in this column for each NEO are reflected as compensation to such NEO in the Summary Compensation Table.
(2) Includes the total market value of deferred compensation program balance at December 31, 2021. The aggregate balance reflects a significant level of earnings on previously earned and deferred compensation.
Employment Agreements and Potential Payments Upon Termination or Change in Control
Employment Agreements
As referenced above, we entered into employment agreements with Ms. Apsey and Mr. Jipping in December 2012 which superseded the employment agreements then in effect. In February 2015, we entered into an employment agreement with Ms. Mason Soneral which superseded her employment agreement then in effect. In July 2017, we entered into an employment agreement with Ms. Holloway, which superseded her employment agreement then in effect. In February 2019, we entered into an employment agreement with Ms. Tanner which superseded her employment agreement then in effect. Each employment agreement is subject to automatic one-year employment term renewals each year beginning on its second anniversary, unless either party provides the other with 30 days’ advance written notice of intent not to renew the employment term. Ms. Apsey’s agreement was modified in October 2016 in connection with her appointment as President and Chief Executive Officer and the initial term of the agreement expired on December 31, 2018 but is subject to the automatic one-year renewal provision described above. The following describes the material terms of the employment agreements, as amended, with the NEOs who remained employed by the Company on December 31, 2021.
The employment agreements provide that each NEO will receive an annual base salary equal to their current base salary, which is subject to annual review and increase by our Board of Directors at its discretion. The employment agreements also provide that NEOs are eligible to receive an annual cash bonus, subject to our achievement of certain performance targets established by our Board of Directors, as detailed in “Compensation Discussion and Analysis.” The employment agreements also provide the NEOs with the right to participate in equity plans, employee benefit plans and retirement plans, including but not limited to welfare plans, retiree welfare benefit plans and defined benefit and defined contribution plans.
In addition, the NEOs’ employment agreements provide for payments by us of certain benefits upon termination of employment. The rights available at termination depend on the situation and circumstances surrounding the terminating event. The terms “Cause” and “Good Reason” are used in the employment agreements of each NEO and an understanding of these terms is necessary to determine the appropriate rights for which a NEO is eligible. The terms are defined as follows:
•Cause means: a NEO’s continued failure to substantially perform his or her duties (other than as a result of total or partial incapacity due to physical or mental illness) for a period of 10 days following written notice by the Company to the NEO of such failure; dishonesty in the performance of the NEO’s duties; a NEO’s conviction of, or plea of nolo contender to, a crime constituting a felony or misdemeanor involving moral turpitude; willful malfeasance or willful misconduct in connection with a NEO’s duties; any act or omission which is injurious to the financial condition or business reputation of the Company; or violation of the non-compete or confidentiality provisions of the employment agreement.
•Good reason means: a greater than 10% reduction in the total value of the NEO’s base salary, target bonus, and employee benefits; or if the NEO’s responsibilities and authority are substantially diminished.
If a NEO’s employment is terminated with cause by the Company or by the NEO without good reason, the NEO will generally only receive his or her accrued but unpaid compensation and benefits as of the date of his or her employment termination. If the NEO terminates due to death or disability (as defined in the employment
agreements), the NEO (or the NEO’s spouse or estate) would also receive a pro rata portion of his or her current year annual target bonus.
If a NEO’s employment is terminated by the Company without cause or by the NEO for good reason, the NEO will receive the following, subject to the NEO’s execution of a release agreement and commencing generally on the earliest date that is permitted under Section 409A of the Internal Revenue Code:
•any accrued but unpaid compensation and benefits including:
◦Ms. Apsey: cash balance and ESRP shift under the Qualified Plan and vested portion of ESRP balance;
◦Mr. Jipping: annual benefit under the traditional component of the Qualified Plan and vested portion of ESRP balance; and
◦Ms. Mason Soneral, Ms. Holloway and Ms. Tanner: cash balance under the Qualified Plan and vested portion of ESRP balance
•continued payment of the NEO’s then-current base salary for two years;
•if the termination is within six months before or two years after a “Change of Control” (as defined in the employment agreements), payment of an amount equal to two times the average of the ACPBs, that were payable to the NEO for the three fiscal years immediately preceding the fiscal year in which his or her employment terminates, payable in equal installments over the period in which continued base salary payments are made;
•a pro rata portion of the ACPB for the year of termination, based upon the Company’s actual achievement of the performance targets for such year as determined under the ACPB and paid at the time that such bonus would normally be paid;
•eligibility to continue coverage under our active medical, dental and vision plans subject to applicable COBRA rules; if such coverage is elected, we will reimburse the NEO for the shorter of 18 months, or until the NEO becomes eligible for coverage under another employer-sponsored group plan, in an amount equal to our periodic cost of such coverage for other executives, plus a tax gross-up amount;
•outplacement services for up to two years; and
•for Ms. Apsey, deemed satisfaction of the eligibility requirements of our Postretirement Welfare Plan for purposes of participation therein; and Mr.Jipping met the age and service eligibility requirements for participation in our Postretirement Welfare Plan. In addition, if we terminate our Postretirement Welfare Plan and, by application of the provisions described in the prior sentence, any of these NEOs would otherwise be entitled to retiree welfare benefits, we will establish other coverage for the NEO or the NEO will receive a cash payment equal to our cost of providing such benefits, in order to assist the NEO in obtaining other retiree welfare benefits.
In addition, while employed by us and for a period of two years after any termination of employment without cause by the Company (other than due to their disability) or for good reason by them and for a period of one year following any other termination of their employment, the NEOs will be subject to certain covenants not to compete with or assist other entities in competing with our business and not to encourage our employees to terminate their employment with us. At all times while employed and thereafter, all of the NEOs will also be subject to a covenant not to disclose confidential information.
In the event the NEO becomes subject to excise taxes under Section 4999 of the Internal Revenue Code as a result of payments and benefits received under the employment agreements or any other plan, arrangement or agreement with us, we will pay the NEO only that portion of such payments which are in total equal to one dollar less than the amount that would subject the NEO to the excise tax.
Payments in the Event of Termination
The benefits to be provided to the NEOs as a result of termination under various scenarios are detailed in the tables below. The tables assume that the termination occurred on December 31, 2021.
Linda H. Apsey - Termination Scenarios: Value of Potential Payments
Total Value of Severance, Benefits and Unvested Equity Awards(1)(2)
Voluntary Resignation Involuntary For Cause Involuntary Not-for-Cause or Voluntary Good Reason Change In Control (pre-tax)(3) Disability Death (pre-retirement)(4)
Compensation
Cash Severance $ - $ - $ 1,681,000 $ 4,129,329 $ - $ -
Target Short-term Bonus - - - - 840,500 840,500
Pro Rata Short-term (Annual) Incentive Comp
- - 1,370,015 1,370,015 - -
Retention Awards - - - -
Service-Based Unit Awards (5) - - - 1,704,161 1,704,161 1,704,161
Performance-Based Unit Awards (6) - - - 1,701,974 3,408,386 3,408,386
Benefits and Perquisites -
Retirement Plan - - - - - -
ESRP - - - - - -
Perquisites - - 25,000 25,000 - -
Health & Welfare Benefits - - 31,592 31,592 - -
Postretirement Welfare Plan (7) - - 775,824 775,824 - -
Total Payout: $ - $ - $ 3,883,431 $ 9,737,895 $ 5,953,047 $ 5,953,047
Gretchen L. Holloway - Termination Scenarios: Value of Potential Payments
Total Value of Severance, Benefits and Unvested Equity Awards(1)(2)
Voluntary Resignation Involuntary For Cause Involuntary Not-for-Cause or Voluntary Good Reason Change In Control (pre-tax)(3) Disability Death (pre-retirement)(4)
Compensation
Cash Severance $ - $ - $ 823,400 $ 2,018,961 $ - $ -
Target Short-term Bonus - - - - 411,700 411,700
Pro Rata Short-term (Annual) Incentive Comp
- - 671,071 671,071 - -
Service-Based Unit Awards (5) - - - 582,936 582,936 582,936
Performance-Based Unit Awards (6) - - - 581,738 1,165,924 1,165,924
280G Cutback - - - - - -
Benefits and Perquisites
Retirement Plan - - - - - -
ESRP - - - - - -
Perquisites - - 25,000 25,000 - -
Health & Welfare Benefits - - 10,596 10,596 - -
Total Payout: $ - $ - $ 1,530,067 $ 3,890,302 $ 2,160,560 $ 2,160,560
Jon E. Jipping - Termination Scenarios: Value of Potential Payments
Total Value of Severance, Benefits and Unvested Equity Awards(1)(2)
Voluntary Resignation or Voluntary Good Reason Involuntary For Cause Involuntary Not-for-Cause Change In Control (pre-tax)(3) Disability Death (pre-retirement)(4)
Compensation
Cash Severance $ - $ - $ 1,195,000 $ 2,972,455 $ - $ -
Target Short-term Bonus - - - - 597,500 597,500
Pro Rata Short-term (Annual) Incentive Comp
- - 973,925 973,925 - -
Service-Based Unit Awards (5) 852,195 - 852,195 852,195 852,195 852,195
Performance-Based Unit Awards (6) - - - 852,485 1,704,419 1,704,419
Benefits and Perquisites
Retirement Plan - - - - - -
ESRP - - - - - -
Perquisites - - 25,000 25,000 - -
Health & Welfare Benefits - - 22,128 22,128 - -
Postretirement Welfare Plan (7) - - 776,225 776,225
Total Payout: $ 852,195 $ - $ 3,844,473 $ 6,474,413 $ 3,154,114 $ 3,154,114
Christine Mason Soneral - Termination Scenarios: Value of Potential Payments
Total Value of Severance, Benefits and Unvested Equity Awards(1)(2)
Voluntary Resignation Involuntary For Cause Involuntary Not-for-Cause or Voluntary Good Reason Change In Control (pre-tax)(3) Disability Death (pre-retirement)(4)
Compensation
Cash Severance $ - $ - $ 799,600 $ 1,999,751 $ - $ -
Target Short-term Bonus - - - - 399,800 399,800
Pro Rata Short-term (Annual) Incentive Comp
- - 651,674 651,674 - -
Service-Based Unit Awards (5) - - - 571,629 286,324 286,324
Performance-Based Unit Awards (6) - - - 572,292 191,548 191,548
Benefits and Perquisites
Retirement Plan - - - - - -
ESRP - - - - - -
Perquisites - - 25,000 25,000 - -
Health & Welfare Benefits - - 22,115 22,115 - -
Total Payout: $ - $ - $ 1,498,389 $ 3,842,461 $ 877,672 $ 877,672
Krista Tanner - Termination Scenarios: Value of Potential Payments
Total Value of Severance, Benefits and Unvested Equity Awards(1)(2)
Voluntary Resignation Involuntary For Cause Involuntary Not-for-Cause or Voluntary Good Reason Change In Control (pre-tax)(3) Disability Death (pre-retirement)(4)
Compensation
Cash Severance $ - $ - $ 709,800 $ 1,411,238 $ - $ -
Target Short-term Bonus - - - - 354,900 354,900
Pro Rata Short-term (Annual) Incentive Comp
- - 578,487 578,487 - -
Service-Based Unit Awards (5) - - - 500,091 249,274 249,274
Performance-Based Unit Awards (6) - - - 498,224 165,137 165,137
280G Cutback - - - (442,488) - -
Benefits and Perquisites
Retirement Plan - - - - - -
ESRP - - - - - -
Perquisites - - 25,000 25,000 - -
Health & Welfare Benefits - - 19,730 19,730 - -
Total Payout: $ - $ - $ 1,333,017 $ 2,590,282 $ 769,311 $ 769,311
____________________________
(1)All scenarios include the value of severance. For Ms. Apsey and Mr. Jipping, the value of the Postretirement Welfare Plan is additionally included where applicable. The Pension Benefits Table assumes that none of the NEOs are terminated prior to retirement age and that benefits are paid once retirement commences (age 58 is assumed). All other accrued pension benefits, outside of present value reductions outlined in footnote (5), and additional pension benefits upon death, have not been included in these termination scenarios but can be found in the “Pension Benefits Table.”
(2)Upon any termination of employment, benefits that are accrued but unpaid prior to that event are paid. These benefits are assumed to be $0 in the above tables.
(3)Change in control values include severance amounts reflecting cutbacks to the extent employer payments exceed the executive respective limits. Ms. Tanner would be subject to an excise tax on the employer payments as of the assumed change in control date; therefore, cutbacks in the amount of $442,488 (Ms. Tanner) have been reflected.
(4)In the event of Mr. Jipping’s termination for death (pre-retirement), his spouse or designated beneficiary if not married would receive half the 50% joint and survivor annuity under the traditional component of the Qualified Plan. Under termination for death (pre-retirement), Ms. Apsey’s, Ms. Mason Soneral’s, Ms. Holloway’s and Ms. Tanner’s Qualified Plan benefits are payable immediately to the surviving spouse or designated beneficiary it not married and ESRP benefits are payable to a designated beneficiary. The above termination scenarios do not reflect the reduction in present value of death benefits ($103,732 for Ms. Apsey, $68,077 for Ms. Holloway, $1,066,469 for Mr. Jipping, $79,399 for Ms. Mason Soneral and $38,559 for Ms. Tanner compared to present value in the Pension Benefits Table).
(5)Under the Fortis Inc. 2020 Restricted Share Unit Plan, outstanding and unvested SBUs and respective dividend equivalents shall be deemed to be vested SBUs and redeemable on the date that is immediately prior to the effective date of the consummation of the transaction resulting from the Change of Control. In the case of Death, Disability or Retirement termination and 15 years or more of service with the Company or its Affiliates, the outstanding and unvested SBU awards and respective dividend equivalents shall be deemed vested and redeemable on the date of the death or on the date on which the grantee’s service is terminated due to Disability or Retirement. In the case of Death, Disability or Retirement termination and less than 15 years of service with the Company or its Affiliates, the outstanding and unvested SBU awards and respective dividend equivalents shall be deemed to have vested pro-rata based on the period served from grant date to termination and redeemable on the date of the death or on the date on which the
grantee’s service is terminated due to Disability or Retirement. In the case of Cause, Involuntary Termination Without Cause and Voluntary Termination outstanding and unvested SBU awards and respective dividend equivalents shall be deemed to be forfeited.
(6)Under the Executive Omnibus Plan, outstanding and unvested PBU awards and respective dividend equivalents shall become redeemable on the Change of Control Redemption Date under a Change in Control (as defined in the Executive Omnibus Plan). In the case of Death, Disability or Retirement termination and 15 years or more of service with the Company or its Affiliates, the outstanding and unvested PBU awards and respective dividend equivalents will remain outstanding and be payable on the payout date of such awards subject to the achievement of the applicable payment criteria. In the case of Death, Disability or Retirement termination and less than 15 years of service with the Company or its Affiliates, the outstanding and unvested PBU awards and respective dividend equivalents shall be deemed to have vested pro-rata based on the period served from grant date to termination and be payable on the payout date of such awards subject to the achievement of the applicable payment criteria. Values shown in the tables above are based on target performance as an estimate of potential payments. In the case of Cause, Involuntary Termination Without Cause and Voluntary Termination outstanding and unvested PBU awards and respective dividend equivalents shall be deemed to be forfeited.
(7)The value of the Postretirement Welfare Plan benefit is included in involuntary termination not for cause and change in control scenarios for Ms. Apsey and Mr. Jipping since their employment agreement includes a provision for deemed satisfaction of the eligibility requirements when terminated under these scenarios. It is assumed each would commence their Postretirement Welfare Benefits at age 58. The rate at which future expected benefit payments were discounted in calculating the Postretirement Welfare Plan present values was 3.14%, the same rate used for fiscal year-end 2021 accounting disclosure of the Postretirement Welfare Plan.
Upon death or disability, a NEO (or his or her estate) receives a pro rata portion of his or her current year target corporate performance bonus. All balances under the cash balance and ESRP shift components of the Qualified Plan, and the ESRP balance (vested portion only for disability), are immediately payable. If the NEO has 10 years of service after age 45, then the NEO (and his or her spouse) is eligible for retiree medical benefits.
Pay Ratio
As required by the Dodd-Frank Wall Street Reform and Consumer Protection Act, and the SEC under Item 402(u) of Regulation S-K, we are providing the following information about the relationship of the annual total compensation of our employees and the annual total compensation of Linda H. Apsey our CEO:
For 2021, our last completed fiscal year:
the median of the annual total compensation of all employees of the Company (other than Ms. Apsey), was $159,801; and
the annual total compensation of Ms. Apsey as reported in the Summary Compensation Table was $4,585,608.
Based on this information, Ms. Apsey’s 2021 annual total compensation was estimated to be 29 times the median annual total compensation for all employees, other than Ms. Apsey.
We determined that, as of December 31, 2020, our employee population consisted of 698 individuals with all of those individuals located in the United States. To identify the “median employee” from our employee population, excluding Ms. Apsey, we utilized a consistently applied compensation measure that included the sum of each employee’s 2020 annualized base salary as of December 31, 2020 as reflected in our payroll records, and target 2020 awards made under our annual corporate performance plan, 2017 Omnibus Plan, Executive Omnibus Plan and Fortis Inc. 2020 Restricted Share Unit Plan that were not paid in 2020. We arrayed these values to select our “median employee.”
Under Item 402(u), a company is permitted to identify its “median employee” once every three years if there has been no significant change to its employee population or employee compensation arrangements that would result in a significant change to its pay ratio disclosure. We updated our “median employee” for 2020 as it had
been three years since we had last identified the “median employee” for this analysis. The same median employee was used to calculate the 2021 pay ratio.
Using our “median employee” and Ms. Apsey, we calculated the applicable Summary Compensation Table values for each according to applicable SEC rules.
Director Compensation
The following table provides information concerning the compensation of each person who served as a non-employee director of the Company during 2021.
Non-Employee Director Compensation Table
Name Fees Earned or Paid in Cash ($) (1) Total ($)
(a) (b) (h)
Leanne M. Bell (2) $ - $ -
Robert A. Elliott (3) 149,518 149,518
Albert Ernst (4) 140,000 140,000
Debora Frodl 140,000 140,000
Alexander I. Greenbaum (5) - -
Ronnie Hawkins, Jr. 140,000 140,000
David G. Hutchens 140,000 140,000
James P. Laurito 140,000 140,000
Jocelyn H. Perry (2) - -
Sandra E. Pierce 190,000 190,000
Kevin L. Prust 145,482 145,482
A. Douglas Rothwell 155,000 155,000
Thomas G. Stephens (4) 14,014 14,014
____________________________
(1)Includes annual Board retainer and committee chairmanship retainer, as well as a chairperson fee (for Ms. Pierce only).
(2)Ms. Perry joined the Board in January 2022 and Ms. Bell joined the Board in February 2022.
(3)Mr. Elliott was appointed to Chairperson of the Audit and Risk Committee in May 2021.
(4)Mr. Stephens left the Board in February 2021 and Mr. Ernst left the Board in February 2022.
(5)Mr. Greenbaum waived all compensation due to him for his service on the Board. Mr. Greenbaum left the Board in September 2021.
Directors who are employees of the Company do not receive separate compensation for their services as a director. All non-employee directors are compensated under our non-employee director compensation policy, pursuant to which they are paid an annual cash retainer of $140,000. In addition, we pay an additional cash retainer of $15,000 annually to the chair of each Board committee and $50,000 annually to our chairperson. We do not pay per-meeting fees under the policy. Non-employee directors are reimbursed for their out-of-pocket expenses incurred for the performance of their duties as directors.
We maintain a Director Deferred Compensation Plan under which nonqualified deferred compensation is permissible. Only non-employee directors of the Company are eligible to participate in this plan. Directors are allowed to defer up to 100% of their annual board compensation. Investment earnings are based on the various investment options available under the plan and are selected by the individual directors. Distributions will be made when the director ceases to serve on the Board and/or ceases to provide other non-employee consulting services to the Company or any Fortis entity. Mr. Laurito and Mr. Stephens participated in this plan in 2021.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.
The following table sets forth certain information regarding the ownership of our common stock and Fortis’ common stock as of February 1, 2022, except as otherwise indicated, by:
•each of our current directors;
•each of the persons named in the “Summary Compensation Table” under Item 11; and
•all current directors and executive officers as a group.
The number of shares beneficially owned is determined under rules of the SEC and the information is not necessarily indicative of beneficial ownership for any other purpose. Under such rules, beneficial ownership includes any shares as to which the individual has sole or shared voting power or investment power and also any shares which the individual has the right to acquire on February 1, 2022 or within 60 days thereafter through the exercise of any stock option or other right. Unless otherwise indicated, each holder has sole investment and voting power with respect to the shares set forth in the following table:
Name of Beneficial Owner Number of Company Shares
Beneficially Owned (#) Percent of Class (%) Number of Fortis shares Beneficially Owned (#) Percent of Class (%)
Linda H. Apsey - - 53,889 *
Gretchen L. Holloway - - 8,862 *
Jon E. Jipping - - 60,000 *
Christine Mason Soneral - - - -
Krista Tanner - - - -
Leanne M. Bell - - - -
Robert A. Elliott - - - -
Albert Ernst - - 10,274 (1) *
Debora Frodl - - - -
Alexander I. Greenbaum - - - -
Ronnie Hawkins - - - -
David G. Hutchens - - 83,907 *
James P. Laurito - - 48,544 *
Jocelyn H. Perry 187,622 *
Sandra E. Pierce - - - -
Kevin L. Prust - - 500 *
A. Douglas Rothwell - - - -
All current directors and executive officers as a group (17 persons) - - % 443,324 *
* Less than one percent
____________________________
(1)Includes 4,234 shares owned by the spouse of Mr. Ernst.
ITC Investment Holdings, which owns all of our outstanding common stock, is 80.1% owned by FortisUS and 19.9% owned by Eiffel. FortisUS is a wholly-owned subsidiary of Fortis.
At December 31, 2021, there were no securities authorized for issuance under any compensation plans of ITC Holdings.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE.
CERTAIN TRANSACTIONS
Pursuant to its charter, the Governance and Human Resources Committee is charged with monitoring and reviewing issues involving independence and potential conflicts of interest with respect to our directors and executive officers. The Committee also determines whether or not a particular relationship serves the best interest of the Company and its shareholder and whether the relationship should be continued or eliminated. In addition, our Code of Conduct and Ethics generally forbids conflicts of interest unless approved by the Board or a designated committee.
Although the Company does not have a written policy with regard to the approval of transactions between the Company and its executive officers and directors, each director and officer must annually submit a form to the General Counsel disclosing his or her conflicts or potential conflicts of interest or certifying that no such conflicts of interest exist. Throughout the year, if any transaction constituting a conflict of interest arises or circumstances otherwise change that would cause a director’s or officer’s annual conflict certification to become incorrect, the director or officer must inform the General Counsel of such circumstances. The Committee reviews existing conflicts as well as potential conflicts of interest and determines whether any further action is necessary, such as recommending to the Board whether a director or officer should be requested to offer his or her resignation. Where the Board makes a determination regarding a potential conflict of interest, a majority of the Board (excluding any interested member or members) shall decide upon an appropriate course of action. Additionally, any director or officer who has a question about whether a conflict exists must bring it to the attention of the Company’s General Counsel or Chairperson of the Committee.
DIRECTOR INDEPENDENCE
Based on the absence of any material relationship between them and us, other than their capacities as directors, the Board has determined that Mmes. Bell, Frodl and Pierce and Messrs. Elliott, Ernst, Hawkins, Jr., Prust, and Rothwell are “independent” as defined in the Shareholders Agreement. In addition, our Board has determined that, as the committees are currently constituted, a majority of the members of the Audit and Risk Committee are “independent” as required in its charter. None of the directors determined to be independent is or ever has been employed by us.
An independent director under the Shareholders Agreement is a director who meets all of the following requirements: (a) is elected by the shareholders of ITC Investment Holdings; (b) is designated as an independent director by the ITC Investment Holdings’ board and Company Board, or the shareholders of ITC Investment Holdings; (c) is not a director that is nominated by Finn Investment Pte Ltd or any successor or permitted assign thereof and appointed as a member of the ITC Investment Holdings’ board and Company Board in accordance with the Shareholders Agreement; (d) is not and during the three years prior to being designated as an independent director has not been any of the following: (i) a director of FortisUS or any of its affiliates (other than ITC Investment Holdings or the Company); or (ii) an officer or employee of ITC Investment Holdings, the Company, FortisUS or any of their affiliates; and (e) would meet the definition of “independent director” under the NYSE Listed Company Manual if such director were a member of the board of directors of Fortis, FortisUS, ITC Investment Holdings, or the Company (assuming, in the case of FortisUS, ITC Investment Holdings and the Company, that such entities were listed on the NYSE).
Mr. Elliott serves on the board of directors of UNS Energy Corporation, a wholly-owned subsidiary of FortisUS. When determining Mr. Elliott’s independence, the board and shareholders agreed to waive the requirements set forth in the definition of independent director under the Shareholders Agreement which states that a director is not and during the three years prior to being designated as a director of the company has not served as a director of FortisUS or any of its affiliates.

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES.
The following table provides a summary of the aggregate fees incurred for Deloitte’s services in 2021 and 2020:
2021 2020
Audit fees (1) $ 2,083,000 $ 1,995,000
Audit-related fees (2) 57,000 56,000
Tax fees (3) 13,000 16,000
All other fees (4) 7,000 4,000
Total fees $ 2,160,000 $ 2,071,000
____________________________
(1) Audit fees were for professional services rendered for the audit of our consolidated financial statements and internal controls and reviews of the interim consolidated financial statements included in quarterly reports and services that are normally provided by Deloitte in connection with statutory and regulatory filing engagements.
(2) Audit-related fees were for assurance and related services that are reasonably related to the performance of the audit or review of our consolidated financial statements and are not reported under “Audit Fees.” These services include audit of our employee benefit plans.
(3) Tax fees were professional services for federal and state tax compliance, tax advice and tax planning.
(4) All other fees were for services other than the services reported above. These services included subscriptions to the Deloitte Accounting Research Tool and attendance at Deloitte sponsored conferences and labs.
The Audit and Risk Committee of the Board of Directors does not consider the provision of the services described above by Deloitte to be incompatible with the maintenance of Deloitte’s independence.
The Audit and Risk Committee has adopted a pre-approval policy for all audit and non-audit services pursuant to which it pre-approves all audit and non-audit services provided by the independent registered public accounting firm prior to the engagement with respect to such services. To the extent that we need an engagement for audit and/or non-audit services between Audit and Risk Committee meetings, the Audit and Risk Committee chairman is authorized by the Audit and Risk Committee to approve the required engagement on its behalf.
The Audit and Risk Committee approved all of the services performed by Deloitte in 2021 pursuant to the pre-approval policy.
PART IV

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.
(a) (1) Financial Statements:
Management’s Report on Internal Control over Financial Reporting
Report of Independent Registered Public Accounting Firm
Consolidated Statements of Financial Position as of December 31, 2021 and 2020
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2021, 2020 and 2019
Consolidated Statements of Changes in Stockholder's Equity for the Years Ended December 31, 2021, 2020 and 2019
Consolidated Statements of Cash Flows for the Years Ended December 31, 2021, 2020 and 2019
Notes to Consolidated Financial Statements
(2) Financial Statement Schedules
Schedule I - Condensed Financial Information of Registrant
All other schedules for which provision is made in Regulation S-X either (i) are not required under the related instructions or are inapplicable and, therefore, have been omitted, or (ii) the information required is included in the consolidated financial statements or the notes thereto that are a part hereof.
(b) Exhibit Listing
The following exhibits are filed as part of this report or filed previously and incorporated by reference to the filing indicated. Our SEC file number is 001-32576.
Exhibit No. Description of Exhibit
2.1 Agreement and Plan of Merger, dated as of February 9, 2016, among FortisUS Inc., Element Acquisition Sub Inc., Fortis Inc., and ITC Holdings Corp. (filed with Registrant’s Form 8-K on February 11, 2016)
3.1 Restated Articles of Incorporation of ITC Holdings Corp. (filed with Registrant’s Form 10-Q for the quarter ended September 30, 2016)
3.2 Tenth Amended and Restated Bylaws of ITC Holdings Corp. (filed with Registrant’s Form 8-K on February 4, 2022)
4.3 Indenture, dated as of July 16, 2003, between ITC Holdings Corp. and BNY Midwest Trust Company, as trustee (filed with Registrant’s Registration Statement on Form S-1, as amended, Reg. No. 333-123657)
4.5 First Mortgage and Deed of Trust, dated as of July 15, 2003, between International Transmission Company and BNY Midwest Trust Company, as trustee (filed with Registrant’s Registration Statement on Form S-1, as amended, Reg. No. 333-123657)
4.6 First Supplemental Indenture, dated as of July 15, 2003, supplementing the First Mortgage and Deed of Trust dated as of July 15, 2003, between International Transmission Company and BNY Midwest Trust Company, as trustee (filed with Registrant’s Registration Statement on Form S-1, as amended, Reg. No. 333-123657)
4.7 Second Supplemental Indenture, dated as of July 15, 2003, supplementing the First Mortgage and Deed of Trust dated as of July 15, 2003, between International Transmission Company and BNY Midwest Trust Company, as trustee (filed with Registrant’s Registration Statement on Form S-1, as amended, Reg. No. 333-123657)
4.8 Amendment to Second Supplemental Indenture, dated as of January 19, 2005, between International Transmission Company and BNY Midwest Trust Company, as trustee (filed with Registrant’s Registration Statement on Form S-1, as amended, Reg. No. 333-123657)
4.9 Second Amendment to Second Supplemental Indenture, dated as of March 24, 2006, between International Transmission Company and The Bank of New York Trust Company, N.A. (as successor to BNY Midwest Trust Company), as trustee (filed with Registrant’s Form 8-K on March 30, 2006)
4.10 Third Supplemental Indenture, dated as of March 28, 2006, supplementing the First Mortgage and Deed of Trust dated as of July 15, 2003, between International Transmission Company and BNY Midwest Trust Company, as trustee (filed with Registrant’s Form 8-K on March 30, 2006)
4.12 Second Supplemental Indenture, dated as of October 10, 2006, supplemental to the Indenture dated as of July 16, 2003, between the Registrant and The Bank of New York Trust Company, N.A., (as successor to BNY Midwest Trust Company, as trustee) (filed with Registrant’s Form 8-K on October 10, 2006)
4.14 First Mortgage Indenture between Michigan Electric Transmission Company, LLC and JPMorgan Chase Bank, dated as of December 10, 2003 (filed with Registrant’s Form 10-Q for the quarter ended September 30, 2006)
4.17 ITC Holdings Corp. Note Purchase Agreement, dated as of September 20, 2007 (filed with Registrant’s Form 10-Q for the quarter ended September 30, 2007)
4.18 Third Supplemental Indenture, dated as of January 24, 2008, supplemental to the Indenture dated as of July 16, 2003, between the Registrant and The Bank of New York Trust Company, N.A. (as successor to BNY Midwest Trust Company), as trustee (filed with Registrant’s Form 8-K on January 25, 2008)
4.19 First Mortgage and Deed of Trust, dated as of January 14, 2008, between ITC Midwest LLC and The Bank of New York Trust Company, N.A., as trustee (filed with Registrant’s Form 8-K on February 1, 2008)
4.20 First Supplemental Indenture, dated as of January 14, 2008, supplemental to the First Mortgage Indenture between ITC Midwest LLC and The Bank of New York Trust Company, N.A., as trustee, First Mortgage and Deed of Trust, dated as of January 14, 2008 (filed with Registrant’s Form 8-K on February 1, 2008)
4.24 Third Supplemental Indenture, dated as of November 25, 2008, between METC and The Bank of New York Mellon Trust Company, N.A. (as successor to JPMorgan Chase Bank, N.A.), as trustee, to the First Mortgage Indenture between Michigan Electric Transmission Company, LLC and JPMorgan Chase Bank, dated as of December 10, 2003 (filed with Registrant’s Form 8-K on December 23, 2008)
4.25 Fourth Supplemental Indenture, dated as of December 11, 2009, between ITC Holdings Corp. and The Bank of New York Mellon Trust Company, N.A. (f.k.a. The Bank of New York Trust Company, N.A., as successor to BNY Midwest Trust Company), as trustee (filed with Registrant’s Form 8-K on December 14, 2009)
4.26 Fourth Supplemental Indenture, dated as of December 10, 2009, between ITC Midwest LLC and The Bank of New York Mellon Trust Company, N.A. (as successor to The Bank of New York Trust Company, N.A.), as trustee (filed with Registrant’s Form 8-K on December 17, 2009)
4.27 Fifth Supplemental Indenture, dated as of April 20, 2010, between Michigan Electric Transmission Company, LLC and The Bank of New York Mellon Trust Company, N.A. (as successor to JPMorgan Chase Bank), as trustee (filed with Registrant’s Form 8-K on May 10, 2010)
4.28 Third Supplemental Indenture, dated as of December 15, 2008, between ITC Midwest LLC and The Bank of New York Mellon Trust Company, N.A. (The Bank of New York Trust Company, N.A.), as trustee (filed with Registrant’s Form 10-Q for the quarter ended June 30, 2011)
4.29 Fifth Supplemental Indenture, dated as of July 15, 2011, between ITC Midwest LLC and The Bank of New York Mellon Trust Company, N.A. (as successor to The Bank of New York Trust Company, N.A.), as trustee (filed with Registrant’s Form 10-Q for the quarter ended June 30, 2011)
4.30 Sixth Supplemental Indenture, dated as of November 29, 2011, between ITC Midwest LLC and The Bank of New York Mellon Trust Company, N.A. (as successor to The Bank of New York Trust Company, N.A.), as trustee (filed with Registrant’s Form 8-K on December 1, 2011)
4.31 Sixth Supplemental Indenture, dated as of October 5, 2012, between Michigan Electric Transmission Company, LLC and The Bank of New York Mellon Trust Company, N.A. (as successor to JPMorgan Chase Bank), as trustee (filed with Registrant’s Form 8-K on October 29, 2012)
4.32 Seventh Supplemental Indenture, dated as of March 18, 2013, between ITC Midwest LLC and The Bank of New York Mellon Trust Company, N.A. (as successor to The Bank of New York Trust Company, N.A.), as trustee (filed with Registrant’s Form 8-K on April 8, 2013)
4.33 Indenture, dated as of April 18, 2013, between ITC Holdings Corp. and Wells Fargo Bank, National Association, as trustee (including form of note) (filed with Registrant’s Form S-3 on April 18, 2013)
4.34 First Supplemental Indenture, dated as of July 3, 2013, between ITC Holdings Corp. and Wells Fargo Bank, National Association, as trustee (including forms of notes) (filed with Registrant’s Form 8-K on July 3, 2013)
4.35 Fifth Supplemental Indenture, dated as of August 7, 2013, between International Transmission Company and The Bank of New York Mellon Trust Company, N.A. (as successor to BNY Midwest Trust Company), as trustee (including form of bonds) (filed with Registrant’s Form 8-K on August 16, 2013)
4.36 Fifth Supplemental Indenture, dated May 16, 2014, between ITC Holdings Corp. and The Bank of New York Mellon Trust Company, N.A. (f.k.a. The Bank of New York Trust Company, N.A., as successor to BNY Midwest Trust Company), as Trustee (filed with Registrant’s Form 8-K on May 16, 2014)
4.38 Second Supplemental Indenture, dated as of June 4, 2014 between ITC Holdings Corp. and Wells Fargo Bank, National Association, as trustee, together with form of 3.65% Senior Note due 2024 (filed with Registrant’s Form 8-K on June 4, 2014)
4.39 Sixth Supplemental Indenture, dated as of May 23, 2014, between International Transmission Company and The Bank of New York Mellon Trust Company, N.A. (as successor to BNY Midwest Trust Company), as trustee (filed with Registrant’s Form 8-K on June 10, 2014)
4.40 First Mortgage and Deed of Trust, dated as of November 12, 2014, between ITC Great Plains, LLC and Wells Fargo Bank, National Association, as trustee (filed with Registrant’s Form 8-K on November 26, 2014)
4.41 First Supplemental Indenture, dated as of November 12, 2014, between ITC Great Plains, LLC and Wells Fargo Bank, National Association, as trustee (filed with Registrant’s Form 8-K on November 26, 2014)
4.42 Seventh Supplemental Indenture, dated as of December 5, 2014, between Michigan Electric Transmission Company, LLC and The Bank of New York Mellon Trust Company, N.A. (as successor to JPMorgan Chase Bank), as trustee (filed with Registrant’s Form 8-K on December 22, 2014)
4.43 Eighth Supplemental Indenture, dated as of March 18, 2015, between ITC Midwest LLC and The Bank of New York Mellon Trust Company, N.A. (as successor to The Bank of New York Trust Company, N.A.), as trustee (filed with Registrant’s Form 8-K on April 8, 2015)
4.44 Eighth Supplemental Indenture, dated as of March 31, 2016, between Michigan Electric Transmission Company, LLC and Bank of New York Mellon Trust Company, N.A. (as successor to JPMorgan Chase Bank), as trustee (filed with Registrant’s Form 8-K on April 26, 2016)
4.45 Third Supplemental Indenture, dated as of July 5, 2016, between ITC Holdings Corp. and Wells Fargo Bank, National Association, as trustee, together with form of 3.25% Note due 2026 (filed with Registrant’s Form 8-K on July 5, 2016)
4.46 Ninth Supplemental Indenture, dated as of March 15, 2017, between ITC Midwest LLC and The Bank of New York Mellon Trust Company, N.A. (as successor to The Bank of New York Trust Company, N.A.), as trustee (filed with Registrant’s Form 8-K on April 18, 2017)
4.47 Fourth Supplemental Indenture, dated as of November 14, 2017 between ITC Holdings Corp. and Wells Fargo Bank, National Association, as trustee (with Form of 2.700% Notes due 2022 and Form of 3.350% Notes due 2027) (filed with Registrant’s Form 8-K on November 15, 2017)
4.48 Seventh Supplemental Indenture, dated as of March 14, 2018, between International Transmission Company and The Bank of New York Mellon Trust Company, N.A. (as successor to BNY Midwest Trust Company), as trustee (filed with Registrant’s Form 8-K on March 29, 2018)
4.49 Tenth Supplemental Indenture, dated as of September 28, 2018, between ITC Midwest LLC and The Bank of New York Mellon Trust Company, N.A. (as successor to The Bank of New York Trust Company, N.A.) as trustee (filed with Registrant’s Form 8-K on November 2, 2018)
4.50 Ninth Supplemental Indenture, dated as of November 28, 2018, between Michigan Electric Transmission Company, LLC and The Bank of New York Mellon Trust Company, N.A. (as successor to JP Morgan Chase Bank), as trustee (filed with Registrant’s Form 8-K on January 15, 2019)
4.51 Eighth Supplemental Indenture, dated as of August 14, 2019, between International Transmission Company and The Bank of New York Mellon Trust Company, N.A. (as successor to BNY Midwest Trust Company), as trustee (filed with Registrant’s Form 8-K on August 28, 2019)
4.52 Fifth Supplemental Indenture, dated as of May 14, 2020, between ITC Holdings Corp. and Wells Fargo Bank, National Association, as trustee (with Form of 2.95% Notes due 2030) (filed with Registrant’s Form 8-K on May 14, 2020).
4.53 Eleventh Supplemental Indenture, dated as of May 8, 2020, between ITC Midwest LLC and The Bank of New York Mellon Trust Company, N.A. (as successor to The Bank of New York Trust Company, N.A.) as trustee (filed with Registrant’s Form 8-K on July 15, 2020).
4.54 Tenth Supplemental Indenture, dated as of August 12, 2020, between Michigan Electric Transmission Company, LLC and The Bank of New York Mellon Trust Company, N.A. (as successor to JP Morgan Chase Bank), as trustee (filed with Registrant’s Form 8-K on October 14, 2020).
4.55 Eleventh Supplemental Indenture, dated as of July 19, 2021, between Michigan Electric Transmission Company, LLC and The Bank of New York Mellon Trust Company, N.A. (as successor to JPMorgan Chase Bank), as trustee (filed with Registrant’s Form 8-K on August 3, 2021)
4.56 Ninth Supplemental Indenture, dated as of November 5, 2021, between International Transmission Company and The Bank of New York Mellon Trust Company, N.A. (as successor to BNY Midwest Trust Company), as trustee (including Form of 2.93% First Mortgage Bonds, Series I, due 2052 and Form of 2.93% First Mortgage Bonds, Series J, due 2052) (filed with Registrant’s Form 8-K on January 14, 2022)
*10.27 Deferred Compensation Plan (filed with Registrant’s Registration Statement on Form S-1, as amended, Reg. No. 333-123657)
10.51 Form of Amended and Restated Easement Agreement between Consumers Energy Company and Michigan Electric Transmission Company (filed with Registrant’s Form 10-Q for the quarter ended September 30, 2006)
*10.81 Executive Supplemental Retirement Plan (filed with Registrant’s Form 10-K for the year ended December 31, 2008)
*10.109 Employment Agreement between ITC Holdings Corp. and Linda H. Blair, effective as of December 21, 2012 (filed with Registrant’s Form 8-K on December 26, 2012)
*10.110 Employment Agreement between ITC Holdings Corp. and Jon E. Jipping, effective as of December 21, 2012 (filed with Registrant’s Form 8-K on December 26, 2012)
*10.111 Employment Agreement between ITC Holdings Corp. and Daniel J. Oginsky, effective as of December 21, 2012 (filed with Registrant’s Form 8-K on December 26, 2012)
*10.120 First Amendment to Executive Supplemental Retirement Plan, dated as of May 16, 2013 (filed with Registrant’s Form 10-Q for the quarter ended June 30, 2013)
*10.122 Recoupment Policy and Related Consent, effective January 1, 2014 (filed with Registrant’s Form 8-K on December 2, 2013)
*10.150 Employment Agreement between ITC Holdings Corp. and Christine Mason Soneral, effective as of February 3, 2015 (filed with Registrant’s Form 10-Q for the quarter ended June 30, 2015)
*10.168 Letter Agreement, dated as of October 14, 2016, between ITC Holdings Corp. and Linda H. Blair (filed with Registrant’s Form 8-K on October 12, 2016)
*10.172 Employment Agreement between ITC Holdings Corp. and Gretchen L. Holloway, effective as of July 10, 2017 (filed with Registrant’s Form 10-K for the year ended December 31, 2020)
*10.173 Letter Agreement, dated as of October 12, 2016 between ITC Holdings Corp. and Christine Mason Soneral (filed with Registrant’s Form 10-K for the year ended December 31, 2016)
*10.176 2017 Omnibus Plan, effective February 27, 2017 (filed with Registrant’s Form 10-Q for the quarter ended March 31, 2017)
*10.177 Summary of 2017 Annual Incentive Plan (filed with Registrant’s Form 10-Q for the quarter ended March 31, 2017)
*10.178 Form of Service-Based Unit Award Agreement under 2017 Omnibus Plan (February 2017) (filed with Registrant’s Form 10-Q for the quarter ended March 31, 2017)
*10.179 Form of Performance-Based Unit Award Agreement under 2017 Omnibus Plan (February 2017) (filed with Registrant’s Form 10-Q for the quarter ended March 31, 2017)
*10.182 Amendment to 2017 Omnibus Plan, dated as of July 10, 2017 (filed with Registrant’s Form 10-Q for the quarter ended June 30, 2017)
*10.183 ITC Holdings Corp. Director Deferred Compensation Plan, effective March 1, 2017 (filed with Registrant’s Form 10-Q for the quarter ended June 30, 2017)
10.184 ITC Holdings Revolving Credit Agreement, dated as of October 23, 2017, among ITC Holdings Corp., with the banks, financial institutions and other institutional lenders listed on the respective signature pages thereof, JPMorgan Chase Bank, N.A., as administrative agent for the Lenders, JPMorgan Chase Bank, N.A., Barclays Bank PLC, Wells Fargo Securities, LLC, The Bank of Nova Scotia and Mizuho Bank, Ltd., as joint lead arrangers and joint bookrunners, Barclays Bank PLC and Wells Fargo Bank, National Association, as co-syndication agents and The Bank of Nova Scotia and Mizuho Bank, Ltd. as co-documentation agents (filed with Registrant’s Form 8-K on October 23, 2017)
10.185 ITCTransmission Revolving Credit Agreement, dated as of October 23, 2017, among International Transmission Company, with the banks, financial institutions and other institutional lenders listed on the respective signature pages thereof, JPMorgan Chase Bank, N.A., as administrative agent for the Lenders, JPMorgan Chase Bank, N.A., Barclays Bank PLC, Wells Fargo Securities, LLC, The Bank of Nova Scotia and Mizuho Bank, Ltd., as joint lead arrangers and joint bookrunners, Barclays Bank PLC and Wells Fargo Bank, National Association, as co-syndication agents and The Bank of Nova Scotia and Mizuho Bank, Ltd. as co-documentation agents (filed with Registrant’s Form 8-K on October 23, 2017)
10.186 METC Revolving Credit Agreement, dated as of October 23, 2017, among Michigan Electric Transmission Company, LLC, with the banks, financial institutions and other institutional lenders listed on the respective signature pages thereof, JPMorgan Chase Bank, N.A., as administrative agent for the Lenders, JPMorgan Chase Bank, N.A., Barclays Bank PLC, Wells Fargo Securities, LLC, The Bank of Nova Scotia and Mizuho Bank, Ltd., as joint lead arrangers and joint bookrunners, Barclays Bank PLC and Wells Fargo Bank, National Association, as co-syndication agents and The Bank of Nova Scotia and Mizuho Bank, Ltd. as co-documentation agents (filed with Registrant’s Form 8-K on October 23, 2017)
10.187 ITC Midwest Revolving Credit Agreement, dated as of October 23, 2017, among ITC Midwest LLC, with the banks, financial institutions and other institutional lenders listed on the respective signature pages thereof, JPMorgan Chase Bank, N.A., as administrative agent for the Lenders, JPMorgan Chase Bank, N.A., Barclays Bank PLC, Wells Fargo Securities, LLC, The Bank of Nova Scotia and Mizuho Bank, Ltd., as joint lead arrangers and joint bookrunners, Barclays Bank PLC and Wells Fargo Bank, National Association, as co-syndication agents and The Bank of Nova Scotia and Mizuho Bank, Ltd. as co-documentation agents (filed with Registrant’s Form 8-K on October 23, 2017)
10.188 ITC Great Plains Revolving Credit Agreement, dated as of October 23, 2017, among ITC Great Plains, LLC, with the banks, financial institutions and other institutional lenders listed on the respective signature pages thereof, JPMorgan Chase Bank, N.A., as administrative agent for the Lenders, JPMorgan Chase Bank, N.A., Barclays Bank PLC, Wells Fargo Securities, LLC, The Bank of Nova Scotia and Mizuho Bank, Ltd., as joint lead arrangers and joint bookrunners, Barclays Bank PLC and Wells Fargo Bank, National Association, as co-syndication agents and The Bank of Nova Scotia and Mizuho Bank, Ltd. as co-documentation agents (filed with Registrant’s Form 8-K on October 23, 2017)
*10.190 International Transmission Company Executive Deferred Compensation Plan, effective January 1, 2019 (filed with Registrant’s Form 10-K for the year ended December 31, 2018)
*10.191 ITC Holdings Corp. Director Deferred Compensation Plan, effective January 1, 2019 (filed with Registrant’s Form 10-K for the year ended December 31, 2018)
*10.192 Letter Agreement, effective as of February 18, 2019, between ITC Holdings Corp. and Jon E. Jipping (filed with Registrant’s Form 8-K on February 22, 2019)
10.194 ITC Holdings Amendment and Restatement Agreement dated as of January 10, 2020, among ITC Holdings Corp., the banks, financial institutions and other institutional lenders listed on the respective signature pages thereof, Wells Fargo Bank, National Association, in its capacity as successor administrative agent and JPMorgan Chase Bank, N.A., in its capacity as resigning administrative agent, amending and restating as of January 10, 2020 in the form attached as Exhibit A thereto the Revolving Credit Agreement, dated as of October 23, 2017, among ITC Holdings Corp., the banks, financial institutions and other institutional party thereto, JPMorgan Chase Bank, N.A., as administrative agent for the lenders, JPMorgan Chase Bank, N.A., Barclays Bank PLC, Wells Fargo Securities, LLC, The Bank of Nova Scotia and Mizuho Bank, Ltd., as joint lead arrangers and joint bookrunners, Barclays Bank PLC and Wells Fargo Bank, National Association, as co-syndication agents and The Bank of Nova Scotia and Mizuho Bank, Ltd. as co-documentation agents (filed with Registrant’s Form 8-K on January 10, 2020)
10.195 ITCTransmission Amendment and Restatement Agreement dated as of January 10, 2020, among International Transmission Company, the banks, financial institutions and other institutional lenders listed on the respective signature pages thereof, Wells Fargo Bank, National Association, in its capacity as successor administrative agent and JPMorgan Chase Bank, N.A., in its capacity as resigning administrative agent, amending and restating as of January 10, 2020 in the form attached as Exhibit A thereto the Revolving Credit Agreement, dated as of October 23, 2017, among International Transmission Company, the banks, financial institutions and other institutional party thereto, JPMorgan Chase Bank, N.A., as administrative agent for the lenders, JPMorgan Chase Bank, N.A., Barclays Bank PLC, Wells Fargo Securities, LLC, The Bank of Nova Scotia and Mizuho Bank, Ltd., as joint lead arrangers and joint bookrunners, Barclays Bank PLC and Wells Fargo Bank, National Association, as co-syndication agents and The Bank of Nova Scotia and Mizuho Bank, Ltd. as co-documentation agents (filed with Registrant’s Form 8-K on January 10, 2020)
10.196 METC Amendment and Restatement Agreement dated as of January 10, 2020, among Michigan Electric Transmission Company, LLC, the banks, financial institutions and other institutional lenders listed on the respective signature pages thereof, Wells Fargo Bank, National Association, in its capacity as successor administrative agent and JPMorgan Chase Bank, N.A., in its capacity as resigning administrative agent, amending and restating as of January 10, 2020 in the form attached as Exhibit A thereto the Revolving Credit Agreement, dated as of October 23, 2017, among Michigan Electric Transmission Company, LLC, the banks, financial institutions and other institutional party thereto, JPMorgan Chase Bank, N.A., as administrative agent for the lenders, JPMorgan Chase Bank, N.A., Barclays Bank PLC, Wells Fargo Securities, LLC, The Bank of Nova Scotia and Mizuho Bank, Ltd., as joint lead arrangers and joint bookrunners, Barclays Bank PLC and Wells Fargo Bank, National Association, as co-syndication agents and The Bank of Nova Scotia and Mizuho Bank, Ltd. as co-documentation agents (filed with Registrant’s Form 8-K on January 10, 2020)
10.197 ITC Midwest Amendment and Restatement Agreement dated as of January 10, 2020, among ITC Midwest LLC, the banks, financial institutions and other institutional lenders listed on the respective signature pages thereof, Wells Fargo Bank, National Association, in its capacity as successor administrative agent and JPMorgan Chase Bank, N.A., in its capacity as resigning administrative agent, amending and restating as of January 10, 2020 in the form attached as Exhibit A thereto the Revolving Credit Agreement, dated as of October 23, 2017, among ITC Midwest LLC, the banks, financial institutions and other institutional party thereto, JPMorgan Chase Bank, N.A., as administrative agent for the lenders, JPMorgan Chase Bank, N.A., Barclays Bank PLC, Wells Fargo Securities, LLC, The Bank of Nova Scotia and Mizuho Bank, Ltd., as joint lead arrangers and joint bookrunners, Barclays Bank PLC and Wells Fargo Bank, National Association, as co-syndication agents and The Bank of Nova Scotia and Mizuho Bank, Ltd. as co-documentation agents (filed with Registrant’s Form 8-K on January 10, 2020)
10.198 ITC Great Plains Amendment and Restatement Agreement dated as of January 10, 2020, among ITC Great Plains, LLC, the banks, financial institutions and other institutional lenders listed on the respective signature pages thereof, Wells Fargo Bank, National Association, in its capacity as successor administrative agent and JPMorgan Chase Bank, N.A., in its capacity as resigning administrative agent, amending and restating as of January 10, 2020 in the form attached as Exhibit A thereto the Revolving Credit Agreement, dated as of October 23, 2017, among ITC Great Plains, LLC, the banks, financial institutions and other institutional party thereto, JPMorgan Chase Bank, N.A., as administrative agent for the lenders, JPMorgan Chase Bank, N.A., Barclays Bank PLC, Wells Fargo Securities, LLC, The Bank of Nova Scotia and Mizuho Bank, Ltd., as joint lead arrangers and joint bookrunners, Barclays Bank PLC and Wells Fargo Bank, National Association, as co-syndication agents and The Bank of Nova Scotia and Mizuho Bank, Ltd. as co-documentation agents (filed with Registrant’s Form 8-K on January 10, 2020)
*10.200 2017 Omnibus Plan, as amended July 10, 2017 and February 4, 2020 (filed with Registrant’s Form 10-K for the year ended December 31, 2019)
*10.201 Executive Omnibus Plan, effective February 4, 2020. (filed with Registrant’s Form 10-K for the year ended December 31, 2019)
*10.202 Form of Performance-Based Unit Award Agreement under Executive Omnibus Plan (January 2020). (filed with Registrant’s Form 10-K for the year ended December 31, 2019)
*10.203 Employment Agreement between ITC Holdings Corp. and Krista K. Tanner, effective as of February 18, 2019 (filed with Registrant’s Form 10-K for the year ended December 31, 2021)
*10.204 Fortis Inc. 2020 Restricted Share Unit Plan, effective January 1, 2020 (filed with Registrant’s Form 10-Q for the quarter ended March 31, 2020)
*10.205 Form of Restricted Share Unit Grant Agreement under Fortis Inc. 2020 Restricted Share Unit Plan (January, 2020) (filed with Registrant’s Form 10-Q for the quarter ended March 31, 2020)
*10.206 Separation and Release Agreement, effective as of May 18, 2020, between ITC Holdings Corp. and Daniel J. Oginsky (filed with Registrant’s Form 10-K for the year ended December 31, 2020)
10.207 Amendment No. 1 to Credit Agreement, dated as of May 17, 2021, among ITC Holdings Corp., with the banks, financial institutions and other institutional lenders listed on the respective signature pages thereof, and Wells Fargo Bank, National Association, in its capacity as administrative agent (filed with Registrant’s Form 8-K on May 17, 2021)
10.208 Amendment No. 1 to Credit Agreement, dated as of May 17, 2021, among International Transmission Company, with the banks, financial institutions and other institutional lenders listed on the respective signature pages thereof, and Wells Fargo Bank, National Association, in its capacity as administrative agent (filed with Registrant’s Form 8-K on May 17, 2021)
10.209 Amendment No. 1 to Credit Agreement, dated as of May 17, 2021, among Michigan Electric Transmission Company, LLC, with the banks, financial institutions and other institutional lenders listed on the respective signature pages thereof, and Wells Fargo Bank, National Association, in its capacity as administrative agent (filed with Registrant’s Form 8-K on May 17, 2021)
10.210 Amendment No. 1 to Credit Agreement, dated as of May 17, 2021, among ITC Midwest LLC, with the banks, financial institutions and other institutional lenders listed on the respective signature pages thereof, and Wells Fargo Bank, National Association, in its capacity as administrative agent (filed with Registrant’s Form 8-K on May 17, 2021)
10.211 Amendment No. 1 to Credit Agreement, dated as of May 17, 2021, among ITC Great Plains, LLC, with the banks, financial institutions and other institutional lenders listed on the respective signature pages thereof, and Wells Fargo Bank, National Association, in its capacity as administrative agent (filed with Registrant’s Form 8-K on May 17, 2021)
***10.212 Executive Omnibus Plan, as amended November 11, 2021
***10.213 Fortis Inc. 2020 Restricted Share Unit Plan, as amended January 1, 2022
***10.214 Employment Agreement between ITC Holdings Corp. and Brian Slocum, effective as of February 14, 2022
**21 List of Subsidiaries
**31.1 Certification of Chief Executive Officer pursuant to Rule 13a-14 of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
**31.2 Certification of Chief Financial Officer pursuant to Rule 13a-14 of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
**32 Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
**101.INS XBRL Instance Document - the instance document does not appear in the Interactive Data file because its XBRL tags are embedded within the Inline XBRL document
**101.SCH Inline XBRL Taxonomy Extension Schema
**101.CAL Inline XBRL Taxonomy Extension Calculation Linkbase
**101.DEF Inline XBRL Taxonomy Extension Definition Database
**101.LAB Inline XBRL Taxonomy Extension Label Linkbase
**101.PRE Inline XBRL Taxonomy Extension Presentation Linkbase
**104 The cover page from the Company’s Annual Report on Form 10-K for the year ended December 31, 2021 (formatted in Inline XBRL and contained in Exhibit 101)
___________________________
* Management contract or compensatory plan or arrangement
** Filed herewith
*** Management contract or compensatory plan or arrangement filed herewith
SCHEDULE I - Condensed Financial Information of Registrant
ITC HOLDINGS CORP.
CONDENSED STATEMENTS OF FINANCIAL POSITION (PARENT COMPANY ONLY)
December 31,
(In millions of USD, except share data) 2021 2020
ASSETS
Current assets
Cash and cash equivalents $ 3 $ 2
Accounts receivable from subsidiaries 20 9
Intercompany tax receivable from subsidiaries 16 8
Prepaid and other current assets 3 -
Advances to subsidiaries 50 -
Total current assets 92 19
Other assets
Investment in subsidiaries 5,784 5,496
Deferred income taxes 142 160
Advances to subsidiaries 4 54
Other assets 112 101
Total other assets 6,042 5,811
TOTAL ASSETS $ 6,134 $ 5,830
LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities
Accrued compensation $ 72 $ 55
Accrued interest 23 23
Debt maturing within one year 654 67
Other current liabilities 8 8
Total current liabilities 757 153
Accrued pension and postretirement liabilities 52 59
Other liabilities 78 58
Long-term debt (net of deferred financing fees and discount of $17 and $21, respectively)
2,773 3,266
TOTAL LIABILITIES 3,660 3,536
STOCKHOLDER’S EQUITY
Common stock, without par value, 235,000,000 shares authorized, 224,203,112 shares issued and outstanding at December 31, 2021 and 2020 892 892
Retained earnings 1,584 1,410
Accumulated other comprehensive loss (2) (8)
Total stockholder’s equity 2,474 2,294
TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY $ 6,134 $ 5,830
See notes to condensed financial statements (parent company only).
SCHEDULE I - Condensed Financial Information of Registrant
ITC HOLDINGS CORP.
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (PARENT COMPANY ONLY)
Year Ended December 31,
(In millions of USD) 2021 2020 2019
Other income (expense), net $ 3 $ 5 $ 5
General and administrative expense (30) (20) (25)
Taxes other than income taxes (2) (1) (2)
Interest expense (129) (122) (119)
LOSS BEFORE INCOME TAXES (158) (138) (141)
INCOME TAX BENEFIT (46) (43) (44)
LOSS AFTER TAXES (112) (95) (97)
EQUITY IN SUBSIDIARIES’ NET EARNINGS 518 502 525
NET INCOME 406 407 428
OTHER COMPREHENSIVE INCOME (LOSS)
Derivative instruments (net of tax of $2 for the year ended December 31, 2021, $7 for the year ended December 31, 2020, $1 for the year ended December 31, 2019 6 (15) 3
TOTAL OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX 6 (15) 3
TOTAL COMPREHENSIVE INCOME $ 412 $ 392 $ 431
See notes to condensed financial statements (parent company only).
SCHEDULE I - Condensed Financial Information of Registrant
ITC HOLDINGS CORP.
CONDENSED STATEMENTS OF CASH FLOWS (PARENT COMPANY ONLY)
Year Ended December 31,
(In millions of USD) 2021 2020 2019
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 406 $ 407 $ 428
Adjustments to reconcile net income to net cash used in operating activities:
Equity in subsidiaries' earnings (518) (502) (525)
Dividends from subsidiaries 10 3 3
Deferred and other income taxes (41) (46) (51)
Net intercompany tax payments from (to) subsidiaries 56 33 14
Share-based compensation 25 15 18
Other 4 2 6
Changes in assets and liabilities, exclusive of changes shown separately:
Accounts receivable from subsidiaries (2) 9 9
Intercompany tax receivable from subsidiaries (9) (4) 11
Income tax receivable - - 1
Accrued compensation 4 (12) 22
Other current and non-current assets and liabilities, net (2) (3) -
Net cash used in operating activities (67) (98) (64)
CASH FLOWS FROM INVESTING ACTIVITIES
Equity contributions to subsidiaries (51) (88) (120)
Return of capital from subsidiaries 259 228 239
Advances to subsidiaries - (50) -
Other 1 (2) (1)
Net cash provided by investing activities 209 88 118
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt - 700 -
Borrowings under revolving credit agreement 93 293 72
Borrowings under term loan credit agreements - 200 200
Net issuance of commercial paper 88 (133) 200
Retirement of long-term debt - including extinguishment of debt costs - - (203)
Repayments of revolving credit agreement (91) (290) (75)
Repayments of term loan credit agreement - (400) -
Dividends to ITC Investment Holdings (232) (330) (250)
Settlement of interest rate swaps - (23) -
Other 1 (7) -
Net cash provided by (used in) financing activities (141) 10 (56)
NET INCREASE (DECREASE) IN CASH, CASH EQUIVALENTS AND RESTRICTED CASH 1 - (2)
CASH, CASH EQUIVALENTS AND RESTRICTED CASH - Beginning of period 2 2 4
CASH, CASH EQUIVALENTS AND RESTRICTED CASH - End of period $ 3 $ 2 $ 2
See notes to condensed financial statements (parent company only).
SCHEDULE I - Condensed Financial Information of Registrant
ITC HOLDINGS CORP.
NOTES TO CONDENSED FINANCIAL STATEMENTS (PARENT COMPANY ONLY)
1. GENERAL
For ITC Holdings Corp.’s (“ITC Holdings,” “we,” “our” and “us”) presentation (Parent Company only), the investment in subsidiaries is accounted for using the equity method. The condensed parent company financial statements and notes should be read in conjunction with the consolidated financial statements and notes of ITC Holdings appearing in this Annual Report on Form 10-K. Certain prior period amounts in the financial statements and notes have been reclassified to conform to the current period presentation for comparative purposes.
As a holding company with no business operations, ITC Holdings’ assets consist primarily of investments in our subsidiaries. ITC Holdings’ material cash inflows are only from dividends and other payments received from our subsidiaries, the proceeds raised from the sale of debt securities, issuances under our commercial paper program and borrowings under our revolving and term loan term credit agreements. ITC Holdings may not be able to access cash generated by our subsidiaries in order to fulfill cash commitments. The ability of our subsidiaries to make dividend and other payments to us is subject to the availability of funds after taking into account their respective funding requirements, the terms of their respective indebtedness, the regulations of the FERC under the FPA and applicable state laws. In addition, there are practical limitations on using the net assets of each of our Regulated Operating Subsidiaries as of December 31, 2021 for dividends based on management's intent to maintain the FERC-approved capital structure targeting 60% equity and 40% debt for each of our Regulated Operating Subsidiaries. These net assets are included in Schedule I as the line-item “Investments in subsidiaries.” Each of our subsidiaries, however, is legally distinct from us and has no obligation, contingent or otherwise, to make funds available to us.
Recent Developments Regarding the COVID-19 Pandemic
In March 2020, the World Health Organization declared COVID-19 a pandemic. Efforts to control the outbreak of COVID-19 have resulted in challenges to businesses and facilities in various industries around the world, including our customers, and disruptions to the global economy and supply chains. To date, COVID-19 has not had a material impact on our net income. However, for 2020, we utilized various temporary cost saving measures related to operating expenses, including operation and maintenance expenses and general and administrative expenses, in an attempt to reduce costs for our customers that were collected through our Formula Rates.
We are unable to predict the ultimate effects of COVID-19 on the U.S. or global economy or our operations. We continue to monitor developments affecting our workforce, customers, suppliers, and operations. The extent of the impact of COVID-19 will depend on its duration, actions by government authorities, and impacts on our customers, employees, or vendors. These developments are continuously evolving, and we cannot predict whether COVID-19 will have a material impact on our financial condition, results of operations or cash flows.
2. DEBT
As of December 31, 2021, the maturities of our debt outstanding were as follows:
(In millions of USD)
2022 $ 655
2023 250
2024 439
2025 -
2026 400
2027 and thereafter 1,700
Total $ 3,444
Refer to Note 9 to the consolidated financial statements for additional information on the ITC Holdings Senior Notes, the ITC Holdings Revolving Credit Agreements, the ITC Holdings Commercial Paper Program and the ITC Holdings Derivative Instruments and Hedging Activities.
Fixed Rate Debt
Based on the borrowing rates obtained from third party lending institutions currently available for bank loans with similar terms and average maturities from active markets, the fair value of the ITC Holdings Senior Notes was $3,516 million and $3,670 million at December 31, 2021 and 2020, respectively. The total book value of the ITC Holdings Senior Notes, net of discount and deferred financing fees, was $3,233 million and $3,229 million at December 31, 2021 and 2020, respectively. The fair values of the ITC Holdings Senior Notes represent Level 2 under the three-tier hierarchy described in Note 12 to the consolidated financial statements.
Revolving Credit Agreements
At December 31, 2021 and 2020, we had $39 million and $37 million, respectively, outstanding under our revolving credit agreements, which are variable rate loans. The fair value of these loans approximates book value based on the borrowing rates currently available for variable rate loans obtained from third party lending institutions. The fair values of the revolving credit agreements represent Level 2 under the three-tier hierarchy described in Note 12 to the consolidated financial statements.
Other Financial Instruments
The carrying value of other financial instruments included in current assets and current liabilities, including cash and cash equivalents, special deposits and commercial paper, approximates their fair value due to the short-term nature of these instruments.
3. RELATED-PARTY TRANSACTIONS
Net Intercompany Receivables and Payables
We may incur charges from our subsidiaries for general corporate expenses incurred. In addition, we may perform additional services for, or receive additional services from our subsidiaries. These transactions are in the normal course of business and payments for these services are settled through accounts receivable and accounts payable, as necessary. We generally settle our intercompany balances with our affiliates on a net basis monthly.
Retirement Benefits
We are the plan sponsor for a pension plan, other postretirement plans and a defined contribution plan. The benefits-related expenses recorded by our affiliates result from the inclusion of benefit costs as a component of the total charge for services performed by our employees under the cost assignment and allocation methods used by us and our subsidiaries.
Equity Transactions
Year Ended December 31,
(In millions of USD) 2021 2020 2019
Equity contributions to subsidiaries $ (51) $ (88) $ (120)
Dividends from subsidiaries (a) 10 3 3
Return of capital from subsidiaries (a) 259 228 239
____________________________
(a)Includes ITCTransmission, MTH, ITC Midwest and other subsidiaries.
Intercompany Tax Sharing Arrangement
As discussed in Note 1 to the condensed financial statements of the parent company, we are a holding company with no business operations. We file consolidated income tax returns that include our affiliates, which are taxed as a corporation for federal and Michigan income tax purposes. We operate under an intercompany tax sharing arrangement with our subsidiaries and as a result may receive or pay federal and state income tax based on their stand-alone company tax positions.
Year Ended December 31,
(In millions of USD) 2021 2020 2019
Net income tax payments (to) from: (a)
ITCTransmission $ 24 $ 17 $ 7
METC 15 9 4
ITC Midwest 10 1 3
ITC Great Plains 6 6 (1)
ITC Interconnection 1 - 1
____________________________
(a)The net income tax payments were pursuant to intercompany tax sharing arrangements, and the total of these tax payments is presented as a net cash outflow or inflow from operating activities in the condensed parent company statements of cash flows. Other reconciling items between the parent company and the consolidated tax liabilities are presented as deferred and other income taxes in the adjustments to reconcile net income to net cash provided by operating activities. Additionally, ITC Holdings paid its subsidiaries for NOLs utilized by the consolidated group.
Intercompany Loan Agreement
On September 21, 2020, we advanced an intercompany loan to ITCTransmission totaling $50 million, due September 21, 2022, which remained outstanding at December 31, 2021. On January 14, 2022, ITCTransmission repaid the intercompany loan in full with proceeds from the issuance of First Mortgage Bonds on January 14, 2022. We received interest payments of $1 million during the year ended December 31, 2021 from ITCTransmission associated with this intercompany loan. Additionally, at December 31, 2021 we had a $4 million intercompany loan with ITC Interconnection, due June 1, 2046. During the year ended December 31, 2021, we received principal and interest payments of $1 million from ITC Interconnection associated with this intercompany loan.
4. SUPPLEMENTAL FINANCIAL INFORMATION
Reconciliation of Cash, Cash Equivalents and Restricted Cash
The following table provides a reconciliation of cash, cash equivalents and restricted cash reported on the condensed statements of financial position that sum to the total of the same such amounts shown in the condensed statements of cash flows:
December 31,
(In millions of USD) 2021 2020 2019 2018
Cash and cash equivalents $ 3 $ 2 $ 2 $ 3
Restricted cash included in:
Other non-current assets - - - 1
Total cash, cash equivalents and restricted cash $ 3 $ 2 $ 2 $ 4
Supplementary Cash Flows Information
Year Ended December 31,
(In millions of USD) 2021 2020 2019
Supplementary cash flows information:
Interest paid $ 119 $ 116 $ 117
Income taxes paid - 2 -
Income tax refunds received - 2 3