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| Table of Contents |
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| Forward-Looking Information | 2 | | Cybersecurity | 19 |
| Glossary | 3 | | Governance and Oversight | 20 |
| Corporate Structure | 5 | | Risk Management and Strategy | 20 |
| Name and Incorporation | 5 | | Focus on Sustainability | 21 |
| Inter-Corporate Relationships | 5 | | Environmental Regulation and Contingencies | 21 |
| General Development of the Business | 5 | | Capital Structure and Dividends | 21 |
| Overview | 5 | | Description of Capital Structure | 21 |
| Three-Year History | 6 | | Dividends and Distributions | 22 |
| Outlook | 7 | | Debt Covenant Restrictions on Dividend Distributions | 22 |
| Description of the Business | 7 | | Credit Ratings | 22 |
| Regulated Utilities | 8 | | Directors and Officers | 25 |
| ITC | 8 | | Audit Committee | 27 |
| UNS Energy | 10 | | Members | 27 |
| Central Hudson | 12 | | Education and Experience | 27 |
| FortisBC Energy | 13 | | Pre-Approval Policies and Procedures | 27 |
| FortisAlberta | 14 | External Auditor Service Fees | 28 |
| FortisBC Electric | 15 | | Transfer Agent and Registrar | 28 |
| Other Electric | 16 | | Interests of Experts | 28 |
| Non-Regulated | 18 | | Additional Information | 28 |
| Corporate and Other | 18 | | Exhibit A: Summary of Terms and Conditions of Authorized Securities | 29 |
| Human Resources | 18 | | Exhibit B: Market for Securities | 31 |
| Legal Proceedings and Regulatory Actions | 19 | | Exhibit C: Audit Committee Mandate | 33 |
| Interest of Management and Others in Material Transactions | 19 | | Exhibit D: Material Contracts | 40 |
| Risk Factors | 19 | | | |
| | | | |
Dated February 8, 2024
Financial information in this AIF has been prepared in accordance with U.S. GAAP and is presented in Canadian dollars ($) based, as applicable, on the following U.S.-to-Canadian dollar exchange rates: (i) average of 1.35 and 1.30 for the years ended December 31, 2023 and 2022, respectively; (ii) 1.32 and 1.36 as at December 31, 2023 and 2022, respectively; and (iii) 1.30 for all forecast periods.
Except as otherwise expressly noted, the information in this AIF is given as of December 31, 2023.
FORWARD-LOOKING INFORMATION
Fortis includes forward-looking information in this AIF within the meaning of applicable Canadian securities laws and forward-looking statements within the meaning of the U.S. Private Securities Litigation Reform Act of 1995 (collectively referred to as "forward-looking information"). Forward-looking information reflects expectations of Fortis management regarding future growth, results of operations, performance, business prospects and opportunities. Wherever possible, words such as anticipates, believes, budgets, could, estimates, expects, forecasts, intends, may, might, plans, projects, schedule, should, target, will, would, and the negative of these terms, and other similar terminology or expressions, have been used to identify the forward-looking information, which includes, without limitation: forecast Capital Expenditures for 2024-2028, including Cleaner Energy Investments; TEP's planned exit from coal generation; the expected funding sources for the Capital Plan; the expected sources of common equity proceeds; the 2030 and 2035 direct GHG emissions reduction targets and how these targets are expected to be achieved; TEP's 2023 Integrated Resource Plan; the 2050 net-zero direct GHG emissions target; the expected nature, timing and benefits of additional opportunities beyond the Capital Plan, including further expansion of the electric transmission grid in the U.S. to facilitate the interconnection of cleaner energy, climate adaptation and grid resiliency investments, renewable gas solutions and LNG infrastructure in British Columbia, and the acceleration of cleaner energy infrastructure investments; forecast rate base and rate base growth rate to 2028; the expectation that long-term growth in rate base will drive earnings that support dividend growth guidance of 4-6% annually through 2028; the expectation that Fortis is positioned well for future investment opportunities; the potential impact of government policies to address climate change and the resultant impact on the competitiveness of natural gas relative to other energy sources; the expected in-service dates for certain projects; the expected output of FortisBC Electric's Kootenay River system plants in the event of the termination of the CPA; the expected timing and benefits of the Wataynikaneyap transmission power project; the expected timing of the finalization of fuel supply contracts at Caribbean Utilities; the expected timing, outcome and impact of regulatory proceedings and decisions; and TEP's estimated mine reclamation costs.
Forward‑looking information involves significant risks, uncertainties and assumptions. Certain material factors or assumptions have been applied in drawing the conclusions contained in the forward-looking information, including, without limitation: reasonable regulatory decisions and the expectation of regulatory stability; the successful execution of the Capital Plan; no material capital project or financing cost overrun; sufficient human resources to deliver service and execute the Capital Plan; the realization of additional opportunities beyond the Capital Plan; no significant variability in interest rates; the Board exercising its discretion to declare dividends, taking into account the business performance and financial condition of the Corporation; no significant operational disruptions or environmental liability or upset; the continued ability to maintain the performance of the electricity and gas systems; no severe and prolonged economic downturn; sufficient liquidity and capital resources; the ability to hedge exposures to fluctuations in foreign exchange rates, natural gas prices and electricity prices; the continued availability of natural gas, fuel, coal and electricity supply; continuation of power supply and capacity purchase contracts; no significant changes in government energy plans, environmental laws and regulations that could have a material negative impact; maintenance of adequate insurance coverage; the ability to obtain and maintain licences and permits; retention of existing service areas; no significant changes in tax laws and the continued tax deferred treatment of earnings from the Corporation's foreign operations; continued maintenance of information technology infrastructure and no material breach of cybersecurity; continued favourable relations with Indigenous Peoples; and favourable labour relations.
Fortis cautions readers that a number of factors could cause actual results, performance or achievements to differ materially from those discussed or implied in the forward-looking information. These factors should be considered carefully and undue reliance should not be placed on the forward-looking information. Risk factors which could cause results or events to differ from current expectations are detailed in the MD&A under the heading "Business Risks" and in other continuous disclosure materials filed from time to time with Canadian securities regulatory authorities and the Securities and Exchange Commission.
All forward-looking information in this AIF is given as of the date of this AIF. Fortis disclaims any intention or obligation to update or revise any forward-looking information, whether as a result of new information, future events or otherwise.
GLOSSARY
Certain terms used in this 2023 Annual Information Form are defined below:
2023 Annual Information Form or AIF: this annual information form of the Corporation in respect of the year ended December 31, 2023
AECO/NIT: Alberta Energy Company/Nova Inventory Transfer
Aitken Creek: Aitken Creek natural gas storage facility
Algoma Power: Algoma Power Inc.
APS: Arizona Public Service Company
ATM Program: At-the-market equity program
AUC: Alberta Utilities Commission
BC Hydro: BC Hydro and Power Authority
BCUC: British Columbia Utilities Commission
Belize Electricity: Belize Electricity Limited
BESS: battery energy storage system
Board: Board of Directors of the Corporation
CAGR: compound annual growth rate. Calculated on a constant U.S. dollar to Canadian dollar exchange rate
Canadian Niagara Power: Canadian Niagara Power Inc.
Capital Expenditures: cash outlay for additions to property, plant and equipment and intangible assets as shown in the Financial Statements, as well as the Corporation's 39% share of capital spending for the Wataynikaneyap Transmission Power Project. See the "Non-U.S. GAAP Financial Measures" section of the MD&A
Capital Plan: forecast Capital Expenditures. Represents a non-U.S. GAAP financial measure calculated in the same manner as Capital Expenditures
Caribbean Utilities: Caribbean Utilities Company, Ltd.
Central Hudson: Central Hudson Gas & Electric Corporation
CIO: Chief Information Officer
Cleaner Energy Investments: Capital Expenditures that support
reductions in air emissions, water usage and/or increases customer energy efficiency
CMS: Consumers Energy Company
Common Equity Earnings: Net earnings attributable to common equity shareholders
Cornwall Electric: Cornwall Street Railway, Light and Power Company, Limited
Corporation: Fortis Inc.
CPA: Canal Plant Agreement
CRMP: Cybersecurity Risk Management Program
CUPE: Canadian Union of Public Employees
DBRS Morningstar: DBRS Limited
DRIP: Dividend reinvestment plan
DTE: DTE Electric Company
EDGAR: SEC's system for Electronic Data Gathering, Analysis and Retrieval available at www.sec.gov
Eiffel Investment: Eiffel Investment Pte Ltd.
EPS: earnings per common share
FHI: FortisBC Holdings Inc.
Financial Statements: the Corporation's Audited Consolidated Financial Statements in respect of the year ended December 31, 2023
Fitch: Fitch Ratings Inc.
Fortis: Fortis Inc.
FortisAlberta: FortisAlberta Inc.
FortisBC Electric: collectively, the operations of FortisBC Inc. and its parent company, FortisBC Pacific Holdings Inc.
FortisBC Energy: FortisBC Energy Inc.
FortisCanada: FortisCanada Inc.
FortisOntario: FortisOntario Inc.
FortisTCI: collectively, FortisTCI Limited and Turks and Caicos Utilities Limited
FortisUS: FortisUS Inc.
FortisUS Holdings: FortisUS Holdings Nova Scotia Limited
Fortis Belize: Fortis Belize Limited, an indirect wholly owned subsidiary of Fortis
GHG: greenhouse gas
GIC: GIC Private Limited
IBEW: International Brotherhood of Electrical Workers
IESO: Independent Electricity System Operator of Ontario
IPL: Interstate Power and Light Company
ITC: ITC Holdings together with all of its subsidiaries
ITC Great Plains: ITC Great Plains, LLC
ITC Holdings: ITC Holdings Corp.
ITC Interconnection: ITC Interconnection LLC
ITC Investment Holdings: ITC Investment Holdings Inc.
ITC Midwest: ITC Midwest LLC
ITC's MISO Regulated Operating Subsidiaries: collectively ITCTransmission, METC and ITC Midwest
ITC's Regulated Operating Subsidiaries: collectively, ITCTransmission, METC, ITC Midwest, ITC Great Plains and ITC Interconnection
ITCTransmission: International Transmission Company
LNG: liquefied natural gas
LRTP: long-range transmission Plan
Maritime Electric: Maritime Electric Company, Limited
MD&A: the Corporation's Management Discussion and Analysis in respect of the year ended December 31, 2023
METC: Michigan Electric Transmission Company
MISO: Midcontinent Independent System Operator, Inc.
Moody's: Moody's Investors Service, Inc.
MoveUP: Movement of United Professionals
NB Power: New Brunswick Power Corporation
NERC: North American Electric Reliability Corporation
Newfoundland Power: Newfoundland Power Inc.
NL Hydro: Newfoundland and Labrador Hydro Corporation
NYSE: New York Stock Exchange
PEI: Prince Edward Island, Canada
PNM: Public Service Company of New Mexico
PPA: power purchase agreement
PUB: Newfoundland and Labrador Board of Commissioners of Public Utilities
PWU: Power Workers' Union
ROFR: right of first refusal
S&P: Standard & Poor's Financial Services LLC
SEC: United States Securities and Exchange Commission
SEDAR+: the System for Electronic Document Analysis and Retrieval + of the Canadian Securities Administrators available at www.sedarplus.ca
SPP: Southwest Power Pool, Inc.
SRP: Salt River Project Agricultural Improvement and Power District
T&D: transmission and distribution
TC Energy: TC Energy Corporation
TCFD: Task Force for Climate-Related Financial Disclosures
TEP: Tucson Electric Power Company
TSX: Toronto Stock Exchange
UNS Electric and UNSE: UNS Electric, Inc.
UNS Energy: UNS Energy Corporation
UNS Gas: UNS Gas, Inc.
U.S.: United States of America
U.S. GAAP: accounting principles generally accepted in the U.S.
UUWA: United Utility Workers' Association of Canada
Waneta Expansion: Waneta Expansion hydroelectric generating facility
Wataynikaneyap Partnership: Wataynikaneyap Power Limited Partnership
Measurements: Conversions:
GW Gigawatt(s) 1 litre = 0.22 imperial gallons
GWh Gigawatt hour(s) 1 kilometer = 0.62 miles
km Kilometer(s)
MW Megawatt(s)
TJ Terajoule(s)
PJ Petajoule(s)
Conversion using the above factors on rounded numbers appearing in this AIF may produce small differences from reported amounts as a result.
CORPORATE STRUCTURE
Name and Incorporation
Fortis Inc. is a holding company that was incorporated as 81800 Canada Ltd. under the Canada Business Corporations Act on June 28, 1977 and continued under the Corporations Act (Newfoundland and Labrador) on August 28, 1987. The corporate head office and registered office of Fortis is located at Fortis Place, Suite 1100, 5 Springdale Street, P.O. Box 8837, St. John's, Newfoundland and Labrador, Canada, A1B 3T2.
The articles of continuance of the Corporation were amended to: (i) change its name to Fortis on October 13, 1987; (ii) set out the rights, privileges, restrictions and conditions attached to the common shares on October 15, 1987; (iii) designate 2,000,000 First Preference Shares, Series A on September 11, 1990; (iv) replace the class rights, privileges, restrictions and conditions attaching to the First Preference Shares and the Second Preference Shares on July 22, 1991; (v) designate 2,000,000 First Preference Shares, Series B on December 13, 1995; (vi) designate 5,000,000 First Preference Shares, Series C on May 27, 2003; (vii) designate 8,000,000 First Preference Shares, Series D and First Preference Shares, Series E on January 23, 2004; (viii) amend the redemption provisions attaching to the First Preference Shares, Series D on July 15, 2005; (ix) designate 5,000,000 First Preference Shares, Series F on September 22, 2006; (x) designate 9,200,000 First Preference Shares, Series G on May 20, 2008; (xi) designate 10,000,000 First Preference Shares, Series H and 10,000,000 First Preference Shares, Series I on January 20, 2010; (xii) designate 8,000,000 First Preference Shares, Series J on November 8, 2012; (xiii) designate 12,000,000 First Preference Shares, Series K and 12,000,000 First Preference Shares, Series L on July 11, 2013; and (xiv) designate 24,000,000 First Preference Shares, Series M and 24,000,000 First Preference Shares, Series N on September 16, 2014.
Inter-Corporate Relationships
The following table lists the principal subsidiaries of the Corporation, their jurisdictions of incorporation and the percentage of votes attaching to voting securities held directly or indirectly by the Corporation as at February 8, 2024. The principal subsidiaries together comprise approximately 90% of the Corporation's consolidated assets as at December 31, 2023 and approximately 86% of the Corporation's 2023 consolidated revenue. This table excludes certain subsidiaries, the assets and revenues of which did not individually exceed 10% or, in the aggregate exceed 20%, of the total consolidated assets or total consolidated revenues of the Corporation as at December 31, 2023.
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| Subsidiary | | Jurisdiction of Incorporation | | Votes attaching to voting securities beneficially owned, controlled or directed by the Corporation (%) |
ITC (1) | | Michigan, United States | | 80.1 |
UNS Energy (2) | | Arizona, United States | | 100 |
Central Hudson (3) | | New York, United States | | 100 |
FortisBC Energy (4) | | British Columbia, Canada | | 100 |
FortisAlberta (5) | | Alberta, Canada | | 100 |
Newfoundland Power (6) | | Newfoundland and Labrador, Canada | | 100 |
(1)ITC Holdings, a Michigan corporation, owns all of the shares of ITC Great Plains, ITC Interconnection, ITC Midwest, ITCTransmission and METC. ITC Investment Holdings, a Michigan corporation, owns all of the shares of ITC Holdings. FortisUS, a Delaware corporation, holds an 80.1% interest in ITC Investment Holdings. FortisUS Holdings, a Canadian corporation, owns all of the shares of FortisUS. Fortis owns all of the shares of FortisUS Holdings. 19.9% of the securities of ITC Investment Holdings are owned by an affiliate of GIC, but are held as a passive investment, retaining only those rights necessary to protect its passive minority investment.
(2)UNS Energy, an Arizona corporation, owns all of the shares of TEP, UNS Electric and UNS Gas. FortisUS owns all of the shares of UNS Energy.
(3)CH Energy Group, Inc., a New York corporation, owns all of the shares of Central Hudson. FortisUS owns all of the shares of CH Energy Group, Inc.
(4)FHI, a British Columbia corporation, owns all of the shares of FortisBC Energy. Fortis owns all of the shares of FHI.
(5)FortisAlberta Holdings Inc., an Alberta corporation, owns all of the shares of FortisAlberta. FortisCanada, a Canadian corporation, owns all of the shares of FortisAlberta Holdings Inc. Fortis owns all of the shares of FortisCanada.
(6)Fortis owns all the shares of Newfoundland Power.
GENERAL DEVELOPMENT OF THE BUSINESS
Overview
Fortis is a well-diversified leader in the North American regulated electric and gas utility industry, with 2023 revenue of $12 billion and total assets of $66 billion as at December 31, 2023.
Regulated utilities account for 99% of the Corporation's assets. The Corporation's 9,600 employees serve 3.5 million utility customers in five Canadian provinces, ten U.S. states and three Caribbean countries. As at December 31, 2023, 67% of the Corporation's assets were located outside Canada and 61% of 2023 revenue was derived from foreign operations.
Three-Year History
Over the past three years, Fortis has continued to experience significant growth. Total assets have increased from $55.5 billion at the start of 2021 to $65.9 billion as at December 31, 2023. Consolidated Capital Expenditures totalled $11.9 billion from 2021 through 2023, resulting in a three-year midyear rate base CAGR of 6.5%. The Corporation's shareholders' equity has also grown from $18.7 billion at the start of 2021 to $21.5 billion as at December 31, 2023. Common Equity Earnings for 2021 totalled $1,231 million compared to $1,506 million in 2023. The growth in earnings over the three-year period reflects the Corporation's organic growth strategy for its regulated utilities, and is also impacted by the higher average U.S.-to-Canadian dollar exchange rate in 2023 of 1.35 compared to 1.25 in 2021.
An overview of the Corporation's performance for the past three years follows:
2021
The Corporation's utilities reliably and safely delivered essential service in 2021. The COVID-19 pandemic did not have a significant impact on the Corporation's financial performance in 2021.
In July 2021, the Corporation's sustainability update was released and included information on the Corporation's progress on reducing carbon emissions and support of TCFD, among other things.
In September 2021, Fortis announced its 2022-2026 Capital Plan of $20 billion. The Capital Plan included $1 billion of additional capital investment at the Corporation's regulated utilities in comparison to the five-year Capital Plan released in 2020. The increase largely reflected customer growth, enhancements to transmission reliability and capacity, and Cleaner Energy Investments. This growth was tempered by $600 million associated with a lower assumed foreign exchange rate from that assumed in the Corporation's previous five-year Capital Plan.
2022
The Corporation's utilities continued to deliver reliable and safe service in 2022. In March 2022, the Corporation made progress on its commitment as a TCFD supporter with the release of its first TCFD and Climate Assessment Report, which included an analysis of four climate-related scenarios and associated risks and opportunities. The report provided information on the Corporation's strategy and actions to combat climate change, identified new opportunities associated with decarbonization, and provided a guide for investment in resilient and adaptable infrastructure. In July 2022, Fortis released its 2022 Sustainability Report, highlighting progress on a number of sustainability priorities, including the addition of more renewable energy, a further reduction in GHG emissions and advances in diversity.
In October 2022, Fortis announced its 2023-2027 Capital Plan of $22.3 billion. The Capital Plan included $2.3 billion of additional capital investment at the Corporation's regulated utilities in comparison to the previous five-year Capital Plan. The increase was driven by organic growth, largely reflecting regional transmission projects associated with the MISO LRTP at ITC, additional Cleaner Energy Investments in Arizona, and enhancements to distribution infrastructure reliability and capacity, as well as investments to support customer growth, across the Corporation's regulated utilities. Approximately $500 million of the increase was driven by a higher assumed U.S.-to-Canadian dollar exchange rate over the five-year period. The five-year Capital Plan reflected $5.9 billion in Cleaner Energy Investments primarily focused on connecting renewables to the grid, renewable and storage investments and cleaner fuel solutions.
2023
The Corporation continued to reliably and safely deliver electricity and gas service, outperforming industry averages in Canada and the U.S. for reliability and safety.
In September 2023, Fortis released its 2024-2028 Capital Plan of $25 billion, reflecting incremental capital investment of $2.7 billion over the prior year five-year plan. The increase is driven by organic growth, largely reflecting regional transmission projects at ITC associated with tranche one of the MISO LRTP (see "Competition" on page 8), as well as investments in Arizona to support TEP’s exit from coal. Investments supporting system adaptation and resiliency, customer growth and economic development are also driving capital growth across the Corporation's regulated utilities.
Cleaner Energy Investments of approximately $7 billion are expected over the five-year planning period, with capital expenditures focused on connecting renewables to the grid, renewable and storage investments in Arizona and the Caribbean, and cleaner natural gas solutions in British Columbia. Fortis remains focused on maintaining customer affordability by controlling costs, investing in cleaner energy resulting in fuel savings for customers, utilizing available tax credits, and implementing innovative practices, among other initiatives.
The five-year Capital Plan is expected to be funded primarily by cash from operations and regulated utility debt. Common equity proceeds are expected to be sourced from the Corporation's DRIP and ATM Program.
The Corporation reported Common Equity Earnings of $1.5 billion in 2023, or $3.10 per common share, compared to $1.3 billion, or $2.78 per common share in 2022. The increase was primarily driven by rate base growth across Fortis' utilities and the new cost of capital parameters approved for FortisBC effective January 1, 2023. Higher earnings in Arizona also contributed to earnings growth, reflecting higher retail electricity sales, new customer rates at TEP effective September 1, 2023, and lower depreciation expense associated with retirement of the San Juan generating station in 2022. An increase in the market value of certain investments that support retirement benefits, and the higher U.S.-to-Canadian dollar exchange rate, also favourably impacted earnings. The increase was partially offset by higher corporate finance costs and lower earnings from Aitken Creek. An increase in the weighted average number of common shares outstanding, largely associated with the Corporation's DRIP, also impacted earnings per common share.
Capital Expenditures of $4.3 billion in 2023 were in-line with the 2023 Capital Plan, with over $700 million of capital investment related to delivering cleaner energy to customers. Capital Expenditures were $0.3 billion higher than 2022, primarily due to construction of the Roadrunner Reserve battery energy storage project in Arizona and investment in various smaller distribution projects across the Corporation's regulated utilities, as well as the impact of the higher average foreign exchange rate.
Outlook
Fortis is transitioning to a cleaner energy future and is on track to achieve its corporate-wide targets to reduce direct GHG emissions by 50% by 2030 and 75% by 2035 from a 2019 base year. The Corporation's 2050 net-zero direct GHG emissions target reinforces Fortis' commitment to further decarbonize over the long-term, while continuing our focus on reliability and affordability.
Fortis continues to enhance shareholder value through the execution of its Capital Plan, the balance and strength of its diversified portfolio of regulated utility businesses, and growth opportunities within and proximate to its service territories. The Corporation's $25 billion five-year Capital Plan is expected to increase midyear rate base from $37.0 billion in 2023 to $49.4 billion by 2028, translating into a five-year CAGR of 6.3%.
Beyond the five-year Capital Plan, additional opportunities to expand and extend growth include: further expansion of the electric transmission grid in the U.S. to facilitate the interconnection of cleaner energy, including infrastructure investments associated with the IRA and the MISO LRTP; climate adaptation and grid resiliency investments; renewable natural gas solutions and LNG infrastructure in British Columbia; and the acceleration of cleaner energy infrastructure investments across our jurisdictions.
Fortis expects its long-term growth in rate base will drive earnings that support dividend growth guidance of 4-6% annually through 2028, and is premised on the assumptions and material factors listed under "Forward-Looking Information".
DESCRIPTION OF THE BUSINESS
Fortis is principally an energy delivery company, with 93% of its assets related to transmission and distribution. The business is characterized by low-risk, stable and predictable earnings and cash flows.
The Corporation's regulated utility businesses are: ITC (electric transmission - Michigan, Iowa, Minnesota, Illinois, Missouri, Kansas, Oklahoma and Wisconsin); UNS Energy (integrated electric and natural gas distribution - Arizona); Central Hudson (electric transmission and distribution, and natural gas distribution - New York State); FortisBC Energy (natural gas transmission and distribution - British Columbia); FortisAlberta (electric distribution - Alberta); FortisBC Electric (integrated electric - British Columbia); Newfoundland Power (integrated electric - Newfoundland and Labrador); Maritime Electric (integrated electric - Prince Edward Island); FortisOntario (integrated electric - Ontario); Caribbean Utilities (integrated electric - Grand Cayman); and FortisTCI (integrated electric - Turks and Caicos Islands). Fortis also holds equity investments in the Wataynikaneyap Partnership (electric transmission - Ontario) and Belize Electricity (integrated electric - Belize).
The Corporation's non-regulated business is limited to Fortis Belize (three hydroelectric generation facilities - Belize). Aitken Creek was sold on November 1, 2023.
Fortis has a unique operating model with a small corporate office in St. John's, Newfoundland and Labrador and business units that operate on a substantially autonomous basis. Each utility has its own management team and board of directors, with most having a majority of independent board members, which provides effective oversight within the broad parameters of Fortis policies and best practices. Subsidiary autonomy supports constructive relationships with regulators, policy makers, customers and communities. Fortis believes this model enhances accountability, opportunity and performance across the Corporation's businesses, and positions Fortis well for future investment opportunities.
Fortis is focused on providing safe, reliable and cost-effective energy service to customers. Delivering a cleaner energy future is the Corporation's core purpose. In addition, management is focused on delivering long-term profitable growth for shareholders through the execution of its Capital Plan and the pursuit of investment opportunities within and proximate to its service territories.
Competition
Most of the Corporation's regulated utilities operate as the sole supplier of electricity and/or gas within their respective service territories. Competition in the regulated electric business is primarily from alternative energy sources and on-site generation by customers, particularly solar. The Corporation faces competition in its transmission business which may restrict its ability to grow this business outside of its established service territories. Challenges to existing ROFR statutes applicable to the transmission business may also restrict future growth. For more information related to an ongoing challenge with respect to a ROFR statute in Iowa, refer to the "Regulatory Highlights - Significant Regulatory Matters" section of the MD&A which is incorporated by reference in this AIF and available on SEDAR+ and EDGAR.
At the Corporation's regulated gas utilities, natural gas primarily competes with electricity for space and hot water heating load. In addition to other price comparisons, upfront capital cost differences between electric and natural gas equipment for hot water and space heating applications continue to present challenges for the competitiveness of natural gas on a fully costed basis. As governments develop policies to address climate change, any resultant changes to energy policy may impact the competitiveness of natural gas relative to other energy sources. Specifically, government policy could impact the competitiveness of natural gas in British Columbia, which accounts for 80% of the Corporation's natural gas revenue.
Seasonality
As the Corporation's subsidiaries operate in various jurisdictions throughout North America, seasonality impacts each utility differently. Most of the annual earnings of the Corporation's gas utilities are realized in the first and fourth quarters due to space-heating requirements. Earnings for the electric distribution utilities in the U.S. are generally highest in the second and third quarters due to the use of air conditioning and other cooling equipment.
Summary of Operations
The following table and sections describe the Corporation's operations and reportable segments.
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| Customers | Peak Demand (1) | Electric T&D Lines (circuit km) | Gas T&D Lines (km) | Generating Capacity (MW) | Revenue ($ millions) | GWh Sales | Gas Volumes (PJ) | Employees |
| Regulated Utilities | | | | | | | | | | |
| ITC | — | | 22,102 | | MW | 26,100 | | — | | — | | 2,085 | | — | | — | | 747 | |
| UNS Energy | 719,000 | | 3,314 | | MW | 23,200 | | 5,100 | | 3,408 | | 3,006 | | 16,173 | | 17 | | 2,061 | |
| | 115 | | TJ | | | | | | | |
| | | | | | | | | | |
| Central Hudson | 405,000 | | 1,046 | | MW | 15,200 | | 2,400 | | 65 | | 1,360 | | 4,921 | | 24 | | 1,193 | |
| | 150 | | TJ | | | | | | | |
| FortisBC Energy | 1,087,000 | | 1,334 | | TJ | — | | 51,600 | | — | | 1,955 | | — | | 213 | | 2,143 | |
| FortisAlberta | 592,000 | | 2,643 | | MW | 90,500 | | — | | — | | 738 | | 16,976 | | — | | 1,234 | |
| FortisBC Electric | 191,000 | | 689 | | MW | 7,300 | | — | | 225 | | 528 | | 3,478 | | — | | 571 | |
| Other Electric | | | | | | | | | | |
| Newfoundland Power | 275,000 | | 1,474 | | MW | 11,500 | | — | | 145 | | 770 | | 5,928 | | — | | 680 | |
| Maritime Electric | 89,000 | | 359 | | MW | 6,700 | | — | | 90 | 261 | | 1,479 | | — | | 224 | |
| FortisOntario | 69,000 | | 261 | | MW | 3,400 | | — | | 5 | 223 | | 1,324 | | — | | 220 | |
| Caribbean Utilities | 34,000 | | 124 | | MW | 700 | | — | | 166 | 394 | | 727 | | — | | 263 | |
| FortisTCI | 17,000 | | 50 | | MW | 700 | | — | | 88 | 113 | | 295 | | — | | 163 | |
| Non-Regulated | | | | | | | | | | |
| Corporate and Other | — | | — | | | — | | — | | 51 | | 84 | | 164 | | — | | 99 | |
| Total | 3,478,000 | 32,062 | | MW | 185,300 | | 59,100 | | 4,243 | | 11,517 | | 51,465 | | 254 | | 9,598 | |
| | 1,599 | | TJ | | | | | | | |
(1)Electric (MW) or gas (TJ)
Regulated Utilities
ITC
ITC's business consists mainly of electric transmission operations. ITC's Regulated Operating Subsidiaries own and operate high-voltage electric transmission systems in Michigan's Lower Peninsula and portions of Iowa, Minnesota, Illinois, Missouri, Kansas, Oklahoma and Wisconsin that transmit electricity from generating stations to local distribution facilities connected to ITC's transmission systems.
The primary operating responsibilities of ITC's Regulated Operating Subsidiaries include maintaining, improving and expanding transmission systems to meet their customers’ ongoing needs, managing and scheduling maintenance and construction, maintaining appropriate system voltages and monitoring flows over transmission lines and other facilities to ensure physical limits are not exceeded. ITC owns and operates approximately 26,100 circuit km of transmission lines.
ITC's Regulated Operating Subsidiaries earn revenues from the use of their transmission systems by customers, including investor-owned utilities, municipalities, cooperatives, power marketers and alternative energy suppliers. As independent transmission companies, ITC's Regulated Operating Subsidiaries are subject to rate regulation by the Federal Energy Regulatory Commission. The rates charged are established using cost-based formula rates.
ITC's principal transmission service customers are DTE, CMS and IPL. These customers, individually and together, have consistently represented a significant percentage of ITC's operating revenues. Nearly all of ITC's revenues are from transmission customers in the U.S.
Market and Sales
Revenues
Revenue was $2,085 million in 2023 compared to $1,906 million in 2022.
ITC derives nearly all of its revenues from transmission, scheduling, control and dispatch services and other related services over ITC's Regulated Operating Subsidiaries' transmission systems to DTE, CMS, IPL and other entities, such as alternative energy suppliers, power marketers and other wholesale customers that provide electricity to end-use customers, as well as from transaction-based capacity reservations on ITC's transmission systems. MISO and SPP are responsible for billing and collecting the majority of transmission service revenues. As the billing agents for ITC's MISO Regulated Operating Subsidiaries and ITC Great Plains, MISO and SPP collect fees for the use of ITC's transmission systems, invoicing DTE, CMS, IPL and other customers on a monthly basis.
The following table compares the composition of ITC's 2023 and 2022 revenue by customer class.
| | | | | | | | |
| Revenue (%) |
| 2023 | 2022 |
| Network revenues | 70.7 | | 69.7 | |
| Regional cost-sharing revenues | 24.8 | | 25.6 | |
| Point-to-point | 1.2 | | 1.4 | |
| Scheduling, control and dispatch | 1.3 | | 1.3 | |
| | |
| Other | 2.0 | | 2.0 | |
| Total | 100.0 | | 100.0 | |
Network revenues are generated from network customers for their use of ITC's electric transmission systems and are based on the actual revenue requirements under its cost-based formula rates that contain a true-up mechanism.
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 for their use of ITC's MISO Regulated Operating Subsidiaries' network upgrade projects that are eligible for regional cost-sharing under provisions of the MISO tariff. 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 ITC's 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 the gross revenue requirement when calculating the net revenue requirement under ITC's cost-based formula rates.
Scheduling, control and dispatch revenues are allocated to ITC's 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 use of jointly-owned assets under ITC's transmission ownership and operating agreements and revenues from providing ancillary services to customers. The majority of other revenues are treated as a revenue credit and taken as a reduction to the gross revenue requirement when calculating the net revenue requirement under ITC's cost-based formula rates.
Contracts
ITCTransmission
DTE 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's and ITCTransmission's ongoing working relationship. These contracts include:
Master Operating Agreement - governs the primary day-to-day operational responsibilities of ITCTransmission and DTE. It identifies the control area coordination services that ITCTransmission is obligated to provide to DTE and certain generation-based support services that DTE is required to provide to ITCTransmission.
Generator Interconnection and Operation Agreement - established and maintains the direct electricity interconnection of DTE's electricity generating assets with ITCTransmission's transmission system for the purposes of transmitting electric power from and to the electricity generating facilities.
Coordination and Interconnection Agreement - governs the rights, obligations and responsibilities of ITCTransmission and DTE regarding, among other things, the operation and interconnection of DTE's distribution system and ITCTransmission's transmission system, and the construction of new facilities or modification of existing facilities. Additionally, this agreement allocates costs for operation of supervisory, communications and metering equipment.
METC
CMS operates an electric distribution system that interconnects with METC's transmission system. METC is a party to a number of operating contracts with CMS that govern the operations and maintenance of its transmission system. These contracts include:
Amended and Restated Easement Agreement - CMS 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 CMS and others, are located. METC pays CMS a nominal annual rent for the easement and also pays for any rentals, property taxes and other fees related to the property covered by the agreement.
Amended and Restated Operating Agreement - METC is responsible for maintaining and operating its transmission system, providing CMS 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 CMS, building connection facilities necessary to permit interaction with new distribution facilities built by CMS.
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 CMS. Currently, under this agreement, METC pays CMS 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 - provides for the interconnection of CMS'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 parties' property, assets and facilities.
Amended and Restated Generator Interconnection Agreement - specifies the terms and conditions under which CMS and METC maintain the interconnection of CMS's generation resources and METC's transmission assets.
ITC Midwest
IPL 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 IPL that govern the operations and maintenance of its transmission system. These contracts include:
Distribution-Transmission Interconnection Agreement - governs the rights, responsibilities and obligations of ITC Midwest and IPL 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, IPL and MISO entered into this agreement in order to establish and maintain the direct electricity interconnection of IPL's electricity generating assets with ITC Midwest's transmission system for the purposes of transmitting electric power from and to the electricity generating facilities.
UNS Energy
UNS Energy is a vertically integrated utility services holding company, headquartered in Tucson, Arizona. It is engaged through its subsidiaries in the regulated electric generation and energy delivery business, primarily in the State of Arizona, serving approximately 719,000 retail electricity and gas customers. UNS Energy primarily consists of three wholly-owned regulated utilities: TEP, UNS Electric and UNS Gas.
TEP, UNS Energy's largest operating subsidiary, is a vertically integrated regulated electric utility that generates, transmits and distributes electricity. TEP serves approximately 447,000 retail customers in a territory comprising approximately 2,991 square km in southeastern Arizona, including the greater Tucson metropolitan area in Pima County, as well as parts of Cochise County. TEP's service area covers a population of over one million people. TEP also sells wholesale electricity to other entities in the western U.S.
UNS Electric is a vertically integrated regulated electric utility that generates, transmits and distributes electricity to approximately 103,000 retail customers in Arizona's Mohave and Santa Cruz counties.
TEP and UNS Electric own generation resources with an aggregate capacity of 3,408 MW, including 318 MW of renewable resources. Several of the generating assets in which TEP and UNS Electric have an interest are jointly owned. As at December 31, 2023, approximately 26% of the generating capacity was fueled by coal.
TEP also owns transmission-related assets representing approximating 14% of UNS Energy's total assets.
UNS Gas is a regulated gas distribution utility that serves approximately 169,000 retail customers in Arizona's Mohave, Yavapai, Coconino, Navajo and Santa Cruz counties.
Market and Sales
UNS Energy's electricity sales were 16,173 GWh in 2023 compared to 16,059 GWh in 2022. Gas volumes were 17 PJ in 2023, compared to 16 PJ in 2022. Revenue was $3,006 million in 2023 compared to $2,758 million in 2022.
The following table provides the composition of UNS Energy's 2023 and 2022 revenue, electricity sales, and gas volumes by customer class.
| | | | | | | | | | | | | | | | | | | | |
| Revenue (%) | GWh Sales (%) | PJ Volumes (%) |
| 2023 | 2022 | 2023 | 2022 | 2023 | 2022 |
| Residential | 37.1 | | 35.3 | | 30.8 | | 30.6 | | 55.5 | | 57.5 | |
| Commercial | 18.8 | | 17.8 | | 16.4 | | 16.4 | | 22.3 | | 23.0 | |
| Industrial | 13.7 | | 12.8 | | 19.4 | | 19.3 | | 1.4 | | 1.7 | |
| Wholesale | 12.8 | | 18.2 | | 33.3 | | 33.6 | | — | | — | |
Other (1) | 17.6 | | 15.9 | | 0.1 | | 0.1 | | 20.8 | | 17.8 | |
| Total | 100.0 | | 100.0 | | 100.0 | | 100.0 | | 100.0 | | 100.0 | |
(1)Electricity sales include transmission, participant billings, alternative revenue and revenue from sources other than from the sale of electricity. Gas volumes include negotiated sales program customers.
Power Supply
TEP meets the electricity supply requirements of its retail and wholesale customers with its owned electrical generating capacity of 3,101 MW and its transmission and distribution system consisting of approximately 16,000 circuit km of line. In 2023, TEP met a peak demand of 2,784 MW, which includes firm sales to wholesale customers. TEP is a member of a regional reserve-sharing organization and has reliability and power sharing relationships with other utilities.
TEP's generating capacity is set forth in the following table.
| | | | | | | | | | | | | | | | | | | | | | | |
Generation Source | Unit No. | Location | Date in
Service | Total Capacity (MW) | Operating Agent | TEP's Share (%) | TEP's Share (MW) |
Coal | | | | | | | |
Springerville Station | 1 | Springerville, AZ | 1985 | 387 | | TEP | 100.0 | | 387 | |
Springerville Station (1) | 2 | Springerville, AZ | 1990 | 406 | | TEP | 100.0 | | 406 | |
Four Corners Station | 4 | Farmington, NM | 1969 | 785 | | APS | 7.0 | | 55 | |
Four Corners Station | 5 | Farmington, NM | 1970 | 785 | | APS | 7.0 | | 55 | |
Natural Gas | | | | | | | |
Gila River Power Station (2) | 2 | Gila Bend, AZ | 2003 | 607 | | SRP | 100.0 | | 607 | |
Gila River Power Station (2) (3) | 3 | Gila Bend, AZ | 2003 | 573 | | SRP | 75.0 | | 430 | |
Luna Generating Station | 1 | Deming, NM | 2006 | 555 | | PNM | 33.3 | | 185 | |
Sundt Station | 3 | Tucson, AZ | 1962 | 104 | | TEP | 100.0 | | 104 | |
Sundt Station | 4 | Tucson, AZ | 1967 | 156 | | TEP | 100.0 | | 156 | |
Sundt Internal Combustion Turbines | | Tucson, AZ | 1972-1973 | 50 | | TEP | 100.0 | | 50 | |
Sundt Reciprocating Internal Combustion Engine (3) | 1-10 | Tucson, AZ | 2019-2020 | 188 | | TEP | 100.0 | | 188 | |
DeMoss Petrie (4) | N/A | Tucson, AZ | 2001 | 75 | | TEP | 100.0 | | 75 | |
North Loop | N/A | Tucson, AZ | 2001 | 96 | | TEP | 100.0 | | 96 | |
Renewable | | | | | | | |
Utility-Owned Renewables | | Various | 2002-2023 | 307 | | TEP | 100.0 | | 307 | |
Total Capacity | | | | | | | 3,101 | |
(1)Springerville Generating Station Unit 2 is owned by San Carlos Resources Inc., a wholly owned subsidiary of TEP.
(2)In 2023, Gila River Unit 2 and Unit 3 turbine upgrades increased capacity by 57 MW and 23 MW for a total nominal capacity of 607 MW and 573 MW, respectively
(3)TEP owns 75% of Gila River Unit 3 and UNS Electric owns 25%.
(4)Demoss Petrie is accompanied by 10 MW of battery storage
UNS Electric meets the electricity supply requirements of its retail customers with its owned electrical generating capacity of 307 MW and purchasing power on the wholesale market, and its transmission and distribution system consisting of approximately 7,000 circuit km of line. In 2023, UNS Electric met a peak demand of 530 MW.
UNS Electric's generating capacity is set forth in the following table.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Generation Source | Unit No. | Location | Date In Service | Resource Type | Total Capacity (MW) | Operating Agent | UNSE's Share (%) | UNSE's Share (MW) |
Black Mountain | 1 | Kingman, AZ | 2011 | Gas | 45 | | UNSE | 100.0 | | 45 | |
Black Mountain | 2 | Kingman, AZ | 2011 | Gas | 45 | | UNSE | 100.0 | | 45 | |
Valencia | 1 | Nogales, AZ | 1989 | Gas/Oil | 14 | | UNSE | 100.0 | | 14 | |
Valencia | 2 | Nogales, AZ | 1989 | Gas/Oil | 14 | | UNSE | 100.0 | | 14 | |
Valencia | 3 | Nogales, AZ | 1989 | Gas/Oil | 14 | | UNSE | 100.0 | | 14 | |
Valencia | 4 | Nogales, AZ | 2006 | Gas/Oil | 21 | | UNSE | 100.0 | | 21 | |
Gila River Power Station (1) | 3 | Gila Bend, AZ | 2003 | Gas | 573 | | SRP | 25.0 | | 143 | |
Utility-Owned Renewables | N/A | Various | 2011-2017 | Solar | 11 | | UNSE | 100.0 | | 11 |
Total Capacity | | | | | | | | | 307 | |
(1) In 2023, Gila River Unit 3 turbine upgrades increased capacity by 23 MW for a total nominal capacity of 573 MW
Utility-Owned Renewable Resources
TEP owns 307 MW of renewable generation resources, has 3 MW of solar generation resources under development, and 200 MW of battery storage resources under development at its BESS Facility which is expected to be put into service the second half of 2025. UNS Electric owns 11 MW of solar generation capacity.
Renewable Power Purchase Agreements
TEP has renewable PPAs of 256 MW from solar resources and 179 MW from wind resources. The solar PPAs contain options that allow TEP to purchase all or part of the related facilities at a future date. In October 2023, TEP executed an amended and restated PPA for the Babacomari North solar facility, which is expected to be placed into service in 2025 and add 160 MW to TEP's renewable capacity. UNS Electric has renewable PPAs of 83 MW from solar resources and 10 MW from wind resources.
Gas Purchases
TEP and UNS Gas directly manage their gas supply and transportation contracts. The price for gas varies based on market conditions, which include weather, supply balance, economic growth rates and other factors. TEP and UNS Gas hedge their gas supply prices by entering into fixed-price forward contracts, collars, and financial swaps from time to time, up to three years in advance, with a view to hedging 70-90% of expected monthly energy volumes prior to the beginning of each month.
UNS Gas met peak demand of 115 TJ in 2023.
Central Hudson
Central Hudson is a regulated electric and gas transmission and distribution utility serving approximately 315,000 electricity customers and 90,000 natural gas customers in portions of New York State's Mid-Hudson River Valley. Central Hudson serves a territory comprising approximately 6,700 square km. Electric service is available throughout the territory, and natural gas service is provided in and around the cities of Poughkeepsie, Beacon, Newburgh, and Kingston, New York, and in certain outlying and intervening territories.
Central Hudson's electric transmission and distribution system consists of approximately 15,200 circuit km of line and met a peak demand of 1,046 MW in 2023.
Central Hudson's natural gas system consists of approximately 2,400 km of transmission and distribution pipelines and met a peak demand of 150 TJ in 2023.
Market and Sales
Central Hudson's electricity sales were 4,921 GWh in 2023 compared to 5,002 GWh in 2022. Natural gas sales volumes were 24 PJ in 2023 compared to 25 PJ in 2022. Revenue was $1,360 million in 2023 compared to $1,325 million in 2022.
The following table compares the composition of Central Hudson's 2023 and 2022 revenue, electricity sales and natural gas volumes by customer class.
| | | | | | | | | | | | | | | | | | | | |
| Revenue (%) | GWh Sales (%) | PJ Volumes (%) |
| 2023 | 2022 | 2023 | 2022 | 2023 | 2022 |
| Residential | 61.9 | | 62.2 | | 42.6 | | 43.8 | | 22.1 | | 24.3 | |
| Commercial | 29.4 | | 28.5 | | 39.4 | | 37.8 | | 28.3 | | 31.5 | |
| Industrial | 3.8 | | 3.3 | | 17.5 | | 17.5 | | 42.6 | | 37.1 | |
Wholesale (1) | 1.2 | | 1.6 | | 0.5 | | 0.9 | | 7.0 | | 7.1 | |
Other (2) | 3.7 | | 4.4 | | — | | — | | — | | — | |
| Total | 100.0 | | 100.0 | | 100.0 | | 100.0 | | 100.0 | | 100.0 | |
(1)Includes sales for resale.
(2)Other includes regulatory deferrals and revenue from sources other than from the sale of gas and electricity.
Power Supply
Central Hudson relies on purchased capacity and energy from third-party providers, together with its own minimal generating capacity, to meet the demands of its full-service customers.
Costs of electric and natural gas commodity purchases are recovered from customers, without earning a profit on these costs. Rates are reset monthly based on Central Hudson's actual costs to purchase the electricity and natural gas needed to serve its full-service customers.
FortisBC Energy
FortisBC Energy is the largest distributor of natural gas in British Columbia, serving approximately 1,087,000 residential, commercial, industrial, and transportation customers. FortisBC Energy provides transmission and distribution services to customers, and obtains natural gas and renewable gas supplies on behalf of most of its residential, commercial and industrial customers. Gas supplies are sourced primarily from northeastern BC and, through FortisBC Energy's Southern Crossing Pipeline, from Alberta. FortisBC Energy owns and operates approximately 51,600 km of natural gas pipelines and met a peak demand of 1,334 TJ in 2023.
Market and Sales
FortisBC Energy's natural gas sales volumes were 213 PJ in 2023 compared to 231 PJ in 2022. Revenue was $1,955 million in 2023 compared to $2,084 million in 2022.
The following table compares the composition of FortisBC Energy's 2023 and 2022 revenue and natural gas volumes by customer class.
| | | | | | | | | | | | | | |
| Revenue (%) | PJ Volumes (%) |
| 2023 | 2022 | 2023 | 2022 |
| Residential | 56.2 | | 56.9 | | 36.2 | | 37.7 | |
| Commercial | 32.3 | | 32.1 | | 26.3 | | 26.4 | |
| Industrial | 7.4 | | 7.1 | | 9.4 | | 8.2 | |
| | | | |
Other (1) | 4.1 | | 3.9 | | 28.1 | | 27.7 | |
| Total | 100.0 | | 100.0 | | 100.0 | | 100.0 | |
(1)Includes revenue and gas volumes from transportation customers. Due to the nature of transportation contracts, the percentage of revenue by customer category may not correlate with associated volumes.
Gas Purchase Agreements
To ensure supply of adequate resources for reliable natural gas deliveries to its customers, FortisBC Energy purchases natural gas supply from counterparties, including producers, aggregators and marketers. FortisBC Energy contracts for approximately 180 PJ of baseload and seasonal supply, of which the majority is sourced in northeastern British Columbia and transported on Westcoast Energy Inc.'s T‑South pipeline system. The remainder is sourced in Alberta and transported on TC Energy's pipeline transportation system. FortisBC Energy purchased approximately 2.9 PJs of Renewable Natural Gas in 2023.
FortisBC Energy procures and delivers natural gas directly to core market customers. Transportation customers are responsible to procure and deliver their own natural gas to the FortisBC Energy system and FortisBC Energy then delivers the gas to the operating premises of these customers. FortisBC Energy contracts for transportation capacity on third-party pipelines, such as the T‑South pipeline and the TC Energy pipeline, to transport gas supply from various market hubs to FortisBC Energy's system. These third-party pipelines are regulated by the Canada Energy Regulator. FortisBC Energy pays both fixed and variable charges for the use of transportation capacity on these pipelines, which are recovered through rates paid by FortisBC Energy's core market customers. FortisBC Energy contracts for firm transportation capacity to ensure it is able to meet its obligation to supply customers within its broad operating region under all reasonable demand scenarios.
Gas Storage and Peak Shaving Arrangements
FortisBC Energy incorporates peak shaving and gas storage facilities into its portfolio to: (i) supplement contracted baseload and seasonal gas supply in the winter months, while injecting excess baseload supply to refill storage in the summer months; (ii) mitigate the risk of supply shortages during cooler weather and peak demand; (iii) manage the cost of gas during the winter months; and (iv) balance daily supply and demand on the distribution system during periods of peak use that occur during the winter months.
FortisBC Energy holds approximately 36 PJs of total storage capacity. FortisBC Energy owns Tilbury and Mount Hayes LNG peak shaving facilities, which provide on-system storage capacity and deliverability. FortisBC Energy also contracts for underground storage capacity and deliverability from parties in northeast British Columbia, Alberta and the Pacific Northwest of the U.S. On a combined basis, FortisBC Energy's Tilbury and Mount Hayes facilities, the contracted storage facilities and other peaking arrangements can deliver up to 0.83 PJs per day of supply to FortisBC Energy on the coldest days of the heating season. The heating season typically occurs during the period from December to February.
Mitigation Activities
FortisBC Energy engages in off-system sales activities that allow for the recovery or mitigation of costs of any unutilized supply and/or pipeline and storage capacity that is available once customers' daily load requirements are met.
Under the Gas Supply Mitigation Incentive Plan revenue sharing model approved by the BCUC, FortisBC Energy can earn an incentive payment for mitigation activities. Subject to the BCUC's approval, FortisBC Energy earned an incentive payment of approximately $7.4 million for the gas contract year ending October 31, 2023.
The BCUC has approved extensions of the program through October 31, 2025.
Price-Risk Management Plan
FortisBC Energy engages in price-risk management activities to mitigate the impact on customer rates of fluctuations in natural gas prices. These activities include: (i) physical gas purchasing and storage strategies; (ii) quarterly commodity rate-setting and a deferral account mechanism; and (iii) the use of derivative instruments, which were implemented pursuant to a price-risk management plan approved by the BCUC, as discussed below.
In May 2023, FortisBC Energy filed its 2023 AECO/NIT Price Risk Mitigation Application to implement fixed price AECO/NIT hedges for the hedging term beginning in April 2024 and ending in March 2028 to mitigate the impact of rising prices at the AECO/NIT market hub and provide increased pricing diversity to the commodity supply portfolio. The BCUC approved the application in June 2023, and FortisBC Energy began implementing the fixed price AECO/NIT hedges in July 2023.
Unbundling
A Customer Choice program at FortisBC Energy allows eligible commercial and residential customers to buy their natural gas commodity supply from FortisBC Energy or from third-party marketers. FortisBC Energy continues to provide the delivery service of the natural gas to all its customers. For the year ended December 31, 2023, approximately 9% of eligible commercial customers and 4% of eligible residential customers purchased their commodity supply from alternate providers.
FortisAlberta
FortisAlberta is a regulated electricity distribution utility operating in Alberta. Its business is the ownership and operation of electric distribution facilities that distribute electricity, generated by other market participants, from high-voltage transmission substations to end-use customers. FortisAlberta is not involved in the generation, transmission or direct retail sale of electricity. FortisAlberta operates the electricity distribution system in a substantial portion of southern and central Alberta around and between the cities of Edmonton and Calgary, totalling approximately 90,500 circuit km of distribution lines. FortisAlberta's distribution network serves approximately 592,000 customers and met a peak demand of 2,643 MW in 2023.
Market and Sales
FortisAlberta's energy deliveries were 16,976 GWh in 2023 compared to 16,923 GWh in 2022. Revenue was $738 million in 2023 compared to $680 million in 2022.
The following table compares the composition of FortisAlberta's 2023 and 2022 revenue and energy deliveries by customer class.
| | | | | | | | | | | | | | |
| Revenue (%) | GWh Deliveries (%) (1) |
| 2023 | 2022 | 2023 | 2022 |
Residential | 43.7 | | 44.3 | | 28.6 | | 28.5 | |
Commercial | 25.4 | | 25.1 | | 13.6 | | 13.6 | |
Industrial | 18.3 | | 18.3 | | 57.8 | | 57.9 | |
| | | | |
Other (2) | 12.6 | | 12.3 | | — | | — | |
Total | 100.0 | | 100.0 | | 100.0 | | 100.0 | |
(1)GWh percentages exclude FortisAlberta's GWh deliveries to "transmission-connected" customers. These deliveries were 6,571 GWh in 2023 and 6,695 GWh in 2022, based on an interim settlement that is expected to be finalized in May 2024, and consisted primarily of energy deliveries to large-scale industrial customers directly connected to the transmission grid.
(2)Includes rate riders, deferrals and adjustments.
Franchise Agreements
FortisAlberta customers located within a city, town, village or summer village boundary are served under franchise agreements between FortisAlberta and the respective customers’ municipality of residence. FortisAlberta maintains standard franchise agreements with many municipalities throughout Alberta. Any franchise agreement that is not renewed at the expiry of the term continues in effect until either FortisAlberta or the municipality terminates it with the approval of the AUC. The Municipal Government Act (Alberta) provides municipalities an option to purchase FortisAlberta assets located within their municipal boundaries upon termination of a franchise agreement. FortisAlberta must be compensated if a franchise agreement is terminated, and the municipality subsequently exercises its option to purchase FortisAlberta distribution assets. In such a case, compensation would likely be determined based on a methodology approved by the AUC.
FortisAlberta holds franchise agreements with 163 municipalities within its service area. The franchise agreements include 10‑year terms with an option to renew for up to two subsequent five-year terms. Notices to extend the franchise agreements expiring in 2024 have been or will be provided to affected municipalities prior to expiration.
FortisBC Electric
FortisBC Electric is an integrated regulated electric utility that owns hydroelectric generating plants, high voltage transmission lines and a large network of distribution assets located in the southern interior of British Columbia. FortisBC Electric serves approximately 191,000 customers and met a peak demand of 689 MW in 2023. FortisBC Electric's transmission and distribution assets include approximately 7,300 circuit km of transmission and distribution lines.
FortisBC Electric is also responsible for operation, maintenance and management services at the 493‑MW Waneta hydroelectric generating facility owned by BC Hydro and the 340‑MW Waneta Expansion, the 149-MW Brilliant hydroelectric plant, the 120‑MW Brilliant hydroelectric expansion plant and the 185-MW Arrow Lakes generating station, all ultimately owned by Columbia Basin Trust and Columbia Power Corporation.
Market and Sales
Electricity sales were 3,478 GWh in 2023 compared to 3,542 GWh in 2022. Revenue was $528 million in 2023 compared to $487 million in 2022.
The following table compares the composition of FortisBC Electric's 2023 and 2022 revenue and electricity sales by customer class.
| | | | | | | | | | | | | | |
| Revenue (%) | GWh Sales (%) |
| 2023 | 2022 | 2023 | 2022 |
| Residential | 48.9 | | 50.0 | | 37.9 | | 39.5 | |
| Commercial | 27.0 | | 26.4 | | 29.2 | | 28.6 | |
| Industrial | 11.3 | | 11.0 | | 16.0 | | 15.3 | |
| Wholesale | 12.8 | | 12.6 | | 16.9 | | 16.6 | |
| | | | |
| Total | 100.0 | | 100.0 | | 100.0 | | 100.0 | |
Generation and Power Supply
FortisBC Electric meets the electricity supply requirements of its customers through a mix of its own generation and PPAs. FortisBC Electric owns four regulated hydroelectric generating plants on the Kootenay River with an aggregate capacity of 225 MW, which provide approximately 41% of its energy needs and 27% of its peak capacity needs. FortisBC Electric meets the balance of its requirements through a portfolio of long-term and short-term PPAs.
FortisBC Electric's four hydroelectric generating facilities are governed by the multiparty CPA that enables the five separate owners of nine major hydroelectric generating plants, with a combined capacity of approximately 1,900 MW and located in relatively close proximity to each other, to coordinate the operation and dispatch of their generating plants.
The following table lists the plants and their respective capacity and owner.
| | | | | | | | | | | |
| Plant | Capacity (MW) | | Owners |
| Canal Plant | 580 | | | BC Hydro |
| Waneta Dam | 493 | | | BC Hydro |
| Waneta Expansion | 340 | | | Waneta Expansion Power Corporation |
| Kootenay River System | 225 | | | FortisBC Electric |
| Brilliant Dam | 149 | | | Brilliant Power Corporation |
| Brilliant Expansion | 120 | | | Brilliant Expansion Power Corporation |
| Total | 1,907 | | | |
Brilliant Power Corporation, Brilliant Expansion Power Corporation, Teck Metals Ltd., Waneta Expansion Power Corporation and FortisBC Electric are collectively defined in the CPA as the entitlement parties. The CPA enables BC Hydro and the entitlement parties to generate more power from their respective generating plants than they could if they operated independently through coordinated use of water flows, subject to the 1961 Columbia River Treaty between Canada and the U.S., and coordinated operation of storage reservoirs and generating plants. Under the CPA, BC Hydro takes into its system all power actually generated by the plants listed in the table above. In exchange for permitting BC Hydro to determine the output of these facilities, each of the entitlement parties is contractually entitled to a fixed annual entitlement of capacity and energy from BC Hydro, which is based on 50-year historical water flows and the plants' generating capabilities. The entitlement parties receive their defined entitlements irrespective of actual water flows to the entitlement parties' generating plants. BC Hydro enjoys the benefits of the additional power generated through coordinated operation and optimal use of water flows. The entitlement parties benefit by knowing years in advance the amount of power that they will receive from their generating plants and, therefore, do not face hydrology variability in generation supply planning. However, FortisBC Electric retains rights to its original water licences and flows in perpetuity. Should the CPA be terminated, the output of FortisBC Electric's Kootenay River system plants would, with the water and storage authorized under its existing licences and on a long‑term average, be approximately the same power output as FortisBC Electric receives under the CPA. The CPA does not affect FortisBC Electric's ownership of its physical generation assets. The CPA continues in force until terminated by any of the parties by giving no less than five years' notice at any time on or after December 31, 2030.
FortisBC Electric's remaining electricity supply is acquired primarily through long-term PPAs with a number of counterparties, including the Brilliant PPA, the BC Hydro PPA and the Waneta Expansion Capacity Agreement. Additionally, FortisBC Electric purchases capacity and energy from the market to meet its peak energy requirements and optimize its overall power supply portfolio. These market purchases provided approximately 9% of FortisBC Electric's energy supply requirements in 2023. FortisBC Electric's PPAs and market purchases have been accepted by the BCUC and prudently incurred costs thereunder flow through to customers through FortisBC Electric's electricity rates.
Other Electric
Other Electric consists of utilities in eastern Canada and the Caribbean as follows: Newfoundland Power; Maritime Electric; FortisOntario; a 39% equity investment in Wataynikaneyap Partnership; an approximate 60% controlling interest in Caribbean Utilities; FortisTCI; and a 33% equity investment in Belize Electricity.
Newfoundland Power is an integrated regulated electric utility and the principal distributor of electricity on the island portion of Newfoundland and Labrador. Maritime Electric is an integrated regulated electric utility and the principal distributor of electricity on PEI. FortisOntario primarily provides integrated electric utility service through its three regulated operating utilities primarily in Fort Erie, Cornwall, Gananoque, Port Colborne and the District of Algoma in Ontario.
The Wataynikaneyap Partnership has a mandate of connecting 17 remote First Nations Communities in Northwestern Ontario to the electricity grid. The partnership is equally owned by 24 First Nations communities (51%), in partnership with FortisOntario (39%) and Algonquin Power & Utilities Corp. (10%). FortisOntario, as project manager, is responsible for construction, management and operation of the transmission line. As at December 31, 2023, project construction was 98% complete, with 1,353 kilometers of transmission line and 14 substations energized, and ten First Nation communities connected to the electric grid. The project is on track to be completed in 2024.
Caribbean Utilities is an integrated regulated electric utility and the sole provider of electricity on Grand Cayman, Cayman Islands. FortisTCI is an integrated regulated electric utility on the Turks and Caicos Islands. Belize Electricity is an integrated electric utility and the principal distributor of electricity in Belize.
Both Wataynikaneyap Partnership and Belize Electricity are excluded from the following discussion as Fortis holds minority interests in these entities.
The following table sets out the customers, installed generating capacity, peak demand and kilometers of transmission and distribution lines for the segment.
| | | | | | | | | | | | | | | | | |
| Customers | Peak Demand (MW) | T&D Lines (circuit km) | Generating Capacity (MW) | Resource Type(s) |
| Newfoundland Power | 275,000 | | 1,474 | | 11,500 | | 145 | | Hydroelectric, Gas, Diesel |
| Maritime Electric | 89,000 | | 359 | | 6,700 | | 90 | | Diesel |
FortisOntario (1) | 69,000 | | 261 | | 3,400 | | 5 | | Natural Gas Cogeneration |
Caribbean Utilities (2) | 34,000 | | 124 | | 700 | | 166 | | Diesel |
| FortisTCI | 17,000 | | 50 | | 700 | | 88 | | Diesel, Solar |
| Total | 484,000 | | 2,268 | | 23,000 | | 494 | | |
(1) FortisOntario also owns a 10% interest in certain regional electric distribution companies serving approximately 40,000 customers.
(2) Includes 24 km of high-voltage submarine cable.
Market and Sales
Electricity sales attributable to Other Electric were 9,753 GWh in 2023 compared to 9,470 GWh in 2022. Revenue was $1,761 million in 2023 compared to $1,652 million in 2022.
The following table compares the composition of revenue and electricity sales by customer class for Other Electric in 2023 and 2022.
| | | | | | | | | | | | | | |
| Revenue (%) | GWh Sales (%) |
| 2023 | 2022 | 2023 | 2022 |
| Residential | 56.4 | | 56.5 | | 56.8 | | 56.4 | |
| Commercial | 37.6 | | 38.3 | | 39.9 | | 40.3 | |
| Industrial | 1.8 | | 1.8 | | 2.7 | | 2.7 | |
| | | | |
Other (1) | 4.2 | | 3.4 | | 0.6 | | 0.6 | |
| Total | 100.0 | | 100.0 | | 100.0 | | 100.0 | |
(1) Includes revenue from sources other than from the sale of electricity.
Power Supply
Newfoundland Power
Approximately 93% of Newfoundland Power's energy requirements are purchased from NL Hydro with the remaining 7% generated by Newfoundland Power. The principal terms of the supply arrangements with NL Hydro are regulated by the PUB on a basis similar to that upon which Newfoundland Power's service to its customers is regulated.
NL Hydro charges Newfoundland Power for purchased power and includes charges for both demand and energy purchased. The demand charge is based on applying a rate to the peak‑billing demand for the most recent winter season. The energy charge is a two-block charge with a higher second‑block charge set to reflect NL Hydro's marginal cost of generating electricity.
Energy from the Muskrat Falls project supplies a significant portion of NL Hydro's electricity requirements, and in turn, Newfoundland Power's electricity requirements. All units of NL Hydro's Muskrat Falls generating facility have been released for service. The Labrador Island Link transmission line from Muskrat Falls in Labrador to Soldiers Pond on Newfoundland's southeast coast was officially commissioned on April 14, 2023.
While it has been commissioned and released for service, the reliability of supply from the Muskrat Falls project remains uncertain and is under review by the PUB as part of its ongoing Reliability and Resource Adequacy Study. In October 2022, NL Hydro filed an updated study with the PUB recommending, among other things, that its 490-megawatt Holyrood Thermal Generating Station remain operational until 2030 as backup generation in the event of an extended outage to the Labrador Island Link. The PUB’s review is expected to continue throughout 2024.
Future increases in supply costs from NL Hydro, including costs associated with the Muskrat Falls project, are expected to increase electricity rates that Newfoundland Power charges to its customers. The final impact of the Muskrat Falls project on customer rates and the associated timing will remain unknown until the finalization of the provincial government’s rate mitigation plans and NL Hydro’s next general rate application. Any additional costs associated with extending the life of existing generating capacity or additional backup generating capacity on the island of Newfoundland could further increase supply costs and, in turn, further increase electricity rates for Newfoundland Power's customers.
Maritime Electric
Maritime Electric is interconnected to the Province of New Brunswick via four provincially owned submarine cables with a total capacity of 560 MW. The company purchases its energy requirements through energy purchase agreements with NB Power, a New Brunswick Crown corporation, and from renewable energy facilities owned by the PEI Energy Corporation. Company-owned on-Island generation facilities totalling 90 MW are used primarily for peaking, submarine-cable loading issues and emergency purposes.
Maritime Electric has the following contracts with NB Power: (i) an energy supply agreement covering the period March 1, 2019 to December 31, 2026; (ii) a transmission capacity contract allowing Maritime Electric to reserve 30 MW of capacity to PEI expiring November 2032; and (iii) an entitlement agreement for approximately 4.55% of the output from NB Power's Point Lepreau Nuclear Generating Station for the life of the unit. Maritime Electric also has several renewable energy contracts with the PEI Energy Corporation for the purchase of energy for remaining periods ranging from one to 15 years.
As part of its entitlement agreement relating to the output of the Point Lepreau Nuclear Generating Station, Maritime Electric is required to pay its share of the unit's capital and operating costs.
FortisOntario
The power requirements of FortisOntario's service territories are met through various sources. Canadian Niagara Power purchases all its power requirements for Fort Erie and Port Colborne from the IESO, purchases approximately 83% of energy requirements for the Gananoque region from Hydro One Networks Inc., and purchases the remaining 17% from five hydroelectric generating plants owned by EO Generation LP. Algoma Power purchases its energy requirements primarily from the IESO. Under the Ontario Energy Board's Standard Supply Code, Canadian Niagara Power and Algoma Power must provide standard service supply to all its customers who do not choose to contract with an electricity retailer. This energy is provided to customers at either regulated or market prices.
Cornwall Electric purchases substantially all of its power requirements from Hydro-Québec Energy Marketing under a contract that expires in December 2030, and which provides a minimum of 537 GWh of energy per year and up to 145 MW of capacity at any one time.
Caribbean Utilities
Caribbean Utilities relies upon in-house diesel-powered generation to produce electricity for its customers. Caribbean Utilities is party to primary and secondary fuel supply contracts with two different suppliers from whom it is committed to purchasing 60% and 40%, respectively, of its diesel fuel requirements for its diesel-powered generating plant. Caribbean Utilities executed two three-month fuel supply contract extensions in October 2023, which expired on January 1, 2024. New contracts are currently under negotiation and are expected to be finalized in February 2024.
FortisTCI
FortisTCI relies upon in-house diesel-powered generation to produce electricity for its customers. The company's generating capacity is expected to increase in 2024 due to the anticipated commissioning of: (i) a new Wartsila engine; and (ii) the Solar Plus BESS Microgrid project which was launched in 2023 and has an expected generation capacity of 1.2 MW. FortisTCI has installed 2.69 MW of rooftop solar in partnership with customers under its Utility Owned Renewable Energy Program.
FortisTCI continues to engage with the Government of the Turks and Caicos Islands on regulatory reform to enable further development of renewable energy resources.
FortisTCI has contracted with a major supplier for all its diesel fuel requirements for electricity generation. The current contract expires in August 2025.
Non-Regulated
Corporate and Other
Corporate and other captures expenses and revenues not specifically related to any reportable segment and those business operations that are below the required threshold for segmented reporting. This segment consists of non-regulated holding company expenses, as well as non-regulated long-term contracted generation assets in Belize. The generation assets include three hydroelectric generating facilities with a combined generating capacity of 51 MW, held through Fortis Belize, the output of which is sold to Belize Electricity under 50-year PPAs expiring in 2055 and 2060. This segment also includes results for Aitken Creek which was sold on November 1, 2023 with a March 31, 2023 effective date.
Market and Sales
Energy sales were 164 GWh in 2023 compared to 225 GWh in 2022. Revenue was $84 million in 2023 compared to $151 million in 2022 reflecting the disposition of Aitken Creek in 2023, and differences in mark-to-market accounting for natural gas derivatives held by Aitken Creek.
HUMAN RESOURCES
Fortis and its subsidiaries have 9,598 employees, with 53% in Canada, 42% in the U.S. and 5% in other countries. The following table provides the breakdown of employees by reportable segment.
| | | | | | | | | | | | | | | | | | | | | | | |
| Employees | Participation in a Collective Agreement | | Union(s) | | Collective Agreement(s) Expiry Date(s) |
| Regulated Utilities |
| ITC | 747 | | None | | — | | — |
| UNS Energy | 2,061 | | 47 | % | | IBEW | | June 2024 – June 2028 |
| Central Hudson | 1,193 | | 53 | % | | IBEW | | March 2024 – April 2026 |
FortisBC Energy (1) | 2,143 | | 59 | % | | IBEW, MoveUP | | June 2023 – March 2027 (2) |
| FortisAlberta | 1,234 | | 75 | % | | UUWA | | December 2025 |
| FortisBC Electric | 571 | | 67 | % | | IBEW, MoveUP | | January 2023 – March 2027 (3) |
| Other Electric | 1,550 | | 39 | % | | CUPE, IBEW, PWU | | June 2022 – December 2026 (4) |
| Non-Regulated | | | | | | |
Corporate and Other (5) | 99 | | None | | — | | — |
| Total | 9,598 | | 50 | % | | | | |
(1)Includes employees at FHI.
(2)The collective agreement with MoveUP, representing employees in administration and operations support, expired on June 30, 2023 and negotiations are ongoing. The collective agreement with MoveUP, representing customer service employees, was ratified in June 2023 and expires on March 31, 2027.
(3)The collective agreement with MoveUP, representing employees in administration and operations support, expired on June 30, 2023 and negotiations are ongoing. The collective agreement with MoveUP, representing customer service employees, was ratified in June 2023 and expires on March 31, 2027. The collective agreement with the IBEW expired in January 2023 and negotiations are ongoing.
(4)The collective agreement between Newfoundland Power and the IBEW expired in June 2022. A tentative collective agreement was reached on September 26, 2023, however, negotiations are ongoing. The collective agreement between Algoma Power and PWU expired in December 2023 and negotiations are ongoing.
(5)Employees at Fortis Inc. and Fortis Belize.
The Corporation's culture is built on safety, diversity and integrity. Fortis and its utilities respect their employees' freedom to associate and right to a fair wage, and strive to maintain positive and constructive relationships with labour associations and unions.
The Corporation's subsidiaries are required to develop and retain a skilled workforce for their operations. Many of the employees of the Corporation's utilities possess specialized skills and training and Fortis must compete in the marketplace for these workers. For information with respect to the Corporation's talent management strategy and practices, refer to the "Focus on Sustainability" section of the MD&A, which is incorporated by reference in this AIF and available on SEDAR+ and EDGAR.
LEGAL PROCEEDINGS AND REGULATORY ACTIONS
There are no legal proceedings that involve a claim for damages exceeding 10% of the Corporation's current assets in respect of which the Corporation is or was a party, or in respect of which any of the Corporation's property is or was the subject during the year ended December 31, 2023, nor are there any such proceedings known to the Corporation to be contemplated.
Information related to the Corporation's legal proceedings can be found in Note 27 of the Financial Statements, which are incorporated by reference in this AIF and available on SEDAR+ and EDGAR.
The Corporation's utilities operate under a cost of service regulation, in combination with performance-based rate-setting mechanisms in certain jurisdictions, and are regulated by the regulatory body in their respective operating jurisdiction.
During the year ended December 31, 2023, there have not been any: (i) penalties or sanctions imposed against the Corporation by a court relating to securities legislation or by a securities regulatory authority; (ii) other penalties or sanctions imposed by a court or regulatory body against the Corporation that would likely be considered important to a reasonable investor in making an investment decision; or (iii) settlement agreements entered into by the Corporation before a court relating to securities legislation or with a securities regulatory authority.
For information with respect to the nature of regulation and material regulatory decisions and applications associated with each of the Corporation's utilities, refer to the "Regulatory Highlights - Significant Regulatory Matters" section of the MD&A and to Notes 2 and 8 of the Financial Statements, each of which are incorporated by reference in this AIF and available on SEDAR+ and EDGAR.
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS
There were no directors or executive officers of the Corporation, or any associate or affiliate of a director or executive officer of the Corporation, with a material interest in any transaction within the three most recently completed financial years or during the current financial year that has materially affected the Corporation or is reasonably expected to materially affect the Corporation.
RISK FACTORS
For information with respect to the Corporation's business risks, refer to the "Business Risks" section of the MD&A, which is incorporated by reference in this AIF and available on SEDAR+ and EDGAR.
CYBERSECURITY
The Corporation and its utilities are at risk of cybersecurity threats, including cyber attacks, data breaches, cyber extortion or similar compromises, which may target operations, critical infrastructure assets, information systems and/or data. The Board and management of the Corporation oversee the Corporation's cybersecurity strategy, policies and practices, including the Corporation's cybersecurity policy and an enterprise-wide comprehensive CRMP. Similarly, each utility has adopted and implemented a cybersecurity policy and comprehensive CRMP. Each subsidiary board, or a designated committee of a subsidiary board, provides oversight of the subsidiary's information technology and operations technology use and protection, including, but not limited to, cybersecurity, data governance, privacy and compliance.
No risks have arisen from any past or present cybersecurity threats that materially affect, or are reasonably likely to materially affect, the Corporation's business strategy, results of operations or financial condition.
Governance and Oversight
The Board, through the Governance and Sustainability Committee, oversees the Corporation's strategies and policies relating to Information Technology (IT) and Operations Technology (OT) infrastructure, as well as reviews the Corporation's cybersecurity risks and the measures taken to monitor or mitigate such exposures. The Governance and Sustainability Committee is responsible specifically for overseeing the Corporation's IT and OT infrastructure use and protection policies and practices, including in respect of cybersecurity, system integrity, data protection, privacy and compliance.
The Corporation's Executive Vice President, Operations and Innovation has oversight responsibilities for operations, cybersecurity and technology functions. The Vice President, CIO of the Corporation, who reports to the Executive Vice President, Operations and Innovation, coordinates the CRMP with the leaders of each subsidiary's IT group, including those identified as cybersecurity risk management leads. The Vice President, CIO has overall accountability for the operation of the CRMP. A summary of the relevant expertise of the Executive Vice President, Operations and Innovation and the Vice President, CIO of the Corporation is below:
| | | | | |
| Executive | Summary of Relevant Experience |
| Gary J. Smith | Mr. Smith has held a number of senior leadership positions with the Fortis group throughout his 35-year tenure including Executive Vice President, Eastern Canadian and Caribbean Operations of Fortis Inc.; President and Chief Executive Officer of Newfoundland Power; Vice President of Customer Operations and Engineering of Newfoundland Power; and Vice President of Operations and Engineering of FortisAlberta. He holds a Bachelor of Engineering (Electrical) from Memorial University of Newfoundland. Mr. Smith serves on the boards of FortisAlberta, FortisOntario, UNS Energy, Caribbean Utilities, FortisTCI and Fortis Belize. He is also Chair of the board of directors of Wataynikaneyap Power PM Inc. Mr. Smith is a former director of the Canadian Electricity Association and was elected as a Fellow of the Canadian Academy of Engineering in 2021. He is a member of the Association of Professional Engineers and Geoscientists of Newfoundland and the Steering Committee on Power Engineering for the Canadian Standards Association. |
| Ronald J. Hinsley | Mr. Hinsley has held several Information Technology leadership positions throughout his over 32 years in the utility industry. Key positions include CIO roles for United Energy (Melbourne, Australia), ITC Holdings (Novi, MI) and the Electric Reliability Council of Texas (ERCOT). Other key leadership positions include VP of Information Technology for Aquila Inc.’s U.S. utilities and Division Manager for Wolf Creek Nuclear Operating Corporation. Mr. Hinsley holds a Bachelor’s degree from College of St. Mary’s, Omaha, Nebraska, and has served on various non-profit boards and the CEO Advisory board for AMPEX Corporation, based in Colorado Springs, CO. |
Management reports on matters related to information security, technology and cybersecurity to the Governance and Sustainability Committee at each quarterly meeting of the Committee. At least annually, the Governance and Sustainability Committee reviews, both with the Board and management, the Corporation's IT and OT risk exposures, including cybersecurity, system integrity, data and privacy risks, and the steps the Corporation has taken to monitor or mitigate such exposures around critical Corporation assets, including the Corporation's procedures and any related policies, such as cyber incident response plans, data and privacy risk assessments, security measures, system controls and testing, and cyber insurance coverage.
The Cybersecurity Executive Committee of the Corporation is chaired by the Vice President, CIO and its members include: the Executive Vice President, Chief Financial Officer, the Executive Vice President, Sustainability and Chief Legal Officer, the Executive Vice President, Operations and Innovation and the Senior Vice President, Capital Markets and Business Development. The Cybersecurity Executive Committee meets at least annually to review various cybersecurity matters which may include objectives, policies, risk assessments, metrics, and audits. The Vice President, CIO further ensures the Cybersecurity Executive Committee is updated regarding material changes to the CRMP throughout the year.
The Cybersecurity Policy requires that operating subsidiaries have a cybersecurity steering committee that meets a minimum of twice annually to review cybersecurity projects, objectives, policies, metrics, audits, and other matters that arise pertaining to cybersecurity risk management. Further, the Fortis CRMP requires each operating subsidiary to identify an individual responsible for cybersecurity risk management for that company. The Cybersecurity Policy requires the Corporation and each operating utility's cybersecurity risk management lead to provide updates on key risk items, the company's cybersecurity programs and disclosure of significant incidents or breaches at each regularly scheduled meeting of the committee or board with the applicable oversight.
Risk Management and Strategy
Under the CRMP, there is a Cybersecurity Risk Framework which establishes enterprise-wide cybersecurity risk management practices for the Corporation and its operating utilities that identifies and monitors cybersecurity risks, and provides insights for remediation of any risks that could lead to cybersecurity incidents throughout the company. The framework includes a process by which key cyber threats and vulnerabilities are identified and sorted by threat actors, motives, and potential attack path. Once threats or vulnerabilities are identified, the CRMP assesses and prioritizes them based on the likelihood and potential impact. Under this framework, operating utilities assess cybersecurity threats and set risk targets that are appropriate for their business.
The CRMP is incorporated into, and closely linked with, the overall Fortis Enterprise Risk Management Program. When the CRMP highlights a risk, the teams develop and implement a mitigation roadmap. Monitoring of the mitigation roadmap occurs to ensure the risk is mitigated at an acceptable level. Further, under the Cybersecurity Policy, operating utilities are required to have a cybersecurity incident response plan, which must include processes and escalation levels for classifying the severity and actual or potential impact of cybersecurity incidents.
We use third parties to manage, monitor and assess cyber activities and cybersecurity risks. The use of third parties supplements the Corporation's internal team and provides unbiased assessments. The Corporation further utilizes a variety of tools and sources to oversee and detect risks from cybersecurity threats associated with our use of third-party service providers. These include external monitoring services and information provided by external information sharing services, such as United States and Canadian intelligence services, reputable cybersecurity raters and the Electricity Information Sharing and Analysis Center (E-ISAC) which is operated by NERC.
The CRMP addresses the requisite technical controls across our critical asset classes for all Fortis companies. The CRMP is aligned with the National Institute of Standards and Technology's (NIST) Cybersecurity Framework, the International Organization for Standardization’s Security Standard (ISO 27001), the Standard of Good Practice for Information Security, and NERC’s Critical Infrastructure Protection (NERC CIP) reliability standards. Our U.S. operating utilities are required to follow NERC CIP requirements, which include standards targeted at protecting critical information assets that operate the bulk electric system, and are audited on a regular basis by their governing regional transmission organization.
The Corporation employs a team of cybersecurity professionals with certifications in cybersecurity engineering and cybersecurity operational areas. Fortis continues to invest in training for all employees on the specific technologies utilized by the Corporation and professional development for cybersecurity professionals to keep their knowledge current. As the cybersecurity threat landscape continues to evolve, the Corporation continues to adapt its defensive strategy and deploy new technology, continue education of its user community and advance its protections from cybersecurity threats, leveraging threat intelligence and external industry practices for continuous improvement and refinement of the CRMP.
FOCUS ON SUSTAINABILITY
For further information with respect to the Corporation's sustainability program and practices, refer to the "Focus on Sustainability" section of the MD&A, which is incorporated by reference in this AIF and available on SEDAR+ and EDGAR.
Environmental Regulation and Contingencies
As part of the regulatory process, operating subsidiaries engage with stakeholders, including community groups, regulators and customers, to consult on the potential environmental impact of their operations. Fortis and its subsidiaries are subject to various federal, provincial, state and municipal laws, regulations and guidelines relating to the protection of the environment. Environmental compliance involves significant operating and capital costs. At the Corporation's regulated utilities, prudently incurred costs associated with environmental protection and compliance are generally eligible for recovery in customer rates.
The following environmental contingencies have been made as of December 31, 2023:
Mine Reclamation at Generation Facilities Not Operated by TEP. TEP pays ongoing reclamation costs related to coal mines that supply generation facilities in which TEP has an ownership interest but does not operate. TEP is permitted to fully recover these costs from customers and, accordingly, these costs are deferred as a regulatory asset for future recovery.
TEP is liable for a portion of final mine reclamation costs upon closure of the mines servicing the San Juan and Four Corners power stations. TEP's estimated share of final mine reclamation costs at Four Corners is $8 million upon expiration of the related coal supply agreement, which expires in 2031. At December 31, 2023, TEP's estimated share of final mine reclamation costs at the San Juan generating station, which was retired in June 2022, was $33 million.
Former Manufactured Gas Plant Facilities. Environmental regulations require Central Hudson to investigate sites at which Central Hudson or its predecessors once owned and/or operated manufactured gas plants and, if necessary, remediate these sites. Central Hudson accrues for remediation costs based on the amounts that can be reasonably estimated. As at December 31, 2023, an obligation of $96 million was recognized. Central Hudson has notified its insurers and intends to seek reimbursement where insurance coverage exists. Further, as authorized by the New York Public Service Commission, Central Hudson is currently permitted to defer, for future recovery from customers, differences between actual costs for manufactured gas plant site investigation and remediation and the associated rate allowances.
CAPITAL STRUCTURE AND DIVIDENDS
Description of Capital Structure
The authorized share capital of the Corporation consists of an unlimited number of common shares without nominal or par value, an unlimited number of first preference shares without nominal or par value, and an unlimited number of second preference shares without nominal or par value.
As at February 8, 2024, the Corporation had issued and outstanding [490.6 million] common shares; 5.0 million First Preference Shares, Series F; 9.2 million First Preference Shares, Series G; 7.7 million First Preference Shares, Series H; 2.3 million First Preference Shares, Series I; 8.0 million First Preference Shares, Series J; 10.0 million First Preference Shares, Series K; and 24.0 million First Preference Shares, Series M.
For a summary of the terms and conditions of the Corporation's authorized securities, and trading information for the Corporation's publicly listed securities, refer to Exhibit "A" and Exhibit "B" of this AIF.
Dividends and Distributions
The declaration and payment of dividends on the Corporation's common shares and first preference shares are at the discretion of the Board. Dividends on the common shares are typically paid quarterly, on the first day of March, June, September and December of each year. Dividends on the Corporation's First Preference Shares, Series F, G, H, I, J, K and M are typically also paid quarterly.
In September 2023, Fortis declared an increase in the 2023 fourth quarter dividend per common share of 4.4% to $0.59 per share, or $2.36 on an annualized basis. In December 2023 and February 2024, the Board declared first and second quarter 2024 dividends, respectively, on the common shares of $0.59 per share and on the First Preference Shares, Series F, G, H, I, J, K and M in accordance with the applicable prescribed rate. The first and second quarter 2024 dividends on the common shares and the First Preference Shares, Series F, G, H, I, J, K and M are to be paid on March 1 and June 1, 2024 to holders of record as of February 16 and May 17, 2024, respectively.
The following table summarizes the dividends declared per share for each of the Corporation's class of shares for the past three years.
| | | | | | | | | | | | | | | | | |
| 2023 | | 2022 | | 2021 | |
| Common Shares | 2.3100 | | 2.2000 | | | 2.0800 | |
First Preference Shares, Series F (1) | 1.2250 | | 1.2250 | | | 1.2250 | |
First Preference Shares, Series G (2) | 1.3145 | | 1.0983 | | | 1.0983 | |
First Preference Shares, Series H (3) | 0.4588 | | 0.4588 | | | 0.4588 | |
First Preference Shares, Series I (4) | 1.5619 | | 0.9157 | | | 0.3926 | |
First Preference Shares, Series J (1) | 1.1875 | | 1.1875 | | | 1.1875 | |
First Preference Shares, Series K (5) | 0.9823 | | 0.9823 | | | 0.9823 | |
First Preference Shares, Series M (6) | 0.9783 | | 0.9783 | | | 0.9783 | |
(1) The dividend rate on the First Preference Shares, Series F and First Preference Shares, Series J are fixed and do not reset.
(2) The annual dividend per share was reset to $1.5308 for the five-year period from September 1, 2023 up to but excluding September 1, 2028.
(3) The annual dividend per share was reset to $0.4588 for the five-year period from June 1, 2020 up to but excluding June 1, 2025.
(4) The First Preference Shares, Series I are entitled to receive floating rate cumulative dividends, which rate will reset every quarter based on the then current three‑month Government of Canada Treasury Bill rate plus 1.45%.
(5) The annual dividend per share was reset to 1.3673 for the five-year period from March 1, 2024 to but excluding March 1, 2029.
(6) The annual dividend per share was reset to $0.9783 for the five-year period from December 1, 2019 to but excluding December 1, 2024.
For purposes of the enhanced dividend tax credit rules contained in the Income Tax Act (Canada) and any corresponding provincial and territorial tax legislation, all dividends paid on common and preference shares after December 31, 2005 by Fortis to Canadian residents are designated as "eligible dividends". Unless stated otherwise, all dividends paid by Fortis hereafter are designated as "eligible dividends" for the purposes of such rules.
Debt Covenant Restrictions on Dividend Distributions
The Trust Indenture pertaining to the Corporation's $200 million Unsecured Debentures contains a covenant which provides that Fortis shall not declare or pay any dividends (other than stock dividends or cumulative preferred dividends on preferred shares not issued as stock dividends) or make any other distribution on its shares or redeem any of its shares or prepay subordinated debt if, immediately thereafter, its consolidated funded obligations would be in excess of 75% of its total consolidated capitalization.
The Corporation has a $1.3 billion unsecured committed revolving corporate credit facility, maturing July 2028, and a US$500 million non-revolving term credit facility, maturing May 2024, that are available for general corporate purposes. The credit facilities contain a covenant that provides that Fortis shall not: (i) declare, pay or make any ordinary course dividend except that in giving effect to the payment of such ordinary course dividend, it would not result in the Corporation's consolidated debt to consolidated capitalization ratio exceeding 70%; or (ii) declare, pay or make any restricted payments (including special or extraordinary dividends) if, immediately thereafter, its consolidated debt to consolidated capitalization ratio would exceed 65%.
As at December 31, 2023 and 2022, the Corporation was in compliance with its debt covenant restrictions pertaining to dividend distributions, as described above.
Credit Ratings
Credit ratings provide an opinion about the creditworthiness of an issuer and the issuer's capacity and willingness to meet its financial commitments on the obligation in accordance with its terms. Credit ratings are intended to provide investors with an independent measure of credit quality of an issue of securities and are not recommendations to buy, sell or hold securities. The ratings assigned to securities issued by Fortis and its utilities are reviewed by the agencies on an ongoing basis. Ratings may be subject to revision or withdrawal at any time by the rating organization. The following table summarizes the Corporation's debt credit ratings as at February 8, 2024.
| | | | | | | | | | | | | | | | | |
| Company/Security | DBRS Morningstar | | S&P | | Moody's |
| Fortis | | | | | |
| Unsecured Debt | A (low), Stable | | BBB+ | | Baa3 |
| Preference Shares | Pfd-2 (low), Stable | | P-2 | | N/A |
Caribbean Utilities - Unsecured Debt | A (low), Stable | | BBB+ | | — | |
Central Hudson - Unsecured Debt(1) | — | | | BBB+ | | Baa1 |
FortisAlberta - Unsecured Debt | A (low), Stable | | A- | | Baa1 |
| FortisBC Electric | | | | | |
| Secured Debt | A (low), Stable | | — | | | — | |
| Unsecured Debt | A (low), Stable | | — | | | Baa1 |
| Commercial Paper | R-1 (low), Stable | | — | | | — | |
| FortisBC Energy | | | | | |
| Unsecured Debt | A, Stable | | — | | | A3 |
| Commercial Paper | R-1 (low), Stable | | — | | | — | |
| ITC Holdings | | | | | |
| Unsecured Debt | — | | | BBB+ | | Baa2 |
| Commercial Paper | — | | | A-2 | | Prime-2 |
ITC Great Plains - First Mortgage Bonds | — | | | A | | A1 |
ITC Midwest - First Mortgage Bonds | — | | | A | | A1 |
ITCTransmission - First Mortgage Bonds | — | | | A | | A1 |
Maritime Electric - Secured Debt | — | | | A | | — | |
METC - Secured Debt | — | | | A | | A1 |
Newfoundland Power - First Mortgage Bonds | A, Stable | | — | | | A2 |
| TEP | | | | | |
| Unsecured Debt | — | | | A- | | A3 |
| Unsecured Bank Credit Facility | — | | | — | | | A3 |
| UNS Electric | | | | | |
| Unsecured Debt | — | | | — | | | A3 |
| Unsecured Bank Credit Facility | — | | | — | | | A3 |
UNS Gas - Unsecured Debt | — | | | — | | | A3 |
(1)Central Hudson's senior unsecured debt is also rated by Fitch at 'A-'. Fitch rates long-term debt on a rating scale that ranges from AAA to C, which represents the range from highest to lowest quality of such securities. Fitch uses '+' or '-' designations to indicate the relative status of securities within a particular rating category. According to Fitch, a long-term obligation rated A denotes the expectation of low credit risk, with strong capacity for payment of financial commitments. The capacity may, nevertheless, be more vulnerable to adverse business or economic conditions than is the case for higher ratings.
In November 2023, S&P confirmed the Corporation's 'A-' issuer and 'BBB+' senior unsecured debt credit ratings and revised the issuer rating outlook for the Corporation and certain of its subsidiaries from stable to negative. S&P noted that the change reflects rising exposure to physical risks due to climate change. S&P also revised the funds from operations (FFO) to debt downgrade threshold for the Corporation from 10.5% to 12.0%.
The table below highlights rating category ranges from highest to lowest quality of such securities for the issuer's credit rating agencies.
| | | | | | | | | | | |
| Security | DBRS Morningstar | S&P | Moody's |
| Long-term debt | AAA to D (1) | AAA to D (2) | Aaa to C (5) |
| Short-term debt | R-1 to D (1) | A-1 to D (3) | Prime-1 to Not Prime (6) |
| Preference Shares | Pfd-1 to D | P-1 to D (4) | N/A |
(1)All rating categories contain subcategories of '(high)' or '(low)' other than AAA and D for long-term debt and below R-2 for short-term debt. The absence of either a '(high)' or '(low)' designation indicates the rating is in the middle of a category.
(2)S&P uses '+' or '-' designations to indicate the relative standing of securities within a particular rating category. Such modifiers are not added to ratings below CCC or ratings at AAA.
(3)Within only the A-1 category may certain obligations be designated with a '+', indicating that the issuer's capacity to meet its financial commitments under these obligations is extremely strong.
(4)S&P uses 'high' or 'low' designations to indicate the relative standing of securities within a particular rating category. Such modifiers are not added to ratings below P-5.
(5)Moody's applies numerical modifiers 1, 2 and 3 to each generic rating classification from Aa to Caa to indicate relative standing within such classification. The modifier 1 indicates that the security ranks at the higher end of its generic rating category, the modifier 2 indicates a mid-range ranking and the modifier 3 indicates a ranking at the lower end of that generic rating category.
(6)Short-term obligations with a Not Prime rating do not fall within any of the Prime rating categories.
DBRS
Long-term debt
According to DBRS Morningstar, a rating of A is assigned to a long-term debt instrument that has good credit quality, with the issuer having substantial capacity to pay its financial obligations, but credit quality is less than AA-rated instruments and may be vulnerable to future events, but qualifying negative factors are considered manageable.
Short-term debt
According to DBRS Morningstar, a rating of R-1 (low) means that the short-term debt obligation has good credit quality, with the issuer having substantial capacity to repay short-term debt obligations and may be vulnerable to future events, but qualifying negative factors are considered manageable. The overall strength of R-1 (low) rated instruments is not as favourable as those in higher rated categories.
Preference shares
According to DBRS Morningstar, a rating of Pfd-2 (low) means that the preference shares have good credit quality and although the protection of dividends and principal is substantial, earnings, the balance sheet and coverage ratios of Pfd-2 rated companies are not as strong as Pfd-1 rated companies.
S&P
Long-term debt
According to S&P, a rating of A is assigned to long-term debt instruments that are somewhat more susceptible to the adverse effects of changes in circumstances and economic conditions than those in higher-rated categories. However, the issuer's capacity to meet its financial obligations is still strong. Debt instruments rated BBB exhibit adequate protection parameters. However, adverse economic conditions or changing circumstances are more likely to lead to a weakened capacity of the issuer to meet its financial commitments on the obligation.
Short-term debt
According to S&P, a short-term obligation rated A-2 is somewhat more susceptible to the adverse effects of changes in circumstances and economic conditions than obligations in higher rating categories. However, the issuer's capacity to meet its financial commitments on the short-term obligation is satisfactory.
Preference shares
According to S&P, a rating of P-2 means that the preference shares have adequate protection parameters. However, adverse economic conditions or changing circumstances are more likely to lead to a weakened capacity of the issuer to meet its financial commitments on the obligation.
Moody's
Long-term debt
According to Moody's, a rating of Baa is assigned to long-term debt instruments considered to be of medium-grade quality. Debt instruments rated Baa are subject to moderate credit risk and may possess certain speculative characteristics. Debt instruments rated A are considered upper-medium grade and are subject to low credit risk.
Short-term debt
According to Moody's, a rating of Prime-2 means that an issuer has a strong ability to repay short-term debt obligations.
The Corporation and/or each of its currently rated utilities pay DBRS Morningstar, S&P, Moody's and/or Fitch an annual monitoring fee and a one-time fee in connection with each rated issuance.
DIRECTORS AND OFFICERS
The Board has governance guidelines that cover various items, including director tenure. The governance guidelines provide that Directors of the Corporation are to be elected for a term of one year and are eligible for re‑election until the annual meeting of shareholders following the date they turn 72 or until they have served on the Board for 12 years, whichever is earlier. Exceptions may be made by the Board if it is in the best interests of the Corporation and the Director has received solid annual performance evaluations, has the necessary skills and experience and meets the other Board policies and legal requirements for Board service.
The following table sets out the name, province or state, and country of residence of each of the Directors of the Corporation and their principal occupations during the five preceding years. Each Director's current term expires at the next annual meeting of shareholders.
| | | | | | | | | | | | | | |
Name, Residence, Principal Occupation Within Five Preceding Years | Director Since | Committees (1) |
AC | GS | HR |
TRACEY C. BALL, British Columbia, Canada Corporate Director. | 2014 | l | l | |
PIERRE J. BLOUIN, Quebec, Canada Corporate Director. | 2015 | | C | l |
LAWRENCE T. BORGARD, Florida, United States of America Corporate Director. | 2017 | l | | l |
MAURA J. CLARK, New York, United States of America Corporate Director. | 2015 | C | | l |
LISA CRUTCHFIELD, Pennsylvania, United States of America Corporate Director. Managing Principal of Hudson Strategic Advisors, LLC since 2012. | 2022 | | l | l |
MARGARITA K. DILLEY, District of Columbia, United States of America Corporate Director. | 2016 | l | | l |
JULIE A. DOBSON, Maryland, United States of America Corporate Director. | 2018 | | l | C |
LISA L. DUROCHER, Ontario, Canada Corporate Director. Executive Vice President, Financial and Emerging Services of Rogers Communications Inc. from January 2021 to June, 2023, and prior to that, Chief Digital Officer from June 2017 to January 2021. | 2021 | l | l | |
DAVID G. HUTCHENS, Arizona, United States of America President and Chief Executive Officer of the Corporation. | 2021 | (2) |
GIANNA M. MANES, South Carolina, United States of America Corporate Director. President and Chief Executive Officer of ENMAX Corporation from 2012 to July 2020. | 2021 | | l | l |
DONALD R. MARCHAND, Alberta, Canada Corporate Director. Executive Vice-President of TC Energy from July to November 2021 and Chief Financial Officer of TC Energy and its predecessor TransCanada Corporation from 2010 until July 2021. | 2023 | l | l | |
JO MARK ZUREL (Chair), Newfoundland and Labrador, Canada Corporate Director. President of Stonebridge Capital Inc., a private investment company, from 2006 to March 2019. | 2016 | l | l | l |
(1) Audit Committee, Governance and Sustainability Committee and Human Resources Committee. "C" represents Chair.
(2) Mr. Hutchens does not serve on any of the committees because he is the President and Chief Executive Officer of the Corporation, but is invited to and attends all committee meetings.
Proceedings
From October 2018 until April 2021, Maura J. Clark served on the board of directors of Garrett Motion Inc. (Garrett), a NYSE listed company. On September 20, 2020, Garrett and certain affiliated companies filed petitions in the United States Bankruptcy Court for the Southern District of New York seeking relief under Chapter 11 of the United States Bankruptcy Code. Garrett emerged from the Chapter 11 proceedings in April 2021.
The following table sets out the name, province or state, and country of residence of each of the executive officers of Fortis and indicates the office held and principal occupations of the executive officers during the five preceding years.
| | | | | |
Name, Residence, Principal Occupation During the Five Preceding Years | Office |
DAVID G. HUTCHENS, Arizona, United States of America President and Chief Executive Officer since January 2021. Chief Operating Officer from January 2020 to December 2020 and Executive Vice President, Western Utility Operations from January 2018 to January 2020. Chief Executive Officer of UNS Energy from January 2020 to December 2020 and President and Chief Executive Officer of UNS Energy from May 2014 to January 2020. | President and Chief Executive Officer |
JOCELYN H. PERRY, Newfoundland and Labrador, Canada Executive Vice President, Chief Financial Officer since June 2018. | Executive Vice President, Chief Financial Officer |
JAMES R. REID, Ontario, Canada Executive Vice President, Sustainability and Chief Legal Officer since July 2022. Executive Vice President, Chief Legal Officer and Corporate Secretary from March 2018 to June 2022. | Executive Vice President, Sustainability and Chief Legal Officer |
GARY J. SMITH, Newfoundland and Labrador, Canada Executive Vice President, Operations and Innovation since January 2022, and Executive Vice President, Eastern Canadian and Caribbean Operations from June 2017 to December 2021. | Executive Vice President, Operations and Innovation |
STUART I. LOCHRAY, Ontario, Canada Senior Vice President, Capital Markets and Business Development since September 2021. Various senior executive roles at Scotiabank in Houston, including Managing Director & Head, US Corporate Investment Banking from September 2019 to September 2021, Managing Director & Head, Power & Utilities, Corporate and Investment Banking from March 2019 to September 2019, and Managing Director & Co-Head, US Corporate Banking from April 2017 to March 2019. | Senior Vice-President, Capital Markets and Business Development |
STEPHANIE A. AMAIMO, Michigan, United States of America Vice President, Investor Relations since October 2017. | Vice President, Investor Relations |
JULIE M. AVERY, Newfoundland and Labrador, Canada Vice President, Controller since July 2022. Senior Director, Finance from September 2020 to June 2022. Director, Financial Planning & Strategic Initiatives from December 2019 to September 2020. Director, Executive Compensation from October 2017 to December 2019. | Vice President, Controller |
TANYA N. FINLAY, Newfoundland and Labrador, Canada Vice President, People and Culture since July 2023. Director, Talent Management and Human Resources from September 2016 to July 2023. | Vice President, People and Culture |
KAREN J. GOSSE, Newfoundland and Labrador, Canada Vice President, Finance since July 2022. Vice President, Controller from September 2021 to June 2022. Vice President, Treasury and Planning from April 2018 to September 2021. | Vice President, Finance |
RONALD J. HINSLEY, Texas, United States of America Vice President, CIO since May 2019. Vice President, Information Technology and CIO of ITC Holdings from 2013 to December 2021. | Vice President, CIO |
KEALEY D. MARTIN, Newfoundland and Labrador, Canada Vice President, Sustainability and Climate Strategy since July 2023. Director, Sustainability from November 2019 to July 2023. Director, Investor Relations from October 2017 to November 2019. | Vice President, Sustainability and Climate Strategy |
KAREN M. MCCARTHY, Newfoundland and Labrador, Canada Vice President, Communications and Government Relations since March 2023. Vice President, Communications and Corporate Affairs from May 2018 to March 2023. | Vice President, Communications and Government Relations |
REGAN P. O'DEA, Newfoundland and Labrador, Canada Vice President, General Counsel since May 2017. | Vice President, General Counsel |
KEVIN D. WOODBURY, Newfoundland and Labrador, Canada Vice President, Innovation & Technology since July 2022. Director, Innovation & Technology from September 2021 to June 2022. Director, Business Development from November 2015 to September 2021. | Vice President, Innovation and Technology |
The directors and executive officers of Fortis, as a group, beneficially own, directly or indirectly, or exercise control or direction over 364,236 common shares, representing 0.07% of the issued and outstanding common shares of Fortis. The common shares are the only voting securities of the Corporation.
AUDIT COMMITTEE
Members
The members of the Corporation's Audit Committee are Maura J. Clark (Chair), Tracey C. Ball, Lawrence T. Borgard, Margarita K. Dilley, Lisa L. Durocher, Donald R. Marchand and Jo Mark Zurel. All members of the Audit Committee are independent and financially literate as those terms are defined by Canadian and U.S. securities laws and TSX and NYSE requirements. In addition, the Board has determined that Tracey C. Ball, Maura J. Clark, Margarita K. Dilley, Donald R. Marchand and Jo Mark Zurel are financial experts and has designated each of them as "audit committee financial experts" under U.S. securities laws.
The Corporation's Audit Committee Mandate, effective as of January 1, 2023 is attached as Exhibit "C" to this AIF.
Education and Experience
The education and experience of each Audit Committee member that is relevant to such member's responsibilities as a member of the Audit Committee are set out below.
| | | | | |
| Committee Member | Relevant Education and Experience |
MAURA J. CLARK (Chair)
| Ms. Clark retired from Direct Energy, a subsidiary of Centrica plc, in March 2014 where she was President of Direct Energy Business, a leading energy retailer in Canada and the U.S. Previously Ms. Clark was Executive Vice President of North American Strategy and Mergers and Acquisitions for Direct Energy. Ms. Clark's prior experience includes investment banking and serving as Chief Financial Officer of an independent oil refining and marketing company. Ms. Clark graduated from Queen's University with a Bachelor of Arts in Economics. She is a member of the Association of Chartered Professional Accountants of Ontario. |
TRACEY C. BALL
| Ms. Ball retired in September 2014 as Executive Vice President and Chief Financial Officer of Canadian Western Bank Group. Ms. Ball has served on several private and public sector boards, including the Province of Alberta Audit Committee and the Financial Executives Institute of Canada. She graduated from Simon Fraser University with a Bachelor of Arts (Commerce). She is a member of the Chartered Professional Accountants of Alberta and the Chartered Professional Accountants of British Columbia. Ms. Ball was elected as a Fellow of the Chartered Professional Accountants of Alberta in 2007. She holds an ICD.D designation from the Institute of Corporate Directors. |
| LAWRENCE T. BORGARD | Mr. Borgard retired from Integrys Energy Group in 2015 where he was President and Chief Operating Officer and the Chief Executive Officer of each of Integrys' six regulated electric and natural gas utilities. Mr. Borgard graduated from Michigan State University with a Bachelor of Science (Electrical Engineering) and the University of Wisconsin-Oshkosh with an MBA. He also attended the Advanced Management Program at Harvard University Business School. |
| MARGARITA K. DILLEY | Ms. Dilley retired from ASTROLINK International LLC in 2004, an international wireless broadband telecommunications company, where she was Vice President and Chief Financial Officer. Ms. Dilley's prior experience includes serving as Director, Strategy & Corporate Development as well as Treasurer for Intelsat. Ms. Dilley graduated from Cornell University with a Bachelor of Arts, from Columbia University with a Master of Arts and from Wharton Graduate School, University of Pennsylvania with an MBA. |
| LISA L. DUROCHER | Ms. Durocher retired in June 2023 from her position leading Financial and Emerging Services at Rogers Communications. Prior to this role, Ms. Durocher was the Chief Digital Officer at Rogers. Prior to joining Rogers 7 years ago, Ms. Durocher held several senior leadership positions over 15 years at American Express in New York City, including leading global product and marketing organizations in digital payments, charge cards and travel. Ms. Durocher is a graduate of Wilfrid Laurier University’s Business Administration program and also sits on the board of Rogers Bank. |
| DONALD R. MARCHAND | Mr. Marchand was Executive Vice President of TC Energy, a leading North American energy infrastructure company, from July 2021 until his retirement in November 2021. He served as Chief Financial Officer of TC Energy and its predecessor, TransCanada Corporation, from 2010 until July 2021, with additional responsibility for Strategy and Corporate Development from 2015 to 2017 and from 2020 to 2021. During his 27-year tenure with the company, Mr. Marchand led many of its financial functions, including treasury, finance, accounting, taxation, risk management and investor relations. Mr. Marchand graduated from the University of Manitoba with a Bachelor of Commerce degree and subsequently qualified as a Chartered Accountant and Chartered Financial Analyst. He is a member of the Institute of Chartered Professional Accountants of Alberta, the CFA Institute and the Calgary Society of Financial Analysts. |
| JO MARK ZUREL | Mr. Zurel was the president of Stonebridge Capital Inc., a private investment company, from 2006 to March 2019. From 1998 to 2006, Mr. Zurel was Senior Vice-President and Chief Financial Officer of CHC Helicopter Corporation. Mr. Zurel graduated from Dalhousie University with a Bachelor of Commerce and is a Fellow of the Association of Chartered Professional Accountants of Newfoundland and Labrador. He holds an ICD.D designation from the Institute of Corporate Directors. |
Pre-Approval Policies and Procedures
The Audit Committee has established a policy that requires pre-approval of all audit and non-audit services provided to the Corporation and its subsidiaries by the Corporation's external auditor. The Pre‑Approval Policy for Independent Auditor Services describes the services that may be contracted from the external auditor and the related limitations and authorization procedures. This policy defines prohibited services, including but not limited to bookkeeping, valuations, internal audit and management functions, which may not be contracted from the external auditor and establishes an annual limit for permissible non-audit services not greater than the total fee for audit services. Audit Committee pre-approval is required for all services provided by the external auditor.
External Auditor Service Fees
The aggregate fees billed by the Corporation's external auditors during each of the last two fiscal years are set out in the following table.
| | | | | | | | | | | |
| | Deloitte LLP |
| ($ thousands) | Description of Fee Category | 2023 | 2022 |
| Audit Fees | Core audit services | 10,807 | | 9,837 | |
| Audit-Related Fees | Assurance and related services that are reasonably related to the audit or review of the Financial Statements and are not included under Audit Fees | 1,582 | | 1,398 | |
| Tax Fees | Services related to tax compliance, planning and advice | 10 | | 92 | |
| All Other Fees | Services which are not Audit Services, Audit-Related Fees or Tax Fees | 99 | | 11 | |
| Total | | 12,498 | | 11,338 | |
TRANSFER AGENT AND REGISTRAR
The transfer agent and registrar in Canada for the common shares and first preference shares of Fortis is Computershare Trust Company of Canada in Montréal and Toronto.
The co-transfer agent and co-registrar in the U.S. for the common shares is Computershare Trust Company, N.A. in Canton, MA, Jersey City, NJ and Providence, RI.
Computershare Trust Company of Canada
8th Floor, 100 University Avenue
Toronto, ON M5J 2Y1
T: 514.982.7555 or 1.866.586.7638
F: 416.263.9394 or 1.888.453.0330
W: www.investorcentre.com/fortisinc
Computershare Trust Company, N.A.
Attn: Shareholder Services
Overnight Mail Delivery: 4150 Royall Street, Canton, MA 02021
Regular Mail Delivery (U.S. Shareholders): P.O. Box 43078, Providence, RI 02940-3078
Regular Mail Delivery (Shareholders outside the U.S.): P.O. Box 43006, Providence, RI 02940-3006
T: 1.781.575.2000 or 1.877.373.6374
F: 1.781.575.2044
E: service@computershare.com
INTERESTS OF EXPERTS
Deloitte LLP is independent with respect to the Corporation within the meaning of the U.S. Securities Act of 1933 and the applicable rules and regulations thereunder adopted by the SEC and the Public Company Accounting Oversight Board (United States) and within the meaning of the rules of professional conduct of the Chartered Professional Accountants of Newfoundland and Labrador.
ADDITIONAL INFORMATION
Additional information relating to the Corporation can be found on the Corporation's website at www.fortisinc.com, on SEDAR+ at www.sedarplus.ca and on EDGAR at www.sec.gov. The information contained on, or accessible through, any of these websites is not incorporated by reference into this document unless otherwise stated.
Additional financial information is provided in the Corporation's MD&A and Financial Statements, which are incorporated by reference in this AIF and can be found on the Corporation's website at www.fortisinc.com, on SEDAR+ and on EDGAR.
Further additional information, including officers' and directors' remuneration and indebtedness, principal holders of the securities of Fortis, options to purchase securities and interests of insiders in material transactions, where applicable, is contained in the Management Information Circular of Fortis dated March 17, 2023 for the May 4, 2023 annual and special meeting of shareholders.
Requests for additional copies of the above‑mentioned documents, as well as this 2023 AIF, should be directed to the Corporate Secretary, Fortis, P.O. Box 8837, St. John's, NL, A1B 3T2 (telephone: 709.737.2800).
EXHIBIT A:
SUMMARY OF TERMS AND CONDITIONS OF AUTHORIZED SECURITIES
Common Shares
Dividends on common shares are declared at the discretion of the Board. Holders of common shares are entitled to dividends on a pro rata basis if, as, and when declared by the Board. Subject to the rights of the holders of the first preference shares and second preference shares and any other classes of shares of the Corporation entitled to receive dividends in priority to or ratably with the holders of the common shares, the Board may declare dividends on the common shares to the exclusion of any other classes of shares of the Corporation.
On the liquidation, dissolution or winding-up of Fortis, holders of common shares are entitled to participate ratably in any distribution of assets of Fortis, subject to the rights of holders of first preference shares and second preference shares and any other classes of shares of the Corporation entitled to receive the assets of the Corporation on such a distribution in priority to or ratably with the holders of the common shares.
Holders of the common shares are entitled to receive notice of and to attend all annual and special meetings of the shareholders of Fortis, other than separate meetings of holders of any other classes or series of shares, and are entitled to one vote in respect of each Common Share held at such meetings.
Preference Shares
First Preference Shares
The following is a summary of the material rights, privileges, conditions and restrictions attached to the first preference shares as a class. The specific terms of the first preference shares, including the currency in which first preference shares may be purchased and redeemed and the currency in which any dividend is payable, if other than Canadian dollars, and the extent to which the general terms described herein apply to those first preference shares, is or will be as set forth in the applicable articles of amendment of Fortis relating to such series.
Issuance in Series
The Board may from time to time issue first preference shares in one or more series. Prior to issuing shares in a series, the Board is required to fix the number of shares in the series and determine the designation, rights, privileges, restrictions and conditions attaching to that series of first preference shares.
Priority
The shares of each series of first preference shares rank on a parity with the first preference shares of every other series and in priority to all other shares of Fortis, including the second preference shares, as to the payment of dividends, return of capital and the distribution of assets in the event of the liquidation, dissolution or winding-up of Fortis, whether voluntary or involuntary, or any other distribution of the assets of Fortis among its shareholders for the purpose of winding-up its affairs.
Each series of first preference shares participates ratably with every other series of first preference shares in respect of accumulated cumulative dividends and returns of capital, if any, cumulative dividends, whether or not declared and any amount payable on the return of capital in respect of a series of first preference shares, if not paid in full.
Voting
The holders of the first preference shares are not entitled to any voting rights as a class except to the extent that voting rights may from time to time be attached to any series of first preference shares, and except as provided by law or as described below under the heading "Modification". At any meeting of the holders of first preference shares, each holder shall have one vote in respect of each first preference share held.
Redemption
Subject to the provisions of the Corporations Act (Newfoundland and Labrador) and any provisions relating to any particular series, Fortis, upon giving proper notice, may redeem out of capital or otherwise at any time, or from time to time, the whole or any part of the then outstanding first preference shares of any one or more series on payment for each such first preference share at such price or prices as may be applicable to such series. Subject to the foregoing, if only a part of the then outstanding first preference shares of any particular series is at any time redeemed, the shares to be redeemed will be selected by lot in such manner as the directors or the transfer agent for the first preference shares, if any, decide, or if the directors so determine, may be redeemed pro rata, disregarding fractions.
Modification
The class provisions attached to the first preference shares may only be amended with the prior approval of the holders of the first preference shares, in addition to any other approvals required by the Corporations Act (Newfoundland and Labrador) or any other statutory provisions of like or similar effect in force from time to time.
The approval of the holders of the first preference shares with respect to any and all matters may be given by at least two-thirds of the votes cast at a meeting of the holders of the first preference shares duly called for that purpose.
First Preference Shares Authorized and Outstanding
The following table summarizes the series of first preference shares as of February 8, 2024.
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Authorized | Issued and Outstanding | Initial Yield (%) | Annual Dividend ($) (1) | Reset Dividend Yield (%) | Redemption and/or Conversion Option Date (2) | Redemption Value ($) | Right to Convert on a One for One Basis |
| Perpetual Fixed Rate | | | | | | | | |
| Series F | 5,000,000 | | 5,000,000 | | 4.90 | | 1.2250 | | — | | Currently Redeemable | 25.00 | | — | |
| Series J | 8,000,000 | | 8,000,000 | | 4.75 | | 1.1875 | | — | | Currently Redeemable | 25.00 | | — | |
Fixed Rate Reset (3) | | | | | | | | |
| Series G | 9,200,000 | | 9,200,000 | | 5.25 | | 1.5308 | | 2.13 | | September 1, 2028 | 25.00 | | — | |
Series H (4) | 10,000,000 | | 7,665,082 | | 4.25 | | 0.4588 | | 1.45 | | June 1, 2025 | 25.00 | | Series I |
Series K (5) | 12,000,000 | | 10,000,000 | | 4.00 | | 0.9823 | | 2.05 | | March 1, 2029 | 25.00 | | Series L |
Series M (4) | 24,000,000 | | 24,000,000 | | 4.10 | | 0.9783 | | 2.48 | | December 1, 2024 | 25.00 | | Series N |
Floating Rate Reset (4) (6) | | | | | | | | |
| Series I | 10,000,000 | | 2,334,918 | | 2.10 | | — | | 1.45 | | June 1, 2025 | 25.00 | | Series H |
| Series L | 12,000,000 | | — | | — | | — | | — | | — | | — | | Series K |
| Series N | 24,000,000 | | — | | — | | — | | — | | — | | — | | Series M |
(1)Holders are entitled to receive a fixed or floating cumulative quarterly cash dividend as and when declared by the Board, payable in equal installments on the first day of each quarter.
(2)On or after the specified redemption dates, the Corporation has the option to redeem for cash the outstanding first preference shares, in whole or in part, at the specified per share redemption value plus all accrued and unpaid dividends up to but excluding the dates fixed for redemption, and in the case of the first preference shares that reset, on every fifth anniversary date thereafter.
(3)On the redemption and/or conversion option date, and on each five-year anniversary thereafter, the reset annual dividend per share will be determined by multiplying $25.00 per share by the annual fixed dividend rate, which is the sum of the five-year Government of Canada Bond Yield on the applicable reset date, plus the applicable reset dividend yield.
(4)On each conversion option date, the holders have the option, subject to certain conditions, to convert any or all of their shares into an equal number of Cumulative Redeemable first preference shares of a specified series.
(5)The annual dividend per share of the First Preference Shares, Series K was reset from 0.9823 to 1.3673 for a five year period from March 1, 2024 up to, but excluding, March 1, 2029.
(6)The floating quarterly dividend rate will be reset every quarter based on the then current three‑month Government of Canada Treasury Bill rate plus the applicable reset dividend yield.
Second Preference Shares
The rights, privileges, conditions and restrictions attaching to the second preference shares are substantially identical to those attaching to the first preference shares, except that the second preference shares are junior to the first preference shares with respect to the payment of dividends, repayment of capital and the distribution of assets of Fortis in the event of a liquidation, dissolution or winding up of Fortis.
The specific terms of the second preference shares, including the currency in which second preference shares may be purchased and redeemed and the currency in which any dividend is payable, if other than Canadian dollars, and the extent to which the general terms described herein apply to those second preference shares, will be as set forth in the applicable articles of amendment of Fortis relating to such series.
As of February 8, 2024, there were no second preference shares issued and outstanding.
EXHIBIT B:
MARKET FOR SECURITIES
Common Shares
The common shares are traded on the TSX in Canada, and on the NYSE in the U.S., in each case under the symbol FTS. The following table sets forth the reported high and low trading prices and trading volumes, on a monthly basis for the year ended December 31, 2023, for the common shares on the TSX and NYSE in Canadian Dollars and U.S. Dollars, respectively.
| | | | | | | | | | | | | | | | | | | | | | | |
| 2023 Trading Prices and Volumes – Common Shares |
| TSX | | NYSE |
| Month | High ($) | Low ($) | Volume | | High ($) | Low ($) | Volume |
| January | 56.68 | | 54.24 | | 40,537,884 | | | 42.35 | | 39.83 | | 8,732,285 | |
| February | 56.10 | | 53.48 | | 48,289,215 | | | 41.97 | | 39.51 | | 13,178,759 | |
| March | 58.10 | | 53.04 | | 44,137,382 | | | 42.97 | | 38.37 | | 13,905,557 | |
| April | 60.64 | | 56.58 | | 25,489,960 | | | 45.03 | | 42.07 | | 8,645,453 | |
| May | 62.00 | | 56.49 | | 45,417,587 | | | 46.28 | | 41.49 | | 16,688,677 | |
| June | 58.31 | | 55.31 | | 32,303,625 | | | 43.33 | | 41.96 | | 10,944,557 | |
| July | 57.93 | | 54.96 | | 24,660,441 | | | 43.84 | | 41.43 | | 10,086,402 | |
| August | 56.52 | | 52.72 | | 40,997,838 | | | 42.51 | | 39.00 | | 14,157,311 | |
| September | 56.59 | | 51.26 | | 26,609,688 | | | 42.01 | | 37.88 | | 14,780,061 | |
| October | 55.89 | | 49.82 | | 34,191,233 | | | 40.84 | | 36.30 | | 23,108,286 | |
| November | 57.73 | | 53.45 | | 36,083,014 | | | 42.17 | | 39.41 | | 15,672,045 | |
| December | 56.12 | | 53.47 | | 25,430,555 | | | 41.76 | | 39.47 | | 14,080,292 | |
Preference Shares
The First Preference Shares, Series F; First Preference Shares, Series G; First Preference Shares, Series H; First Preference Shares, Series I; First Preference Shares, Series J; First Preference Shares, Series K; and First Preference Shares, Series M of Fortis are listed on the TSX under the symbols FTS.PR.F; FTS.PR.G; FTS.PR.H; FTS.PR.I; FTS.PR.J; FTS.PR.K and FTS.PR.M, respectively.
The following tables set forth the reported high and low trading prices and volumes for the First Preference Shares, Series F; First Preference Shares, Series G; First Preference Shares, Series H; First Preference Shares, Series I; First Preference Shares, Series J; First Preference Shares, Series K; and First Preference Shares, Series M on a monthly basis for the year ended December 31, 2023.
| | | | | | | | | | | | | | | | | | | | | | | |
| 2023 Trading Prices and Volumes – First Preference Shares |
| First Preference Shares, Series F | | First Preference Shares, Series G |
Month | High ($) | Low ($) | Volume | | High ($) | Low ($) | Volume |
January | 21.45 | | 19.42 | | 60,578 | | | 18.48 | | 17.17 | | 139,880 | |
February | 21.38 | | 20.00 | | 45,695 | | | 19.00 | | 18.16 | | 223,964 | |
March | 20.96 | | 19.89 | | 71,422 | | | 18.87 | | 17.00 | | 84,073 | |
April | 21.10 | | 20.46 | | 39,596 | | | 18.48 | | 17.19 | | 49,260 | |
May | 20.70 | | 19.75 | | 38,494 | | | 18.12 | | 16.70 | | 74,654 | |
June | 20.48 | | 19.46 | | 41,843 | | | 18.95 | | 16.92 | | 128,759 | |
July | 19.77 | | 19.15 | | 51,483 | | | 19.47 | | 18.31 | | 239,406 | |
August | 20.10 | | 19.15 | | 74,565 | | | 19.35 | | 18.50 | | 300,384 | |
September | 19.82 | | 19.25 | | 50,426 | | | 19.17 | | 18.20 | | 309,955 | |
October | 19.47 | | 17.62 | | 52,811 | | | 19.12 | | 17.85 | | 374,761 | |
November | 19.50 | | 18.00 | | 57,663 | | | 20.05 | | 18.40 | | 218,364 | |
December | 19.46 | | 18.10 | | 62,723 | | | 20.62 | | 19.05 | | 249,249 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| First Preference Shares, Series H | | First Preference Shares, Series I |
Month | High ($) | Low ($) | Volume | | High ($) | Low ($) | Volume |
January | 13.85 | | 12.22 | | 10,148 | | | 16.32 | | 15.00 | | 22,096 | |
February | 13.84 | | 13.00 | | 41,836 | | | 17.30 | | 15.95 | | 22,203 | |
March | 13.21 | | 12.07 | | 105,046 | | | 17.00 | | 15.35 | | 270,429 | |
April | 13.00 | | 12.49 | | 149,134 | | | 16.48 | | 15.50 | | 16,802 | |
May | 12.90 | | 11.65 | | 58,546 | | | 15.60 | | 14.45 | | 13,755 | |
June | 12.50 | | 11.89 | | 90,754 | | | 15.68 | | 14.55 | | 8,164 | |
July | 13.25 | | 12.50 | | 83,265 | | | 15.40 | | 14.99 | | 55,405 | |
August | 13.20 | | 12.30 | | 97,555 | | | 15.95 | | 14.91 | | 56,380 | |
September | 12.62 | | 12.01 | | 62,658 | | | 15.20 | | 14.75 | | 18,731 | |
October | 12.64 | | 12.17 | | 84,358 | | | 15.36 | | 14.71 | | 114,395 | |
November | 13.72 | | 12.40 | | 50,222 | | | 15.50 | | 14.71 | | 162,040 | |
December | 13.23 | | 12.53 | | 107,256 | | | 15.37 | | 14.66 | | 59,038 | |
| First Preference Shares, Series J | | First Preference Shares, Series K |
Month | High ($) | Low ($) | Volume | | High ($) | Low ($) | Volume |
January | 20.99 | | 18.97 | | 70,426 | | | 17.20 | | 15.68 | | 63,542 | |
February | 20.85 | | 19.53 | | 38,420 | | | 17.58 | | 16.94 | | 100,862 | |
March | 20.35 | | 19.20 | | 81,616 | | | 16.93 | | 15.29 | | 96,664 | |
April | 20.36 | | 19.67 | | 48,777 | | | 16.89 | | 15.82 | | 42,765 | |
May | 20.01 | | 18.93 | | 67,293 | | | 17.05 | | 15.18 | | 51,197 | |
June | 19.67 | | 18.90 | | 102,783 | | | 16.75 | | 15.33 | | 114,916 | |
July | 19.06 | | 18.50 | | 91,480 | | | 17.34 | | 16.26 | | 129,420 | |
August | 19.28 | | 18.10 | | 97,101 | | | 17.50 | | 16.35 | | 168,743 | |
September | 18.79 | | 18.25 | | 231,573 | | | 17.50 | | 16.35 | | 258,951 | |
October | 18.67 | | 17.03 | | 79,273 | | | 17.45 | | 16.51 | | 112,263 | |
November | 19.00 | | 17.43 | | 162,440 | | | 18.39 | | 16.79 | | 141,940 | |
December | 18.86 | | 17.61 | | 124,829 | | | 18.09 | | 16.71 | | 53,711 | |
| First Preference Shares, Series M | | |
Month | High ($) | Low ($) | Volume | | | | |
January | 18.35 | | 16.53 | | 130,094 | | | | | |
February | 18.40 | | 17.71 | | 152,728 | | | | | |
March | 17.78 | | 16.16 | | 176,082 | | | | | |
April | 17.39 | | 16.41 | | 153,179 | | | | | |
May | 17.00 | | 15.60 | | 124,912 | | | | | |
June | 16.90 | | 16.35 | | 436,994 | | | | | |
July | 17.69 | | 16.58 | | 274,112 | | | | | |
August | 17.30 | | 16.21 | | 309,295 | | | | | |
September | 17.00 | | 16.30 | | 304,450 | | | | | |
October | 17.00 | | 16.25 | | 515,076 | | | | | |
November | 17.70 | | 16.70 | | 94,093 | | | | | |
December | 17.67 | | 16.81 | | 226,667 | | | | | |
EXHIBIT C:
AUDIT COMMITTEE MANDATE
(effective January 1, 2023)
1.0 PURPOSE AND AUTHORITY
1.1 The purpose of the Committee is to advise and assist the Board in fulfilling its oversight responsibilities relating to, among other things:
a.the integrity of the Corporation's financial statements, financial disclosures and internal controls over financial reporting and disclosure controls and procedures;
b.the Corporation's compliance with related legal and regulatory requirements;
c.the qualifications, independence and performance of the Independent Auditor and Internal Auditor, together with the compensation of the Independent Auditor;
d.the Corporation's ERM Program and the management and mitigation of significant risks identified thereunder;
e.the related policies of the Corporation set out herein; and
f.other matters set out herein or otherwise delegated to the Committee by the Board.
1.2 Consistent with this purpose, the Committee shall encourage continuous improvement of, and foster adherence to, the Corporation's policies, procedures and practices at all levels. The Committee shall also provide for open communication among the Independent Auditor, the Internal Auditor, Management and the Board.
1.3 To perform its duties and responsibilities, the Committee has the authority to: (i) conduct investigations into any matters within its scope of responsibility; (ii) have unrestricted access to information, management and employees and books and records of the Corporation and its affiliates; and (iii) directly access and communicate with the Independent Auditor and Internal Auditor.
2.0 DEFINITIONS
2.1 In this Mandate:
a."Board" means the board of directors of the Corporation;
b."Chair" means the Chair of the Committee;
c."Committee" means the audit committee of the Board;
d."Core Audit Services" means services necessary to: (i) audit the Corporation's annual consolidated or non-consolidated financial statements; (ii) review the Corporation's condensed consolidated interim financial statements; and (iii) audit internal controls over financial reporting in accordance with the requirements of all applicable laws, regulations and professional standards;
e."Corporation" means Fortis Inc.;
f."CPAB" means the Canadian Public Accountability Board or its successor;
g."Director" means a member of the Board;
h."ERM Program" means the Corporation's Enterprise Risk Management Program that incorporates an effective risk management framework to identify, evaluate, manage, monitor and communicate key corporate risks;
i."Financial Expert" means an "audit committee financial expert" as defined in SEC Regulation S-K;
j."Financially Literate" means having the ability to read and understand a set of financial statements that present a breadth and level of complexity of accounting issues that are generally comparable to the breath and complexity of the issues that can reasonably be expected to be present in the Corporation's financial statements;
k."Governance and Sustainability Committee" means the governance and sustainability committee of the Board;
l."Independent" means, in the context of a Member and in accordance with all applicable laws and stock exchange requirements, being free from any direct or indirect material relationship with the Corporation and its subsidiaries which, in the view of the Board, could reasonably be expected to interfere with the exercise of a Member's independent judgment;
m."Independent Auditor" means the firm of chartered professional accountants, registered with the CPAB and the PCAOB, and appointed by the shareholders to act as external auditor;
n."Internal Auditor" means the person(s) employed or engaged by the Corporation to perform the internal audit function of the Corporation;
o."Management" means the senior officers of the Corporation;
p."Mandate" means this mandate of the Committee;
q."MD&A" means the Corporation's management discussion and analysis prepared in accordance with the requirements of National Instrument 51-102 and the SEC in respect of the Corporation's annual consolidated and interim condensed consolidated financial statements;
r."Member" means a Director appointed to the Committee;
s."NYSE" means the New York Stock Exchange;
t."PCAOB" means the Public Company Accounting Oversight Board or its successor;
u."Related Party Transactions" means those transactions required to be disclosed under Items 404(a) and 404(b) of SEC Regulation S-K and required to be evaluated by an appropriate group within the Corporation pursuant to Section 314.00 of the NYSE Listed Company Manual and all applicable laws and stock exchange requirements which include, without limitation, transactions between: (i) executive officers, directors, principal shareholders or their immediate family members; and (ii) the Corporation or any of its subsidiaries; and
v."SEC" means the United States Securities and Exchange Commission.
3.0 ESTABLISHMENT AND COMPOSITION OF COMMITTEE
3.1 The Committee shall be comprised of three (3) or more Directors, each of whom is Independent and Financially Literate. No Member may be a member of Management or an employee of the Corporation or of any affiliate of the Corporation. The Board shall appoint to the Committee at least one (1) Director who is a Financial Expert.
3.2 Members shall be appointed annually by the Board, or as otherwise necessary, provided, however, that each Director serving as a Member shall continue to serve until such Member resigns, is removed or has a successor appointed.
3.3 The Board may appoint a Member to fill a vacancy which occurs on the Committee between annual elections of Directors. If a vacancy exists on the Committee, the remaining Members shall exercise all of the powers of the Committee so long as at least three (3) Members remain in office.
3.4 Any Member may be removed from the Committee or replaced by a resolution of the Board.
3.5 No Member shall serve on more than three (3) public company audit committees (inclusive of the Corporation) without the prior approval of the Board.
3.6 The Board shall appoint a Chair on the recommendation of the Corporation's Governance and Sustainability Committee, or such other committee as the Board may authorize. The Chair shall continue in that role until a successor is appointed. The Board shall periodically rotate the Chair and shall make reasonable efforts to rotate the Chair every four (4) years.
4.0 COMMITTEE MEETINGS
4.1 The Committee shall meet at least quarterly and at such other times as it deems appropriate. Meetings of the Committee shall be held at the call of: (i) the Chair; (ii) any two Members; or (iii) the Independent Auditor.
4.2 The Chief Executive Officer, the Chief Financial Officer, the Independent Auditor and the Internal Auditor shall receive notice of and, unless otherwise determined by the Chair, shall be entitled to attend all meetings of the Committee. For clarity, the Independent Auditor must attend the Committee meetings at which the Corporation's annual audited consolidated and non-consolidated financial statements and unaudited condensed consolidated interim financial statements are reviewed.
4.3 A quorum at any meeting of the Committee shall be three (3) Members.
4.4 Each Member shall have the right to vote on matters that come before the Committee.
4.5 Matters to be determined by the Committee shall be decided by a majority of votes cast at a meeting of the Committee where such matter is considered. Actions of the Committee may also be taken by instruments in writing signed by all of the Members.
4.6 The Chair shall act as chair of all meetings of the Committee at which the Chair attends, otherwise the Members present at the meeting shall appoint one of their number to act as chair of the meeting.
4.7 Unless otherwise determined by the Chair, the Corporate Secretary of the Corporation shall act as secretary of all meetings of the Committee.
4.8 The Committee shall periodically meet separately with Management, the Internal Auditor and the Independent Auditor to discuss any matters that the Committee or any of these persons or firms believes should be discussed privately. The Committee shall conduct in camera sessions without Management present at each meeting of the Committee.
4.9 The Committee may invite any Directors, officers or employees of the Corporation or any other person to attend the meetings of the Committee to assist in the discussion and examination of the matters under consideration by the Committee.
4.10 Subject to section 5.4, the Committee may delegate authority to individual Members or subcommittees, if deemed appropriate.
5.0 DUTIES AND RESPONSIBILITIES OF THE COMMITTEE
A. Independent Auditor
5.1 In consultation and coordination with the subsidiary audit committees, the Committee shall be directly responsible for the selection and appointment (through a recommendation to the Board for the appointment by the shareholders), compensation and retention of the Independent Auditor.
5.2 The Committee shall oversee the work of the Independent Auditor in connection with the Core Audit Services and any other services performed for the Corporation. The Independent Auditor shall report directly to the Committee and the Committee has the authority to communicate directly with the Independent Auditor.
5.3 The Committee shall oversee the resolution of any disagreements between Management and the Independent Auditor. The Committee shall discuss with the Independent Auditor the matters required to be discussed under PCAOB Auditing Standard No. 1301 relating to the conduct of the audit, including any problems or difficulties encountered and Management's responses thereto and any restrictions on the scope of activities or access to requested information.
5.4 The Committee shall pre-approve all services performed by the Independent Auditor in accordance with the Corporation's Pre-Approval Policy for Independent Auditor Services. For any service, other than Core Audit Services, requiring specific pre-approval in accordance with such policy, the Committee may delegate pre-approval authority to one or more of its Members. Currently, pre-approval authority in this regard has been delegated to the Chair or, in that person's absence, the Chair of the Board who is a Member. Delegates must report all pre-approval decisions to the Committee at the next scheduled meeting.
5.5 The Committee shall annually obtain and review a report from the Independent Auditor delineating all relationships between the Independent Auditor and the Corporation and its subsidiaries in accordance with Item 407(d) of SEC Regulation S-K and Section 303A.07 of the NYSE Listed Company Manual and addressing the matters set forth in PCAOB Rule 3526 and all applicable laws and stock exchange requirements and any other applicable regulations and professional standards. The Committee shall use reasonable efforts, including discussion with the Independent Auditor, to satisfy itself as to the Independent Auditor's independence in accordance with Canadian generally accepted auditing standards and PCAOB standards, the applicable requirements and interpretative guidance of SEC Regulation S-X and any other applicable regulations and professional standards. The Committee shall discuss any potential independence issues with the Board and recommend any action that the Committee deems appropriate.
5.6 The Committee shall review and evaluate the qualifications, independence and performance of the Independent Auditor and its lead engagement partner. Without limiting the foregoing, the Committee shall:
a.review and discuss with Management and separately with the Independent Auditor the results of the Corporation's annual Independent Auditor assessment process; and
b.at least annually, obtain and review a report from the Independent Auditor describing the firm's internal quality control processes and procedures, including any material issues raised by the most recent internal quality control review or peer review, or by any inquiry or investigation by governmental or professional authorities (including without limitation the PCAOB and the CPAB) within the preceding five (5) years with respect to independent audits carried out by the Independent Auditor, and any steps taken to address such issues.
The Committee shall discuss any material issues identified with the Board and recommend any action that the Committee deems appropriate.
5.7 The Committee shall ensure the rotation of the audit partner(s) as required by applicable law and consider the need for rotation of the Independent Auditor.
5.8 The Committee shall meet with the Independent Auditor prior to the audit to discuss the planning and staffing of the audit, including the general approach, scope, areas subject to significant risk of material misstatement, estimated fees and other terms of engagement.
B. Financial Reporting
5.9 In consultation with Management, the Independent Auditor and the Internal Auditor, the Committee shall review and satisfy itself as to: (i) the integrity of the Corporation's internal and external financial reporting processes; (ii) the adequacy and effectiveness of the Corporation's disclosure controls and procedures (including those pertaining to the review of disclosure containing financial information extracted or derived from the Corporation's financial statements) and internal controls over financial reporting; and (iii) the competence of the Corporation's personnel responsible for accounting and financial reporting. Without limiting the generality of the foregoing, the Committee shall receive and review:
a.reports regarding: (i) critical accounting estimates, policies and practices; (ii) goodwill impairment testing; (iii) derivatives and hedges; (iv) any reserves, accruals, provisions and estimates that may have a material effect on the Corporation's financial statements; (v) any pro forma, adjusted or restated financial information, forecasts, or projections; and (vii) the effect of regulatory and accounting initiatives, as well as off-balance sheet arrangements, on the Corporation's financial statements;
b.analyses by Management and the Independent Auditor regarding significant financial reporting issues and judgments made in connection with the preparation of the Corporation's consolidated financial statements including: (i) alternative treatments of financial information within generally accepted accounting principles related to material matters that have been discussed with Management, their ramifications and the treatment preferred by the Independent Auditor; (ii) major issues regarding auditing and accounting principles and presentations, including significant changes in the selection or application of auditing and accounting principles; and (iii) major issues regarding the adequacy of the Corporation's internal controls over financial reporting and disclosure controls and procedures and any specific audit steps adopted in light of material weaknesses or significant deficiencies in such controls; and
c.other material written communication between Management and the Independent Auditor.
5.10 The Committee shall, prior to external release, if applicable, review and discuss with Management and the Independent Auditor, and with others as it deems appropriate:
a.the Corporation's annual audited consolidated and non-consolidated financial statements and unaudited condensed consolidated interim financial statements and the Independent Auditor's related attestation reports, as well as any related MD&As;
b.Management's report and the Independent Auditor's audit report on internal controls over financial reporting;
c.significant reports or summaries thereof pertaining to the Corporation's processes for compliance with the requirements of the Sarbanes Oxley Act of 2002 with respect to internal controls over financial reporting;
d. the Independent Auditor's quarterly review reports and annual audit results report summarizing the scope, status, results and recommendations of the quarterly reviews of the Corporation's condensed consolidated interim financial statements and of the audit of the Corporation's annual consolidated financial statements and related audit of internal controls over financial reporting, and also containing at least: (i) the communications with respect thereto between the Independent Auditor and the Committee required by PCAOB Auditing Standard No. 1301 and any other applicable regulations and professional standards, including without limitation schedules of corrected and uncorrected account and disclosure misstatements and significant deficiencies and material weaknesses in internal controls; (ii) the (at least) annual independence communication required by PCAOB Rule 3526; (iii) the Management representation letter; and (iv) the documentation and communication required quarterly from the Independent Auditor under the Corporation's Pre-Approval Policy for Independent Auditor Services;
e. the report to shareholders contained in the Corporation's annual report; and
f. any other document that the Committee determines should be reviewed and discussed with Management and the Independent Auditor or for which a legal or regulatory requirement in that regard exists.
5.11 The Committee shall, prior to external release, review and discuss with Management and with others as it deems appropriate, the financial information to be disclosed in the Corporation's interim and annual earnings releases or other news releases.
5.12 The Committee shall recommend the Corporation's annual audited consolidated financial statements together with the Independent Auditor's audit report thereon and on internal controls over financial reporting, Management's report on internal controls over financial reporting and disclosure controls and procedures, MD&As, earnings releases, and reports to shareholders for approval by the Board and subsequent external release, as well as inclusion of the noted financial statements in the Corporation's annual reports on Form 40-F. The Committee shall approve the external release of the Corporation's unaudited condensed consolidated interim financial statements and related interim MD&As and earnings releases on behalf of the Board.
5.13 The Committee shall, prior to external release, review and discuss with Management and with others as it deems appropriate, and recommend for approval by the Board:
a.any future oriented financial information, financial outlooks, and earnings or dividend guidance to be provided by the Corporation;
b.the Annual Information Form and Management Information Circular to be filed by the Corporation;
c.any prospectus or other offering documents and documents related thereto for the issuance of securities by the Corporation; and
d.other disclosure documents to be released publicly by the Corporation containing or derived from financial information.
5.14 The Committee shall review, discuss with Management and with others as it deems appropriate, the disclosures made by the Chief Executive Officer and Chief Financial Officer of the Corporation pursuant to their certification of the Corporation's annual and quarterly reports regarding significant deficiencies or material weaknesses in the design or operation of internal controls over financial reporting and any alleged fraud involving Management or other employees.
5.15 The Committee shall use reasonable efforts to satisfy itself as to the appropriateness of the Corporation's material financing, capital and tax structures.
5.16 The Committee shall review, discuss with Management and with others as it deems appropriate, financial information provided to analysts and ratings agencies. Such discussions may be in general terms (i.e. discussion of the types of information to be disclosed and the types of presentations to be made) and need not occur in advance of each release of information.
5.17 The Committee shall prepare, or cause to be prepared, any reports of the Committee required to be included in the Corporation's public disclosures or otherwise required by applicable laws.
5.18 The Committee shall review, discuss with Management and with others as it deems appropriate, and approve all Related Party Transactions and the disclosure thereof.
C. Internal Audit
5.19 The Committee shall be responsible for the appointment and oversight of the Internal Auditor in accordance with the Policy on the Role of the Internal Audit Function and has the authority to communicate directly with the Internal Auditor.
5.20 The Committee shall review and discuss with the Internal Auditor and others as it deems appropriate, and approve the annual internal audit plan.
5.21 The Committee shall review and discuss with Management, the Internal Auditor and others as it deems appropriate, the quarterly internal audit reports prepared for the Committee (which shall incorporate all significant activities of the internal audit function for the quarter) and any Management responses thereto.
5.22 The Committee shall periodically discuss with the Internal Auditor any significant difficulties, disagreements with Management, or scope restrictions encountered in the course of carrying out the work of the internal audit function.
5.23 The Committee shall periodically discuss with the Internal Auditor the internal audit function's responsibility, budget, staffing and compensation.
5.24 The Committee shall satisfy itself as to the performance of the internal audit function and the integrity and qualifications of its staff.
D. Risk Management and Other
5.25 The Committee shall be responsible for the oversight of the ERM Program and shall report any actions or findings of the ERM Program to the Board.
5.26 The Committee shall review and discuss with Management, the Internal Auditor and others as it deems appropriate Management's report regarding identifying, assessing, managing and mitigating significant risks and related matters identified pursuant to the ERM Program.
5.27 The Committee shall satisfy itself as to the appropriateness of the Corporation's internal controls and processes associated with the release of any sustainability disclosures.
5.28 The Committee shall review and discuss with Management and others as it deems appropriate the quarterly report prepared by Management regarding significant litigation and other material legal matters that could have a significant impact on the Corporation or its financial statements.
5.29 The Committee shall be responsible for the oversight of the Corporation's insurance programs, any renewals or replacements thereof, including in respect of directors' and officers' insurance and indemnification of Directors.
E. Policies and Mandate
5.30 The Committee is responsible for the oversight of the following policies:
a.Policy on Reporting Allegations of Suspected Improper Conduct and Wrongdoing (Speak Up Policy), including overseeing procedures for the receipt, retention, and treatment of complaints regarding accounting, internal controls, or auditing matters as well as procedures for confidential, anonymous submissions by employees regarding questionable accounting or auditing matters as required by applicable law;
b.Derivative Instruments and Hedging Policy;
c.Pre-Approval Policy for Independent Auditor Services;
d.Guidelines for Hiring Employees or Former Employees of the Independent Auditor;
e.Policy on the Role of the Internal Audit Function;
f.Disclosure Policy; and
g.other policies that may be established from time-to-time regarding accounting, financial reporting, disclosure controls and procedures, internal controls over financial reporting, oversight of the external audit of the Corporation's financial statements, and oversight of the internal audit function.
5.31 The Committee shall periodically review this Mandate and the policies in Section 5.30 and recommend any necessary amendments to the Governance and Sustainability Committee for consideration and recommendation to the Board for approval, as deemed appropriate.
6.0 REPORTING
6.1 The Chair, or another designated Member, shall report to the Board at each regular meeting on those matters that were dealt with by the Committee since the last regular meeting of the Board.
7.0 REMUNERATION OF MEMBERS
7.1 Members and the Chair shall receive such remuneration for their service on the Committee as the Board may determine from time to time, having considered the recommendation of the Governance and Sustainability Committee.
8.0 GENERAL
8.1 This Mandate shall be posted on the Corporation's corporate website at www.fortisinc.com.
8.2 The Committee shall annually review its own effectiveness and performance.
8.3 The Committee shall perform any other activities consistent with this Mandate, the Corporation's by-laws and applicable laws, that the Board or Committee determines are necessary or appropriate.
8.4 The Committee may, in its discretion and in circumstances that it considers appropriate, obtain advice and assistance from outside legal, accounting and other advisors and approve the engagement by the Committee or any Member of outside advisors or persons having special expertise, all at the expense of the Corporation. The Corporation shall provide appropriate compensation, as determined by the Committee, for the Independent Auditor, to any independent counsel or other advisors that the Committee chooses to engage, and for payment of ordinary administrative expenses of the Committee that are necessary and appropriate in carrying out its duties and responsibilities.
8.5 The Committee is not responsible for certifying the accuracy or completeness of the Corporation's financial statements or their presentation in accordance with generally accepted accounting principles, or for guaranteeing the accuracy of the attestation reports of the Independent Auditor. The fundamental responsibility for the Corporation's financial statements and reporting, internal controls over financial reporting and disclosure controls and processes rests with Management and, in accordance with its professional responsibilities, the Independent Auditor. Nothing in this Mandate is intended to modify or augment the obligations of the Corporation or the fiduciary duties of the members of the Committee or the Board under applicable laws.
EXHIBIT D:
MATERIAL CONTRACTS
The following are the material contracts of Fortis filed on SEDAR+ and EDGAR during 2023 or which were entered into prior to 2023 and are still in effect. Requests for additional copies of these material contracts should be directed to the Corporate Secretary, Fortis, P.O. Box 8837, St. John's, NL, A1B 3T2 (telephone: 709.737.2800). All such contracts are also available under the Corporation's profile at www.sedarplus.ca and www.sec.gov.
Revolving Credit Facility
Fortis is a party to a Fourth Amended and Restated Credit Facility dated May 4, 2022, with The Bank of Nova Scotia as underwriter, sole lead arranger, book runner, sustainability structuring agent and administrative agent and Canadian Imperial Bank of Commerce and Royal Bank of Canada as co-syndication agents, and the lenders party thereto from time to time, as amended by the First Amending Agreement dated May 4, 2023 between Fortis, The Bank of Nova Scotia and the lenders named therein. The Fourth Amended and Restated Credit Facility is a $1.3 billion unsecured committed revolving credit facility and contains the terms and conditions upon which such credit is available to Fortis during the duration of the facility. The Fourth Amended and Restated Credit Facility contains customary representations and warranties, affirmative and negative covenants and events of default. Customary fees are payable by Fortis in respect of the facility and amounts outstanding under the facility bear interest at market rates.
Amended and Restated Shareholders' Agreement
On January 28, 2021, ITC Investment Holdings, ITC Holdings, FortisUS and Eiffel Investment, an affiliate of GIC, entered into an Amended and Restated Shareholders' Agreement, amending the shareholders' agreement among the parties originally entered into on October 14, 2016. The Amended and Restated Shareholders' Agreement governs the rights of the parties in their respective capacities as direct or indirect shareholders of ITC Holdings.
Under the terms of the Amended and Restated Shareholders' Agreement, Eiffel Investment has certain minority approval rights relating to ITC Investment Holdings and ITC Holdings which depend on: (x) whether Eiffel Investment is a holder of Class A common stock or Class B non-voting common stock at the relevant time and (y) the satisfaction by Eiffel Investment of certain ownership thresholds with respect to ITC Investment Holdings. The minority approval rights available to Eiffel Investment contingent on its ITC Investment Holdings share class and percentage ownership include rights with respect to: (i) amendments to charter documents; (ii) changes in board size; (iii) issuances of equity; (iv) business combinations that would impact Eiffel Investment differently than other shareholders; (v) insolvency; (vi) certain acquisitions of, investments in, or joint ventures relating to non-core assets, or certain material sales or dispositions of core assets; (vii) in limited circumstances, the incurrence of indebtedness by ITC Investment Holdings, ITC Holdings or its subsidiaries or the taking of certain actions that would reasonably be expected to result in the long-term unsecured indebtedness of ITC Investment Holdings, ITC Holdings and its subsidiaries being rated below investment grade; (viii) actions that would cause a ratio of ITC Holding's cash flow to debt to exceed an agreed targeted threshold; (ix) limitations on corporate overhead costs paid by ITC Holdings to Fortis; and (x) expansion of the core business outside ITC Holdings' current regulatory jurisdictions. The Amended and Restated Shareholders' Agreement also provides for a dividend policy, which can be amended only with the approval of all the independent directors of ITC Investment Holdings.
Indenture and First Supplemental Indenture
On October 4, 2016, Fortis entered into an Indenture and a First Supplement thereto with The Bank of New York Mellon, as U.S. trustee, and BNY Trust Company of Canada, as Canadian co-trustee. The Indenture and the First Supplement set forth the terms of the Corporation's currently outstanding US$1.1 billion aggregate principal amount of 3.055% Unsecured Notes due 2026. The Indenture contains customary covenants, events of default and rights for the benefit of security holders and the trustees. An unlimited amount of debt securities may be issued under the Indenture, which is governed by the laws of the State of New York.
Exhibit 99.3
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| Management Discussion and Analysis |
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| | | | |
| Contents |
| About Fortis | 1 | | Cash Flow Requirements | 17 |
| Key Developments | 2 | | Cash Flow Summary | 18 |
| Performance at a Glance | 2 | | Contractual Obligations | 20 |
| The Industry | 5 | | Capital Structure and Credit Ratings | 21 |
| Focus on Sustainability | 6 | | Capital Plan | 21 |
| Operating Results | 9 | | Business Risks | 25 |
| Business Unit Performance | 10 | | Accounting Matters | 32 |
| ITC | 10 | | Financial Instruments | 35 |
| UNS Energy | 10 | | Long-Term Debt and Other | 35 |
| Central Hudson | 11 | | Derivatives | 35 |
| FortisBC Energy | 11 | | Selected Annual Financial Information | 38 |
| FortisAlberta | 12 | | Fourth Quarter Results | 39 |
| FortisBC Electric | 12 | | Summary of Quarterly Results | 40 |
| Other Electric | 12 | | Related-Party and Inter-Company Transactions | 41 |
| Corporate and Other | 13 | | Management's Evaluation of Controls and Procedures | 41 |
| Non-U.S. GAAP Financial Measures | 13 | | Outlook | 42 |
| Regulatory Highlights | 14 | | Forward-Looking Information | 42 |
| Financial Position | 16 | | Glossary | 44 |
| Liquidity and Capital Resources | 17 | | Annual Consolidated Financial Statements | F-1 |
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Dated February 8, 2024
This MD&A has been prepared in accordance with National Instrument 51-102 - Continuous Disclosure Obligations. It should be read in conjunction with the 2023 Annual Financial Statements and is subject to the cautionary statement and disclaimer provided under "Forward-Looking Information" on page 42. Further information about Fortis, including its Annual Information Form filed on SEDAR+, can be accessed at www.fortisinc.com, www.sedarplus.ca, or www.sec.gov.
Financial information herein has been prepared in accordance with U.S. GAAP (except for indicated Non-U.S. GAAP Financial Measures) and, unless otherwise specified, is presented in Canadian dollars based, as applicable, on the following U.S. dollar-to-Canadian dollar exchange rates: (i) average of 1.35 and 1.30 for the years ended December 31, 2023 and 2022, respectively; (ii) 1.32 and 1.36 as at December 31, 2023 and 2022, respectively; (iii) average of 1.36 for the quarters ended December 31, 2023 and 2022; and (iv) 1.30 for all forecast periods. Certain terms used in this MD&A are defined in the "Glossary" on page 44.
ABOUT FORTIS
Fortis (TSX/NYSE: FTS) is a well-diversified leader in the North American regulated electric and gas utility industry, with revenue of $12 billion in 2023 and total assets of $66 billion as at December 31, 2023.
Regulated utilities account for 99% of the Corporation's assets. The Corporation's 9,600 employees serve 3.5 million utility customers in five Canadian provinces, ten U.S. states and three Caribbean countries. As at December 31, 2023, 64% of the Corporation's assets were located in the U.S., 33% in Canada and the remaining 3% in the Caribbean. Operations in the U.S. accounted for 56% of the Corporation's 2023 revenue, with the remaining 39% in Canada, and 5% in the Caribbean.
Fortis is principally an energy delivery company, with 93% of its assets related to transmission and distribution. The business is characterized by low-risk, stable and predictable earnings and cash flows. Earnings, EPS and TSR are the primary measures of financial performance.
Fortis' regulated utility businesses are: ITC (electric transmission - Michigan, Iowa, Minnesota, Illinois, Missouri, Kansas, Oklahoma and Wisconsin); UNS Energy (integrated electric and natural gas distribution - Arizona); Central Hudson (electric transmission and distribution, and natural gas
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1 | FORTIS INC. | DECEMBER 31, 2023 |
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| Management Discussion and Analysis |
distribution - New York State); FortisBC Energy (natural gas transmission and distribution - British Columbia); FortisAlberta (electric distribution - Alberta); FortisBC Electric (integrated electric - British Columbia); Newfoundland Power (integrated electric - Newfoundland and Labrador); Maritime Electric (integrated electric - Prince Edward Island); FortisOntario (integrated electric - Ontario); Caribbean Utilities (integrated electric - Grand Cayman); and FortisTCI (integrated electric - Turks and Caicos Islands). Fortis also holds equity investments in the Wataynikaneyap Partnership (electric transmission - Ontario) and Belize Electricity (integrated electric - Belize).
The Corporation's non-regulated business is limited to Fortis Belize (three hydroelectric generation facilities - Belize). The Aitken Creek natural gas storage facility in British Columbia was sold on November 1, 2023 with a March 31, 2023 effective date (see "Key Developments" below). With the disposition of Aitken Creek, the Corporation's non-regulated business is now reported in the Corporate and Other segment.
Fortis has a unique operating model with a small corporate office in St. John's, Newfoundland and Labrador and business units that operate on a substantially autonomous basis. Each utility has its own management team and board of directors, with most having a majority of independent board members, which provides effective oversight within the broad parameters of Fortis policies and best practices. Subsidiary autonomy supports constructive relationships with regulators, policy makers, customers and communities. Fortis believes this model enhances accountability, opportunity and performance across the Corporation's businesses, and positions Fortis well for future investment opportunities.
Fortis is focused on providing safe, reliable and cost-effective energy service to customers. Delivering a cleaner energy future is the Corporation's core purpose. In addition, management is focused on delivering long-term profitable growth for shareholders through the execution of its Capital Plan and the pursuit of investment opportunities within and proximate to its service territories.
Additional information about the Corporation's business and reporting units is provided in Note 1 in the 2023 Annual Financial Statements.
KEY DEVELOPMENTS
Regulatory Updates
See "Regulatory Highlights - Significant Regulatory Matters" on page 14.
Sale of Aitken Creek
On November 1, 2023, FortisBC Holdings Inc. completed the sale of its Aitken Creek business to a subsidiary of Enbridge Inc. for approximately $470 million including working capital and closing adjustments, following the satisfaction of all regulatory requirements. The transaction reflected a March 31, 2023 effective date. Net proceeds from the transaction further strengthened the Corporation's balance sheet and provided additional funding flexibility in support of our regulated utility growth strategy.
In accordance with U.S. GAAP, Common Equity Earnings includes the results for Aitken Creek until the November 1, 2023 date of disposition. Management has excluded Aitken Creek's earnings recognized from the March 31st effective date through to the November 1st disposition date, as well as the gain recorded on the sale, in arriving at Adjusted Common Equity Earnings and Adjusted Basic EPS (see "Non-U.S. GAAP Financial Measures" on page 13).
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| PERFORMANCE AT A GLANCE | | | | | |
| Key Financial Metrics | | | | | |
| ($ millions, except as indicated) | 2023 | | | 2022 | | | Variance |
| Common Equity Earnings | | | | | |
| Actual | 1,506 | | | 1,330 | | | 176 | |
Adjusted (1) | 1,502 | | | 1,329 | | | 173 | |
Basic EPS ($) | | | | | |
| Actual | 3.10 | | | 2.78 | | | 0.32 | |
Adjusted (1) | 3.09 | | | 2.78 | | | 0.31 | |
Dividends | | | | | |
Paid per common share ($) | 2.29 | | | 2.17 | | | 0.12 | |
Actual Payout Ratio (%) | 73.7 | | | 78.1 | | | (4.4) | |
Adjusted Payout Ratio (%) (1) | 73.9 | | | 78.1 | | | (4.2) | |
Weighted average number of common shares outstanding (# millions) | 486.3 | | | 478.6 | | | 7.7 | |
Operating Cash Flow | 3,545 | | | 3,074 | | | 471 | |
Capital Expenditures (1) | 4,329 | | | 4,034 | | | 295 | |
(1)See "Non-U.S. GAAP Financial Measures" on page 13
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2 | FORTIS INC. | DECEMBER 31, 2023 |
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| Management Discussion and Analysis |
Earnings and EPS
Common Equity Earnings increased by $176 million in comparison to 2022. The increase was primarily driven by Rate Base growth across our utilities and the new cost of capital parameters approved for FortisBC effective January 1, 2023. Higher earnings in Arizona also contributed to earnings growth, reflecting higher retail electricity sales, new customer rates at TEP effective September 1, 2023, and lower depreciation expense associated with retirement of the San Juan generating station in 2022. An increase in the market value of certain investments that support retirement benefits, and the higher U.S.-to-Canadian dollar exchange rate, also favourably impacted earnings year over year. The increase was partially offset by higher corporate finance costs and lower earnings from Aitken Creek.
In addition to the above-noted items impacting earnings, the change in EPS also reflected an increase in the weighted average number of common shares outstanding, largely associated with the Corporation's DRIP.
Adjusted Common Equity Earnings and Adjusted Basic EPS increased by $173 million and $0.31, respectively. Refer to "Non-U.S. GAAP Financial Measures" on page 13 for a reconciliation of these measures. The changes in Adjusted Basic EPS are illustrated in the chart below.
(1) Includes FortisBC Energy, FortisAlberta and FortisBC Electric. Primarily reflects the impact of the new cost of capital parameters approved for FortisBC effective January 1, 2023 and Rate Base growth
(2) Includes UNS Energy and Central Hudson. Reflects higher earnings at UNS Energy due to: (i) new customer rates at TEP effective September 1, 2023; (ii) higher retail electricity sales, including the impact of warmer weather and customer additions; (iii) lower depreciation expense associated with the retirement of the San Juan generating station in 2022; and (iv) an increase in the market value of investments that support retirement benefits, partially offset by higher operating costs due to inflationary increases and higher income tax expense. Earnings at Central Hudson were consistent with 2022.
(3) Reflects Rate Base growth and an increase in the market value of investments that support retirement benefits, partially offset by higher non-recoverable finance and stock-based compensation costs
(4) Primarily reflects Rate Base growth and higher electricity sales, as well as equity income from Wataynikaneyap Power
(5) Average foreign exchange rate of 1.35 in 2023 compared to 1.30 in 2022
(6) Reflects higher holding company finance costs, lower hydroelectric production in Belize, and lower earnings from Aitken Creek due to the March 31, 2023 effective date of disposition
(7) Weighted average shares of 486.3 million in 2023 compared to 478.6 million in 2022
Dividends
Fortis paid a dividend of $0.59 per common share in the fourth quarter of 2023, up 4.4% from $0.565 paid in each of the previous four quarters. This marked the Corporation's 50th consecutive year of increases in dividends paid. The Actual Payout Ratio was 74% in 2023 and an average of 71% over the five-year period of 2019 through 2023.
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3 | FORTIS INC. | DECEMBER 31, 2023 |
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| Management Discussion and Analysis |
Fortis is targeting annual dividend growth of approximately 4-6% through 2028. See "Outlook" on page 42.
Growth in dividends and changes in the market price of the Corporation's common shares have yielded the following TSRs.
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TSR (1) (%) | 1-Year | | 5-Year | | 10-Year | | 20-Year |
| Fortis | 4.8 | | | 7.6 | | | 10.1 | | | 10.7 | |
(1)Annualized TSR per Bloomberg, as at December 31, 2023
Operating Cash Flow
The $471 million increase in Operating Cash Flow was due to: (i) higher cash earnings, reflecting Rate Base growth as well as higher retail electricity sales and new customer rates at TEP; (ii) the timing of flow-through costs in customer rates, reflecting fluctuations in commodity costs, as well as transmission-related amounts in Alberta; and (iii) the higher U.S.-to-Canadian dollar exchange rate. The increase in Operating Cash Flow was partially offset by higher development expenditures, net of deposits received, associated with the Eagle Mountain Woodfibre Gas Line project, as well as proceeds received in 2022 at ITC related to the settlement of interest rate swaps. Higher interest and income tax payments also tempered the increase in Operating Cash Flow for the year.
Capital Expenditures
Capital Expenditures in 2023 were $4.3 billion, consistent with the annual Capital Plan. For a detailed discussion of the Corporation's Capital Expenditure program, see "Capital Plan" on page 21. Capital Expenditures in 2023 were $0.3 billion higher than in 2022, primarily due to construction of the Roadrunner Reserve battery energy storage project in Arizona and investments in various smaller distribution projects across the Corporation's regulated utilities, as well as the impact of the higher average foreign exchange rate.
The Corporation's 2024-2028 Capital Plan of $25 billion is the largest in the Corporation’s history and is $2.7 billion higher than the previous five-year plan. The increase is driven by organic growth, largely reflecting regional transmission projects at ITC associated with tranche one of the MISO LRTP, as well as investments in Arizona to support TEP’s exit from coal. Investments supporting system adaptation and resiliency, customer growth and economic development are also driving capital growth across the Corporation's regulated utilities.
Funding of the Capital Plan is expected to be primarily through Operating Cash Flow, debt issued at the regulated utilities and common equity proceeds expected to be sourced from the Corporation's DRIP and ATM Program.
The five-year Capital Plan is expected to increase midyear Rate Base from $37.0 billion in 2023 to $49.4 billion by 2028, translating into a five-year CAGR of 6.3%.
Capital Expenditures and Capital Plan reflect Non-U.S. GAAP financial measures. Refer to "Non-U.S. GAAP Financial Measures" on page 13 and "Capital Plan" on page 21.
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4 | FORTIS INC. | DECEMBER 31, 2023 |
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| Management Discussion and Analysis |
Beyond the five-year Capital Plan, additional opportunities to expand and extend growth include: further expansion of the electric transmission grid in the U.S. to facilitate the interconnection of cleaner energy, including infrastructure investments associated with the IRA and the MISO LRTP; climate adaptation and grid resiliency investments; RNG solutions and LNG infrastructure in British Columbia; and the acceleration of cleaner energy infrastructure investments across our jurisdictions.
THE INDUSTRY
The North American energy transformation is accelerating rapidly, driven by the impacts of climate change and the growing need for the development of cleaner energy sources and the deployment of energy conservation measures. The goal of carbon emissions reduction, including associated advancements in technology, has attracted interest from investors and customers. Electric transmission is seen as a critical enabler of large-scale renewable generation. Natural gas continues to be an important part of the energy mix, providing resiliency, a supplemental source of generation to support the intermittent nature of renewables, and a cost-effective heating source. Longer term, advancements in the use of hydrogen and RNG will further contribute to carbon reduction. These factors are driving significant investment opportunities in the utility sector.
Meaningful customer engagement is important for utilities as customer expectations change. Customers want to make informed energy choices and become active participants in the delivery of their energy. They also expect personalized service, customized self-service offerings, and more real-time, digital communication. Fortis' utilities are enhancing customer information systems and digital technologies to improve customer service.
Energy policies at the federal, state, and provincial levels reflect the rising focus on climate change, with clean energy and carbon reduction at the forefront. In the U.S., the IRA has been passed into law and includes, among other items, incentives and tax credits to encourage investment in clean energy, energy storage, electric vehicles and manufacturing, all to support a targeted 40% reduction in carbon emissions by 2030. With states and provinces also setting ambitious carbon reduction targets, the regulatory and compliance environment continues to evolve. These changes are creating opportunities to expand investment in new, renewable generation sources, as well as transmission infrastructure to connect renewable energy sources to the grid. Investment opportunities in energy storage technology are also being created. Electrification of the transportation sector continues to grow rapidly and represents a significant opportunity to reduce carbon emissions while increasing the output and efficiency of the grid. The Corporation's utilities are well positioned and actively involved in pursuing these opportunities, which will drive significant investment.
New technology is stimulating change across all of the Corporation's service territories. Energy delivery systems are becoming more intelligent, with advanced meters, additional remote sensing and grid automation, and more capable operational technology providing utilities with detailed usage data and predictive maintenance information to improve cost efficiency and safety. Energy management capabilities are expanding through emerging storage and demand response systems, and customers have increasing options to access distributed generation and to manage their energy usage. Grid resilience is growing in importance with the increasing frequency and intensity of weather events such as hurricanes, wildfires, floods and storms. With electricity expected to represent a larger portion of society's energy mix, investments in grid hardening and resiliency are necessary to improve the grid’s ability to withstand and recover from these climate events.
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5 | FORTIS INC. | DECEMBER 31, 2023 |
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| Management Discussion and Analysis |
Fortis' culture of innovation underlies a continuous drive to find better ways to safely, reliably and affordably deliver the energy and services that customers need, and the choice and control they increasingly seek. Fortis is a partner in Energy Impact Partners, a strategic private venture fund that invests in emerging technologies, products, services and business models that are transforming the industry. The Corporation is also involved in the Low Carbon Resources Initiative, a collaboration between EPRI and GTI Energy, along with other major utilities, to develop and demonstrate the low- and zero-carbon energy technologies needed to enable pathways to decarbonization. Fortis has also joined EPRI’s Climate READi, an initiative involving major North American utilities, regulators, policy makers, and other stakeholders focused on developing an industry-wide best practice framework for managing physical climate risk.
On the security front, with the advent of new and increasing cyber threats to our information and operations technology systems, increased focus and investment on protection and response to these cyber threats is an ongoing priority. Upgrades to the physical security environment are also required to keep pace with evolving challenges. All these technological advancements and challenges offer strategic investment opportunities for improving and expanding customer service and enhancing security.
The Corporation's culture and decentralized structure support the efforts required to meet changing customer expectations. Each of our utilities work constructively with regulators and all stakeholders on policy, energy and service solutions, and are an integral partner in all the communities they serve. Fortis is committed to be an industry leader in the clean energy transition.
FOCUS ON SUSTAINABILITY
Fortis is dedicated to operating in an environmentally and socially responsible manner in the interests of all of its stakeholders. Oversight and accountability for sustainability are established at the most senior levels of the Corporation and its operating subsidiaries. At Fortis, the Board has overall responsibility for sustainability. However, primary oversight of the issues, policies and practices pertaining to sustainability has been delegated to the governance and sustainability committee of the Board, reflecting sustainability’s important role in the Corporation’s strategy and risk management.
Key aspects of Fortis' sustainability program and practices are outlined below.
Climate Change and Environmental Matters
Fortis is primarily an energy delivery company with 93% of its assets related to transmission and distribution. The focus for Fortis is the delivery of cleaner energy to its customers and this limits the impact of the Corporation’s utilities on the environment when compared to more generation-intensive businesses. Fortis has a relatively small amount of fossil-fuel generation in its portfolio and plans to transition to more renewable sources of energy for its customers.
The Corporation's direct GHG emissions come primarily from its generation assets, which largely consist of fossil fuel-based generation at TEP, representing 4% of the Corporation's total assets. Fortis continues to lower its already low emissions profile, and has set a 2050 net-zero direct GHG emissions target. This goal is in addition to the Corporation’s interim targets to reduce direct GHG emissions 50% by 2030 and 75% by 2035 from a 2019 base year. Fortis expects to achieve both interim targets primarily through TEP's plan to exit from coal, as well as clean energy initiatives across the Corporation's other utilities.
Fortis has made significant progress on its emissions reduction targets. Through 2023, the Corporation’s Scope 1 emissions were 33% lower compared to 2019 levels. The retirement of certain coal generating stations, the commencement of seasonal operations at other generating stations, and the introduction of renewable wind and solar energy in Arizona, have supported our carbon emissions reduction to date.
Beyond 2035, most of the Corporation's Scope 1 emissions are expected to relate to natural gas generation at TEP. To reach net-zero by 2050, TEP will focus on developing and adopting new technologies, improving the efficiency of natural gas units, utilizing lower-carbon fuels and preparing its generating units for future hydrogen injection. Reliability and affordability will remain key priorities as Fortis works to meet its emissions reduction targets.
The Corporation expects to issue its second Climate Report in 2024. This report will provide further information on Fortis' strategy and actions to address climate change, physical and transition risks, and business opportunities including investments in resilient and adaptable infrastructure.
In the development of the Corporation's five-year Capital Plan, each of the utilities considered the investment required to deliver cleaner energy to customers, strengthen infrastructure, and improve network resiliency to deal with the expected impacts of climate change on utility infrastructure. Fortis' 2024-2028 Capital Plan includes Cleaner Energy Investments of approximately $7 billion, with investments focused on connecting renewables to the grid, renewable energy and energy storage, and cleaner natural gas solutions. Additional information can be found in the "Capital Plan" section on page 21. In support of the Capital Plan, Fortis' unsecured $1.3 billion revolving term committed credit facility agreement incorporates a sustainability-linked loan structure based on the Corporation's achievement of targets related to diversity on the Board and reduction of Scope 1 GHG emissions through 2025.
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6 | FORTIS INC. | DECEMBER 31, 2023 |
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| Management Discussion and Analysis |
The Corporation's environmental statement sets out its commitment to comply with all applicable laws and regulations relating to the protection of the environment, regularly conduct monitoring and audits of environmental management systems, seek feasible, cost-effective opportunities to decrease GHG emissions and increase renewable energy sources. Each operating subsidiary has extensive environmental compliance programs aligned with the ISO 14001 standard, regularly reviews its environmental management systems and protocols, strives for continual performance improvement and sets and reviews its own environmental objectives, targets and programs.
Safety and Reliability
Fortis is an industry leader in safety and reliability, with the Corporation consistently performing above industry averages. Fortis leverages its unique operating model and utility experience to deliver safe and reliable service to its customers and the communities it serves. Senior operational executives from all Fortis utilities meet regularly to share best practices and identify opportunities for collaboration on a range of operational areas including health and safety.
All contractors are required to share our commitment to conduct work in a safe manner. Contractors must demonstrate a strong safety program with a high level of training centered around risk management. Historical safety performance is a consideration when selecting successful contractors.
Engaging with Stakeholders and Communities
Fortis' utilities work closely with their customers and communities to improve the overall customer service experience. Customer satisfaction targets are established and customer service surveys are completed regularly focusing on customer satisfaction, reliability and accuracy of billing and metering, contact center services and reliability of energy supply.
Customer affordability is a priority for Fortis. Historically, Fortis utilities have managed annual increases in controllable operating costs per customer to below inflation. As we transition to a cleaner energy future, Fortis utilities continue to focus on controlling costs, identifying efficiencies and implementing innovative practices to maintain affordability. In addition, Fortis' utilities work to ensure customers are aware of available bill payment options, external government payment assistance programs, as well as energy efficiency programs and rebates.
Fortis and its utilities work with a number of Indigenous groups, with the goal of developing long-term partnerships and creating economic opportunities. The Wataynikaneyap Power Transmission project is connecting 17 First Nations communities to the Ontario power grid for the first time. These communities have had inefficient and unreliable access to electricity based on diesel generation, compromising their economic and social well-being and limiting opportunities for growth. The project is majority-owned by 24 First Nations, while Fortis has a 39% ownership interest and acts as project manager. Additional information can be found in the "Capital Plan" section on page 21.
In October 2023, FortisBC was awarded silver-level designation in Progressive Aboriginal RelationsTM from the Canadian Council of Aboriginal Business. The Progressive Aboriginal Relations certification program is an internationally recognized, Indigenous-led program that confirms corporate performance in Indigenous relations at the bronze, silver or gold level. Earning a Progressive Aboriginal Relations designation marks a significant achievement in FortisBC's long-standing commitment to fostering strong, respectful and mutually beneficial relationships with Indigenous communities.
Regular community engagement includes donations to local charities, partnerships with educational institutions, and participation on local boards, which enables Fortis and its utilities to serve as meaningful contributors to their local communities. In 2023, the Fortis group of companies contributed $11 million to the communities they serve.
Cybersecurity
Fortis' CRMP aims to continually improve information sharing and the culture of security. Fortis has an enterprise-wide CRMP that allows for the identification, measurement, monitoring and management of cybersecurity risks. Further, the Corporation and each of the utilities continually consider investments required in security, in both the corporate and grid environments, during the development of the five-year Capital Plan. Physical and cyber security leaders share best practices in areas such as threat monitoring, protecting customer information and risk management. The group also conducts training exercises to test systems and identify opportunities to improve. Oversight of cybersecurity is the responsibility of Fortis' Vice President, Chief Information Officer as well as the respective boards and executive committees at Fortis and at each utility. The Corporation has not had any material cybersecurity breaches since we began reporting this performance indicator in 2018.
People
Fortis values its 9,600 employees and recognizes that success is dependent on a strong workforce which is safe, supported and empowered. Fortis and its utilities have compensation and benefit programs designed to attract and retain talent. Fortis believes that the foundation for a healthy work environment starts with leadership from the most senior levels of the organization and must be driven by clearly articulated values that are understood and practiced at all levels of the organization.
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7 | FORTIS INC. | DECEMBER 31, 2023 |
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| Management Discussion and Analysis |
Fortis has a longstanding corporate-wide talent management strategy that enhances our ability to identify, mentor and develop current executives and employees for more senior positions. The Corporation seeks to continually enhance its talent management strategy. The second cohort of our leadership training program for high-potential employees across the organization was completed in 2023, providing attendees substantive training, mentoring opportunities and exposure to senior management. This program supports talent development and ensures there is a pipeline of qualified talent, preparing the Corporation and its utilities for an orderly succession of critical roles.
Our utilities strive to maintain good employee and labour relations and regular communications and collaboration between union and management leaders. Approximately 50% of the employees across our group of companies are represented by a labour union.
Advancing DEI remains a priority at Fortis. The Corporation has adopted an Inclusion and Diversity Commitment that applies to all employees of Fortis and its operating subsidiaries. The commitment is supported by a framework built upon three pillars - talent, culture and community. A DEI Advisory Council with diverse, senior level representation from across the Fortis organization guides the inclusion and diversity strategy and its implementation.
We are committed to building a diverse, equitable and inclusive workplace. Engagement is key to fostering inclusion and sustainable high performance. In 2023, we partnered with an independent research-based consulting company to conduct a confidential employee engagement survey that provided an enterprise-wide baseline inclusion index.
The Corporation's Board and Executive Diversity Policy describes the principles and objectives for diversity among the Board and executive leadership, including a commitment to maintain a Board where women and men each represent at least 40% of independent directors. As of December 31, 2023, 58% of Board members were women, 50% of Fortis' executives were women and 82% of Fortis utilities had either a female president or female board chair. The Corporation has also achieved its objective of having at least two Board members who identify as a visible minority or Indigenous person.
Ethical Conduct & Executive Compensation
The Fortis Code of Conduct is guided by the Corporation's purpose and values and sets out standards for the ethical conduct of its directors, officers, and employees. The core principles of the Code of Conduct apply across the organization, with each operating subsidiary adopting its own substantially similar Code. Fortis and its utilities hold regular Code of Conduct employee training and all Fortis employees and Board members annually certify compliance.
The Code of Conduct is supported by other policies that outline the actions and behaviours expected from management and employees, including the Anti-Corruption Policy and Respectful Workplace Policy. As of January 1, 2024, the Corporation adopted a Vendor Code of Conduct, which applies to vendors, suppliers, contractors, consultants and other service providers that do business with the Corporation, and a Human Rights Policy which details the Corporation's commitment to respecting and upholding human rights. All Fortis operating subsidiaries have policies in place that uphold the Corporation's values as contained in these policies and demonstrate their commitment to ensuring equal opportunity and providing safe, respectful work environments.
Fortis and each of its operating subsidiaries have a Speak Up Policy to support and facilitate the anonymous reporting of conduct that may breach the Code of Conduct or other workplace policies.
Achieving Fortis' sustainability objectives is a focus for the Board and forms a component of executive compensation. Sustainability-related performance measures relating to climate, carbon reduction, safety and reliability, and people are embedded in the Corporation's executive compensation program.
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8 | FORTIS INC. | DECEMBER 31, 2023 |
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| Management Discussion and Analysis |
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| OPERATING RESULTS | | | | | | | |
| | | | | Variance |
| ($ millions) | 2023 | | | 2022 | | | FX | | Other |
| Revenue | 11,517 | | | 11,043 | | | 233 | | | 241 | |
| Energy supply costs | 3,771 | | | 3,952 | | | 66 | | | (247) | |
| Operating expenses | 2,889 | | | 2,683 | | | 69 | | | 137 | |
| Depreciation and amortization | 1,773 | | | 1,668 | | | 35 | | | 70 | |
| | | | | | | |
| Other income, net | 291 | | | 165 | | | 6 | | | 120 | |
| Finance charges | 1,305 | | | 1,102 | | | 24 | | | 179 | |
| Income tax expense | 360 | | | 289 | | | 8 | | | 63 | |
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| Net earnings | 1,710 | | | 1,514 | | | 37 | | | 159 | |
| | | | | | | |
| Net earnings attributable to: | | | | | | | |
| Non-controlling interests | 137 | | | 120 | | | 4 | | | 13 | |
| Preference equity shareholders | 67 | | | 64 | | | — | | | 3 | |
| Common equity shareholders | 1,506 | | | 1,330 | | | 33 | | | 143 | |
| Net Earnings | 1,710 | | | 1,514 | | | 37 | | | 159 | |
Revenue
The increase in revenue, net of foreign exchange, was due primarily to: (i) Rate Base growth; (ii) higher retail revenue at UNS Energy driven by new customer rates effective September 1, 2023, customer additions, and warmer weather; and (iii) the recognition of a regulatory deferral at FortisBC associated with the new cost of capital parameters approved by the BCUC effective January 1, 2023 (see "Regulatory Highlights - Significant Regulatory Matters" on page 14). The increase was partially offset by the flow-through of lower commodity costs in customer rates.
Energy Supply Costs
The decrease in energy supply costs, net of foreign exchange, was due primarily to lower commodity costs, mainly at FortisBC Energy, reflecting reduced pricing and volumes.
Operating Expenses
The increase in operating expenses, net of foreign exchange, was due primarily to general inflationary and employee-related cost increases.
Depreciation and Amortization
The increase in depreciation and amortization, net of foreign exchange, was due to continued investment in energy infrastructure at the Corporation's regulated utilities, partially offset by lower depreciation expense at UNS Energy associated with the retirement of the San Juan generating station in 2022.
Other Income, Net
The increase in other income, net of foreign exchange, was due primarily to: (i) gains on total return swaps and foreign exchange contracts, as compared to losses in 2022, as well as the pre-tax gain recognized on the sale of Aitken Creek, included in the Corporate and Other segment; (ii) an increase in the market value of certain investments that support retirement benefits at UNS Energy and ITC; and (iii) higher interest income, mainly at UNS Energy and ITC, largely reflecting interest on short-term deposits and regulatory deferrals.
Finance Charges
The increase in finance charges, net of foreign exchange, was due to higher debt levels to support the Corporation's Capital Plan, as well as higher interest rates impacting the Corporation's credit facilities and new debt issuances.
Income Tax Expense
The increase in income tax expense, net of foreign exchange, was driven by higher earnings before taxes.
Net Earnings
See "Performance at a Glance - Earnings and EPS" on page 3.
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9 | FORTIS INC. | DECEMBER 31, 2023 |
| | | | | | | | |
| Management Discussion and Analysis |
| | | | | | | | | | | | | | | | | | | | | | | |
| BUSINESS UNIT PERFORMANCE | | | | | | | |
| Common Equity Earnings | | | | | Variance |
| ($ millions) | 2023 | | | 2022 | | | FX (1) | | Other |
| Regulated Utilities | | | | | | | |
| ITC | 508 | | | 454 | | | 17 | | | 37 | |
| UNS Energy | 400 | | | 328 | | | 11 | | | 61 | |
| Central Hudson | 105 | | | 103 | | | 3 | | | (1) | |
| FortisBC Energy | 274 | | | 203 | | | — | | | 71 | |
| FortisAlberta | 162 | | | 151 | | | — | | | 11 | |
| FortisBC Electric | 68 | | | 64 | | | — | | | 4 | |
Other Electric (2) | 146 | | | 134 | | | 2 | | | 10 | |
| 1,663 | | | 1,437 | | | 33 | | | 193 | |
| Non-Regulated | | | | | | | |
Corporate and Other (3) | (157) | | | (107) | | | — | | | (50) | |
| Common Equity Earnings | 1,506 | | | 1,330 | | | 33 | | | 143 | |
(1)The reporting currency of ITC, UNS Energy, Central Hudson, Caribbean Utilities, FortisTCI and Fortis Belize is the U.S. dollar. The reporting currency of Belize Electricity is the Belizean dollar, which is pegged to the U.S. dollar at BZ$2.00=US$1.00. Certain corporate and non-regulated holding company transactions, included in the Corporate and Other segment, are denominated in U.S. dollars
(2)Consists of the utility operations in eastern Canada and the Caribbean: Newfoundland Power; Maritime Electric; FortisOntario; Wataynikaneyap Partnership; Caribbean Utilities; FortisTCI; and Belize Electricity
(3)Consists of non-regulated holding company expenses, as well as long-term contracted generation assets in Belize. Also includes Aitken Creek up to the November 1, 2023 date of disposition
| | | | | | | | | | | | | | | | | | | | | | | |
| ITC | | | | | Variance |
| ($ millions) | 2023 | | | 2022 | | | FX | | Other |
Revenue (1) | 2,085 | | | 1,906 | | | 72 | | | 107 | |
Earnings (1) | 508 | | | 454 | | | 17 | | | 37 | |
(1)Revenue represents 100% of ITC. Earnings represent the Corporation's 80.1% controlling ownership interest in ITC and reflect consolidated purchase price accounting adjustments.
Revenue
The increase in revenue, net of foreign exchange, was due primarily to Rate Base growth and higher flow-through costs in customer rates.
Earnings
The increase in earnings, net of foreign exchange, mainly reflected Rate Base growth, an increase in the market value of certain investments that support retirement benefits, and costs incurred in 2022 related to the suspension of the Lake Erie Connector project. The increase was partially offset by higher non-recoverable finance and stock-based compensation costs.
In 2023, the state of Iowa reduced its corporate income tax rate from 8.4% to 7.1%, effective January 1, 2024. As a result, ITC revalued the related deferred income tax assets, resulting in a $9 million unfavourable impact to earnings. A similar corporate income tax rate reduction was implemented by the state of Iowa in 2022.
| | | | | | | | | | | | | | | | | | | | | | | |
| UNS Energy | | | | | Variance |
| ($ millions, except as indicated) | 2023 | | | 2022 | | | FX | | Other |
Retail electricity sales (GWh) | 10,786 | | | 10,658 | | | — | | | 128 | |
Wholesale electricity sales (GWh) (1) | 5,387 | | | 5,401 | | | — | | | (14) | |
Gas sales (PJ) | 17 | | | 16 | | | — | | | 1 | |
Revenue | 3,006 | | | 2,758 | | | 96 | | | 152 | |
Earnings | 400 | | | 328 | | | 11 | | | 61 | |
(1) Primarily short-term wholesale sales
Sales
The increase in retail electricity sales was due primarily to warmer weather and customer additions.
| | | | | | | | |
10 | FORTIS INC. | DECEMBER 31, 2023 |
| | | | | | | | |
| Management Discussion and Analysis |
The decrease in wholesale electricity sales was driven by lower long-term wholesale sales, partially offset by an increase in short-term wholesale sales. Revenue from short-term wholesale sales, which relate to contracts that are less than one-year in duration, is primarily credited to customers through the PPFAC mechanism and, therefore, does not materially impact earnings.
Gas sales were consistent with 2022.
Revenue
The increase in revenue, net of foreign exchange, was due primarily to: (i) the recovery of overall higher fuel and non-fuel costs through the normal operation of regulatory mechanisms; (ii) new customer rates effective September 1, 2023 at TEP; and (iii) higher retail electricity sales, discussed above. The increase was partially offset by lower wholesale electricity sales.
Earnings
The increase in earnings, net of foreign exchange, was due primarily to: (i) new customer rates effective September 1, 2023 at TEP; (ii) higher retail electricity sales, discussed above; (iii) lower depreciation expense associated with the retirement of the San Juan generating station in 2022; and (iv) an increase in the market value of certain investments that support retirement benefits. The increase was partially offset by higher operating costs and income tax expense.
| | | | | | | | | | | | | | | | | | | | | | | |
| Central Hudson | | | | | Variance |
| ($ millions, except as indicated) | 2023 | | | 2022 | | | FX | | Other |
Electricity sales (GWh) | 4,921 | | | 5,002 | | | — | | | (81) | |
Gas sales (PJ) | 24 | | | 25 | | | — | | | (1) | |
Revenue | 1,360 | | | 1,325 | | | 49 | | | (14) | |
Earnings | 105 | | | 103 | | | 3 | | | (1) | |
Sales
The decrease in electricity and gas sales was due primarily to lower average consumption by residential customers due to milder weather.
Changes in electricity and gas sales at Central Hudson are subject to regulatory revenue decoupling mechanisms and, therefore, do not materially impact earnings.
Revenue
The decrease in revenue, net of foreign exchange, was due primarily to the flow-through of lower energy supply costs driven by commodity prices, partially offset by an increase in gas and electricity delivery rates effective July 1, 2023.
Earnings
The decrease in earnings, net of foreign exchange, was due to higher operating expenses related to an increase in labour costs, as well as finance costs in excess of amounts collected in customer rates, partially offset by Rate Base growth.
| | | | | | | | | | | | | | | | | |
| FortisBC Energy | | | | | |
| ($ millions, except as indicated) | 2023 | | | 2022 | | | Variance |
Gas sales (PJ) | 213 | | | 231 | | | (18) | |
Revenue | 1,955 | | | 2,084 | | | (129) | |
Earnings | 274 | | | 203 | | | 71 | |
Sales
The decrease in gas sales was due primarily to lower average consumption by residential, commercial and transportation customers, largely due to milder weather, partially offset by customer additions.
Revenue
The decrease in revenue was due to a lower cost of natural gas recovered from customers. The decrease was partially offset by revenue associated with the new cost of capital parameters approved by the BCUC effective January 1, 2023, which has been recognized through a regulatory deferral to be collected in future customer rates (see "Regulatory Highlights - Significant Regulatory Matters" on page 14), and Rate Base growth.
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11 | FORTIS INC. | DECEMBER 31, 2023 |
| | | | | | | | |
| Management Discussion and Analysis |
Earnings
The increase in earnings was due primarily to the new cost of capital parameters, discussed above, which resulted in $46 million of earnings in 2023. Rate Base growth also contributed to the increase in earnings.
FortisBC Energy earns approximately the same margin regardless of whether a customer contracts for the purchase and delivery of natural gas or only for delivery. Due to regulatory deferral mechanisms, changes in consumption levels and commodity costs do not materially impact earnings.
| | | | | | | | | | | | | | | | | |
| FortisAlberta | | | | | |
| ($ millions, except as indicated) | 2023 | | | 2022 | | | Variance |
Electricity deliveries (GWh) | 16,976 | | | 16,923 | | | 53 | |
Revenue | 738 | | | 680 | | | 58 | |
Earnings | 162 | | | 151 | | | 11 | |
Deliveries
The increase in electricity deliveries was due to higher average consumption by residential customers due to colder weather, as well as customer additions.
As approximately 85% of FortisAlberta's revenue is derived from fixed or largely fixed billing determinants, changes in quantities of energy delivered are not entirely correlated with changes in revenue. Revenue is a function of numerous variables, many of which are independent of actual energy deliveries. Significant variations in weather conditions, however, can impact revenue and earnings.
Revenue and Earnings
The increase in revenue and earnings was due to: (i) Rate Base growth; (ii) higher revenue associated with an increase in demand charges, as well as higher energy deliveries due to colder weather and customer additions, as discussed above; and, (iii) the operation of the PBR efficiency carry-over mechanism, which was earned in the second term of PBR and recognized in 2023. The increases were partially offset by the lower recovery of costs attributable to REAs (see "Regulatory Highlights - Significant Regulatory Matters" on page 14).
| | | | | | | | | | | | | | | | | |
| FortisBC Electric | | | | | |
| ($ millions, except as indicated) | 2023 | | | 2022 | | | Variance |
Electricity sales (GWh) | 3,478 | | | 3,542 | | | (64) | |
Revenue | 528 | | | 487 | | | 41 | |
Earnings | 68 | | | 64 | | | 4 | |
Sales
The decrease in electricity sales was due primarily to lower average consumption by residential customers due to milder weather.
Revenue
The increase in revenue was due primarily to the normal operation of regulatory mechanisms, including the regulatory deferral associated with the new cost of capital parameters approved by the BCUC effective January 1, 2023 (see "Regulatory Highlights - Significant Regulatory Matters" on page 14). Higher energy supply costs recovered from customers and Rate Base growth also contributed to the increase in revenue, partially offset by lower electricity sales and a decrease in third party contract work.
Earnings
The increase in earnings was primarily due to the new cost of capital parameters, discussed above. Rate Base growth also contributed to the increase in earnings, partially offset by higher operating costs reflecting inflationary increases.
Due to regulatory deferral mechanisms, changes in consumption levels do not materially impact earnings.
| | | | | | | | | | | | | | | | | | | | | | | |
| Other Electric | | | | | Variance |
| ($ millions, except as indicated) | 2023 | | | 2022 | | | FX | | Other |
Electricity sales (GWh) | 9,753 | | | 9,470 | | | — | | | 283 | |
Revenue | 1,761 | | | 1,652 | | | 16 | | | 93 | |
Earnings | 146 | | | 134 | | | 2 | | | 10 | |
| | | | | | | | |
12 | FORTIS INC. | DECEMBER 31, 2023 |
| | | | | | | | |
| Management Discussion and Analysis |
Sales
The increase in electricity sales was due primarily to higher average consumption by residential and commercial customers, as well as customer additions. Higher average consumption was largely due to the conversion of home heating systems from oil to electric in Eastern Canada.
Revenue
The increase in revenue, net of foreign exchange, was due to higher electricity sales, discussed above, and the normal operation of regulatory mechanisms at Newfoundland Power.
Earnings
The increase in earnings, net of foreign exchange, was due to Rate Base growth and higher electricity sales, partially offset by higher operating and finance costs. Equity income from Wataynikaneyap Power also contributed to the increase in earnings.
| | | | | | | | | | | | | | | | | |
| Corporate and Other | | | | | |
| ($ millions) | 2023 | | | 2022 | | | Variance |
Electricity sales (GWh) (1) | 164 | | | 225 | | | (61) | |
Revenue (2) | 84 | | | 151 | | | (67) | |
Net loss (3) | (157) | | | (107) | | | (50) | |
(1) Reflects electricity sales at Fortis Belize
(2) Includes revenue for Fortis Belize as well as revenue for Aitken Creek up to the November 1, 2023 date of disposition
(3) Includes non-regulated holding company expenses, earnings for Fortis Belize, as well as earnings for Aitken Creek up to the November 1, 2023 date of disposition
Sales
The decrease in electricity sales reflected a decrease in hydroelectric production in Belize associated with lower rainfall levels.
Revenue
The decrease in revenue reflected: (i) the disposition of Aitken Creek, including the unfavourable impact of mark-to-market accounting of natural gas derivatives at Aitken Creek, which resulted in unrealized losses of $22 million through November 1, 2023 compared to unrealized gains of $20 million in 2022; and (ii) lower hydroelectric production in Belize.
Net Loss
The increase in net loss includes lower earnings at Aitken Creek of $25 million. The decrease in earnings at Aitken Creek reflects the November 1, 2023 disposition date and the unfavourable impact of mark-to-market accounting of natural gas derivatives, partially offset by higher margins on gas sold. The impact of lower earnings at Aitken Creek was partially offset by the $10 million gain on disposition of Aitken Creek recognized by FortisBC Holdings Inc., also included in the Corporate and Other segment.
Excluding the impacts associated with Aitken Creek, the net loss in the Corporate and Other segment increased by $35 million year over year. The increase reflected: (i) higher holding company finance costs, reflecting higher interest rates and borrowings outstanding under the Corporation's credit facilities, as well as the refinancing of long-term debt; and (ii) lower hydroelectric production in Belize. The increase was partially offset by unrealized gains on foreign exchange contracts, reflecting market conditions.
NON-U.S. GAAP FINANCIAL MEASURES
Adjusted Common Equity Earnings, Adjusted Basic EPS, Adjusted Payout Ratio and Capital Expenditures are Non-U.S. GAAP Financial Measures and may not be comparable with similar measures used by other entities. They are presented because management and external stakeholders use them in evaluating the Corporation's financial performance and prospects.
Net earnings attributable to common equity shareholders (i.e., Common Equity Earnings) and basic EPS are the most directly comparable U.S. GAAP measures to Adjusted Common Equity Earnings and Adjusted Basic EPS, respectively. The Actual Payout Ratio calculated using Common Equity Earnings is the most comparable U.S. GAAP measure to the Adjusted Payout Ratio. These adjusted measures reflect the removal of items that management excludes in its key decision-making processes and evaluation of operating results.
Capital Expenditures include additions to property, plant and equipment and additions to intangible assets, as shown on the consolidated statements of cash flows. It also includes Fortis' 39% share of capital spending for the Wataynikaneyap Transmission Power Project, consistent with Fortis' evaluation of operating results and its role as project manager during the construction of this MCP.
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13 | FORTIS INC. | DECEMBER 31, 2023 |
| | | | | | | | |
| Management Discussion and Analysis |
| | | | | | | | | | | | | | | | | |
| Non-U.S. GAAP Reconciliation | | | | | |
| ($ millions, except as indicated) | 2023 | | | 2022 | | | Variance |
Adjusted Common Equity Earnings, Adjusted Basic EPS and Adjusted Payout Ratio | | | | | |
| Common Equity Earnings | 1,506 | | | 1,330 | | | 176 | |
| Adjusting items: | | | | | |
Disposition of Aitken Creek (1) | (15) | | | — | | | (15) | |
Unrealized loss (gain) on mark-to-market of derivatives (2) | 2 | | | (20) | | | 22 | |
Revaluation of deferred income tax assets (3) | 9 | | | 9 | | | — | |
Lake Erie Connector project suspension costs (4) | — | | | 10 | | | (10) | |
| Adjusted Common Equity Earnings | 1,502 | | | 1,329 | | | 173 | |
Adjusted Basic EPS (5) ($) | 3.09 | | | 2.78 | | | 0.31 | |
Adjusted Payout Ratio (6) (%) | 73.9 | | | 78.1 | | | (4.2) | |
| | | | | |
| Capital Expenditures | | | | | |
| Additions to property, plant and equipment | 3,986 | | | 3,587 | | | 399 | |
| Additions to intangible assets | 183 | | | 278 | | | (95) | |
| Adjusting item: | | | | | |
Wataynikaneyap Transmission Power Project (7) | 160 | | | 169 | | | (9) | |
| Capital Expenditures | 4,329 | | | 4,034 | | | 295 | |
(1) Aitken Creek was sold on November 1, 2023, with a March 31, 2023 effective date. The adjustment represents: (i) the $10 million gain on disposition, net of income tax expense of $13 million; and (ii) $5 million of net earnings at Aitken Creek, recognized in accordance with U.S. GAAP, during the March 31, 2023 to November 1, 2023 stub period, net of income tax expense of $2 million, included in the Corporate and Other segment
(2) Represents the impact of mark-to-market accounting of natural gas derivatives at Aitken Creek through the March 31, 2023 effective date of disposition, net of income tax recovery of $1 million in 2023 (2022 - net of income tax expense of $7 million), included in the Corporate and Other segment
(3) Represents the revaluation of deferred income tax assets resulting from the reduction in the corporate income tax rate in the state of Iowa, included in the ITC segment
(4) Represents costs incurred upon the suspension of the Lake Erie Connector project, net of income tax recovery of $4 million, included in the ITC segment
(5) Calculated using Adjusted Common Equity Earnings divided by weighted average common shares of 486.3 million in 2023 (2022 - 478.6 million)
(6) Calculated using dividends paid per common share of $2.29 in 2023 (2022 - $2.17) divided by Adjusted Basic EPS
(7) Represents Fortis' 39% share of capital spending for the Wataynikaneyap Transmission Power Project, included in the Other Electric segment
REGULATORY HIGHLIGHTS
General
The earnings of the Corporation's regulated utilities are determined under COS regulation, with some using PBR mechanisms.
Under COS regulation, the regulator sets customer rates to permit a reasonable opportunity for the timely recovery of the estimated costs of providing service, including a fair rate of return on a deemed or targeted capital structure applied to an approved Rate Base. PBR mechanisms generally apply a formula that incorporates inflation and assumed productivity improvements for a set term.
The ability to recover prudently incurred costs of providing service and earn the regulator‑approved ROE or ROA may depend on achieving the forecasts established in the rate-setting process. There can be varying degrees of regulatory lag between when costs are incurred and when they are recovered in customer rates.
Transmission operations in the U.S. are regulated federally by FERC. Remaining utility operations in the U.S. and Canada are regulated by state or provincial regulators. Utility operations in the Caribbean are regulated by regulatory and governmental authorities.
Additional information about regulation and the regulatory matters discussed below is provided in Note 2 in the 2023 Annual Financial Statements. Also refer to "Business Risks - Utility Regulation" on page 25.
Significant Regulatory Matters
ITC
MISO Base ROE: In 2022, the D.C. Circuit Court issued a decision vacating certain FERC orders that had established the methodology for setting the base ROE for transmission owners operating in the MISO region, including ITC. This matter dates back to complaints filed at FERC in 2013 and 2015 challenging the MISO base ROE then in effect. The court has remanded the matter to FERC for further process, the timing and outcome of which remain unknown.
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14 | FORTIS INC. | DECEMBER 31, 2023 |
| | | | | | | | |
| Management Discussion and Analysis |
Transmission Incentives: In 2021, FERC issued a supplemental NOPR on transmission incentives modifying the proposal in the initial NOPR released by FERC in 2020. The supplemental NOPR proposes to eliminate the 50-basis point RTO ROE incentive adder for RTO members that have been members for longer than three years. The timing and outcome of this proceeding remain unknown.
Although any potential impact to Fortis is uncertain, every 10-basis point change in ROE at ITC impacts Fortis' annual EPS by approximately $0.01.
Transmission ROFR: In December 2023, the Iowa District Court ruled that the manner in which Iowa's ROFR statute was passed is unconstitutional. The statute grants incumbent electric transmission owners, including ITC, a ROFR to construct, own and maintain certain electric transmission assets in the state. The District Court did not make any determination on the merits of the ROFR itself, but did issue a permanent injunction preventing ITC and others from taking further action to construct the MISO LRTP tranche one Iowa projects in reliance on the ROFR. ITC has filed for reconsideration of the District Court’s decision with respect to the scope of the injunction.
MISO's decision with respect to the assignment of the tranche one LRTP projects was finalized on July 25, 2022. MISO is the only entity charged with determining what projects are to be competitively bid pursuant to its tariff, and we believe it is unlikely that MISO will change the designation of the tranche one LRTP projects. Further, under the MISO tariff, approximately 70% of the Iowa tranche one projects are upgrades to ITC facilities along existing rights-of-way, which under MISO's tariff grants ITC the option to construct the upgrades regardless of the outcome of the ROFR legislation. For any portion of the first tranche of MISO’s LRTP projects in Iowa to be competitively bid, we believe it would require a federal decision that significantly departs from existing rules under the MISO tariff.
Forecast capital expenditures for 2024 associated with the first tranche of MISO's LRTP in Iowa is US$40 million, and approximately US$900 million is reflected in the 2024-2028 Capital Plan. The timing and outcome of the filing for reconsideration, and any other subsequent legal proceedings, as well as the impact on the five-year Capital Plan and the potential for future projects, is unknown.
UNS Energy
TEP General Rate Application: In August 2023, the ACC issued a decision on TEP's general rate application approving, among other things, an increase in non-fuel revenue of US$100 million, a 9.55% ROE and a 54.32% common equity component of capital structure. The decision reflects an increase from TEP's previous ROE and common equity component of capital structure of 9.15% and 53%, respectively. New customer rates became effective on September 1, 2023.
UNS Electric General Rate Application: In January 2024, the ACC issued a decision on UNS Electric's general rate application approving, among other things, an increase in the ROE and common equity component of capital structure from 9.50% and 52.8% to 9.75% and 53.7%, respectively. The decision also approved the System Reliability Benefit mechanism which allows UNS Electric to recover qualifying generation and energy storage investments between rate cases subject to an annual cap and earnings test. New customer rates became effective on February 1, 2024.
Central Hudson
General Rate Application: In July 2023, Central Hudson filed a rate application with the PSC requesting an increase in electric and natural gas delivery rates effective July 1, 2024. The application includes a request to set Central Hudson's ROE at 9.8% and a 50% common equity component of capital structure. The timing and outcome of this proceeding remain unknown.
CIS Implementation: In January 2023, Central Hudson filed a response to the PSC's Order to Commence Proceeding and Show Cause, which had directed Central Hudson to explain why the PSC should not pursue civil or administrative penalties or initiate a proceeding to review the prudence of implementation costs associated with its new CIS. In July 2023, an interim agreement was reached with the PSC, in which Central Hudson agreed to independent third-party verification of recent system improvements related to its billing system, and to accelerate the implementation of its monthly meter reading plan. The independent third-party review remains ongoing and an initial report is expected in the first quarter of 2024. The timing and outcome of this proceeding remain unknown.
FortisBC Energy and FortisBC Electric
GCOC Proceeding: In September 2023, the BCUC issued a decision on the GCOC proceeding approving new cost of capital parameters for FortisBC Energy and FortisBC Electric retroactive to January 1, 2023. For FortisBC Energy, the decision increased the ROE and common equity component of capital structure from 8.75% and 38.5% to 9.65% and 45%, respectively. For FortisBC Electric, the decision increased the ROE and common equity component of capital structure from 9.15% and 40% to 9.65% and 41%, respectively. Recovery of the GCOC decision in customer rates will begin in 2024, and the associated revenue deficiency deferral is expected to be fully collected by the end of 2029.
FortisAlberta
2024 GCOC Proceeding: In October 2023, the AUC issued a decision on the 2024 GCOC proceeding. The decision, which is effective January 1, 2024, adopts a formulaic approach in determining the ROE on an annual basis, which will adjust the notional ROE of 9.0% with reference to forecast long-term Government of Canada bond and utility bond yields. The ROE for 2024 has been set at 9.28%, an increase from FortisAlberta's previous ROE of 8.50%. The decision also concluded that there will be no change in the common equity component of capital structure of 37%.
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15 | FORTIS INC. | DECEMBER 31, 2023 |
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| Management Discussion and Analysis |
In November 2023, FortisAlberta sought permission to appeal the GCOC decision to the Court of Appeal of Alberta on the basis that the AUC erred in its decision to not adjust FortisAlberta's ROE and common equity component of capital structure to address incremental business risk associated with competition from REAs located in FortisAlberta's service area, as well as heightened regulatory risk due to the non-recovery of costs attributable to REAs (see "REA Cost Recovery" below). The decision on the request for appeal is expected by the end of 2024.
Third PBR Term: In October 2023, the AUC issued a decision establishing the parameters for the third PBR term for the period of 2024-2028. FortisAlberta's base distribution rates for the third PBR term are based on the 2023 COS revenue requirement previously approved by the AUC. The third PBR plan incorporates new inputs for the calculation of the inflation and productivity factors, the introduction of an earnings sharing mechanism that will allocate achieved earnings above the approved ROE between the utility and its customers, and the removal of the efficiency carry-over incentive mechanism. Capital funding mechanisms are preserved with modifications including: (i) base capital funding established on the approved 2023 COS Rate Base and a level of annual capital additions premised on 2018-2022 historical averages that are escalated as prescribed by the AUC; and (ii) criteria to meet eligibility for incremental capital funding on extraordinary expenditures is expanded to provide potential eligibility for net-zero plan related expenditures.
In November 2023, FortisAlberta sought permission to appeal the Third PBR decision to the Court of Appeal of Alberta on the basis that the AUC erred in its decision to determine capital funding using 2018-2022 historical capital investments without consideration for funding of new capital programs included in the company's 2023 COS revenue requirement as approved by the AUC. The decision on the request for appeal is expected by the end of 2024.
REA Cost Recovery: In 2021, the AUC determined that costs attributable to REAs, approximating $10 million annually, can no longer be recovered from FortisAlberta's rate payers, effective January 1, 2023. FortisAlberta continues to assess other means, including legislative amendments, to recover these costs.
FINANCIAL POSITION
| | | | | | | | | | | |
Significant Changes between December 31, 2023 and 2022 |
| | | |
| Balance Sheet Account | Variance | |
| ($ millions) | FX | Other | Explanation |
| Cash and cash equivalents | (3) | | 419 | | Primarily due to the issuance of US$800 million in unsecured senior notes at ITC in June 2023. ITC expects to utilize the unused net proceeds from this issuance to fund short-term capital requirements. Balances on hand have been largely invested in interest-bearing accounts. |
| Accounts receivable and other current assets | (30) | | (491) | | Due to: (i) a decrease in the fair value of energy contracts at UNS Energy and FortisBC Energy; and (ii) lower gas sales in the fourth quarter of 2023, as compared to the fourth quarter of 2022, at FortisBC Energy due to milder weather, partially offset by an increase in income taxes receivable. |
| | | |
| | | |
| Regulatory assets (current and long-term) | (32) | | 407 | | Due primarily to: (i) an increase in deferred income taxes; (ii) unrealized losses on energy derivatives at UNS Energy and FortisBC Energy; and (iii) higher energy management costs to be recovered in customer rates. |
| Property, plant and equipment, net | (615) | | 2,337 | | Due to capital expenditures, partially offset by depreciation. |
| | | |
| Goodwill | (253) | | (27) | | Reflects the disposition of Aitken Creek. |
| Short-term borrowings | (6) | | (128) | | Reflects the repayment of commercial paper at ITC. |
| Accounts payable & other current liabilities | (36) | | (280) | | Due to: (i) lower energy supply costs, primarily at UNS Energy and FortisBC Energy; and (ii) lower customer deposits, largely related to the Eagle Mountain Woodfibre Gas Line project, partially offset by an increase in trade accounts payable due to the timing of payments. |
| Other liabilities | (16) | | 140 | | Reflects an increase in employee future benefit liabilities driven by lower discount rates. |
| | | |
| Deferred income taxes | (59) | | 398 | | Due to higher temporary differences associated with ongoing capital investment as well as lower deferred tax assets associated with the utilization of tax losses. |
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16 | FORTIS INC. | DECEMBER 31, 2023 |
| | | | | | | | |
| Management Discussion and Analysis |
| | | | | | | | | | | |
Significant Changes between December 31, 2023 and 2022 |
| | | |
| Balance Sheet Account | Variance | |
| ($ millions) | FX | Other | Explanation |
| Long-term debt (including current portion) | (428) | | 1,547 | | Reflects debt issuances, partially offset by debt repayments, and higher borrowings under committed credit facilities, in support of the Corporation's Capital Plan. |
| | | |
| Shareholders' equity | (361) | | 836 | | Due primarily to: (i) Common Equity Earnings for 2023, less dividends declared on common shares; and (ii) the issuance of common shares, largely under the DRIP. |
| | | |
LIQUIDITY AND CAPITAL RESOURCES
Cash Flow Requirements
At the subsidiary level, it is expected that operating expenses and interest costs will be paid from Operating Cash Flow, with varying levels of residual cash flow available for capital expenditures and/or dividend payments to Fortis. Remaining capital expenditures are expected to be financed primarily from borrowings under credit facilities, long-term debt offerings and equity injections from Fortis. Borrowings under credit facilities may be required periodically to support seasonal working capital requirements.
Cash required of Fortis to support subsidiary growth is generally derived from borrowings under the Corporation's committed credit facility, the operation of the DRIP, as well as issuances of long-term debt, preference equity, and common shares including those issued through the ATM Program discussed below. The subsidiaries pay dividends to Fortis and receive equity injections from Fortis when required. Both Fortis and its subsidiaries initially borrow through their committed credit facilities and periodically replace these borrowings with long-term financing. Financing needs also arise to refinance maturing debt.
Credit facilities are syndicated primarily with large banks in Canada and the U.S., with no one bank holding more than approximately 20% of the Corporation's total revolving credit facilities. Approximately $5.7 billion of the total credit facilities are committed with maturities ranging from 2024 through 2028. Available credit facilities are summarized in the following table.
| | | | | | | | | | | | | | | | | | | | | | | |
| Credit Facilities | | | | | | | |
| As at December 31 | Regulated | | Corporate | | | | |
($ millions) | Utilities | | and Other | | 2023 | | 2022 | |
Total credit facilities (1) | 3,943 | | | 2,233 | | | 6,176 | | | 5,850 | |
| Credit facilities utilized: | | | | | | | |
| Short-term borrowings | (119) | | | — | | | (119) | | | (253) | |
Long-term debt (including current portion) | (910) | | | (662) | | | (1,572) | | | (1,657) | |
| Letters of credit outstanding | (78) | | | (23) | | | (101) | | | (128) | |
| Credit facilities unutilized | 2,836 | | | 1,548 | | | 4,384 | | | 3,812 | |
(1)Additional information about the Corporation's credit facilities is provided in Note 14 in the 2023 Annual Financial Statements
In April 2023, ITC increased its total credit facilities available from US$900 million to US$1 billion and extended the maturity to April 2028.
In May 2023, the Corporation amended its $1.3 billion revolving term committed credit facility agreement to extend the maturity to July 2028. Also in May 2023, the Corporation extended the maturity on its unsecured US$500 million non-revolving term credit facility to May 2024. The facility is repayable at any time without penalty.
In October 2023, FortisUS Inc., a holding company subsidiary of Fortis, entered into a US$150 million uncommitted revolving credit facility. The facility matures in October 2025 and will provide funding flexibility for short-term liquidity needs.
The Corporation's ability to service debt and pay dividends is dependent on the financial results of, and the related cash payments from, its subsidiaries. Certain regulated subsidiaries are subject to restrictions that limit their ability to distribute cash to Fortis, including restrictions by certain regulators limiting annual dividends and restrictions by certain lenders limiting debt to total capitalization. There are also practical limitations on using the net assets of the regulated subsidiaries to pay dividends, based on management's intent to maintain the subsidiaries' regulator-approved capital structures. Fortis does not expect that maintaining such capital structures will impact its ability to pay dividends in the foreseeable future.
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17 | FORTIS INC. | DECEMBER 31, 2023 |
| | | | | | | | |
| Management Discussion and Analysis |
As at December 31, 2023, consolidated fixed-term debt maturities/repayments are expected to average $1,492 million annually over the next five years and approximately 73% of the Corporation's consolidated long-term debt, excluding credit facility borrowings, had maturities beyond five years.
In November 2022, Fortis filed a short-form base shelf prospectus with a 25-month life under which it may issue common or preference shares, subscription receipts, or debt securities in an aggregate principal amount of up to $2.0 billion. In September 2023, Fortis established an ATM Program pursuant to the short-form base shelf prospectus, that allows the Corporation to issue up to $500 million of common shares from treasury to the public from time to time, at the Corporation's discretion. As at December 31, 2023, $500 million remained available under the ATM Program and $1.5 billion remained available under the short-form base shelf prospectus.
Fortis is well positioned with strong liquidity. This combination of available credit facilities and manageable annual debt maturities/repayments provides flexibility in the timing of access to capital markets. Given current credit ratings and capital structures, the Corporation and its subsidiaries currently expect to continue to have reasonable access to long-term capital in 2024.
Fortis and its subsidiaries were in compliance with debt covenants as at December 31, 2023 and are expected to remain compliant in 2024.
| | | | | | | | | | | | | | | | | |
| Cash Flow Summary | | | | | |
| Summary of Cash Flows | | | | | |
| Years ended December 31 | | | | | |
| ($ millions) | 2023 | | | 2022 | | | Variance |
| Cash and cash equivalents, beginning of year | 209 | | | 131 | | | 78 | |
| Cash from (used in): | | | | | |
| Operating activities | 3,545 | | | 3,074 | | | 471 | |
| Investing activities | (3,742) | | | (4,059) | | | 317 | |
| Financing activities | 613 | | | 1,035 | | | (422) | |
| Effect of exchange rate changes on cash and cash equivalents | — | | | 28 | | | (28) | |
| | | | | |
| Cash and cash equivalents, end of year | 625 | | | 209 | | | 416 | |
Operating Activities
See "Performance at a Glance - Operating Cash Flow" on page 4.
Investing Activities
The decrease in cash used in investing activities was due to proceeds received on the disposition of Aitken Creek, lower planned equity contributions associated with the Wataynikaneyap Transmission Power Project, and higher customer contributions in aid of construction. The decrease was partially offset by higher capital expenditures in 2023, as well as the higher U.S.-to-Canadian dollar exchange rate. See "Performance at a Glance - Capital Expenditures" on page 4 and "Capital Plan" on page 21.
Financing Activities
Cash flow related to financing activities will fluctuate as a result of changes in the subsidiaries' capital expenditures and the amount of Operating Cash Flow available to fund those capital expenditures, which together impact the amount of funding required from debt and common equity issuances. See "Cash Flow Requirements" on page 17. The decrease in cash from financing activities in 2023 also reflected the repayment of credit facility borrowings with the proceeds received from the sale of Aitken Creek.
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18 | FORTIS INC. | DECEMBER 31, 2023 |
| | | | | | | | |
| Management Discussion and Analysis |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Debt Financing | Month
Issued | | Interest Rate (%) | | Maturity | | Amount ($ millions) | | Use of Proceeds |
| Significant Long-Term Debt Issuances | | | | |
Year ended December 31, 2023
| | | | |
| ITC | | | | | | | | | |
Unsecured senior notes | June | | 5.40 | | (1) | 2033 | | US | 500 | | | (2) (3) (4) |
Unsecured senior notes | June | | 4.95 | | (5) | 2027 | | US | 300 | | | (2) (3) (4) |
Secured senior notes | November | | 5.65 | | | 2028 | | US | 90 | | | (3) (4) (6) |
| UNS Energy | | | | | | | | | |
| Unsecured senior notes | February | | 5.50 | | | 2053 | | US | 375 | | | (2) (3) |
| Unsecured senior notes | August | | 5.65 | | | 2038 | | US | 50 | | | (2) |
| Central Hudson | | | | | | | | | |
| Unsecured senior notes | March | | 5.68 | | | 2033 | | US | 40 | | | (3) (4) |
| Unsecured senior notes | March | | 5.78 | | | 2035 | | US | 15 | | | (3) (4) |
| Unsecured senior notes | March | | 5.88 | | | 2038 | | US | 35 | | | (3) (4) |
| Unsecured senior notes | November | | 6.17 | | | 2028 | | US | 60 | | | (3) (4) |
| FortisAlberta | | | | | | | | | |
| Unsecured senior debentures | May | | 4.86 | | | 2053 | | 200 | | | (3) (4) |
| Newfoundland Power | | | | | | | | | |
| First mortgage sinking fund bonds | August | | 5.12 | | | 2053 | | 90 | | | (3) (4) |
| Maritime Electric | | | | | | | | | |
| First mortgage bonds | September | | 5.20 | | | 2053 | | 60 | | | (3) (4) |
| Fortis | | | | | | | | | |
| Unsecured senior notes | November | | 5.68 | | (7) | 2033 | | 500 | | | (3) (4) |
(1) ITC entered into interest rate locks which reduced the effective interest rate to 5.32%. See Note 26 to the 2023 Annual Financial Statements(2) Repay maturing long-term debt
(3) General corporate purposes
(4) Repay short-term and/or credit facility borrowings
(5) Represents a second tranche of ITC's existing 4.95% senior notes, originally issued in 2022
(6) Fund capital expenditures
(7) Fortis entered into an interest rate lock which reduced the effective interest rate to 5.52%. See Note 26 to the 2023 Annual Financial Statements
In January 2024, ITC issued US$85 million of 10-year, 5.98% secured senior notes, US$75 million of 5-year, 5.11% first mortgage bonds, and US$75 million of 10-year, 5.38% first mortgage bonds. Proceeds will be used to repay credit facility borrowings, fund capital expenditures, and for general corporate purposes.
| | | | | | | | | | | | | | | | | |
| Common Equity Financing | | | | | |
| Common Equity Issuances and Dividends Paid |
| Years ended December 31 |
| ($ millions, except as indicated) | 2023 | | | 2022 | | | Variance |
| Common shares issued: | | | | | |
Cash (1) | 43 | | | 53 | | | (10) | |
Non-cash (2) | 409 | | | 366 | | | 43 | |
| Total common shares issued | 452 | | | 419 | | | 33 | |
Number of common shares issued (# millions) | 8.4 | | | 7.4 | | 1.0 | |
| Common share dividends paid: | | | | | |
| Cash | (701) | | | (673) | | | (28) | |
Non-cash (3) | (408) | | | (364) | | | (44) | |
| Total common share dividends paid | (1,109) | | | (1,037) | | | (72) | |
Dividends paid per common share ($) | 2.29 | | 2.17 | | | 0.12 | |
(1) Includes common shares issued under stock option and employee share purchase plans
(2) Common shares issued under the DRIP and stock option plan
(3) Common share dividends reinvested under the DRIP
On December 6, 2023 and February 8, 2024, Fortis declared a dividend of $0.59 per common share payable on March 1, 2024 and June 1, 2024, respectively. The payment of dividends is at the discretion of the Board and depends on the Corporation's financial condition and other factors.
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19 | FORTIS INC. | DECEMBER 31, 2023 |
| | | | | | | | |
| Management Discussion and Analysis |
On September 1, 2023, the annual fixed dividend per share for the First Preference Shares, Series G was reset from $1.0983 to $1.5308 for the five-year period up to but excluding September 1, 2028.
| | | | | | | | | | | | | | | | | | | | | | | |
| Contractual Obligations | | | | | | | |
| Contractual Obligations | | | | | |
As at December 31, 2023 | | |
| ($ millions) | Total | Year 1 | Year 2 | Year 3 | Year 4 | Year 5 | Thereafter |
| Long-term debt: | | | | | | | |
Principal (1) | 29,703 | | 2,296 | | 511 | | 2,388 | | 2,334 | | 1,501 | | 20,673 | |
| Interest | 18,007 | | 1,189 | | 1,154 | | 1,123 | | 1,038 | | 955 | | 12,548 | |
Finance leases (2) | 1,158 | | 36 | | 36 | | 36 | | 36 | | 36 | | 978 | |
Other obligations (3) | 435 | | 127 | | 82 | | 91 | | 28 | | 26 | | 81 | |
Other commitments: (4) | | | | | | | |
| Gas and fuel purchase obligations | 6,073 | | 697 | | 592 | | 490 | | 439 | | 339 | | 3,516 | |
| Waneta Expansion capacity agreement | 2,418 | | 55 | | 56 | | 58 | | 59 | | 60 | | 2,130 | |
| Renewable power purchase agreements | 1,754 | | 128 | | 128 | | 128 | | 127 | | 127 | | 1,116 | |
| Power purchase obligations | 1,534 | | 336 | | 253 | | 199 | | 120 | | 114 | | 512 | |
| | | | | | | |
| ITC easement agreement | 354 | | 13 | | 13 | | 13 | | 13 | | 13 | | 289 | |
| TEP EPC Agreement for Roadrunner Reserve Project | 270 | | 266 | | 4 | | — | | — | | — | | — | |
| Debt collection agreement | 102 | | 3 | | 3 | | 3 | | 3 | | 3 | | 87 | |
| Renewable energy credit purchase agreements | 63 | | 19 | | 7 | | 6 | | 6 | | 6 | | 19 | |
| Other | 139 | | 30 | | 24 | | 8 | | 5 | | 4 | | 68 | |
| 62,010 | | 5,195 | | 2,863 | | 4,543 | | 4,208 | | 3,184 | | 42,017 | |
(1)Amounts not reduced by unamortized deferred financing and discount costs of $172 million. Additional information is provided in Note 14 of the 2023 Annual Financial Statements
(2)Additional information is provided in Note 15 of the 2023 Annual Financial Statements
(3)Primarily includes commitments with respect to long-term compensation and employee future benefit arrangements
(4)Represents unrecorded commitments. Additional information is provided in Note 27 of the 2023 Annual Financial Statements
Other Contractual Obligations
The Corporation's regulated utilities are obligated to provide service to customers within their respective service territories. Capital Expenditures are forecast to be approximately $4.8 billion for 2024 and approximately $25 billion over the five-year 2024-2028 Capital Plan. See "Capital Plan" on page 21.
Under a funding framework with the Governments of Ontario and Canada, Fortis will contribute a minimum of approximately $155 million of equity capital to the Wataynikaneyap Partnership, based on Fortis' proportionate 39% ownership interest and the final regulatory-approved capital cost of the related project. The Wataynikaneyap Partnership has loan agreements in place to finance the project during construction. In the event a lender under the loan agreements realizes security on the loans, Fortis may be required to accelerate its equity capital contributions, which may be in excess of the amount otherwise required of Fortis under the funding framework, to a maximum total funding of $235 million. Equity of $137 million has been contributed as of December 31, 2023.
UNS Energy has joint generation performance guarantees with participants at Four Corners and Luna, with agreements expiring in 2041 and 2046, respectively, and at San Juan and Navajo through decommissioning. The participants have guaranteed that in the event of payment default, each non-defaulting participant will bear its proportionate share of expenses otherwise payable by the defaulting participant. In exchange, the non-defaulting participants are entitled to receive their proportionate share of the generation capacity of the defaulting participant. In the case of San Juan and Navajo, participants would seek financial recovery from the defaulting party. There is no maximum amount under these guarantees, except for a maximum of $331 million for Four Corners. As at December 31, 2023, there was no obligation under these guarantees.
Off-Balance Sheet Arrangements
With the exception of letters of credit outstanding of $101 million as at December 31, 2023 and the unrecorded commitments in the table above, the Corporation had no off-balance sheet arrangements.
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20 | FORTIS INC. | DECEMBER 31, 2023 |
| | | | | | | | |
| Management Discussion and Analysis |
Capital Structure and Credit Ratings
Fortis requires ongoing access to capital and, therefore, targets a consolidated long-term capital structure that will enable it to maintain investment-grade credit ratings. The regulated utilities maintain their own capital structures in line with those reflected in customer rates.
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Consolidated Capital Structure | 2023 | | 2022 |
| As at December 31 | ($ millions) | | (%) | | ($ millions) | | (%) |
Debt (1) | 29,364 | | | 55.7 | | | 28,792 | | | 55.8 | |
Preference shares | 1,623 | | | 3.1 | | | 1,623 | | | 3.1 | |
Common shareholders' equity and non-controlling interests (2) | 21,709 | | | 41.2 | | | 21,219 | | | 41.1 | |
| 52,696 | | | 100.0 | | | 51,634 | | | 100.0 | |
(1)Includes long-term debt and finance leases, including current portion, and short-term borrowings, net of cash
(2)Includes shareholders equity, excluding preference shares, and non-controlling interests. Non-controlling interests represented 3.5% as at December 31, 2023 (December 31, 2022 - 3.5%)
Outstanding Share Data
As at February 8, 2024, the Corporation had issued and outstanding 490.6 million common shares and the following First Preference Shares: 5.0 million Series F; 9.2 million Series G; 7.7 million Series H; 2.3 million Series I; 8.0 million Series J; 10.0 million Series K; and 24.0 million Series M.
Only the common shares of the Corporation have voting rights. The Corporation's first preference shares do not have voting rights unless and until Fortis fails to pay eight quarterly dividends, whether or not consecutive or declared.
If all outstanding stock options were exercised as at February 8, 2024, an additional 1.9 million common shares would be issued and outstanding.
Credit Ratings
The Corporation's credit ratings shown below reflect its low business risk profile, diversity of operations, the stand-alone nature and financial separation of each regulated subsidiary, and the level of holding company debt.
| | | | | | | | | | | | | | | | | |
As at December 31, 2023 | Rating | | Type | | Outlook |
| S&P | A- | | Issuer | | Negative |
| BBB+ | | Unsecured debt | | |
| DBRS Morningstar | A (low) | | Issuer | | Stable |
| A (low) | | Unsecured debt | | Stable |
| Moody's | Baa3 | | Issuer | | Stable |
| Baa3 | | Unsecured debt | | |
In November 2023, S&P confirmed the Corporation's 'A-' issuer and 'BBB+' senior unsecured debt credit ratings and revised the issuer rating outlook for the Corporation and certain of its subsidiaries from stable to negative. S&P noted that the change reflects rising exposure to physical risks due to climate change. S&P also revised the funds from operations (FFO) to debt downgrade threshold for the Corporation from 10.5% to 12.0%.
Capital Plan
Capital investment in energy infrastructure is required to ensure the continued and enhanced performance, reliability and safety of the electricity and gas systems, to meet customer growth, and to deliver cleaner energy.
Capital Expenditures of $4.3 billion were in-line with the 2023 Capital Plan. During 2023, over $700 million of capital investment related to delivering cleaner energy to customers.
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2023 Capital Expenditures (1) |
| Regulated Utilities | | Total
Regulated
Utilities | | Non-Regulated Corporate and Other | | Total |
| ($ millions, except as indicated) | ITC | | UNS
Energy | | Central
Hudson | | FortisBC
Energy | | Fortis
Alberta | | FortisBC
Electric | | Other Electric | | | |
| Total | 1,103 | | | 916 | | | 341 | | | 593 | | | 608 | | | 126 | | | 626 | | | 4,313 | | | 16 | | | 4,329 | |
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21 | FORTIS INC. | DECEMBER 31, 2023 |
| | | | | | | | |
| Management Discussion and Analysis |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Forecast 2024 Capital Expenditures (2)(3) |
| Regulated Utilities | | Total
Regulated
Utilities | | Non-Regulated Corporate and Other | | Total (4) |
| ($ millions, except as indicated) | ITC | | UNS Energy | | Central Hudson | | FortisBC Energy | | Fortis Alberta | | FortisBC Electric | | Other Electric | | | |
| Total | 1,252 | | | 1,111 | | | 408 | | | 764 | | | 586 | | | 134 | | | 507 | | | 4,762 | | | 7 | | | 4,769 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
2024-2028 Capital Plan (2)(3) |
| ($ billions) | 2024 | | 2025 | | 2026 | | 2027 | | 2028 | | Total (4) |
| Five-year capital plan | 4.8 | | | 4.8 | | | 4.8 | | | 5.6 | | | 5.0 | | | 25.0 | |
(1)See "Non-U.S. GAAP Financial Measures" on page 13
(2)Represents a forward-looking non-U.S. GAAP financial measure calculated in the same manner as Capital Expenditures. See "Non-U.S. GAAP Financial Measures" on page 13
(3)Excludes the non-cash equity component of AFUDC
(4)Reflects an assumed U.S. dollar-to-Canadian dollar exchange rate of 1.30. On average, Fortis estimates that a five-cent increase or decrease in the U.S. dollar relative to the Canadian dollar would increase or decrease Capital Expenditures by approximately $600 million over the five-year planning period
The Corporation's 2024-2028 Capital Plan of $25 billion is $2.7 billion higher than the previous five-year plan. The increase is driven by organic growth, largely reflecting regional transmission projects at ITC associated with tranche one of the MISO LRTP, as well as investments in Arizona to support TEP’s exit from coal. Investments supporting system adaptation and resiliency, customer growth and economic development are also driving capital growth across the Corporation's regulated utilities.
Cleaner Energy Investments of approximately $7 billion are expected over the five-year planning period, and are largely related to connecting renewables to the grid, renewable and storage investments in Arizona and the Caribbean, and cleaner natural gas solutions in British Columbia. Fortis remains focused on maintaining customer affordability by controlling costs, investing in cleaner energy resulting in fuel savings for customers, utilizing available tax credits, and implementing innovative practices, among other initiatives.
The five-year Capital Plan is low risk and highly executable, with nearly 100% of planned expenditures to occur at the regulated utilities and approximately 20% of investments relating to major capital projects. Geographically, 58% of planned expenditures are expected in the U.S., including 29% at ITC, with 38% in Canada and the remaining 4% in the Caribbean.
The five-year Capital Plan is expected to be funded primarily by cash from operations and regulated utility debt. Common equity proceeds are expected to be sourced from the Corporation's DRIP and ATM Program.
Planned Capital Expenditures are based on detailed forecasts of energy demand as well as labour and material costs, including inflation, supply chain availability, general economic conditions, foreign exchange rates and other factors. These could change and cause actual expenditures to differ from forecast.
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Midyear Rate Base (1) |
| ($ billions) | 2023 | | 2024 | | | 2028 | |
| ITC | 11.5 | | | 12.0 | | | 15.6 | |
| UNS Energy | 7.3 | | | 7.6 | | | 9.5 | |
| Central Hudson | 3.0 | | | 3.1 | | | 4.1 | |
| FortisBC Energy | 5.9 | | | 5.9 | | | 8.4 | |
| FortisAlberta | 4.2 | | | 4.4 | | | 5.2 | |
| FortisBC Electric | 1.7 | | | 1.7 | | | 2.0 | |
| Other Electric | 3.4 | | | 3.7 | | | 4.6 | |
| Total | 37.0 | | | 38.4 | | | 49.4 | |
(1)Simple average of Rate Base at beginning and end of the year
Total midyear Rate Base is forecast to grow to $49.4 billion by 2028 underpinned by the five-year Capital Plan, translating to a CAGR of 6.3%.
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22 | FORTIS INC. | DECEMBER 31, 2023 |
| | | | | | | | |
| Management Discussion and Analysis |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Major Capital Projects in 2024-2028 Capital Plan | | | | | Forecast | | | |
| Pre- | | Actual | | | | 2025- | | Expected | |
| ($ millions) | 2023 | | | 2023 | | | 2024 | | | 2028 | | | Completion | |
ITC | | | | | | | | | | |
| MISO LRTP | — | | | 25 | | | 106 | | | 1,371 | | | Post-2028 | |
UNS Energy | | | | | | | | | | |
| Roadrunner Reserve Battery Storage Project | — | | | 137 | | | 300 | | | 45 | | | 2025 | | |
| Vail-to-Tortolita Transmission Project | 65 | | | 87 | | | 76 | | | 210 | | | 2026 | | |
| IRP Energy Resources | — | | | — | | | 110 | | | 307 | | | 2027 | | |
| FortisBC Energy | | | | | | | | | | |
Eagle Mountain Woodfibre Gas Line Project (1) (2) | — | | | — | | | 250 | | | 500 | | | 2027 | | |
| Tilbury LNG Storage Expansion | 20 | | | 9 | | | 18 | | | 519 | | | Post-2028 | |
| AMI Project | 2 | | | 5 | | | 20 | | | 495 | | | 2028 | | |
| Tilbury 1B Project | 36 | | | 8 | | | 30 | | | 348 | | | Post-2028 | |
| Okanagan Capacity Upgrade | 15 | | | 2 | | | 14 | | | 199 | | | 2026 | | |
| Other Electric | | | | | | | | | | |
Wataynikaneyap Transmission Power Project (3) | 524 | | | 160 | | | 65 | | | — | | | 2024 | |
| Total | | | 433 | | | 989 | | | 3,994 | | | | |
(1)Capital expenditures of $71 million in 2023 were fully funded by customer contributions
(2)2024 through 2028 is net of customer contributions
(3)Fortis' share of estimated capital spending. Under the funding framework, Fortis will be funding its equity component only.
MISO LRTP
In 2022, the MISO board approved the first tranche of projects associated with the LRTP, representing 18 transmission projects across the MISO Midwest subregion with total associated costs estimated at US$10 billion. Six of these projects run through ITC's MISO operating companies' service territories, including Michigan and Iowa, where ROFR provisions have existed for incumbent transmission owners (see "Regulatory Highlights - Significant Regulatory Matters" on page 14). ITC estimates transmission investments of US$1.4 billion to US$1.8 billion through 2030 associated with six of the 18 projects, with capital expenditures of approximately $1.5 billion (US$1.2 billion) included in the Corporation's 2024-2028 Capital Plan. Other projects within ITC's MISO service territory may be subject to competitive bidding, depending on the state in which they are located.
Roadrunner Reserve Battery Storage Project
The largest battery energy storage system in TEP's portfolio. The 200 MW system will store 800 MW hours of energy, enough to serve approximately 42,000 homes for four hours when deployed at full capacity. TEP will own and operate the system which is scheduled for completion in 2025.
Vail-to-Tortolita Transmission Project
Construction and upgrades to connect existing TEP substations to a new 230kV line within TEP’s service territory. Construction commenced in late 2023, and is scheduled for completion in 2026.
IRP Energy Resources
Includes capital expenditures for resource requirements, including wind and solar generation and energy storage systems, supporting the transition to cleaner energy as outlined in TEP's 2023 IRP. An All-Source Request for Proposal was issued in late 2023 based on the company's resource requirements. TEP will be reviewing the proposals and determining next steps in 2024.
Eagle Mountain Woodfibre Gas Line Project
Gas line expansion to a proposed LNG site in Squamish, British Columbia. FortisBC Energy commenced construction of the project in the second half of 2023, with costs funded through contributions from Woodfibre LNG. The project is scheduled for completion in 2027.
FortisBC Energy's total anticipated investment in the project has increased to $750 million, net of customer contributions, as compared to $420 million previously expected. The increase was due to amendments to previous development, construction, transportation and other commercial agreements with Woodfibre LNG Limited and other partners, that became effective with the completion of the remaining substantive conditions, including BCUC approval of amended transportation rate schedules. The projected five-year Capital Plan for FortisBC Energy, and the Corporation, remains unchanged in consideration of timing of approvals which may shift certain capital expenditures beyond the five year period.
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| Management Discussion and Analysis |
Tilbury LNG Storage Expansion
This project replaces the original LNG storage tank at the Tilbury site and increases the available regasification capacity to provide backup gas supply for lower mainland customers. The regulatory process was adjourned in early 2023 in order for FortisBC Energy to prepare further information in support of the CPCN application. FortisBC Energy intends to file the additional evidence in mid-2024, with a decision from the BCUC expected by the end of 2024.
AMI Project
The project includes replacement of residential and small commercial meters with advanced meters to support the safety, resiliency, and efficient operation of FortisBC Energy's gas distribution system. The CPCN application was approved by the BCUC in 2023, and installation of the advanced meters is expected to commence in 2024, with construction to be substantially complete in 2028.
Tilbury 1B Project
Construction of additional liquefaction and dispensing, including on-shore piping, in support of marine bunkering and to further optimize the Tilbury Phase 1A Expansion Project. This FortisBC Energy project received an Order in Council from the Government of British Columbia in 2017. An initial project scope has been filed with regulators to support the federal impact assessment and provincial environmental assessment required to further expand the Tilbury site. Engineering design and related studies will continue in 2024.
Okanagan Capacity Upgrade
Construction of a new section of pipeline and associated facilities to address expected load growth in the Okanagan region. In May 2023, FortisBC Energy submitted a supplemental filing with the BCUC to provide updates to key evidence in the proceeding. In December 2023, the BCUC denied the CPCN application, stating that it may not be the optimal solution to address the imminent capacity shortfall, and approved the establishment of a deferral account to capture development costs already incurred.
FortisBC Energy is awaiting a decision from the BCUC on its Revised Renewable Gas Comprehensive Review application, the purpose of which is to enable all new residential connections to receive 100% renewable gas. The outcome of that application, as well as other alternatives being considered, will provide the company an opportunity to rescope the project, if necessary, or resubmit the current CPCN application with certain modifications. FortisBC Energy will be determining the next steps with respect to this project with the BCUC by mid-2024.
Wataynikaneyap Transmission Power Project
Construction of an 1,800 kilometer, regulated transmission line to connect 17 remote First Nations communities in Northwestern Ontario to the main electricity grid, in which Fortis holds a 39% equity interest. FortisOntario is responsible for construction management and operation of the transmission line. As at December 31, 2023, project construction was 98% complete, with 1,353 kilometers of transmission line and 14 substations energized, and ten First Nation communities connected to the electric grid. The project is on track to be completed in 2024.
Additional Investment Opportunities
Fortis is pursuing additional investment opportunities within existing service territories that are not yet included in the five-year Capital Plan.
Inflation Reduction Act of 2022
In 2022, the IRA was passed into U.S. law which included, among other items, a focus on energy security and climate change programs. With incentives and clean energy tax credits encouraging investments in clean energy, energy storage, electric vehicles and manufacturing, the IRA aligns with Fortis' cleaner energy goals and provides an opportunity for continued investment in a cleaner energy future.
ITC - MISO LRTP
The MISO LRTP is expected to consist of four tranches. Incremental opportunity associated with the first tranche of projects is outlined above. MISO is expected to identify projects associated with the second tranche of the LRTP in the second half of 2024, which is expected to provide further investment opportunities at ITC.
UNS Energy - 2023 IRPs
The 2023 IRPs for TEP and UNS Electric were filed with the ACC in November 2023 and outlined the resource energy transition required to satisfy customers’ increasing energy needs over the next 15 years while reducing carbon emissions and other environmental impacts. This transition is expected to reduce carbon emissions by 80% by 2035. This plan supports reliable and affordable service and is expected to provide incremental capital investment opportunity of approximately US$2.5 billion to US$5.0 billion through 2038. The IRPs may be impacted by various federal and state energy policies, including policies currently under consideration. The ACC review process is expected to conclude in the fall of 2024. Details of specific projects will continue to be defined as the review process evolves and further information becomes available.
FortisBC Energy - LNG
LNG infrastructure opportunities in British Columbia include further expansion of the Tilbury LNG facility, which is uniquely positioned to meet customer demand for clean-burning natural gas. The site is scalable and can accommodate additional storage and liquefaction equipment and is close to international shipping lanes.
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24 | FORTIS INC. | DECEMBER 31, 2023 |
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| Management Discussion and Analysis |
With respect to further Tilbury expansion, FortisBC Energy's parent company, FortisBC Holdings Inc., has entered into an agreement with an Indigenous community to provide the ability to participate, through equity ownership, in certain future LNG investments if the parties are able to satisfy certain obligations. Any proposed transaction is subject to regulatory approvals and certain conditions precedent.
Propel New York Energy Project
Central Hudson owns a minority equity interest in Transco, a joint venture with affiliates of other investor-owned utilities in New York State, which was created to develop, own, and operate electric transmission projects in the state. In June 2023, the New York Independent System Operator selected a proposal by Transco, in partnership with the New York Power Authority, to construct transmission infrastructure to deliver at least 3,000 MW from Long Island offshore wind facilities to the rest of the state by 2030. Transco's portion of the project, titled the "Propel New York Energy Project," is estimated to cost approximately US$2.2 billion, of which Central Hudson's share is approximately 10%.
Other Opportunities
Includes incremental regulated transmission investment and grid modernization projects at ITC; energy storage projects, grid modernization, infrastructure resiliency, and transmission investments at UNS Energy; further gas infrastructure opportunities at FortisBC Energy; and cleaner energy infrastructure, as well as climate change adaptation investments across our jurisdictions.
BUSINESS RISKS
Fortis has an ERM program that identifies and evaluates the severity and probability of risks to its business. The Fortis Board, through its audit committee, oversees Fortis’ ERM program ensuring that management has an effective risk management system to support strategic planning. The ERM program at the subsidiary level is overseen by each subsidiary's board of directors and any material risks identified form part of Fortis' ERM program. Materiality thresholds are reviewed annually. Systems of internal controls are used by management to monitor and manage identified risks. A summary of the Corporation's significant business risks follows.
Utility Regulation
Regulated utility assets represented approximately 99% of the Corporation's total assets as at December 31, 2023. Regulatory jurisdictions include five Canadian provinces, ten U.S. states and three Caribbean countries, as well FERC regulation for transmission assets in the U.S.
Regulators administer legislation covering material aspects of the utilities' business including: customer rates, allowed ROEs and deemed capital structures; capital expenditures; the terms and conditions for the provision of energy and capacity, ancillary services and affiliate services; securities issuances; and certain accounting matters. Regulatory or legislative changes and decisions, and delays in the recovery of costs in rates due to regulatory lag, could have a Material Adverse Effect. The risk of regulatory lag is particularly significant for UNS Energy given the use of historical test years by its regulator in setting customer rates.
The ability to recover the actual cost of service and earn the approved ROE or ROA typically depends upon achieving the forecasts established in the rate-setting process. For those utilities subject to PBR mechanisms, rates reflect assumed inflation rates and productivity improvement factors, and variances therefrom could adversely affect rates of return. Failure to recover costs and/or earn a return could have a Material Adverse Effect.
For transmission operations, the underlying elements of FERC-established formula rates can be challenged by third parties which could result in rate reductions and customer refunds. These underlying elements include the ROE, ROE adders and deemed capital structure, as well as operating and capital expenditures.
In addition, the U.S. Congress periodically considers enacting energy legislation that could assign new responsibilities to FERC, modify provisions of the U.S. Federal Power Act or the Natural Gas Act, or provide FERC or another entity with increased authority to regulate U.S. federal energy matters.
While Fortis is well-positioned to maintain constructive regulatory relationships through local management teams and subsidiary boards of directors comprised mostly of independent local members, it cannot predict future legislative or regulatory changes, whether caused by economic, political or other factors. The Corporation and its utilities may experience challenges and compliance costs in responding to such regulatory changes in an effective and timely manner. Any such regulatory changes or operational impacts could have a Material Adverse Effect.
Physical Risks
The provision of electric and gas service is subject to physical risks, including impacts from severe weather and natural disasters, wars, terrorism, vandalism, critical equipment failure and other catastrophic events within and outside the Corporation's service territories.
Certain electric utilities operate in remote or mountainous terrain that can be difficult to access for timely repairs and maintenance, or otherwise face risk of loss or damage from wildfires, floods, hurricanes, storm surges, washouts, landslides, earthquakes, avalanches, snow or ice storms, and other acts of nature. Also, the operation of electricity transmission and distribution assets has the potential to cause fires, mainly as a result of equipment failure, falling trees or lightning strikes to lines or equipment.
The gas utilities are exposed to operational risks associated with natural gas, including fires, explosions, pipeline corrosion and leaks, accidental damage to mains and service lines, equipment failure, damage and destruction from earthquakes, fires, floods and other natural disasters.
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| Management Discussion and Analysis |
Accidents or natural disasters affecting any of the Corporation's electricity or gas utilities can lead to service disruption, spills and commensurate environmental or other liability.
Generating equipment and facilities are subject to physical risks, including equipment breakdown or damage from fire, floods or other natural disasters, that may result in the uncontrolled release of water, interruption of fuel supply, lower-than-expected operational efficiency or performance, and service disruption.
The foregoing risks associated with fire damage vary depending on weather, forestation, the proximity of habitation and third-party facilities to utility facilities, and other factors. The utilities may become liable for fire-suppression costs, regeneration and timber value costs, and third-party claims if their facilities are determined to have been responsible for, or contributed to, a fire.
Electricity and gas systems require ongoing maintenance, improvement and replacement. The utilities are responsible for operating and maintaining their assets in a safe manner, including the development and application of appropriate standards, system processes and/or procedures to ensure the safety of employees, contractors and the general public.
Service disruption, other effects and liability, whether caused by the failure to properly implement or complete approved maintenance and capital expenditures, severe weather or other physical risks, if not mitigated through insurance policies or the recovery of such costs in customer rates, could result in loss. Any of the foregoing potential impacts of physical risk could have a Material Adverse Effect.
The foregoing physical risks can be exacerbated by the "Climate Change" risks discussed below.
Climate Change
Climate-Related Physical Risk
Climate change may negatively impact the ability to provide reliable and safe electric and gas service. The changing climate is predicted to lead to higher temperatures and more frequent and severe weather events which may impact or disrupt the reliability of electric or gas systems. The physical risks associated with a changing climate requires the Corporation’s utilities to respond to continue delivering reliable service to customers.
Severe weather and events related to severe weather impact the Corporation's service territories, primarily in the form of thunderstorms, flooding, wildfires, hurricanes, storm surges, atmospheric rivers and snow, or ice storms. Increased frequency of such events could increase the cost of providing service through increased repairs and use of contingency plans. Extreme weather conditions and changes in air temperature require system backup and can result in system stress, including service disruptions, and decreased efficiency of operating facilities over time. Changes in precipitation that impact soil moisture and water levels, or result in droughts, could increase the risk of wildfire caused by the Corporation's electricity assets or may cause water shortages that could adversely affect operations.
Longer-term climate change impacts, such as sustained higher temperatures, higher sea levels, larger storm surges and floods, could result in service disruption, shortened asset life, increased repair and replacement costs, and costs associated with strengthened design standards and systems. The impacts of climate change can intensify the "Physical Risks" (see "Physical Risks" on page 25).
The physical risks posed by the impacts of climate change and resultant damage to assets, service disruption repair and replacement costs, and liability for third party damages could have a Material Adverse Effect if not resolved in a timely and effective manner and/or mitigated through insurance policies or regulatory cost recovery. An increase in business risk associated with climate change can also impact credit ratings, which could affect credit risk spreads on new long-term debt and credit facilities, as well as their availability (see "Access to Capital" on page 31).
Climate-Related Transition Risk
As economies transition toward decarbonization and increase renewable energy use under various national and international commitments, risks arise related to associated policy, legal, technological and market changes, which may have related capital and financial implications for the Corporation and its utilities.
The impacts of the transition to a cleaner energy future will require the Corporation’s utilities to effectively manage, among other things, evolving regulatory and legislative requirements, new resiliency standards, the integration of new technologies and impacts on customer demand and rates. Failure to appropriately respond to climate change and decarbonize may disrupt the ability of the utilities to provide safe and cost-effective service, which could cause reputational harm and other impacts.
Fortis expects the pace of government policy and regulatory changes to accelerate in the coming years (see "Environmental Regulation" on page 27). Further, the emergence of initiatives designed to reduce GHG emissions, increase renewable energy use, and control or limit the effects of climate change has increased the incentive for the development of new technologies that produce renewable energy, enable more efficient storage of energy and reduce energy consumption. As new technologies become widely available, infrastructure design risks and time delays may emerge. Utility energy delivery systems will require technological changes and updates in order to effectively deliver increasing amounts of renewable energy to customers (see "Technology Developments" on page 28).
The availability of regulatory mechanisms or the ability of the Corporation's utilities to pass related costs on to customers remains uncertain. Regulatory lag in relation to the adoption of climate change initiatives and/or the availability of regulatory recovery mechanisms in certain jurisdictions could contribute to financial harm to Fortis and its utilities (see "Utility Regulation" on page 25).
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| Management Discussion and Analysis |
Fortis has a plan to reduce GHG direct emissions 50% by 2030 and 75% by 2035 from a 2019 base year. Technological advancements will be required in order for the Corporation to eliminate the last 25% of its GHG direct emissions by 2050 to achieve its net-zero target while preserving system reliability and customer affordability. In addition to the development and implementation of relevant energy technologies, the Corporation's ability to achieve its climate-related targets depends upon many factors, including the size of the Corporation's service territory, capacity needs remaining in line with current expectations, the impacts of future regulations or legislation, or the adoption of alternative energy products by the public, any of which could cause actual results and the ability to achieve such targets to materially differ from expectations. The ultimate impact of achieving or failing to achieve such targets could cause reputational damage which could result in a Material Adverse Effect.
Cybersecurity and Information and Operations Technology
As operators of critical energy infrastructure, the Corporation's utilities are at risk of cybercrime, including cyber attacks, data breaches, cyber extortion and similar compromises. The ability of the Corporation's utilities to operate effectively is dependent upon using and maintaining complex information systems and infrastructure that: (i) support the operation of generation, transmission and distribution facilities, including electric and gas facilities; (ii) provide customers with billing, consumption and load settlement information, where applicable; and (iii) support financial and general operations. The Corporation also engages third-party service providers to help facilitate the management and monitoring of the Corporation's information security systems, communication tools and data processing.
Information and operations technology systems, including those of the Corporation's third-party service providers, may be vulnerable to unauthorized access or disruption due to cyber- and other attacks, including hacking, malware, acts of war or terrorism, and acts of vandalism, among others. Further, geopolitical conflicts may further increase the sophistication, magnitude or frequency of cyberattacks, some of which may even be initiated by nation state actors. Any such event could result in the disruption of energy service and other business operations, including disruption of internal control processes, property damage, corruption or unavailability of critical data, and the theft, loss, misappropriation and/or disclosure of sensitive, confidential and proprietary business information, intellectual property, or personal information of customers and/or employees. The Corporation's exposure to these risks increases as the Corporation continues to partner with third-party providers (see "Reliance on Supply Chain and Third Parties" on page 30).
A material cybersecurity breach of the Corporation's information security systems or those of a third-party service provider, or any delay or failure in assessing the materiality of such breach and related reporting/disclosure, could adversely affect the financial performance of the Corporation, its reputation and standing with customers, regulators and financial markets, and expose it to claims for third-party damages or regulatory penalties. The resultant financial impacts may not be fully covered by insurance policies or, in the case of utilities, through regulatory cost recovery, and could have a Material Adverse Effect.
Growth
Fortis has a history of both growth through acquisitions and organic growth from capital investment in existing service territories. The Corporation's dividend growth guidance is significantly dependent upon achieving the Rate Base growth expected from the execution of the five-year Capital Plan as described under "Capital Plan" on page 21. Projects, particularly Major Capital Projects, are subject to risks of delay and cost overruns during construction caused by commodity price fluctuations, supply and labour costs, supply chain constraints, supplier non-performance, weather, geologic conditions or other factors beyond the Corporation's control. There is no assurance that regulators will approve: (i) all of the planned projects or their amounts or timing; (ii) permits in a timely manner, or with reasonable terms and conditions; or (iii) the recovery of cost overruns in customer rates, which may have a Material Adverse Effect.
Environmental Regulation
The Corporation's businesses are subject to environmental laws and regulations, including those which concern emissions into the air, discharges into water or soil, use of water, hazardous waste disposal and containment, and the investigation and remediation of contamination, among others.
The risk of contamination of air, soil and water associated with electricity operations primarily relates to: (i) the transportation, handling, storage and combustion of fuel; (ii) the use of petroleum-based products, mainly transformer and lubricating oil; (iii) the management and disposal of coal combustion residuals and other wastes; and (iv) accidents resulting in hazardous release at or from coal mines that supply generating facilities. Contamination risks at gas operations primarily relate to leaks and other accidents involving gas systems. The key environmental risks for hydroelectric generation operations include dam failures and the creation of artificial water flows that may disrupt natural habitats.
Failure to comply with environmental laws and regulations, or to obtain or comply with any necessary environmental permits pursuant to such laws and regulations, could result in injunctions, fines or other penalties. Further, liabilities relating to contamination investigation and remediation, and related claims for personal injury or property damage, may arise at many locations, including formerly and currently owned/operated properties and waste treatment or disposal sites, regardless of whether such contamination was caused by the business at the time it owned the property, whether it resulted from non-compliance with applicable environmental laws and regulations, or whether it resulted from any act or omission of the business. These liabilities could result in substantial monetary judgments for clean-up costs, damages, fines and/or penalties. To the extent not fully covered by insurance or through regulatory mechanisms, these foregoing costs could have a Material Adverse Effect.
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27 | FORTIS INC. | DECEMBER 31, 2023 |
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| Management Discussion and Analysis |
Environmental laws and regulations continue to develop and may result in significant additional expense. In particular, the management of GHG emissions and related decarbonization requirements is a major concern due to new and emerging federal, state and provincial GHG laws, regulations and guidelines. Regulation and the pace of regulatory change to address reliability, resiliency, resource planning and safety is expected to increase in response to climate change. Future legislation could impact generation assets, operations, energy supply, operational costs, reporting obligations and other material aspects of the Corporation's business. Increased compliance costs or additional operating restrictions from revised or additional regulation could have a Material Adverse Effect (see "Climate Change" at page 26).
Health and Safety
The operations of the Corporation's utilities inherently involve risk to the health and safety of both employees and the public. Personal injury or loss of life could result from failure to implement or observe appropriate health and safety procedures and gives rise to operational, reputational or financial impacts, any of which could have a Material Adverse Effect. In addition, failure to comply with health and safety regulations could result in fines, penalties, reputational damage, litigation, increased capital and operating costs or adverse regulatory outcomes.
Natural Gas Competitiveness
Approximately 21% of the Corporation's revenue is derived from the delivery of natural gas. In British Columbia, which accounts for 80% of the Corporation's natural gas revenue, natural gas primarily competes with electricity for space and hot water heating load. Upfront capital costs for gas service continue to present competitive challenges for natural gas compared to electricity service. If gas becomes less competitive due to price or other factors, such as government policy or public perception of natural gas or its carbon intensity relative to other energy sources, the ability to add new customers could be impaired. Existing customers could also reduce their consumption or switch to electricity, placing further pressure on rates and, in the extreme, could ultimately lead to an inability to recover the utility's cost of service through customer rates.
Government policy could further impact the competitiveness of natural gas in British Columbia. As governments develop policies to address climate change, any resultant changes to energy policy may impact the competitiveness of natural gas relative to other energy sources.
Additionally, there are other competitive challenges that are impacting the penetration of natural gas into new housing stock such as the carbon intensity of the energy source and the type of housing stock being built. As part of their own climate change policy plans, local governments may use various tools at their disposal such as franchise agreements, permits, building codes and zoning bylaws to impose limitations on energy sources permitted in new and existing developments. Municipalities can also provide incentives, such as higher density allowance, to builders to adopt carbon free energy options for their developments. These actions and policies may hinder the Corporation's ability to attract new natural gas customers or retain existing customers.
A decrease in the competitiveness of natural gas due to pricing, government policy or other factors could have a Material Adverse Effect.
Political Environment
The political environment, at the local, national or global level, may impact energy laws, governmental energy policies or regulatory decisions. For example, political pressure or intervention to address energy prices and customer affordability concerns may impact regulatory decisions, as well as the period over which the Corporation’s utilities recover allowed costs.
The business is further exposed to risks associated with international relations and geopolitical events. Political, economic or social instability or events, trade disputes, increased tariffs, changes in laws or the imposition of onerous regulations applicable to existing operations, currency restrictions, and the impacts of changes in political leadership could lead to an increase in commodity prices, impact the availability and cost of energy or generally affect global economic conditions, any of which could have a Material Adverse Effect (see "Environmental Regulation" at page 27 and "General Economic Conditions" at page 29).
Technology Developments
New technology developments in distributed generation, particularly solar, and energy efficiency products and services, as well as the implementation of renewable energy and energy efficiency standards, will continue to impact retail sales. Heightened awareness of energy costs and environmental concerns have increased demand for products that reduce energy consumption. The Corporation's utilities are also promoting demand-side management programs. New technologies available to customers include energy derived from renewable sources, customer-owned generation, energy-efficient appliances, battery storage and control systems. Advances in these or other technologies could have a significant impact on retail sales with a potential Material Adverse Effect.
Further, the implementation of new information technology systems and emerging technologies, such as cloud computing and artificial intelligence, into the business, including those impacting utility operations and customer billing systems, carries risk that any such technology or system will not operate as expected. Failure to maintain, upgrade, replace or properly implement such new technology or systems could result in increased risk of a cybersecurity incident and have an adverse effect on operational efficiency, revenue or reputation (see "Cybersecurity and Information and Operations Technology" on page 27).
Weather Variability and Seasonality
Electricity consumption varies significantly in response to seasonal weather changes which have been and will continue to be impacted by climate change (see "Climate Change" on page 26). Cool summers may reduce the use of air conditioning and other cooling equipment, while less severe winters may reduce heating load. Alternatively, severe weather could unexpectedly increase heating and cooling loads, negatively impacting system reliability. Hydroelectric generation is sensitive to rainfall levels and unexpected variations in seasonal rainfall levels can negatively impact operations.
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28 | FORTIS INC. | DECEMBER 31, 2023 |
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| Management Discussion and Analysis |
Weather and seasonality have a significant impact on gas distribution volumes as a major portion of natural gas is used for space heating by residential customers. The earnings of the Corporation's gas utilities are typically highest in the first and fourth quarters. Regulatory deferral and revenue decoupling mechanisms are in place at certain of the Corporation's utilities to minimize the volatility in earnings that would otherwise be caused by variations in weather conditions. The absence or the discontinuance of key regulatory mechanisms could result in significant and prolonged weather variations from seasonal norms having a Material Adverse Effect.
Required Approvals
The acquisition, ownership and operation of electric and gas businesses require numerous licences, permits, agreements, orders, certificates, consultations, and other approvals from various levels of government, regulators, government agencies and/or other third parties. There is no assurance that: (i) such approvals will be obtained, continuously maintained or renewed without delay; and (ii) the terms and conditions thereof will be fully complied with at all times and will not change in a material adverse manner. Significant failures in these regards could prevent the operation of the businesses and have a Material Adverse Effect.
Reliability Standards
The Energy Policy Act of 2005 provides for a regulatory framework which requires owners, operators and users of the bulk electric system in the U.S. to meet mandatory reliability standards developed by the North American Electric Reliability Corporation and its regional entities, which are approved and enforced by FERC. Many of these, or similar, standards have been adopted in certain Canadian provinces including British Columbia and Alberta. The failure to develop, implement and maintain appropriate operating practices/systems and capital plans to address reliability obligations could lead to compliance violations and a Material Adverse Effect, including as a result of the exclusion of related costs from customer rates and other potentially significant penalties.
Indigenous Peoples' Land Claims
In British Columbia, the Corporation's utilities provide service to customers on Indigenous Peoples' lands and maintain facilities on lands that are subject to Indigenous Peoples' land claims. Various treaty negotiation processes involving Indigenous Peoples and the Governments of British Columbia and Canada are underway, but the basis for potential settlements is unclear and not all Indigenous Peoples are participating in such processes. To date, the policy of the Government of British Columbia has been to structure settlements without prejudicing existing third-party rights; however, there is no assurance that the settlement processes will not have a Material Adverse Effect.
FortisAlberta has distribution assets on Indigenous Peoples' lands in Alberta with access permits held by a third party. Some of these permits require approvals from First Nations and Crown-Indigenous Relations and Northern Affairs Canada. FortisAlberta may be unable to obtain such approvals or negotiate land-use agreements with reasonable terms. Significant failures in these regards could have a Material Adverse Effect.
Certain jointly owned facilities and portions of TEP's transmission lines are located on tribal lands pursuant to leases, land easements and other rights-of-way that are effective for specified time periods. The inability to receive future approvals for continued access to the facilities and land could have a Material Adverse Effect.
Joint-Ownership Interests and Third-Party Operators
Certain generating facilities from which TEP receives power are jointly owned with, or are operated by, third parties. TEP may not have sole discretion or any ability to affect the management or operations of such facilities, including how to best address changing economic conditions or environmental requirements. A divergence in the interests of TEP and those of the joint owners or operators could have a Material Adverse Effect.
Wataynikaneyap Partnership, which is owned 51% by 24 First Nations communities and 49% by a partnership between Fortis (80%) and Algonquin Power & Utilities Corp. (20%), is responsible for the Wataynikaneyap Transmission Power Project. Fortis does not have sole discretion on decisions for the project and divergence in the interest of Fortis and the other partners could delay the project's completion, increase its anticipated cost, or adversely affect the reputation of Fortis, any of which could have a Material Adverse Effect.
General Economic Conditions
Fluctuations in general economic conditions, inflation, energy prices, employment levels, personal disposable incomes, housing starts, industrial activity and other factors may lower energy demand and sales and reduce capital spending, particularly to the extent that related customer and Rate Base growth are impacted. A severe and prolonged economic downturn could also impair customers' ability to pay their bills in a timely manner. Each of these factors could lead to the impairment of goodwill or other long-term assets, and could have a Material Adverse Effect. Further, the impact of macroeconomic factors, including, but not limited to, international relations and geopolitical events, could cause weaker economic conditions or increase the volatility of the equity capital markets, which could impact the business and financial condition of the Corporation or adversely impact the Corporation's share price.
Commodity Price Volatility
Purchased power and gas, and generation fuel costs are subject to commodity price volatility, which is managed through regulator-approved: (i) mechanisms that permit the flow through in customer rates of commodity price changes and/or that provide for rate-stabilization and other deferral accounts; and (ii) price-risk management strategies such as the use of derivative contracts that effectively fix costs (see "Financial Instruments - Derivatives" on page 35).
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| Management Discussion and Analysis |
There is no assurance that current regulator-approved mechanisms or strategies will continue to exist in the future. Additionally, despite these mechanisms and strategies, severe and prolonged commodity price increases could result in rates that customers are unable to pay and/or could affect consumption and sales growth, which could have a Material Adverse Effect.
Purchased Power Supply
A significant portion of electricity and gas sold by the Corporation's utilities is purchased through the wholesale energy markets or pursuant to contracts with energy suppliers and is not being produced by the Corporation's utilities. A disruption in the wholesale energy markets, or a failure on the part of energy or fuel suppliers or operators of energy delivery systems that connect to the Corporation's utilities, could result in a loss and/or increase in the cost of purchased power and gas, which could have a Material Adverse Effect. The cost and availability of purchased power and gas may be adversely impacted by factors discussed under "Climate Change" on page 26, "Environmental Regulation" on page 27 and "Commodity Price Volatility" on page 29.
Counterparty Credit Risk
ITC has a concentration of credit risk as approximately 70% of its revenue is derived from three customers. These customers have investment-grade credit ratings and credit risk is further managed by MISO by requiring a letter of credit or cash deposit equal to the credit exposure, which is determined by a credit-scoring model and other factors.
FortisAlberta has a concentration of credit risk as its distribution service billings are to a relatively small group of retailers. Credit risk is managed by obtaining from the retailers either a cash deposit, letter of credit, an investment-grade credit rating, or a financial guarantee from an entity with an investment-grade credit rating.
Central Hudson has seen an increase in accounts receivable due to the suspension of collection efforts in response to the COVID-19 Pandemic, as well as higher commodity prices. Central Hudson continues to proactively contact customers regarding past-due balances to advise them of financial assistance available through state programs, and collection efforts continue to expand. Under its regulatory framework, Central Hudson can defer uncollectible write-offs that exceed 10 basis points above the amounts collected in customer rates for future recovery.
UNS Energy, Central Hudson, FortisBC Energy, and Fortis may be exposed to credit risk from non‑performance by counterparties to derivative contracts. Credit risk is managed by net settling payments, when possible, and dealing only with counterparties that have investment-grade credit ratings. At UNS Energy, Central Hudson and FortisBC Energy, certain contractual arrangements require counterparties to post collateral.
There is no assurance that credit risk management strategies will continue to be effective. Significant counterparty defaults could have a Material Adverse Effect.
Reliance on Supply Chain and Third Parties
Domestic and global supply chain disruptions, as a result of either physical or cyber issues, may delay the delivery or result in shortages of certain materials, equipment and other resources that are critical to the operation of the Corporation's utilities. Failure to eliminate or manage constraints in the supply chain may impact the availability of items that are necessary to support operations as well as materials that are required for continued infrastructure growth and could have a Material Adverse Effect. Further, cybersecurity incidents in the Corporation's supply chain or cyber attacks originating from the Corporation's supply chain may further result in disruption of energy service and other business operations which could have a Material Adverse Effect.
Interest Rates
Generally, the market price of the Corporation's common shares is inversely correlated to interest rate changes. Additionally, allowed ROEs are exposed to changes in long-term interest rates. While a rising interest rate environment could result in higher allowed ROEs, such ROE changes tend to lag as a result of regulatory timelines. Borrowings under variable-rate credit facilities and long-term debt, as well as new debt issuances, are also exposed to interest rate changes. Although interest costs at the regulated utilities are generally recovered through customer rates, the discontinuance of regulatory mechanisms that permit the flow-through of actual interest costs, the impact of regulatory lag at UNS Energy, and higher finance costs on holding company debt could have a Material Adverse Effect.
Foreign Exchange Exposure
As at December 31, 2023, 67% of the Corporation's assets were located outside Canada and 61% of 2023 revenue was derived from foreign operations. The reporting currency of ITC, UNS Energy, Central Hudson, Caribbean Utilities, FortisTCI, Fortis Belize and Belize Electricity is, or is pegged to, the U.S. dollar. The earnings and cash flow from, and net investments in, these entities are exposed to fluctuations in the U.S. dollar-to-Canadian dollar exchange rate. The Corporation’s $25 billion five-year Capital Plan for 2024 through 2028 also includes exposure to foreign exchange.
Fortis has limited its U.S. dollar currency exposure through hedging. The Corporation has issued and designated U.S. dollar-denominated long-term debt as an effective hedge of foreign net investments. Fortis has also entered into foreign exchange contracts and cross-currency swaps to manage a portion of its exposure to foreign currency risk.
Given only partial hedging, earnings and cash flow continue to be impacted by exchange rate fluctuations. In addition, there is no assurance that existing hedging strategies will continue to be effective, and therefore a significant, prolonged decrease in the U.S. dollar-to-Canadian dollar exchange rate could have a Material Adverse Effect.
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30 | FORTIS INC. | DECEMBER 31, 2023 |
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| Management Discussion and Analysis |
Access to Capital
The Corporation and certain of its subsidiaries have incurred material amounts of indebtedness. Ongoing access to cost-effective capital is required to fund, among other things, capital expenditures and the repayment of maturing debt.
Operating Cash Flow may not be sufficient to fund the repayment of all outstanding liabilities when due or fund anticipated capital expenditures.
The ability to meet long-term debt repayments is dependent upon obtaining sufficient and cost-effective financing to replace maturing indebtedness. The ability to arrange financing is subject to numerous factors, including the results of operations and financial condition of Fortis and its subsidiaries, the regulatory environments including regulatory decisions regarding capital structure and allowed ROEs, capital market conditions, general economic conditions, credit ratings, and the environmental, social and governance profile of Fortis and its subsidiaries. Changes in credit ratings could affect credit risk spreads on new long-term debt and credit facilities, as well as their availability.
Fortis is a holding company and, as such, has no revenue-generating operations of its own. The Corporation’s subsidiaries are separate legal entities and have no independent obligation to pay dividends to Fortis. Prior to paying dividends to the Corporation, the subsidiaries have financial obligations that must be satisfied, including, among others, their operating expenses and obligations to creditors. Furthermore, the Corporation’s utilities are required by regulation to maintain a minimum equity-to-total capital ratio that may restrict their ability to pay dividends to the Corporation or may require the Corporation to contribute capital to such subsidiaries. The future enactment of laws or regulations may prohibit or further restrict the ability of the Corporation's subsidiaries to pay dividends or to repay intercorporate indebtedness. In addition, in the event of a subsidiary’s liquidation or reorganization, the Corporation’s right to participate in a distribution of assets is subject to the prior claims of the subsidiary’s creditors. As a result, the Corporation’s ability to generate cash flow to service its debt obligations and pay dividends is reliant on the ability of its subsidiaries to generate sustained earnings and cash flows and to pay dividends and repay loans.
There is no assurance that sufficient capital will continue to be available on acceptable terms. For further information see "Liquidity and Capital Resources" on page 17.
Taxation
Earnings at Fortis and its subsidiaries could be impacted by changes in income tax rates and other tax legislation in Canada, the U.S. and other international jurisdictions. The nature, timing or impact of changes in tax laws cannot be predicted and could have a Material Adverse Effect. Although income taxes at the regulated utilities are generally recovered in customer rates, tax-related regulatory lag can result in recovery delays or non-recovery for certain periods. At the non-regulated level, changes in income tax rates and other tax legislation could materially affect the after-tax cost of existing and future debt which is not recoverable in customer rates.
Insurance
Insurance is maintained with reputable industry insurers for property damage, potential liabilities and business interruption for coverage considered appropriate and in accordance with industry practice.
A significant portion of transmission and distribution assets is uninsured, as is customary in North America, as the cost to insure such assets is prohibitive. Insurance is subject to coverage limits and deductibles, as well as time-sensitive claims discovery and reporting provisions. There is no assurance that: (i) the amounts and types of losses from actual damage, liabilities or business interruption will be fully covered by insurance; (ii) regulatory relief would be obtained for coverage shortfalls; (iii) adequate insurance at reasonable rates will continue to be available; or (iv) insurers will fulfill their obligations. Significant actual shortfalls in insurance coverage or claims payment could have a Material Adverse Effect. The availability and cost of certain types of insurance may be adversely impacted by the risks described under "Climate Change" on page 26.
Pandemics and Public Health Crises
The Corporation could be negatively impacted by widespread outbreaks of communicable diseases or other public health crises that cause economic and/or other disruptions. Outbreaks of communicable diseases, as well as efforts to reduce the health impacts and control disease spread, can lead to restrictions on business operations, including business closures and the potential impacts of reduced labour availability and productivity, supply chain disruptions, project construction delays, disruptions to capital markets, governmental and regulatory action, and a prolonged reduction in economic activity. An extended economic slowdown could reduce energy sales and adversely impact the ability of customers, contractors and suppliers to fulfill their obligations and could disrupt operations and capital expenditure programs or cause impairment of goodwill (see "General Economic Conditions" on page 29).
The Corporation's utilities provide essential services and must be operational and maintained throughout any pandemic or public health crisis, though such events can challenge operations and increase operating costs. The duration and severity of a pandemic or public health crisis could have a Material Adverse Effect.
Talent Management
The delivery of safe, reliable and cost-effective service depends on the attraction, development and retention of a skilled workforce as well as filling strategic positions. Like its peers, Fortis faces demographic challenges and competitive markets relating to trades, technical and professional staff, particularly considering its significant Capital Plan. ITC relies heavily on agreements with third parties to provide services for the construction, maintenance and operation of certain aspects of its business. Significant failures in attracting or retaining a skilled workforce or filling strategic positions within the Corporation or its utilities could have a Material Adverse Effect.
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31 | FORTIS INC. | DECEMBER 31, 2023 |
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| Management Discussion and Analysis |
Labour Relations
Most of the Corporation's utilities employ members of labour unions or associations under collective bargaining agreements. Fortis considers its labour relationships to be satisfactory, but there is no assurance that this will continue or that existing collective bargaining agreements will be renewed on reasonable terms without work disruption or other job action. Significant failures in these regards could cause service interruptions and/or labour cost increases for which regulators may not allow full recovery in customer rates, and could have a Material Adverse Effect.
Post-Retirement Obligations
Fortis and most of its subsidiaries maintain a combination of defined benefit pension and/or OPEB plans for certain employees and retirees. The most significant cost drivers for these plans are investment performance and interest rates, which are affected by global financial markets. Regulatory deferral mechanisms are in place at many of the Corporation’s utilities that permit the flow through in customer rates of certain impacts associated with market fluctuations. Severe and prolonged market disruptions, significant declines in the market values of investments held to meet plan obligations, discount rate changes, participant demographics, changes in laws and regulations, as well as changes in existing regulatory treatment of post-retirement benefit costs, may increase plan expenses or require additional plan funding and could have a Material Adverse Effect.
Reputation, Relationships and Stakeholder Activism
There can be no assurance that internal processes, controls or audits will ensure compliance with the Corporation's internal policies, including its Code of Conduct, or anti-bribery and anti-corruption laws. Employees, affiliates, independent contractors or agents may violate such policies and laws, which may potentially lead to reputational damage, in addition to potential fines, penalties or litigation, any of which could have a Material Adverse Effect.
The Corporation's operations and growth prospects require strong relationships with key stakeholders, including regulators, governments and agencies, Indigenous communities, landowners, and environmental organizations. Inadequately managing expectations and issues important to stakeholders, including those arising during construction of Major Capital Projects, could affect the Corporation's reputation as well as have a significant impact on its operations and infrastructure development. See "Required Approvals" and "Indigenous Land Claims" at page 29.
External stakeholders are increasingly challenging companies regarding climate change, sustainability, diversity, returns (including ROEs and ROAs), executive compensation and other matters. Public opposition to larger infrastructure projects is becoming increasingly common, which can challenge capital plans and resultant organic growth. While the Corporation actively monitors such activism and is committed to developing stronger relationships with its external stakeholders, failure to effectively manage or respond to stakeholder activism could have a Material Adverse Effect.
DCP and ICFR
DCP and ICFR may not prevent or detect all misstatements, and even those controls determined to be effective can only provide reasonable, not absolute, assurance with respect to financial statement preparation and presentation. Failure to adequately prevent, detect and correct misstatements could have a Material Adverse Effect.
Legal, Administrative and Other Proceedings
Legal, administrative and other proceedings arise in the ordinary course of business and may include environmental claims, employment-related claims, securities-based litigation, contractual disputes, personal injury or property damage claims, actions by regulatory or tax authorities, and other matters. Unfavourable outcomes such as judgments or settlements for monetary or other damages, injunctions, denial or revocation of permits, reputational harm, and other results could have a Material Adverse Effect.
ACCOUNTING MATTERS
Future Accounting Pronouncements
Segment Reporting
ASU No. 2023-07, Improvements to Reportable Segment Disclosures, issued in November 2023, is effective for Fortis on January 1, 2024 for annual periods and on January 1, 2025 for interim periods, both on a retrospective basis. The ASU requires disclosure of incremental segment information on an annual and interim basis, including significant segment expenses and other segment items that are included in segment profit or loss. Fortis is assessing the impact of adoption on its disclosures.
Income Taxes
ASU No. 2023-09, Improvements to Income Tax Disclosures, issued in December 2023, is effective for Fortis on January 1, 2025 on a prospective basis, with retrospective application and early adoption permitted. The ASU requires additional disclosure of income tax information by jurisdiction to reflect an entity's exposure to potential changes in tax legislation, and associated risks and opportunities. Fortis is assessing the impact of adoption on its disclosures.
Additional information about future accounting pronouncements is provided in Note 3 in the 2023 Annual Financial Statements.
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32 | FORTIS INC. | DECEMBER 31, 2023 |
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| Management Discussion and Analysis |
Critical Accounting Estimates
General
The preparation of the 2023 Annual Financial Statements required management to make estimates and judgments that affect the reported amounts of, and disclosures related to, assets, liabilities, revenues, expenses, gains, losses and contingencies. Management evaluates these estimates on an ongoing basis based upon historical experience, current conditions, and assumptions believed to be reasonable at the time they are made, with any adjustments recognized in the period they become known. Actual results may differ significantly from these estimates.
Regulatory Assets and Liabilities
As at December 31, 2023, Fortis recognized regulatory assets of $4.4 billion (2022 - $4.0 billion) and regulatory liabilities of $4.0 billion (2022 - $3.9 billion).
Regulatory assets represent future revenues and/or receivables associated with certain costs incurred that will be, or are expected to be, recovered from customers in future periods through the rate-setting process. Regulatory liabilities represent: (i) future reductions or limitations of increases in revenue associated with amounts that will be, or are expected to be, refunded to customers through the rate-setting process; or (ii) obligations to provide future service that customers have paid for in advance.
The recognition of regulatory assets and liabilities and the period(s) of settlement are often estimates based on past, existing or expected regulatory orders in relation to the nature of the underlying amounts, and are subject to regulatory approval. There is no assurance that actual settlement amounts and the related settlement periods will not be materially different from those estimated. Differences arising from the regulator's orders would be recognized in accordance with those orders, whereby any amounts disallowed would be immediately recognized in earnings with the remainder recognized in earnings in accordance with their inclusion in customer rates.
| | | | | | | | | | | | | | | | | | | | | | | |
| Employee Future Benefits | | | | | | | |
| Key Estimates and Assumptions | Defined Benefit Pension Plans | | OPEB Plans |
| Years ended December 31 | |
| ($ millions, except as indicated) | 2023 | | | 2022 | | | 2023 | | | 2022 | |
Funded status: (1) | | | | | | | |
Benefit obligation (2) | (3,347) | | | (3,063) | | | (596) | | | (582) | |
| Plan assets | 3,313 | | | 3,079 | | | 430 | | | 389 | |
| (34) | | | 16 | | | (166) | | | (193) | |
Net benefit cost (2) | 21 | | | 19 | | | 15 | | | 26 | |
Key assumptions: (weighted average %) | | | | | | | |
| | | | | | | |
| | | | | | | |
Discount rate as at December 31 (3) | 4.84 | | | 5.27 | | | 4.94 | | | 5.36 | |
Expected long-term rate of return on plan assets (4) | 6.58 | | | 5.87 | | | 5.92 | | | 5.00 | |
Rate of compensation increase | 3.37 | | | 3.33 | | | — | | | — | |
Health care cost trend increase rate (5) | — | | | — | | | 4.52 | | | 4.48 | |
(1)Periodic actuarial valuations determine funding contributions for the pension plans and U.S. OPEB plans, while Canadian OPEB plans are unfunded
(2)Actuarially determined using the projected benefits method prorated on service and management's best estimate of expected plan investment performance, salary escalation, average remaining service life of employees, mortality rates and, for OPEB plans, expected health care costs
(3)Reflects market interest rates on high‑quality bonds with cash flows that match the timing and amount of expected pension payments. The discount rate used during the year for defined benefit pension plans is 5.36% (2022 - 2.97%) and 5.39% (2022 - 2.97%) for OPEB Plans
(4)Developed using best estimates of expected returns, volatilities and correlations for each class of asset. Estimates are based on historical performance, future expectations and periodic portfolio rebalancing among the diversified asset classes
(5)Actuarially determined, the projected 2024 rate is 5.95% and is assumed to decrease over the next 10 years to the ultimate rate of 4.52% in 2033 and thereafter
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| Sensitivity Analysis | Rate of Return | | Discount Rate | | Health Care Costs
Trend Rate |
Year ended December 31, 2023 | 1% change | | 1% change | | 1% change |
| ($ millions) | Increase | | Decrease | | Increase | | Decrease | | Increase | | Decrease |
| Defined benefit pension plans: | | | | | | | | | | | |
| Net benefit cost | (30) | | | 26 | | | (29) | | | 38 | | | n/a | | n/a |
| Projected benefit obligation | 8 | | | (58) | | | (382) | | | 456 | | | n/a | | n/a |
| OPEB plans: | | | | | | | | | | | |
| Net benefit cost | (4) | | | 4 | | | (9) | | | 10 | | | 13 | | | (11) | |
| Accumulated benefit obligation | — | | | — | | | (71) | | | 87 | | | 66 | | | (63) | |
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33 | FORTIS INC. | DECEMBER 31, 2023 |
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| Management Discussion and Analysis |
At the regulated utilities, changes in net benefit cost are generally expected to be reflected in customer rates, subject to regulatory lag and forecast risk at certain utilities.
ITC, Central Hudson, FortisBC Energy, FortisBC Electric and Newfoundland Power have regulator‑approved mechanisms to defer variations between actual net pension cost and that forecast and reflected in customer rates. There is no assurance that these deferral mechanisms will continue in the future.
Depreciation and Amortization
As at December 31, 2023, Fortis recognized property, plant and equipment and intangible assets of $44.9 billion (2022 - $43.2 billion) representing 68% of total assets (2022 - 67%). Depreciation and amortization of these assets totalled $1.7 billion for 2023 (2022 - $1.6 billion).
Depreciation and amortization reflect the estimated useful lives of the underlying assets, which considers historical experience, manufacturers' ratings and specifications, the past and expected future pattern and nature of usage, and other factors.
At the regulated utilities, depreciation rates require regulatory approval and include a provision for estimated future removal costs, not identified as a legal obligation. Estimates primarily reflect historical experience and expected cost trends. The provision is recognized as a long-term regulatory liability against which actual removal costs are netted when incurred. As at December 31, 2023, this regulatory liability was $1.5 billion (2022 - $1.3 billion).
Depreciation rates at the regulated utilities are typically determined through periodic depreciation studies performed by external experts. Where actual experience differs from previous estimates, resultant differences are generally reflected in future depreciation rates and thereby recovered or refunded through customer rates in the manner prescribed by the regulator.
Goodwill Impairment
As at December 31, 2023, Fortis recognized goodwill of $12.2 billion (2022 - $12.5 billion), representing 18% of total assets (2022 - 19%). The decrease in goodwill was due to a lower U.S.-to-Canadian dollar exchange rate at December 31, 2023 in comparison to December 31, 2022, and the associated impact on the translation of U.S. dollar-denominated goodwill. Goodwill was also reduced by $27 million in 2023 due to the disposition of Aitken Creek.
Goodwill at each of the Corporation's reporting units is tested for impairment annually and whenever an event or change in circumstances indicates that fair value may be below carrying value. If so determined, goodwill is written down to estimated fair value and an impairment loss is recognized.
The Corporation performs a qualitative assessment on each reporting unit and if it is determined that it is not likely that fair value is less than carrying value, then a quantitative estimate of fair value is not required. When a quantitative assessment is performed, the primary method for estimating fair value of the reporting units is the income approach, whereby net cash flow projections are discounted. Underlying estimates and assumptions, with varying degrees of uncertainty, include the amount and timing of expected future cash flows, growth rates, and discount rates. A secondary valuation, the market approach along with a reconciliation of the total estimated fair value of all the reporting units to the Corporation's market capitalization, is also performed and evaluated.
The recognition of impairment losses could have a Material Adverse Effect. Such losses are not recoverable in regulated utility rates. To the extent impairment losses signal lower expected future cash flows to support interest payments on unregulated holding company debt and dividends on common shares, they could adversely affect the future cost of such capital, expressed as higher interest rates on such debt, which is not recoverable in regulated utility rates, and lower common share market prices.
Income Tax
As at December 31, 2023, deferred income tax liabilities, income tax receivable included in accounts receivable and other current assets, deferred income taxes included in regulatory assets, and deferred income taxes included in regulatory liabilities totalled $4.4 billion, $78 million, $2.1 billion and $1.3 billion, respectively (2022 - $4.1 billion, income tax payable in accounts payable and other current liabilities of $88 million, $1.9 billion and $1.4 billion, respectively). Income tax expense was $360 million in 2023 (2022 - $289 million).
Current income taxes reflect the estimated taxes payable/receivable in the current year based on enacted tax rates and laws, and the estimated proportion of taxable earnings/loss attributable to various jurisdictions.
Deferred income tax assets and liabilities reflect temporary differences between the tax and accounting basis of assets and liabilities. A deferred income tax asset or liability is determined for each temporary difference based on enacted income tax rates and laws in effect when the temporary differences are expected to be recovered or settled. A valuation allowance is recognized in earnings to the extent that future tax recovery is not assessed as "more likely than not".
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34 | FORTIS INC. | DECEMBER 31, 2023 |
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| Management Discussion and Analysis |
At the regulated utilities, differences between the income tax expense or recovery recognized under U.S. GAAP and reflected in customer rates, which is expected to be recovered from, or refunded to, customers in future rates, are recognized as regulatory assets or liabilities. These are subsequently amortized to earnings in accordance with their inclusion in customer rates pursuant to the regulator's orders. Otherwise, changes in expectations and resultant estimates arising from changes in tax rates, tax laws, jurisdictional earnings allocations and other factors are recognized in earnings upon occurrence.
The Corporation and certain of its subsidiaries are subject to taxation in Canada, the United States and other foreign jurisdictions. The material jurisdictions in which the Corporation is subject to potential income tax compliance examinations include the United States (Federal, Arizona, Kansas, Iowa, Michigan, Minnesota and New York) and Canada (Federal, British Columbia and Alberta). The Corporation's 2018 to 2023 taxation years are still open for audit in Canadian jurisdictions, and its 2019 to 2023 taxation years are still open for audit in U.S. jurisdictions. The impact of such income tax compliance examinations could be material to the Corporation (see "Business Risks - Taxation" on page 31).
In 2023, the U.S. introduced a 15% corporate alternative minimum income tax. There was no material impact to Fortis in 2023 and the Corporation does not currently expect it to have a material impact on its financial results, Operating Cash Flow or credit ratings over the five-year planning period.
In November 2023, the Canadian Department of Finance updated its draft legislation with respect to interest deductibility limitations and global minimum tax. Legislation is expected to be enacted in 2024 with an effective date of January 1, 2024. While this limitation and tax are expected to be applicable to Fortis, the Corporation does not currently expect it to have a material impact on its financial results, Operating Cash Flow or credit ratings.
Derivatives
The fair values of derivatives are based on estimates that cannot be determined with precision as they involve uncertainties and matters of judgment and, therefore, may not be relevant in predicting future earnings or cash flows.
Contingencies
The Corporation and its subsidiaries are subject to various legal proceedings and claims arising in the ordinary course of business, including those generally described under "Business Risks - Legal, Administrative and Other Proceedings" on page 32, for which no amounts have been accrued because the outcomes currently cannot be reasonably determined. Further information is provided in Note 27 in the 2023 Annual Financial Statements.
FINANCIAL INSTRUMENTS
Long-Term Debt and Other
As at December 31, 2023, the carrying value of long-term debt, including the current portion, was $29.7 billion (2022 - $28.6 billion) compared to an estimated fair value of $27.9 billion (2022 - $25.8 billion).
The consolidated carrying value of the remaining financial instruments, other than derivatives, approximates fair value, reflecting their short-term maturity, normal trade credit terms and/or nature.
Derivatives
The Corporation generally limits the use of derivatives to those that qualify as accounting, economic or cash flow hedges, or those that are approved for regulatory recovery. Derivatives are recorded at fair value, with certain exceptions, including those derivatives that qualify for the normal purchase and normal sale exception.
Energy contracts subject to regulatory deferral
UNS Energy holds electricity power purchase contracts, customer supply contracts and gas swap contracts to reduce its exposure to energy price risk. Fair values are measured primarily under the market approach using independent third-party information, where possible. When published prices are not available, adjustments are applied based on historical price curve relationships, transmission costs and line losses.
Central Hudson holds swap contracts for electricity and natural gas to minimize price volatility by fixing the effective purchase price. Fair values are measured using forward pricing provided by independent third-party information.
FortisBC Energy holds gas supply contracts to fix the effective purchase price of natural gas. Fair values reflect the present value of future cash flows based on published market prices and forward natural gas curves.
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35 | FORTIS INC. | DECEMBER 31, 2023 |
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| Management Discussion and Analysis |
Unrealized gains or losses associated with changes in the fair value of these energy contracts are deferred as a regulatory asset or liability for recovery from, or refund to, customers in future rates, as permitted by the regulators. As at December 31, 2023, unrealized losses of $197 million (2022 - $84 million) were recognized as regulatory assets and unrealized gains of $37 million (2022 - $224 million) were recognized as regulatory liabilities.
Energy contracts not subject to regulatory deferral
UNS Energy holds wholesale trading contracts to fix power prices and realize potential margin, of which 10% of any realized gains is shared with customers through rate stabilization accounts. Fair values are measured using a market approach incorporating, where possible, independent third-party information.
Aitken Creek, which was sold on November 1, 2023, held gas swap contracts to manage exposure to changes in natural gas prices, capture natural gas price spreads, and manage the financial risk posed by physical transactions. Fair values were measured using forward pricing from published market sources.
Unrealized gains or losses associated with changes in the fair value of these energy contracts are recognized in revenue. In 2023, unrealized losses of $28 million (2022 - gains of $34 million) were recognized in revenue.
Total return swaps
The Corporation holds total return swaps to manage the cash flow risk associated with forecast future cash settlements of certain stock-based compensation obligations. The swaps have a combined notional amount of $118 million and terms of one to three years expiring at varying dates through January 2026. Fair value is measured using an income valuation approach based on forward pricing curves. Unrealized gains and losses associated with changes in fair value are recognized in other income, net. In 2023, unrealized losses of less than $1 million (2022 - $22 million) were recognized in other income, net.
Foreign exchange contracts
The Corporation holds U.S. dollar-denominated foreign exchange contracts to help mitigate exposure to foreign exchange rate volatility. The contracts expire at varying dates through September 2025 and have a combined notional amount of $467 million. Fair value was measured using independent third-party information. Unrealized gains and losses associated with changes in fair value are recognized in other income, net. In 2023, unrealized gains of $10 million (2022 - losses of $9 million) were recognized in other income, net.
Interest rate locks
During 2023, the Corporation entered into and settled an interest rate lock with a notional value of $100 million. The contract was used to manage interest rate risk associated with the issuance of $500 million unsecured senior notes in November 2023. A realized gain of $8 million was recognized in other comprehensive income, which will be reclassified to earnings as a component of interest expense over 10 years.
ITC also entered into and settled interest rate locks in 2023 with a combined notional value of US$500 million. The contracts were used to manage interest rate risk associated with the issuance of US$500 million unsecured senior notes in June 2023. Realized gains of US$4 million were recognized in other comprehensive income, which will be reclassified to earnings as a component of interest expense over 10 years.
Cross-Currency interest rate swaps
The Corporation holds cross-currency interest rate swaps, maturing in 2029, to effectively convert its $500 million, 4.43% unsecured senior notes to US$391 million, 4.34% debt. The Corporation has designated this notional U.S. debt as an effective hedge of its foreign net investments and unrealized gains and losses associated with exchange rate fluctuations on the notional U.S. debt are recognized in other comprehensive income, consistent with the translation adjustment related to the foreign net investments. Other changes in the fair value of the swaps are also recognized in other comprehensive income but are excluded from the assessment of hedge effectiveness. Fair value is measured using a discounted cash flow method based on secured overnight financing rates. In 2023, unrealized gains of $15 million (2022 - unrealized losses of $17 million) were recorded in other comprehensive income.
Other investments
UNS Energy holds investments in money market accounts, and ITC and Central Hudson hold investments in trust associated with supplemental retirement benefit plans for select employees, which include mutual funds and money market accounts. These investments are recorded at fair value based on quoted market prices in active markets. Gains and losses are recognized in other income, net. In 2023, unrealized gains of $8 million (2022 - unrealized losses of $11 million) were recognized in other income, net.
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36 | FORTIS INC. | DECEMBER 31, 2023 |
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| Management Discussion and Analysis |
Derivative Fair Values
The following table presents derivative assets and liabilities that are accounted for at fair value on a recurring basis.
| | | | | | | | | | | | | | | | | | | | | | | |
| ($ millions) | Level 1 (1) | | Level 2 (1) | | Level 3 (1) | | Total |
As at December 31, 2023 | | | | | | | |
Assets (2) | | | | | | | |
| Energy contracts subject to regulatory deferral | — | | | 49 | | | — | | | 49 | |
| Energy contracts not subject to regulatory deferral | — | | | 6 | | | — | | | 6 | |
| Foreign exchange contracts | — | | | 5 | | | — | | | 5 | |
| Other investments | 145 | | | — | | | — | | | 145 | |
| 145 | | | 60 | | | — | | | 205 | |
| | | | | | | |
Liabilities (3) | | | | | | | |
| Energy contracts subject to regulatory deferral | — | | | (209) | | | — | | | (209) | |
| Energy contracts not subject to regulatory deferral | — | | | (3) | | | — | | | (3) | |
| Total return and cross-currency interest rate swaps | — | | | (6) | | | — | | | (6) | |
| — | | | (218) | | | — | | | (218) | |
| | | | | | | |
As at December 31, 2022 | | | | | | | |
Assets (2) | | | | | | | |
| Energy contracts subject to regulatory deferral | — | | | 304 | | | — | | | 304 | |
| Energy contracts not subject to regulatory deferral | — | | | 49 | | | — | | | 49 | |
| | | | | | | |
| Other investments | 150 | | | — | | | — | | | 150 | |
| 150 | | | 353 | | | — | | | 503 | |
| | | | | | | |
Liabilities (3) | | | | | | | |
| Energy contracts subject to regulatory deferral | — | | | (164) | | | — | | | (164) | |
| Energy contracts not subject to regulatory deferral | — | | | (8) | | | — | | | (8) | |
| Foreign exchange contracts, total return and cross-currency interest rate swaps | — | | | (26) | | | — | | | (26) | |
| — | | | (198) | | | — | | | (198) | |
(1)Under the hierarchy, fair value is determined using: (i) Level 1 - unadjusted quoted prices in active markets; (ii) Level 2 - other pricing inputs directly or indirectly observable in the marketplace; and (iii) Level 3 - unobservable inputs, used when observable inputs are not available. Classifications reflect the lowest level of input that is significant to the fair value measurement.
(2)Included in cash and cash equivalents, accounts receivable and other current assets or other assets
(3)Included in accounts payable and other current liabilities or other liabilities
| | | | | | | | | | | |
| Derivative Volumes | | | |
| As at December 31 | 2023 | | | 2022 | |
Energy contracts subject to regulatory deferral (1) | | | |
Electricity swap contracts (GWh) | 628 | | | 586 | |
Electricity power purchase contracts (GWh) | 588 | | | 224 | |
Gas swap contracts (PJ) | 228 | | | 185 | |
Gas supply contracts (PJ) | 134 | | | 148 | |
Energy contracts not subject to regulatory deferral (1) | | | |
Wholesale trading contracts (GWh) | 1,310 | | | 1,886 | |
Gas swap contracts (PJ) | 3 | | | 34 | |
(1)Energy contracts settle on various dates through 2029
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37 | FORTIS INC. | DECEMBER 31, 2023 |
| | | | | | | | |
| Management Discussion and Analysis |
SELECTED ANNUAL FINANCIAL INFORMATION
| | | | | | | | | | | | | | | | | |
| Years ended December 31 | | | | | |
| ($ millions, except as indicated) | 2023 | | | 2022 | | | 2021 | |
Revenue | 11,517 | | | 11,043 | | | 9,448 | |
Net earnings | 1,710 | | | 1,514 | | | 1,405 | |
Common Equity Earnings | 1,506 | | | 1,330 | | | 1,231 | |
EPS: ($) | | | | | |
Basic | 3.10 | | | 2.78 | | | 2.61 | |
Diluted | 3.10 | | | 2.78 | | | 2.61 | |
Total assets | 65,920 | | | 64,252 | | | 57,659 | |
Long-term debt (excluding current portion) | 27,235 | | | 25,931 | | | 23,707 | |
Dividends declared: ($) | | | | | |
Per common share | 2.31 | | | 2.20 | | | 2.08 | |
Per first preference share: | | | | | |
Series F | 1.2250 | | | 1.2250 | | | 1.2250 | |
Series G (1) | 1.3145 | | | 1.0983 | | | 1.0983 | |
Series H | 0.4588 | | | 0.4588 | | | 0.4588 | |
Series I (2) | 1.5619 | | | 0.9157 | | | 0.3926 | |
Series J | 1.1875 | | | 1.1875 | | | 1.1875 | |
Series K | 0.9823 | | | 0.9823 | | | 0.9823 | |
Series M | 0.9783 | | | 0.9783 | | | 0.9783 | |
(1)The annual dividend per share was reset to $1.5308 for the five-year period from September 1, 2023 up to but excluding September 1, 2028
(2)Floating quarterly dividend rate is reset every quarter based on the then current three-month Government of Canada Treasury Bill rate plus the applicable reset dividend yield
2023/2022
For a discussion of the changes in revenue, net earnings, Common Equity Earnings, EPS, total assets and long-term debt see "Performance at a Glance" on page 2, "Operating Results" on page 9, and "Financial Position" on page 16.
2022/2021
The increase in revenue was due to: (i) higher flow-through costs in customer rates, driven by higher commodity prices; (ii) Rate Base growth; and (iii) higher retail and wholesale electricity sales, as well as transmission revenue, at UNS Energy, partially offset by the normal operation of regulatory deferrals at FortisBC Energy. The increase in revenue was also due to a higher U.S.-to-Canadian dollar exchange rate.
Common Equity Earnings increased by $99 million compared to 2021. The increase was primarily driven by Rate Base growth across our utilities. The increase in earnings was also due to: (i) higher retail and wholesale electricity sales, as well as transmission revenue in Arizona; (ii) higher margins on gas sold and the mark-to-market accounting of natural gas derivatives at Aitken Creek; and (iii) the impact of new customer rates at Central Hudson. The translation of U.S. dollar-denominated subsidiary earnings at the higher U.S.-to-Canadian dollar foreign exchange rate and lower stock based compensation costs also contributed to results, with these impacts exceeding the related losses on derivatives associated with hedging activities.
Growth in Common Equity Earnings was tempered by certain discrete items at ITC including: (i) costs associated with the suspension of the Lake Erie Connector project; (ii) the revaluation of deferred income tax assets due to a reduction in the corporate income tax rate in the state of Iowa; and (iii) a favourable adjustment recognized in 2021 related to interest rate swaps. Losses on investments that support retirement benefits at UNS Energy and ITC, higher operating costs at Central Hudson related to the implementation of a new CIS, and higher corporate costs also tempered results.
In addition to the above-noted items impacting earnings, the change in EPS reflected an increase in the weighted average number of common shares outstanding, largely associated with the Corporation's DRIP.
The increase in total assets was primarily due to: (i) the translation of U.S. dollar-denominated assets at a higher U.S.-to-Canadian dollar exchange rate; (ii) capital expenditures in 2022; and (iii) an increase in accounts receivable and other current assets, largely due to the flow through of higher energy supply costs.
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38 | FORTIS INC. | DECEMBER 31, 2023 |
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| Management Discussion and Analysis |
FOURTH QUARTER RESULTS
| | | | | | | | | | | | | | | | | |
| Sales | | | | | |
| (GWh, except as indicated) | 2023 | | | 2022 | | | Variance |
| Regulated Utilities | | | | | |
UNS Energy | | | | | |
Retail Electricity | 2,302 | | | 2,264 | | | 38 | |
Wholesale Electricity | 1,349 | | | 1,247 | | | 102 | |
Gas (PJ) | 5 | | | 5 | | | — | |
Central Hudson | | | | | |
Electricity | 1,196 | | | 1,158 | | | 38 | |
Gas (PJ) | 6 | | | 8 | | | (2) | |
FortisBC Energy (PJ) | 66 | | | 75 | | | (9) | |
FortisAlberta | 4,273 | | | 4,200 | | | 73 | |
FortisBC Electric | 901 | | | 967 | | | (66) | |
Other Electric | 2,525 | | | 2,443 | | | 82 | |
Non-Regulated | | | | | |
| Corporate and Other | 58 | | | 83 | | | (25) | |
The increase in electricity sales was driven by: (i) UNS Energy, due to higher short-term wholesale electricity sales, as well as higher retail electricity sales due to customer additions; (ii) FortisAlberta, reflecting customer additions and higher average consumption from commercial and industrial customers; and (iii) the Other Electric segment, due to higher average consumption by residential and commercial customers. The increase was partially offset by FortisBC Electric, reflecting lower average consumption by residential customers due to milder weather.
The decrease in gas sales was driven by FortisBC Energy due to lower average consumption by residential, commercial and transportation customers due to milder weather.
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| Revenue and Common Equity Earnings | Revenue | | Earnings |
| ($ millions, except as indicated) | 2023 | | | 2022 | | | Variance | | 2023 | | | 2022 | | | Variance |
| Regulated Utilities | | | | | | | | | | | |
| ITC | 527 | | | 500 | | | 27 | | | 136 | | | 126 | | | 10 | |
| UNS Energy | 706 | | | 716 | | | (10) | | | 62 | | | 45 | | | 17 | |
| Central Hudson | 311 | | | 396 | | | (85) | | | 36 | | | 37 | | | (1) | |
| FortisBC Energy | 544 | | | 725 | | | (181) | | | 105 | | | 84 | | | 21 | |
| FortisAlberta | 188 | | | 169 | | | 19 | | | 36 | | | 34 | | | 2 | |
| FortisBC Electric | 145 | | | 136 | | | 9 | | | 15 | | | 14 | | | 1 | |
| Other Electric | 457 | | | 448 | | | 9 | | | 35 | | | 40 | | | (5) | |
| Non-regulated | | | | | | | | | | | |
| Corporate and Other | 7 | | | 78 | | | (71) | | | (44) | | | (10) | | | (34) | |
| | | | | | | | | | | |
| Total | 2,885 | | | 3,168 | | | (283) | | | 381 | | | 370 | | | 11 | |
| | | | | | | | | | | |
Weighted average number of common shares outstanding (# millions) | | 489.4 | | | 481.1 | | | 8.3 | |
Basic EPS ($) | | | | | | | 0.78 | | | 0.77 | | | 0.01 | |
The decrease in revenue was due primarily to: (i) lower flow-through costs in customer rates, driven by lower commodity prices at FortisBC Energy and Central Hudson; (ii) lower wholesale electricity sales revenue at UNS Energy due to market prices; and (iii) the disposition of Aitken Creek on November 1, 2023, including the impact of mark-to-market accounting of natural gas derivatives, reflected in the Corporate and Other segment. The decrease was partially offset by Rate Base growth, higher retail electricity revenue at TEP due to new customer rates effective September 1, 2023 and customer additions, and the new cost of capital parameters approved for FortisBC in 2023.
The increase in Common Equity Earnings was driven by: (i) Rate Base growth; (ii) higher retail revenue in Arizona, due to new customer rates at TEP; and (iii) the new cost of capital parameters approved for FortisBC effective January 1, 2023. The increase was partially offset by lower earnings at Aitken Creek, due to the November 1, 2023 disposition, as well as the recognition of mark-to-market accounting gains on natural gas derivatives and margins on gas sold in the fourth quarter of 2022.
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39 | FORTIS INC. | DECEMBER 31, 2023 |
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| Management Discussion and Analysis |
The increase in basic EPS reflects higher Common Equity Earnings, as discussed above, partially offset by an increase in the weighted average number of common shares outstanding, largely associated with the Corporation's DRIP.
| | | | | | | | | | | | | | | | | |
| Cash Flows | | | | | |
| ($ millions) | 2023 | | | 2022 | | | Variance |
| Cash and cash equivalents, beginning of period | 765 | | | 395 | | | 370 | |
| Cash from (used in): | | | | | |
| Operating activities | 746 | | | 869 | | | (123) | |
| Investing activities | (748) | | | (1,152) | | | 404 | |
| Financing activities | (134) | | | 103 | | | (237) | |
| Effect of exchange rate changes on cash and cash equivalents | (13) | | | (6) | | | (7) | |
| Change in cash associated with assets held for sale | 9 | | | — | | | 9 | |
| Cash and cash equivalents, end of period | 625 | | | 209 | | | 416 | |
Operating Activities
The decrease in Operating Cash Flow was largely driven by FortisBC Energy, reflecting: (i) the timing of flow-through costs in customer rates, due to fluctuations in commodity costs; and (ii) higher development expenditures, net of deposits received, associated with the Eagle Mountain Woodfibre Gas Line project. Higher interest and income tax payments also impacted Operating Cash Flow for the quarter. The decrease was partially offset by higher cash earnings, reflecting Rate Base growth, as well as new customer rates at TEP, and the timing of flow-through of transmission-related amounts in Alberta.
Investing Activities
The decrease in cash used in investing activities was due to proceeds received on the disposition of Aitken Creek and higher customer contributions in aid of construction, partially offset by higher capital expenditures.
Financing Activities
See "Cash Flow Summary" on page 18.
SUMMARY OF QUARTERLY RESULTS
| | | | | | | | | | | | | | | | | | | | | | | |
| | | Common | | | | |
| | | Equity | | | | |
| Revenue | | Earnings | | Basic EPS | | Diluted EPS |
| Quarter ended | ($ millions) | | ($ millions) | | ($) | | ($) |
| December 31, 2023 | 2,885 | | | 381 | | | 0.78 | | | 0.78 | |
| September 30, 2023 | 2,719 | | | 394 | | | 0.81 | | | 0.81 | |
| June 30, 2023 | 2,594 | | | 294 | | | 0.61 | | | 0.61 | |
| March 31, 2023 | 3,319 | | | 437 | | | 0.90 | | | 0.90 | |
| December 31, 2022 | 3,168 | | | 370 | | | 0.77 | | | 0.77 | |
| September 30, 2022 | 2,553 | | | 326 | | | 0.68 | | | 0.68 | |
| June 30, 2022 | 2,487 | | | 284 | | | 0.59 | | | 0.59 | |
| March 31, 2022 | 2,835 | | | 350 | | | 0.74 | | | 0.74 | |
Generally, within each calendar year, quarterly results fluctuate in accordance with seasonality. Given the diversified nature of the Corporation's subsidiaries, seasonality varies. Most of the annual earnings of the gas utilities are realized in the first and fourth quarters due to space-heating requirements. Earnings for the electric distribution utilities in the U.S. are generally highest in the second and third quarters due to the use of air conditioning and other cooling equipment.
Generally, from one calendar year to the next, quarterly results reflect: (i) continued organic growth driven by the Corporation's Capital Plan; (ii) any significant temperature fluctuations from seasonal norms; (iii) the impact of market conditions, particularly with respect to long-term wholesale sales and transmission revenue at UNS Energy; (iv) the timing and significance of any regulatory decisions; (v) changes in the U.S.-to-Canadian dollar exchange rate; (vi) for revenue, the flow through in customer rates of commodity costs; and (vii) for EPS, increases in the weighted average number of common shares outstanding.
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40 | FORTIS INC. | DECEMBER 31, 2023 |
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| Management Discussion and Analysis |
December 2023/December 2022
See "Fourth Quarter Results" on page 39.
September 2023/September 2022
Common Equity Earnings increased by $68 million and basic EPS increased by $0.13 in comparison to the third quarter of 2022. The increase was primarily due to the new cost of capital parameters approved for FortisBC by the BCUC in September 2023, which resulted in $38 million of earnings in the quarter, including $26 million associated with the retroactive impact to January 1, 2023. The increase in earnings was also driven by higher retail revenue in Arizona, due to warmer weather and new customer rates at TEP effective September 1, 2023, as well as Rate Base growth across our utilities. A higher U.S.-to-Canadian dollar exchange rate and higher earnings at Aitken Creek, reflecting market conditions, also favourably impacted earnings. Earnings were tempered by: (i) lower long-term wholesale and transmission revenue, as well as higher operating costs and income tax expense at UNS Energy; (ii) higher corporate finance costs; and (iii) higher operating expenses at Central Hudson and FortisAlberta, as expected, due to the timing of costs in the first half of the year. The change in basic EPS also reflected an increase in the weighted average number of common shares outstanding, largely associated with the Corporation's DRIP.
June 2023/June 2022
Common Equity Earnings increased by $10 million and basic EPS increased by $0.02 in comparison to the second quarter of 2022 primarily due to Rate Base growth, largely at ITC and the western Canadian utilities. Also contributing to growth was the timing of operating expenses at Central Hudson and FortisAlberta, an increase in the market value of certain investments that support retirement benefits, and a higher U.S.-to-Canadian dollar exchange rate. Growth was tempered by lower earnings in Arizona, driven by a decrease in retail electricity sales due to milder weather, the timing of wholesale sales, and higher operating costs, partially offset by lower depreciation expense associated with the retirement of the San Juan generating station in June 2022. Lower earnings from Aitken Creek due to the mark-to-market accounting of natural gas derivatives, as well as higher corporate finance costs, also impacted results as compared to the second quarter of 2022. The change in basic EPS also reflected an increase in the weighted average number of common shares outstanding, largely associated with the Corporation's DRIP.
March 2023/March 2022
Common Equity Earnings increased by $87 million and basic EPS increased by $0.16 in comparison to the first quarter of 2022 due to Rate Base growth, mainly at ITC and the western Canadian utilities, as well as higher earnings at UNS Energy. Market conditions resulted in wholesale electricity sales with favourable margins and higher transmission revenue at UNS Energy in the first quarter of 2023 compared to later quarters in 2022. Higher retail electricity sales, including the impact of favourable weather, and lower depreciation expense associated with the retirement of the San Juan generating station in June 2022, also contributed to results in Arizona. Results for the quarter also reflected higher earnings at Aitken Creek, an increase in the market value of investments that support retirement benefits at UNS Energy and ITC, and a higher U.S.-to-Canadian dollar exchange rate, partially offset by higher corporate finance costs. The change in basic EPS also reflected an increase in the weighted average number of common shares outstanding, largely associated with the Corporation's DRIP.
RELATED-PARTY AND INTER-COMPANY TRANSACTIONS
Related-party transactions are in the normal course of operations and are measured at the amount of consideration agreed to by the related parties. There were no material related-party transactions in 2023 or 2022.
The lease of gas storage capacity and gas sales from Aitken Creek to FortisBC Energy, from January 1, 2023 through to the November 1, 2023 disposition of Aitken Creek, of $25 million (twelve month period in 2022 - $37 million) are inter-company transactions between non-regulated and regulated entities, which were not eliminated on consolidation.
Fortis periodically provides short-term financing to subsidiaries to support capital expenditures and seasonal working capital requirements, the impacts of which are eliminated on consolidation. As at December 31, 2023 and 2022, there were no inter-segment loans outstanding. Interest charged on inter-segment loans was not material in 2023 and 2022.
MANAGEMENT'S EVALUATION OF CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
DCP are designed to provide reasonable assurance that information required to be disclosed in reports filed with, or submitted to, securities regulatory authorities is recorded, processed, summarized and reported within the time periods specified under Canadian and U.S. securities laws. As of December 31, 2023, an evaluation was carried out under the supervision of, and with the participation of, the Corporation's management, including the CEO and CFO, of the effectiveness of the Corporation's DCP, as defined in the applicable Canadian and U.S. securities laws. Based on that evaluation, the CEO and CFO concluded that such DCP are effective as of December 31, 2023.
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41 | FORTIS INC. | DECEMBER 31, 2023 |
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| Management Discussion and Analysis |
Internal Control over Financial Reporting
ICFR is designed by, or under the supervision of, the Corporation's CEO and CFO and effected by the Corporation's Board, management and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with U.S. GAAP. Because of its inherent limitations, ICFR may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
The Corporation's management, including the Corporation's CEO and CFO, assessed the effectiveness of the Corporation's ICFR as of December 31, 2023, based on the criteria set forth in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, management concluded that, as of December 31, 2023, the Corporation's ICFR was effective.
During the year ended December 31, 2023, there have been no changes in the Corporation's ICFR that have materially affected, or are reasonably likely to materially affect, the Corporation's ICFR.
OUTLOOK
Fortis is executing on the transition to a cleaner energy future and is on track to achieve its corporate-wide targets to reduce direct GHG emissions by 50% by 2030 and 75% by 2035 from a 2019 base year. The Corporation's additional 2050 net-zero direct GHG emissions target reinforces Fortis' commitment to further decarbonize over the long-term, while continuing our focus on reliability and affordability.
Fortis continues to enhance shareholder value through the execution of its Capital Plan, the balance and strength of its diversified portfolio of regulated utility businesses, and growth opportunities within and proximate to its service territories. The Corporation's $25 billion five-year Capital Plan is expected to increase midyear Rate Base from $37.0 billion in 2023 to $49.4 billion by 2028, translating into a five-year CAGR of 6.3%.
Beyond the five-year Capital Plan, additional opportunities to expand and extend growth include: further expansion of the electric transmission grid in the U.S. to facilitate the interconnection of cleaner energy, including infrastructure investments associated with the IRA and the MISO LRTP; climate adaptation and grid resiliency investments; RNG solutions and LNG infrastructure in British Columbia; and the acceleration of cleaner energy infrastructure investments across our jurisdictions.
Fortis expects its long-term growth in Rate Base will drive earnings that support dividend growth guidance of 4-6% annually through 2028, and is premised on the assumptions and material factors listed under "Forward-Looking Information".
FORWARD-LOOKING INFORMATION
Fortis includes forward-looking information in the MD&A within the meaning of applicable Canadian securities laws and forward-looking statements within the meaning of the U.S. Private Securities Litigation Reform Act of 1995, (collectively referred to as "forward-looking information"). Forward-looking information reflects expectations of Fortis management regarding future growth, results of operations, performance, business prospects and opportunities. Wherever possible, words such as anticipates, believes, budgets, could, estimates, expects, forecasts, intends, may, might, plans, projects, schedule, should, target, will, would, and the negative of these terms, and other similar terminology or expressions, have been used to identify the forward-looking information, which includes, without limitation: the expectation that Fortis is well-positioned for future investment opportunities that will drive significant investment; forecast capital expenditures for 2024 and 2024 through 2028, including Cleaner Energy Investments; the expected timing, outcome and impact of legal and regulatory proceedings and decisions; the recovery of the GCOC decision in customer rates and the collection of the associated revenue deficiency deferral; annual dividend growth guidance through 2028; the expected sources of funding for the Capital Plan; the expected sources of common equity proceeds; forecast Rate Base and Rate Base growth for 2024 and through 2028; the expectation that advancements in the use of hydrogen and RNG will further contribute to carbon reduction; the 2050 net-zero direct GHG emissions target; the 2030 and 2035 direct GHG emissions reduction targets; how GHG emissions targets are expected to be achieved, including TEP's plan to exit coal by 2032; the release of the 2024 climate report and expected contents thereof; the nature, timing, benefits and expected costs of certain capital projects, including ITC's transmission projects associated with the MISO LRTP, the Roadrunner Reserve Battery Storage Project, the Vail-to-Tortolita Transmission Project, IRP Energy Resources, the Eagle Mountain Woodfibre Gas Line Project, the Tilbury LNG Storage Expansion, the AMI Project; the Tilbury 1B Project, the Okanagan Capacity Upgrade, the Wataynikaneyap Transmission Power Project, and additional opportunities beyond the capital plan, including investments associated with the IRA, the MISO LRTP, UNS Energy's 2023 IRPs, FortisBC Energy's LNG infrastructure, the Propel New York Energy Project, climate adaptation and grid resiliency, further gas infrastructure opportunities in British Columbia, and other cleaner energy infrastructure; the targeted capital structure; the expected or potential funding sources for operating expenses, interest costs and capital expenditures; the expected consolidated fixed-term debt maturities and repayments over the next five years; the expectation that maintaining the targeted capital structure of the regulated operating subsidiaries will not have an impact on the Corporation's ability to pay dividends in the foreseeable future; the expectation that the Corporation and its subsidiaries will continue to have access to long-term capital and will remain compliant with debt covenants in 2024; the expected uses of proceeds from debt financings; the performance of contractual obligations to provide equity capital to the Wataynikaneyap Partnership; the potential and expected impacts of income tax compliance examinations, the U.S. corporate alternative minimum income tax and the enactment of draft Canadian legislation with respect to interest deductibility limitations and global minimum tax; and the expectation that long-term growth in Rate Base will drive earnings that support dividend growth guidance of 4-6% annually through 2028.
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42 | FORTIS INC. | DECEMBER 31, 2023 |
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| Management Discussion and Analysis |
Forward-looking information involves significant risks, uncertainties and assumptions. Certain material factors or assumptions have been applied in drawing the conclusions contained in the forward-looking information including, without limitation: reasonable legal and regulatory decisions and the expectation of regulatory stability; the successful execution of the capital plan; no material capital project or financing cost overrun; sufficient human resources to deliver service and execute the capital plan; the realization of additional opportunities beyond the capital plan; no significant variability in interest rates; the Board exercising its discretion to declare dividends, taking into account the financial performance and condition of the Corporation; no significant operational disruptions or environmental liability or upset; the continued ability to maintain the performance of the electricity and gas systems; no severe and prolonged economic downturn; sufficient liquidity and capital resources; the ability to hedge exposures to fluctuations in foreign exchange rates, natural gas prices and electricity prices; the continued availability of natural gas, fuel, coal and electricity supply; continuation of power supply and capacity purchase contracts; no significant changes in government energy plans, environmental laws and regulations that could have a material negative impact; maintenance of adequate insurance coverage; the ability to obtain and maintain licences and permits; retention of existing service areas; no significant changes in tax laws and the continued tax deferred treatment of earnings from the Corporation's foreign operations; continued maintenance of information technology infrastructure and no material breach of cybersecurity; continued favourable relations with Indigenous Peoples; and favourable labour relations.
Fortis cautions readers that a number of factors could cause actual results, performance or achievements to differ materially from those discussed or implied in the forward-looking information. These factors should be considered carefully and undue reliance should not be placed on the forward-looking information. Risk factors which could cause results or events to differ from current expectations are detailed under the heading "Business Risks" in this MD&A and in other continuous disclosure materials filed from time to time with Canadian securities regulatory authorities and the Securities and Exchange Commission. Key risk factors for 2024 include, but are not limited to: uncertainty regarding changes in utility regulation, including the outcome of regulatory proceedings at the Corporation's utilities; the physical risks associated with the provision of electric and gas service, which are exacerbated by the impacts of climate change; risks related to environmental laws and regulations; risks associated with capital projects and the impact on the Corporation's continued growth; risks associated with cybersecurity and information and operations technology; the impact of weather variability and seasonality on heating and cooling loads, gas distribution volumes and hydroelectric generation; risks associated with commodity price volatility and supply of purchased power; and risks related to general economic conditions, including inflation, interest rate and foreign exchange risks.
All forward-looking information herein is given as of February 8, 2024. Fortis disclaims any intention or obligation to update or revise any forward-looking information, whether as a result of new information, future events or otherwise.
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43 | FORTIS INC. | DECEMBER 31, 2023 |
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| Management Discussion and Analysis |
2023 Annual Financial Statements: the Corporation's audited consolidated financial statements and notes thereto for the year ended December 31, 2023
Actual Payout Ratio: dividends paid per common share divided by basic EPS
Adjusted Basic EPS: Adjusted Common Equity Earnings divided by the basic weighted average number of common shares outstanding
Adjusted Common Equity Earnings: net earnings attributable to common equity shareholders adjusted as shown under "Non-U.S. GAAP Financial Measures" on page 13
Adjusted Payout Ratio: dividends paid per common share divided by Adjusted Basic EPS as shown under "Non-U.S. GAAP Financial Measures" on page 13
AFUDC: allowance for funds used during construction
Aitken Creek: Aitken Creek Gas Storage ULC, a 93.8%-owned subsidiary of FortisBC Holdings Inc., sold on November 1, 2023
AMI: Advanced Metering Infrastructure
ATM Program: at-the-market equity program
ACC: Arizona Corporation Commission
ASU: accounting standards update
AUC: Alberta Utilities Commission
BCUC: British Columbia Utilities Commission
Belize Electricity: Belize Electricity Limited, in which Fortis indirectly holds a 33% equity interest
Board: Board of Directors of the Corporation
CAGR(s): compound annual growth rate of a particular item CAGR=(EV/BV)(1/n)-1, where: (i) EV is the ending value of the item; (ii) BV is the beginning value of the item; and (iii) n is the number of periods. Calculated on a constant U.S. dollar-to-Canadian dollar exchange rate
Capital Expenditures: cash outlay for additions to property, plant and equipment and intangible assets as shown in the Annual Financial Statements, as well as Fortis' 39% share of capital spending for the Wataynikaneyap Transmission Power Project. See "Non-U.S. GAAP Financial Measures" on page 13
Capital Plan: forecast Capital Expenditures. Represents a non-U.S. GAAP financial measure calculated in the same manner as Capital Expenditures
Caribbean Utilities: Caribbean Utilities Company, Ltd., an indirect approximately 60%-owned (as at December 31, 2023) subsidiary of Fortis, together with its subsidiary
Central Hudson: CH Energy Group, Inc., an indirect wholly owned subsidiary of Fortis, together with its subsidiaries, including Central Hudson Gas & Electric Corporation
CEO: Chief Executive Officer of Fortis
CFO: Chief Financial Officer of Fortis
CIS: customer information system
Cleaner Energy Investments: capital expenditures that support reductions in air emissions, water usage and/or increases customer energy efficiency
Common Equity Earnings: net earnings attributable to common equity shareholders
Corporation: Fortis Inc.
COS: cost of service
CPCN: Certificate of Public Convenience and Necessity
CRMP: Cybersecurity Risk Management Program
DBRS Morningstar: DBRS Limited
D.C. Circuit Court: U.S. Court of Appeals for the District of Columbia Circuit
DCP: disclosure controls and procedures
DEI: diversity, equity and inclusion
DRIP: dividend reinvestment plan
EPC: engineering, procurement and construction
EPRI: Electric Power Research Institute
EPS: earnings per common share
ERM: enterprise risk management
ESG: environmental, social and corporate governance
FERC: Federal Energy Regulatory Commission
Fortis: Fortis Inc.
FortisAlberta: FortisAlberta Inc., an indirect wholly owned subsidiary of Fortis
FortisBC Electric: FortisBC Inc., an indirect wholly owned subsidiary of Fortis, together with its subsidiaries
FortisBC Energy: FortisBC Energy Inc., an indirect wholly owned subsidiary of Fortis, together with its subsidiaries
FortisOntario: FortisOntario Inc., a direct wholly owned subsidiary of Fortis, together with its subsidiaries
FortisTCI: FortisTCI Limited, an indirect wholly owned subsidiary of Fortis, together with its subsidiary
Fortis Belize: Fortis Belize Limited, an indirect wholly owned subsidiary of Fortis
Four Corners: Four Corners Generating Station, Units 4 and 5
FX: foreign exchange associated with the translation of U.S. dollar-denominated amounts. Calculated by applying the change in the U.S.-to-Canadian dollar FX rates to the prior period U.S. dollar balance.
GCOC: generic cost of capital
GHG: greenhouse gas
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44 | FORTIS INC. | DECEMBER 31, 2023 |
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| Management Discussion and Analysis |
GWh: gigawatt hour(s)
ICFR: internal control over financial reporting
IRA: Inflation Reduction Act of 2022
IRP: Integrated Resource Plan
ITC: ITC Investment Holdings Inc., an indirect 80.1%-owned subsidiary of Fortis, together with its subsidiaries, including International Transmission Company, Michigan Electric Transmission Company, LLC, ITC Midwest LLC, and ITC Great Plains, LLC
LNG: liquefied natural gas
LRTP: long range transmission plan
Luna: Luna Energy Facility
kV: kilovolt
Major Capital Projects: projects, other than ongoing maintenance projects, individually costing $200 million or more
Maritime Electric: Maritime Electric Company, Limited, an indirect wholly owned subsidiary of Fortis
Material Adverse Effect: a material adverse effect on the Corporation's business, results of operations, financial position or liquidity, on a consolidated basis
MD&A: the Corporation's management discussion and analysis for the year ended December 31, 2023
MISO: Midcontinent Independent System Operator, Inc.
Moody's: Moody's Investor Services, Inc.
MW: megawatt(s)
Navajo: Navajo Generating Station
Newfoundland Power: Newfoundland Power Inc., a direct wholly owned subsidiary of Fortis
Non-U.S. GAAP Financial Measures: financial measures that do not have a standardized meaning prescribed by U.S. GAAP
NOPR: notice of proposed rulemaking
NYSE: New York Stock Exchange
OPEB: other post-employment benefits
Operating Cash Flow: cash from operating activities
PBR: performance-based rate-setting
PJ: petajoule(s)
PPFAC: purchased power and fuel adjustment clause
PSC: New York State Public Service Commission
Rate Base: the stated value of property on which a regulated utility is permitted to earn a specified return in accordance with its regulatory construct
REA: Rural Electrification Association
RNG: renewable natural gas
ROA: rate of return on Rate Base
ROE: rate of return on common equity
ROFR: right of first refusal
RTO: regional transmission organization
S&P: Standard & Poor's Financial Services LLC
SEDAR+: Canadian System for Electronic Document Analysis and Retrieval
TEP: Tucson Electric Power Company, a direct wholly owned subsidiary of UNS Energy
Transco: New York Transco LLC
TSR: total shareholder return, which is a measure of the return to common equity shareholders in the form of share price appreciation and dividends (assuming reinvestment) over a specified time period in relation to the share price at the beginning of the period.
TSX: Toronto Stock Exchange
UNS Electric: UNS Electric, Inc.
UNS Energy: UNS Energy Corporation, an indirect wholly owned subsidiary of Fortis, together with its subsidiaries, including TEP, UNS Electric and UNS Gas, Inc.
U.S.: United States of America
U.S. GAAP: accounting principles generally accepted in the U.S.
Waneta Expansion: Waneta Expansion hydroelectric generation facility
Wataynikaneyap Partnership: Wataynikaneyap Power Limited Partnership
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45 | FORTIS INC. | DECEMBER 31, 2023 |
