Management Discussion and Analysis
Contents
About Fortis .......................................................................................
Key Developments ............................................................................
Performance at a Glance ...................................................................
The Industry .......................................................................................
Focus on Sustainability ......................................................................
Operating Results ..............................................................................
Business Unit Performance ................................................................
ITC .................................................................................................
UNS Energy ...................................................................................
Central Hudson .............................................................................
FortisBC Energy .............................................................................
FortisAlberta ..................................................................................
FortisBC Electric .............................................................................
Other Electric ................................................................................
Energy Infrastructure .....................................................................
Corporate and Other .....................................................................
Non-U.S. GAAP Financial Measures ....................................................
Regulatory Highlights ........................................................................
Financial Position ...............................................................................
Liquidity and Capital Resources .........................................................
12
13
14
17
17
19
20
21
21
22
22
22
23
23
24
24
24
25
26
27
Dated February 10, 2022
Cash Flow Requirements ......................................................................
Cash Flow Summary .............................................................................
Contractual Obligations ........................................................................
Capital Structure and Credit Ratings .....................................................
Capital Plan ...........................................................................................
Business Risks ............................................................................................
Accounting Matters ...................................................................................
Financial Instruments ................................................................................
Long-Term Debt and Other ..................................................................
Derivatives ............................................................................................
Selected Annual Financial Information ......................................................
Fourth Quarter Results ...............................................................................
Summary of Quarterly Results ...................................................................
Related-Party and Inter-Company Transactions ........................................
Management's Evaluation of Controls and Procedures .............................
Outlook .....................................................................................................
Forward-Looking Information ...................................................................
Glossary .....................................................................................................
27
28
30
31
31
36
42
45
45
45
47
48
49
50
51
51
52
53
Consolidated Financial Statements ...........................................................
55
This MD&A has been prepared in accordance with National Instrument 51-102 - Continuous Disclosure Obligations. It should be read in
conjunction with the 2021 Annual Financial Statements and is subject to the cautionary statement and disclaimer provided under "Forward-
Looking Information" on page 52. Further information about Fortis, including its Annual Information Form filed on SEDAR, can be accessed at
www.fortisinc.com, www.sedar.com, 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 1.25 and 1.34 for the years ended December 31, 2021 and 2020, respectively; (ii) 1.26 and 1.27 as at December 31, 2021
and 2020, respectively; (iii) average of 1.26 and 1.30 for the quarters ended December 31, 2021 and 2020, respectively; and (iv) 1.25 for all
forecast periods. Certain terms used in this MD&A are defined in the "Glossary" on page 53.
ABOUT FORTIS
Fortis (TSX/NYSE: FTS) is a well-diversified leader in the North American regulated electric and gas utility industry, with revenue of $9.4 billion
in 2021 and total assets of $58 billion as at December 31, 2021.
Regulated utilities account for 99% of the Corporation's assets with the remainder primarily attributable to non-regulated energy
infrastructure. The Corporation's 9,100 employees serve 3.4 million utility customers in five Canadian provinces, nine U.S. states and three
Caribbean countries. As at December 31, 2021, 66% of the Corporation's assets were located outside Canada and 57% of 2021 revenue was
derived from foreign operations.
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FORTIS INC.
2021 Annual Report
Management Discussion and Analysis
TOTAL ASSETS AT DECEMBER 31, 2021
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 and Oklahoma); 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).
Non-regulated energy infrastructure consists of BECOL (three hydroelectric generation facilities - Belize) and Aitken Creek (natural gas storage
facility - British Columbia).
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 strives to provide safe, reliable and cost-effective energy service to customers while focusing on sustainability policies and practices.
The Corporation has established delivering a cleaner energy future as its 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 2021 Annual Financial Statements.
KEY DEVELOPMENTS
COVID-19 Pandemic
The Corporation's utilities continue to reliably and safely deliver an essential service during the COVID-19 Pandemic. Developments are
monitored and commensurate measures taken, particularly with respect to the health and safety of our employees and the public. The
Corporation's utilities are monitoring the impact of the pandemic on commodity prices and the supply chain, and are advancing
procurement and hedging activities to mitigate the impact on customer rates. These and other potential impacts of the pandemic, including
labour disruption risk, are evaluated and actions are taken to ensure that Fortis and its utilities can continue to provide safe, reliable and cost-
effective service while supporting public health.
The Corporation continues to assess economic conditions in its service territories and the associated impacts on: (i) energy sales, particularly
for UNS Energy and the Other Electric segment as revenue in these segments is not protected by regulatory mechanisms; (ii) the ability of
customers to pay their energy bills and the related impact on Operating Cash Flow; (iii) the progress of regulatory proceedings and the ability
to recover costs in a timely manner; and (iv) the execution of the Capital Plan. Except for the delay in TEP's general rate application in 2020,
the COVID-19 Pandemic did not have a significant impact on financial performance for the years ended December 31, 2021 and 2020.
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FORTIS INC.
2021 Annual Report
RegulatedElectric82%RegulatedGas17%Non-Regulated1%U.S.63%Canada34%Caribbean3% Management Discussion and Analysis
There continues to be uncertainty surrounding the pandemic, particularly with respect to the emergence of new variants of the virus, the
long-term efficacy and global distribution of COVID-19 vaccines, the impact of vaccine mandates and isolation requirements on labour
availability, potential government action to mitigate public health effects, and disruptions to the global supply chain. Potential financial and
operating impacts of the COVID-19 Pandemic on Fortis are discussed under "Business Risks" on page 36.
U.S. Infrastructure Spending and Tax Proposals
In November 2021, the U.S. government approved significant infrastructure spending, including investments in transmission, electrification
and economic development, as well as electrical grid resilience. Fortis continues to review the intended spending, as details become
available, in order to assess the impact on its business.
The Biden administration has also been drafting significant tax proposals including, amongst other things, amendments to rules associated
with international and minimum taxation, the introduction of a transmission investment tax credit, and the extension of clean energy tax
credits. Proposals continue to evolve and while it is unknown when legislation incorporating these tax proposals could be enacted, it is
currently expected in 2022.
In February 2022, the Department of Finance Canada released draft legislation including a proposal on interest deductibility. The proposal is
open for public comment until May 2022 and it is unknown when the legislation may be enacted. In addition, in April 2021, the Canadian
federal budget was released which proposed changes in relation to international taxation. There has been no significant update on this
proposal, and it is unknown when draft legislation may be available.
Changes in tax legislation could affect the results of operations, financial condition and cash flows of the Corporation. Potential impacts of
changes in tax laws are discussed under “Business Risks” on page 36. Fortis will continue to assess the impacts as more details on the U.S. and
Canadian tax proposals become available.
PERFORMANCE AT A GLANCE
Key Financial Metrics
($ millions, except as indicated)
Common Equity Earnings
Actual
Adjusted (1)
Basic EPS ($)
Actual
Adjusted (1)
Dividends
Paid per common share ($)
Actual Payout Ratio (%)
Adjusted Payout Ratio (%) (1)
Weighted average number of common shares outstanding (# millions)
Operating Cash Flow
Capital Expenditures (1)
(1) See "Non-U.S. GAAP Financial Measures" on page 24
2021
1,231
1,219
2.61
2.59
2.0500
78.5
79.2
470.9
2,907
3,564
2020
1,209
1,195
2.60
2.57
1.9375
74.5
75.4
464.8
2,701
4,177
Variance
22
24
0.01
0.02
0.1125
4.0
3.8
6.1
206
(613)
Earnings and EPS
Common Equity Earnings increased by $22 million compared to 2020. Growth in Common Equity Earnings was tempered by the
unfavourable impact of foreign exchange of $48 million, and significant one-time items recognized in 2020 of $14 million. The significant
items in 2020 included an adjustment to ITC's base ROE, partially offset by the finalization of U.S. tax reform. These impacts were partially
offset by unrealized mark-to-market gains of $12 million in 2021 on natural gas derivatives at Aitken Creek.
The Corporation delivered earnings growth of $72 million excluding the impact of the above noted items. Operational growth in 2021
reflected: (i) Rate Base growth; (ii) higher earnings in Arizona primarily due to new customer rates at TEP effective January 1, 2021, partially
offset by lower sales due to unfavourable weather and higher operating costs; (iii) continued recovery in the Caribbean from economic
conditions experienced in 2020 associated with the COVID-19 Pandemic; and (iv) higher sales at FortisAlberta associated with favourable
weather, partially offset by a higher effective income tax rate. This growth was partially offset by lower hydroelectric production in Belize, and
lower earnings at Aitken Creek due to realized losses on natural gas contracts.
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.
14 FORTIS INC.
2021 Annual Report
Management Discussion and Analysis
Adjusted Common Equity Earnings and Adjusted Basic EPS increased by $24 million and $0.02, respectively. Refer to "Non-U.S. GAAP Financial
Measures" on page 24 for a reconciliation of these measures. The changes in Adjusted Basic EPS, including the unfavourable impact of foreign
exchange described above, are illustrated in the chart below.
(1) Primarily reflects Rate Base growth and an adjustment related to interest rate swaps, partially offset by higher non-recoverable expenses
(2) Includes FortisBC Energy, FortisAlberta and FortisBC Electric. Primarily reflects Rate Base growth, as well as higher sales due to favourable weather partially offset by a
higher effective income tax rate at FortisAlberta
(3) Includes UNS Energy and Central Hudson. Increase at UNS Energy primarily reflects the impact of new customer rates at TEP partially offset by lower sales driven by
unfavourable weather and higher operating costs mainly related to planned generation maintenance. Earnings at Central Hudson reflects the finalization of its
general rate application effective July 1, 2021, partially offset by the impact of regulatory mechanisms and higher operating costs
(4) Primarily reflects higher earnings in the Caribbean, related to the continued recovery from economic conditions in 2020 associated with the COVID-19 Pandemic
(5) Average foreign exchange rate of 1.25 in 2021 compared to 1.34 in 2020
(6) Primarily reflects variations in hydroelectric production in Belize associated with rainfall levels, and lower earnings at Aitken Creek due to realized losses on natural gas
contracts, as certain contracts were settled in 2021 in consideration of favourable forward curves
(7) Weighted average shares of 470.9 million in 2021 compared to 464.8 million in 2020
Dividends
Fortis paid a dividend of $0.535 per common share in the fourth quarter of 2021, up 5.9% from $0.505 paid in each of the previous four
quarters and in line with the Corporation's dividend guidance. The Actual Payout Ratio was 78.5% in 2021 compared to 74.5% in 2020 and an
annual average of 65.9% over the five-year period of 2017 through 2021.
Fortis has increased its common share dividend for 48 consecutive years. In September 2021, Fortis reaffirmed its targeted average annual
dividend growth of approximately 6% through 2025.
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FORTIS INC.
2021 Annual Report
CHANGES IN ADJUSTED BASIC EPS$2.57$0.07$0.05$0.04$0.02$(0.10)$(0.03)$(0.03)$2.592020AdjustedBasic EPSITCTransmission(1)WesternCanadianElectric andGas (2)U.S. Electricand Gas(3)OtherElectric(4)ForeignExchange(5)EnergyInfrastructure(6)WeightedAverageShares(7)2021AdjustedBasic EPS48 YEARS OF CONSECUTIVE DIVIDEND INCREASESDividend Payments73747576777879808182838485868788899091929394959697989900010203040506070809101112131415161718192021 Management Discussion and Analysis
Growth of dividends and the market price of the Corporation's common shares have together yielded the following TSR.
TSR (1) (%)
Fortis
1-Year
21.8
5-Year
12.1
10-Year
10.2
20-Year
12.6
(1) Annualized TSR per Bloomberg, as at December 31, 2021
Operating Cash Flow
The $206 million increase in Operating Cash Flow was due to higher cash earnings, reflecting Rate Base growth and new customer rates at
TEP effective January 1, 2021, partially offset by higher operating costs at TEP and an upfront payment received by FortisAlberta in 2020
associated with a long-term energy retailer agreement. Favourable changes in regulatory deferrals due to the timing of flow-through costs in
customer rates and lower transmission payments at FortisAlberta also contributed to the increase. The increase was partially offset by the
lower U.S.-to-Canadian dollar exchange rate in 2021.
Capital Expenditures
Capital Expenditures were $3.6 billion, broadly consistent with the 2021 Capital Plan. For a detailed discussion of the Corporation's capital
expenditure program, see "Capital Plan" on page 31. Capital Expenditures in 2021 were $0.6 billion lower than 2020 primarily due to the
timing of costs associated with the construction of the Oso Grande generating facility at UNS Energy, and the impact of the lower average
foreign exchange rate.
The Corporation's five-year 2022-2026 Capital Plan of $20.0 billion reflects $1.0 billion of additional capital investment at the Corporation's
regulated utilities in comparison to the 2021-2025 Capital Plan disclosed in the 2020 MD&A. The increase largely reflects customer growth,
enhancements to transmission reliability and capacity, and investments in cleaner energy. This growth is tempered by $600 million associated
with the lower assumed foreign exchange rate of 1.25, down from a rate of 1.32 assumed in the Corporation's previous five-year Capital Plan.
Overall, the COVID-19 Pandemic did not have a material impact on capital expenditures in 2021. While the Corporation does not expect the
COVID-19 Pandemic to materially impact its overall five-year Capital Plan, the timing of forecast capital expenditures will continue to be
evaluated. Depending on the length and severity of the pandemic, including any impacts of supply chain disruptions, certain planned
expenditures may shift within the 2022-2026 Capital Plan. Funding of the Capital Plan is expected to be primarily through Operating Cash
Flow, regulated utility debt and common equity from the Corporation's DRIP.
The five-year Capital Plan is expected to increase midyear Rate Base from $31.1 billion in 2021 to $41.6 billion by 2026, representing a five-year
CAGR of approximately 6%. Fortis expects this growth in Rate Base will support earnings and dividend growth.
Capital Expenditures and Capital Plan reflect Non-U.S. GAAP financial measures. Refer to "Non-U.S. GAAP Financial Measures" on page 24 and
"Capital Plan" on page 31.
Additional opportunities to expand and extend growth include: further expansion of the electric transmission grid in the U.S. to facilitate the
interconnection of cleaner energy, including infrastructure investments associated with MISO's long-range transmission plan; natural gas
resiliency investments in pipelines and LNG infrastructure in British Columbia; the fully permitted, cross-border, Lake Erie Connector electric
transmission project in Ontario; and the acceleration of cleaner energy infrastructure investments across our jurisdictions.
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FORTIS INC.
2021 Annual Report
($ billions)PROJECTED RATE BASE GROWTH31.133.535.737.339.441.6Canadian and CaribbeanU.S.20212022F2023F2024F2025F2026F Management Discussion and Analysis
THE INDUSTRY
The North American energy industry’s transformation is accelerating at a rapid pace, driven by the impacts of climate change and the need
for a cleaner energy future. This creates a growing need for the development of cleaner energy sources and the deployment of energy
conservation measures to preserve the planet for future generations. The goal of carbon emission reduction creates the need for increased
innovation, and associated advancements in technology have attracted interest from investors and customers. Renewable generation
continues to be a key element in a decarbonized future, with electric transmission seen as a critical enabler of large-scale renewables. Natural
gas also continues to be an important part of the energy mix, as supplemental generation to the intermittency of renewables, and as a cost-
effective heating source. Longer term, advancements in the use of hydrogen and RNG may also contribute to carbon reduction. Each of these
factors, as well as the increasing affordability of cleaner energy, is driving significant investment opportunity in the utility sector.
Energy policies at the federal, state, and provincial levels continue to reflect the rising focus on climate change, with clean energy and carbon
reduction goals and initiatives at the forefront. In the U.S., legislation has been approved for significant infrastructure investments, including
those in the energy sector involving renewables, transmission and storage. Additional legislation is under consideration, which would further
increase the investments required to meet new and aggressive federal carbon reduction goals. With states and provinces also setting
ambitious carbon reduction targets, the regulatory and compliance environment continues to evolve and become increasingly complex.
These changes are creating opportunities to expand investment in new, renewable generation sources, including solar and wind, as well as
transmission infrastructure to interconnect renewable energy sources to the grid. As the amount of renewables grow, investment
opportunities in energy storage are also being created, driven by the decreasing costs of energy storage technology. The electrification of the
transportation sector is gaining momentum and represents a significant opportunity to reduce GHG 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 well into the future.
New technology is stimulating change across all service territories. Energy delivery systems are becoming more intelligent, with upgraded
advanced meters, additional 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 been enabled with options to manage and reduce energy usage and access
more affordable distributed generation technology. Grid resilience is growing in importance with the increasing frequency of extreme
weather events such as hurricanes, wildfires, tornadoes and storms. As a result, investments in grid hardening and resiliency are increasing in
importance to improve the grid’s ability to withstand and recover from these climate events.
Fortis' culture of innovation underlies a continuous drive to find a better way to safely, reliably and affordably deliver the energy and services
that customers need. To further advance innovation, Fortis is a partner in the Energy Impact Partners utility coalition, which is a strategic
private equity fund that invests in emerging technologies, products, services and business models that are transforming the industry. The
Corporation is also involved in the Electric Power Research Institute’s Low Carbon Resources Initiative, along with other major North American
utilities. By leveraging these strengths and partnerships, Fortis expects to remain at the forefront of this ever-changing industry.
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 services. They also expect personalized service, customized self-service
offerings and more real-time, digital communication. Fortis' utilities are capitalizing on this as an opportunity to provide enhanced customer
information systems and digital technologies to improve customer service.
On the security front, with the advent of new and increasing cyber threats to our information and operational technology systems, increased
focus and investment on protection and response to these events is an ongoing effort. Upgrades to the physical security environment is 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.
Fortis is positioned to capitalize on evolving industry opportunities. The Corporation's decentralized structure and customer-focused business
culture support the efforts required to meet changing customer expectations. Each of the 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 being a strong energy partner for its communities by operating in an environmentally and socially responsible manner.
Fortis believes that responsible environmental and sustainability management not only creates business value, but it is also good for our
customers and the planet.
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FORTIS INC.
2021 Annual Report
Management Discussion and Analysis
To bring focus and accountability to sustainability, oversight is coordinated at the most senior levels of Fortis and is a priority at each of our
operating subsidiaries. Sustainability efforts are managed at the utility level to address applicable federal, provincial/state and municipal laws
and regulations, which may differ in each service territory. Fortis' Executive Vice-President, Sustainability and Chief Human Resource Officer
reports to the President and CEO and collectively they are responsible for enterprise-wide sustainability and stewardship at the executive
level. The Board is responsible for risk management oversight and ensuring that business is conducted to meet high standards of
environmental and social responsibility. The governance and sustainability committee of the Board is responsible for overseeing governance
structure and sustainability programs and practices.
Key aspects of Fortis' sustainability program and practices are outlined below. Additional information may be found in the Corporation's
Annual Information Form.
Climate Change and Environmental Matters
Fortis is primarily an energy delivery company with 93% of its assets dedicated to the movement of energy through our wires and natural gas
lines. This presents a unique opportunity for Fortis to facilitate the delivery of cleaner energy to its customers and limits its impact on the
environment when compared to energy generation-intensive businesses. Although Fortis has limited fossil-fuel generation exposure, it has a
plan to transition to more sustainable energy for its customers.
The Corporation's direct GHG emissions come primarily from its generation assets, and largely include fossil fuel-based generation at TEP
representing 5% of the Corporation's total assets. Fortis continues to build on its low emissions profile and is committed to achieve its
corporate-wide target to reduce carbon emissions by 75% by 2035 from a 2019 base year. Fortis expects to achieve this target through
delivering on TEP's plan to reduce carbon emissions, as well as clean energy initiatives across the Corporation's other utilities.
In 2021, Fortis' Scope 1 emissions were 20% lower relative to 2019 levels, equivalent to taking approximately 540,000 vehicles off the road in
one year and marking significant progress to our 75% target. Closure of Navajo at TEP in late 2019 as well as recently commissioned
renewable projects, such as the 250-MW Oso Grande wind project, the 99-MW Borderlands wind project and the 100-MW Wilmot solar
project, have supported our carbon emissions reduction target to date.
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. Fortis' most recent
sustainability update was released in July 2021 and included information on: (i) the Corporation's progress on reducing carbon emissions;
(ii) updated sustainability key indicators; (iii) alignment with standards issued by the Sustainability Accounting Standards Board; and (iv) the
Corporation's support of the Task Force on Climate-related Financial Disclosures. The Corporation is currently completing a climate scenario
analysis to assess the resiliency of our energy delivery businesses with a progress update planned in 2022.
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.
In 2021, $600 million in Capital Expenditures were focused on the delivery of cleaner energy to customers. In addition, in the development of
the Corporation's five-year Capital Plan, each of the utilities consider investment required to deliver cleaner energy to customers, strengthen
infrastructure, and improve network resiliency, with the intent of maintaining customer reliability, while also mitigating the expected impacts
of climate change, such as more frequent and intense weather events, on utility infrastructure. Additional information on the Corporation's
Capital Plan can be found in the "Capital Plan" section on page 31.
Customer Service and Community Efforts
Fortis' utilities work closely with their customers and communities to drive enhancements and 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 centre services and reliability of energy supply.
Fortis and its utilities consistently look for opportunities for growth, innovation and energy efficiency in the communities served. Regular
community engagement through donations to local charities, partnerships with educational institutions, and participation on local boards,
amongst other initiatives, enables Fortis to remain a meaningful contributor to our local communities.
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FORTIS INC.
2021 Annual Report
Management Discussion and Analysis
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. Oversight of cybersecurity is the responsibility of Fortis' Vice President, Chief Information Officer and the respective boards and
executive committees at Fortis and at each utility.
Human Capital Management
Fortis values its 9,100 employees and recognizes that success is dependent on a strong workforce which is safe, supported and empowered.
Fortis has 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 reflected throughout the organization. The
Corporation has established delivering a cleaner energy future as its core purpose, driven by values embedded at all levels of the
organization.
Governance
Fortis has a Code of Conduct which is guided by the Corporation's purpose and values and sets out standards for the ethical conduct of its
business, including all of its directors, officers, employees, consultants, contractors and representatives, as applicable. The core principles of
the Fortis Code of Conduct apply universally 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 annually certify compliance.
The Code of Conduct is supported by other policies that outline the behaviour expected from management and employees, including the
Anti-Corruption Policy and Respectful Workplace Policy. 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 reporting of conduct that may breach the
Code of Conduct or other workplace policies.
Diversity, Equity and Inclusion
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 maintaining a Board where at least 40% of independent directors are women. Currently, 50% of the
Board and 45% of its executive leadership team are women. 60% of Fortis utilities have either a female president or female board chair. Fortis
has also recently introduced a target of two directors identifying as a visible minority or indigenous by 2023.
Advancing diversity, equity and inclusion is a priority at Fortis. The Corporation has a formal Inclusion and Diversity Commitment that applies
to all employees at Fortis and its operating subsidiaries. The commitment is supported by a framework built upon three pillars - talent, culture
and community. A Diversity, Equity and Inclusion Advisory Council with diverse, senior level representation from across the Fortis organization
guides the inclusion and diversity strategy and its implementation.
OPERATING RESULTS
($ millions)
Revenue
Energy supply costs
Operating expenses
Depreciation and amortization
Other income, net
Finance charges
Income tax expense
Net earnings
Net earnings attributable to:
Non-controlling interests
Preference equity shareholders
Common equity shareholders
Net Earnings
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FORTIS INC.
2021 Annual Report
2021
9,448
2,951
2,523
1,505
173
1,003
234
1,405
111
63
1,231
1,405
2020
8,935
2,562
2,437
1,428
154
1,042
231
1,389
115
65
1,209
1,389
Variance
FX
(345)
(77)
(107)
(52)
—
(40)
(14)
(55)
(7)
—
(48)
(55)
Other
858
466
193
129
19
1
17
71
3
(2)
70
71
Management Discussion and Analysis
Revenue
The increase in revenue, net of foreign exchange, was due primarily to: (i) higher flow-through costs in customer rates; (ii) Rate Base growth;
(iii) new customer rates, effective January 1, 2021 and higher wholesale sales at TEP; and (iv) higher retail electricity sales, primarily in Western
Canada and the Caribbean, partially offset by lower sales in Arizona due to unfavourable weather. The increase was partially offset by a $40
million favourable base ROE adjustment recognized at ITC in 2020 as a result of the May 2020 FERC Decision.
Energy Supply Costs
The increase in energy supply costs, net of foreign exchange, was due primarily to overall higher commodity costs due to pricing and
volumes, and the impact of higher wholesale sales at TEP.
Operating Expenses
The increase in operating expenses, net of foreign exchange, was due primarily to: (i) higher flow-through costs, particularly at ITC; (ii) higher
operating costs mainly related to planned generation maintenance at UNS Energy; and (iii) general inflationary and employee-related cost
increases. The increase was partially offset by lower credit loss expense.
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.
Other Income, Net
The increase, net of foreign exchange, was due primarily to non-service benefit costs and higher mark-to-market gains on total returns swaps
associated with share price growth, partially offset by lower equity income from Belize Electricity.
Finance Charges
Finance charges, net of foreign exchange, were consistent with 2020. The impact of higher debt levels to support the Corporation's Capital
Plan was largely offset by the benefit of refinancing debt at lower interest rates.
Income Tax Expense
The increase in income tax expense, net of foreign exchange, was driven by: (i) a higher consolidated state tax rate associated with changes in
regional sales mix; and (ii) a higher effective income tax rate at FortisAlberta, partially offset by the reversal of a $13 million tax recovery in
2020 resulting from the finalization of U.S. tax reform and associated anti-hybrid regulations.
Net Earnings
See "Performance at a Glance - Earnings and EPS" on page 14.
BUSINESS UNIT PERFORMANCE
Common Equity Earnings
($ millions)
Regulated Utilities
ITC
UNS Energy
Central Hudson
FortisBC Energy
FortisAlberta
FortisBC Electric
Other Electric (2)
Non-Regulated
Energy Infrastructure (3)
Corporate and Other (4)
Common Equity Earnings
2021
426
292
93
185
141
59
118
1,314
38
(121)
1,231
2020
449
302
91
175
133
56
112
1,318
39
(148)
1,209
Variance
FX (1)
Other
(31)
(20)
(4)
—
—
—
(2)
(57)
—
9
(48)
8
10
6
10
8
3
8
53
(1)
18
70
(1) The reporting currency of ITC, UNS Energy, Central Hudson, Caribbean Utilities, FortisTCI and BECOL 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$1.00. The Corporate and Other segment includes certain transactions denominated in U.S. dollars.
(2) Consists of the utility operations in eastern Canada and the Caribbean: Newfoundland Power; Maritime Electric; FortisOntario; Caribbean Utilities; FortisTCI; and Belize Electricity
(3) Primarily consists of long-term contracted generation assets in Belize and Aitken Creek in British Columbia
(4)
Includes Fortis net corporate expenses and non-regulated holding company expenses
20 FORTIS INC.
2021 Annual Report
Management Discussion and Analysis
ITC
($ millions)
Revenue (1)
Earnings (1)
2021
1,691
426
2020
1,744
449
Variance
FX
(117)
(31)
Other
64
8
(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, reflected higher flow-through costs in customer rates and Rate Base growth. The increase
was partially offset by a $40 million favourable base ROE adjustment recognized in 2020 as a result of the May 2020 FERC Decision.
Earnings
The increase in earnings, net of foreign exchange, reflected Rate Base growth and an adjustment related to the amortization of interest rate
swaps. The increase was partially offset by a $27 million favourable base ROE adjustment as a result of the May 2020 FERC Decision, discussed
above, and higher non-recoverable operating expenses related to an increase in stock-based compensation costs due to the Corporation's
share price growth.
UNS Energy
($ millions, except as indicated)
Retail electricity sales (GWh)
Wholesale electricity sales (GWh) (1)
Gas sales (PJ)
Revenue
Earnings
(1) Primarily short-term wholesale sales
2021
10,559
6,283
16
2,334
292
2020
10,920
5,843
15
2,260
302
Variance
FX
—
—
—
(147)
(20)
Other
(361)
440
1
221
10
Sales
The decrease in retail electricity sales was largely due to unfavourable weather as compared to 2020.
The increase in wholesale electricity sales was due primarily to favourable market conditions, including customer demand in the first quarter
of 2021 resulting from a severe winter storm in southwestern U.S. in February 2021. Revenue from short-term wholesale sales is primarily
credited to customers through regulatory deferral mechanisms and, therefore, does not materially impact earnings.
Gas sales were consistent with 2020.
Revenue
The increase in revenue, net of foreign exchange, was due primarily to: (i) new customer rates effective January 1, 2021 at TEP; (ii) higher
wholesale electricity sales reflecting favourable market conditions; (iii) higher transmission revenue; and (iv) the recovery of higher fuel and
non-fuel costs through the normal operation of regulatory mechanisms. The increase was partially offset by lower retail electricity sales,
discussed above.
Earnings
The increase in earnings, net of foreign exchange, was due to the impact of new customer rates and higher transmission revenue at TEP,
partially offset by: (i) higher operating costs mainly related to planned generation maintenance in 2021, including outages at the Springerville
and Sundt generating facilities; and (ii) lower retail electricity sales driven by unfavourable weather.
21
FORTIS INC.
2021 Annual Report
Management Discussion and Analysis
Central Hudson
($ millions, except as indicated)
Electricity sales (GWh)
Gas sales (PJ)
Revenue
Earnings
2021
5,000
23
1,000
93
2020
4,969
23
953
91
Variance
FX
—
—
(60)
(4)
Other
31
—
107
6
Sales
Electricity and gas sales were largely consistent with 2020.
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 increase in revenue, net of foreign exchange, was due primarily to: (i) the flow through of higher energy supply costs driven by higher
commodity prices; and (ii) the finalization of Central Hudson's general rate application including an increase in gas and electricity delivery
rates with retroactive effect to July 1, 2021, reflecting a return on increased Rate Base assets, the recovery of higher operating and finance
expenses, and the recovery of finance charges which had not been billed to customers since the second quarter of 2020. See "Regulatory
Highlights" on page 25 for further details. The increase in revenue was partially offset by the normal operation of regulatory mechanisms to
be reflected in future customer rates.
Earnings
The increase in earnings, net of foreign exchange, was due primarily to the finalization of Central Hudson's general rate application, partially
offset by the operation of regulatory mechanisms, discussed above, as well as higher operating costs.
FortisBC Energy
($ millions, except as indicated)
Gas sales (PJ)
Revenue
Earnings
2021
228
1,715
185
2020
219
1,385
175
Variance
9
330
10
Sales
The increase in gas sales was due primarily to higher consumption by residential and commercial customers due to colder temperatures in
the fourth quarter of 2021 as compared to the same period in 2020.
Revenue
The increase in revenue was due primarily to a higher cost of natural gas recovered from customers, Rate Base growth, and the normal
operation of regulatory deferrals.
Earnings
The increase in earnings was due primarily to Rate Base growth.
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)
Electricity deliveries (GWh)
Revenue
Earnings
22 FORTIS INC.
2021 Annual Report
2021
16,643
644
141
2020
16,092
596
133
Variance
551
48
8
Management Discussion and Analysis
Deliveries
The increase in electricity deliveries was due to: (i) higher average consumption by residential and small commercial customers due to
favourable weather largely in the first and third quarters of 2021; (ii) customer additions; and (iii) higher load from industrial customers.
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 increases in revenue and earnings were due to: (i) Rate Base growth and customer additions; (ii) higher revenue associated with
significantly colder and warmer temperatures in the first and third quarters of 2021, respectively; and (iii) higher revenue associated with a
long-term energy retailer agreement. The increase in earnings was partially offset by the impact of a higher effective income tax rate
associated with lower available tax deductions in 2021 as compared to 2020, and higher operating costs.
FortisBC Electric
($ millions, except as indicated)
Electricity sales (GWh)
Revenue
Earnings
2021
3,460
468
59
2020
3,291
424
56
Variance
169
44
3
Sales
The increase in electricity sales was due primarily to: (i) higher average consumption, as a result of warmer temperatures in the second quarter
of 2021 and colder temperatures in the fourth quarter of 2021 compared to the same periods in 2020; and (ii) higher average consumption by
commercial and industrial customers due, in part, to the impact of the COVID-19 Pandemic, which resulted in tighter public health restrictions
during 2020 as compared to 2021.
Revenue
The increase in revenue was due primarily to: (i) higher electricity sales, partially offset by the normal operation of regulatory deferrals; (ii) Rate
Base growth; and (iii) an increase in third-party contract work.
Earnings
The increase in earnings was due primarily to Rate Base growth.
Due to regulatory deferral mechanisms, changes in consumption levels do not materially impact earnings.
Other Electric
($ millions, except as indicated)
Electricity sales (GWh)
Revenue
Earnings
2021
9,266
1,498
118
2020
9,175
1,485
112
Variance
FX
—
(21)
(2)
Other
91
34
8
Sales
The increase in electricity sales was due primarily to overall higher average consumption, reflecting the continued recovery from the impacts
of the COVID-19 Pandemic in 2020, including the temporary closure of non-essential businesses and lower tourism-related activities in the
Caribbean.
Revenue
The increase in revenue, net of foreign exchange, reflected higher sales, the flow through of overall higher energy supply costs, and Rate Base
growth.
Earnings
The increase in earnings, net of foreign exchange, primarily reflected the continued recovery of economic conditions in the Caribbean and
Rate Base growth, partially offset by lower equity income from Belize Electricity.
23 FORTIS INC.
2021 Annual Report
Management Discussion and Analysis
Energy Infrastructure
($ millions, except as indicated)
Electricity sales (GWh)
Revenue
Earnings
2021
147
98
38
2020
229
88
39
Variance
(82)
10
(1)
Sales
The change in electricity sales reflected variations in hydroelectric production in Belize associated with rainfall levels.
Revenue
The increase in revenue was due to year-over-year changes at Aitken Creek, including unrealized gains associated with mark-to-market
accounting of natural gas derivatives partially offset by realized losses on natural gas contracts, as certain contracts were settled in 2021 in
consideration of favourable forward curves. The increase in revenue was also partially offset by lower hydroelectric production in Belize.
Earnings
The decrease in earnings was primarily due to lower hydroelectric production in Belize, partially offset by higher earnings at Aitken Creek as
discussed above.
Aitken Creek is subject to commodity price risk, as it purchases and holds natural gas in storage to earn a profit margin from its ultimate sale.
Aitken Creek mitigates this risk by using derivatives to materially lock in the profit margin that will be realized upon the sale of natural gas. The
fair value accounting of these derivatives creates timing differences and the resultant earnings volatility can be significant.
Corporate and Other
($ millions)
Net expenses
2021
(121)
2020
(148)
Variance
FX
9
Other
18
The decrease in net expenses, net of foreign exchange, was due primarily to: (i) the reversal of a $13 million tax recovery in 2020, originally
recognized in 2019, resulting from the finalization of U.S. tax reform and associated anti-hybrid regulations; (ii) lower operating expenses; and,
(iii) higher mark-to-market gains on total returns swaps associated with share price growth. The decrease was partially offset by a lower
income tax recovery resulting from a higher consolidated state tax rate associated with changes in regional sales mix.
NON-U.S. GAAP FINANCIAL MEASURES
Adjusted Common Equity Earnings, Adjusted Basic EPS, Adjusted Payout Ratio and Capital Expenditures are Non-U.S. GAAP Financial
Measures and may not be comparable with similar measures used by other entities. They are presented because management and external
stakeholders use them in evaluating the Corporation's financial performance and prospects.
Net earnings attributable to common equity shareholders (i.e., Common Equity Earnings) and basic EPS are the most directly comparable
U.S. GAAP measures to Adjusted Common Equity Earnings and Adjusted Basic EPS, respectively. The Actual Payout Ratio calculated using
Common Equity Earnings is the most comparable U.S. GAAP measure to the Adjusted Payout Ratio. These adjusted measures reflect the
removal of items that management excludes in its key decision-making processes and evaluation of operating results.
Capital Expenditures include additions to property, plant and equipment and additions to intangible assets, as shown on the consolidated
statements of cash flows. It also includes Fortis' 39% share of capital spending for the Wataynikaneyap Transmission Power Project, consistent
with Fortis' evaluation of operating results and its role as project manager during the construction of this Major Capital Project.
24 FORTIS INC.
2021 Annual Report
Management Discussion and Analysis
Non-U.S. GAAP Reconciliation
($ millions, except as indicated)
Adjusted Common Equity Earnings, Adjusted Basic EPS
and Adjusted Payout Ratio
Common Equity Earnings
Adjusting items:
Unrealized gain on mark-to-market of derivatives (1)
May 2020 FERC decision (2)
U.S. tax reform (3)
Adjusted Common Equity Earnings
Adjusted Basic EPS (4) ($)
Adjusted Payout Ratio (5) (%)
Capital Expenditures
Additions to property, plant and equipment
Additions to intangible assets
Adjusting item:
Wataynikaneyap Transmission Power Project (6)
Capital Expenditures
2021
1,231
(12)
—
—
1,219
2.59
79.2
3,189
197
178
3,564
2020
1,209
—
(27)
13
1,195
2.57
75.4
3,857
182
138
4,177
Variance
22
(12)
27
(13)
24
0.02
3.8
(668)
15
40
(613)
(1) Represents timing differences related to the accounting of natural gas derivatives at Aitken Creek, net of income tax expense of $5 million in 2021 (2020 - $nil),
included in the Energy Infrastructure segment
(2) Represents prior period impacts of the May 2020 FERC Decision, net of income tax expense of $11 million, included in the ITC segment
(3) Represents income tax expense resulting from the finalization of U.S. tax reform and associated anti-hybrid regulations, included in the Corporate and Other segment
(4) Calculated using Adjusted Common Equity Earnings divided by weighted average common shares of 470.9 million in 2021 (2020 - 464.8 million)
(5) Calculated using dividends paid per common share of $2.05 in 2021 (2020 - $1.9375) divided by Adjusted Basic EPS
(6) 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 regulatory 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 generally depends 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 reflected 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 governmental authorities.
Additional information about regulation and the regulatory matters discussed below is provided in Note 2 in the 2021 Annual Financial
Statements. Also refer to "Business Risks - Utility Regulation" on page 36.
Significant Regulatory Developments
ITC
Transmission Incentives: In April 2021, FERC issued a supplemental NOPR on transmission incentives modifying the proposal in the initial
NOPR released in March 2020. The supplemental NOPR proposes to eliminate the 50-basis point RTO ROE incentive adder for existing RTO
members that have been members longer than three years, like ITC. In June 2021, ITC filed its comments on the supplemental NOPR
supporting the continuation of the ROE incentive adder for RTO members. The timeline for FERC to issue a final rule in this proceeding and
the likely outcome cannot be determined at this time. Although any potential impact to Fortis remains uncertain, every 10-basis point change
in ROE at ITC impacts Fortis' annual EPS by approximately $0.01.
25 FORTIS INC.
2021 Annual Report
Management Discussion and Analysis
UNS Energy
FERC Rate Case: In 2019, FERC issued an order accepting formula transmission rates proposed by TEP, subject to refund following hearing
and settlement procedures. A settlement in principle was reached in August 2021, and a settlement agreement including an ROE of 9.79%
was filed with FERC in December 2021. Until conclusion of the proceeding, customer rates continue to be charged under the 2019 FERC
order and remain subject to refund pending the final order. The timing and outcome of this proceeding remains unknown.
Central Hudson
General Rate Application: In November 2021, the PSC approved a three-year rate plan for Central Hudson with retroactive application to
July 1, 2021, including an ROE of 9.0%, and a common equity component of capital structure of 50% declining by 1% annually to 48% in the
third rate year. The three-year rate plan also reflects the use of existing regulatory balances and other measures to reduce customer bill
impacts, the recovery of finance charges which had not been billed to customers since the second quarter of 2020, as well as initiatives to
support New York State's climate goals.
FortisBC Energy and FortisBC Electric
GCOC Proceeding: In January 2021, the BCUC announced the initiation of a GCOC proceeding including a review of the common equity
component of capital structure and the allowed ROE. The timing and outcome of this proceeding, including the effective date of any change
in the cost of capital for 2022 or beyond, remains unknown.
FortisAlberta
2022 GCOC Proceeding: In March 2021, the AUC concluded the 2022 GCOC proceeding and extended the existing allowed ROE of 8.5% using
a 37% equity component of capital structure through 2022.
2023 COS Application: The final year of FortisAlberta's second PBR term is 2022. In June 2021, the AUC issued a decision confirming the
approach to be adopted by Alberta distribution utilities for the COS rebasing year in 2023. In November 2021, FortisAlberta filed its 2023 COS
application and a decision is expected in the third quarter of 2022.
2023/2024 GCOC Proceeding: In January 2022, the AUC initiated proceedings to establish the cost of capital parameters for 2023 and to
consider a formula-based approach to setting the allowed ROE for 2024 and beyond. The AUC is considering extending the existing allowed
ROE of 8.5% using a 37% equity component of capital structure through 2023. Comments on this proposal are due in February 2022 and a
decision is expected in the first quarter of 2022. The GCOC proceeding for 2024 and beyond is expected to commence in the third quarter of
2022, with a decision expected in 2023.
Third PBR Term: In July 2021, the AUC issued a decision confirming that Alberta distribution utilities will be subject to a third PBR term
commencing in 2024 with going-in rates based on the 2023 COS rebasing. The AUC also initiated a new proceeding to consider the design of
the third PBR term. FortisAlberta will submit comments with respect to the design of the third PBR term in 2022 and a decision from the AUC
is expected in 2023.
Independent System Operator Tariff Proceeding: In April 2021, the AUC issued a decision confirming that distribution facility owners, such as
FortisAlberta, will no longer be permitted to earn a return on AESO contributions made on a prospective basis from the date of the decision.
Contributions made prior to that date are not impacted. The decision did not have a material financial impact on the Corporation in 2021 and
it is not expected to materially impact future periods. In January 2022, the Alberta Court of Appeal granted a full appeal on this matter. In
doing so, the Alberta Court of Appeal also permitted a related appeal regarding the legality of the AUC's AESO customer contribution policy.
FortisAlberta will fully participate in the appeal regarding the legality of the AESO customer contribution policy and will closely monitor the
preceding related to earned returns on future AESO contributions.
FINANCIAL POSITION
Significant Changes between December 31, 2021 and 2020
Balance Sheet Account
($ millions)
Cash and cash equivalents
Variance
FX
(1)
Other
Explanation
(117)
Reflects the timing of debt
reinvestment in capital and operating requirements.
issuances, and the related
Accounts receivable and other current assets
(5)
147
Due primarily to the flow through of higher energy supply
costs and an increase in the fair value of energy contracts,
partially offset by a lower income tax receivable.
Other assets
(4)
289
Due primarily to an increase in employee future benefit assets,
largely at Central Hudson, driven by higher discount rates.
Property, plant and equipment, net
(156)
1,974
Due to capital expenditures, partially offset by depreciation.
26 FORTIS INC.
2021 Annual Report
Management Discussion and Analysis
Significant Changes between December 31, 2021 and 2020
Balance Sheet Account
($ millions)
Short-term borrowings
Variance
FX
(1)
Other
Explanation
116
Reflects the issuance of commercial paper at ITC to finance
working capital and capital investment requirements.
Accounts payable & other current liabilities
(8)
257
Due to higher energy supply costs at FortisBC Energy and
UNS Energy.
Other liabilities
(6)
(184) Due primarily to a decrease in employee future benefit
Regulatory liabilities (current and long-term)
(15)
134
liabilities driven by higher discount rates.
Due to the normal operation of regulatory mechanisms
including employee future benefits, largely at Central Hudson,
and the fair value of energy contracts at UNS Energy, partially
offset by a reduction in deferred income taxes.
Deferred income tax liabilities
(13)
296
Due to higher temporary differences associated with ongoing
capital investment.
Long-term debt (including current portion)
(112)
1,080
Shareholders' equity
(82)
673
Reflects debt issuances, partially offset by debt repayments, at
Corporate and the regulated utilities, as well as higher
borrowings under committed credit facilities.
Due primarily to: (i) Common Equity Earnings for 2021, 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 and issuances of common shares, preference equity and long-term debt. 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 total facilities. Approximately $4.6 billion of the total credit facilities are committed with maturities ranging from 2022 through 2026.
Available credit facilities are summarized in the following table.
Credit Facilities
As at December 31
($ millions)
Total credit facilities (1)
Credit facilities utilized:
Short-term borrowings
Long-term debt (including current portion)
Letters of credit outstanding
Credit facilities unutilized
Regulated
Utilities
3,466
(247)
(1,019)
(70)
2,130
Corporate
and Other
1,380
—
(286)
(45)
1,049
2021
4,846
(247)
(1,305)
(115)
3,179
2020
5,581
(132)
(980)
(130)
4,339
(1) Additional information about the Corporation's credit facilities is provided in Note 14 in the 2021 Annual Financial Statements
In April 2021, the Corporation's unsecured $500 million revolving one-year term committed credit facility expired and was not renewed, and
in June 2021 the Corporation extended its unsecured $1.3 billion revolving term committed credit facility to July 2026. In October 2021, UNS
Energy terminated a US$150 million revolving credit facility and entered into an arrangement with Fortis.
27
FORTIS INC.
2021 Annual Report
Management Discussion and Analysis
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.
As at December 31, 2021, consolidated fixed-term debt maturities/repayments are expected to average $1,209 million annually over the next
five years and approximately 75% of the Corporation's consolidated long-term debt, excluding credit facility borrowings, had maturities
beyond five years.
In December 2020, 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 May 2021, the Corporation issued 7-
year $500 million unsecured senior notes at 2.18% and, as at December 31, 2021, $1.5 billion remained available under the short-form base
shelf prospectus.
Fortis is well positioned with strong liquidity. This combination of available credit facilities and manageable annual debt maturities/
repayments provides flexibility in the timing of access to capital markets. Given current credit ratings and capital structures, the Corporation
and its subsidiaries currently expect to continue to have reasonable access to long-term capital in 2022.
Fortis and its subsidiaries were in compliance with debt covenants as at December 31, 2021 and are expected to remain compliant in 2022.
Cash Flow Summary
Summary of Cash Flows
Years ended December 31
($ millions)
Cash and cash equivalents, beginning of year
Cash from (used in):
Operating activities
Investing activities
Financing activities
Effect of exchange rate changes on cash and cash equivalents
Cash and cash equivalents, end of year
Operating Activities
See "Performance at a Glance - Operating Cash Flow" on page 16.
2021
249
2,907
(3,488)
451
12
131
2020
370
2,701
(4,132)
1,327
(17)
249
Variance
(121)
206
644
(876)
29
(118)
Investing Activities
The decrease in cash used in investing activities reflects higher capital expenditures in 2020, largely related to the Oso Grande generating
facility at UNS Energy, as well as the lower U.S.-to-Canadian dollar exchange rate. See "Performance at a Glance - Capital Expenditures" on
page 16 and "Capital Plan" on page 31.
Financing Activities
Cash flow related to financing activities will fluctuate largely 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 27.
28 FORTIS INC.
2021 Annual Report
Management Discussion and Analysis
Debt Financing
Long-Term Debt Issuances
Year ended December 31, 2021
ITC
Series A secured senior notes (1)
UNS Energy
Unsecured senior notes
Central Hudson
Unsecured senior notes
Unsecured senior notes
FortisBC Energy
Unsecured debentures
Maritime Electric
Secured first mortgage bonds
Fortis
Unsecured senior notes
Month
Issued
August
May
March
October
April
December
May
Interest Rate
(%)
Maturity
Amount
($ millions)
Use of
Proceeds
2.90
3.25
3.29
3.22
2.42
3.40
2.18
2051
US
75
2051
US
325
US
US
2051
2051
2031
2051
2028
75
55
150
40
500
(2)
(3)(4)
(3)(4)
(3)(5)
(5)
(5)
(3)(4)(5)
(1) US$75 million Series B secured senior notes were priced at 3.05% with issuance expected in May 2022
(2) Fund or refinance a portfolio of eligible green projects
(3) General corporate purposes
(4) Repay maturing long-term debt
(5) Repay credit facility borrowings
In January 2022, ITC issued 30-year US$150 million secured first mortgage bonds at 2.93%. The net proceeds are expected to be used to repay
credit facility borrowings, fund or refinance a portfolio of eligible green projects, fund capital expenditures and for other general corporate
purposes.
In January 2022, Central Hudson issued 5-year US$50 million unsecured senior notes at 2.37% and 7-year US$60 million unsecured senior
notes at 2.59%. The net proceeds are expected to be used to repay maturing long-term debt and for general corporate purposes.
Common Equity Financing
Common Equity Issuances and Dividends Paid
Years ended December 31
($ millions, except as indicated)
Common shares issued:
Cash (1)
Non-cash (2)
Total common shares issued
Number of common shares issued (# millions)
Common share dividends paid:
Cash
Non-cash (3)
Total common share dividends paid
2021
60
358
418
8.0
(608)
(356)
2020
58
116
174
3.5
(786)
(114)
Variance
2
242
244
4.5
178
(242)
(964)
2.0500
(900)
1.9375
(64)
0.1125
Dividends paid per common share ($)
(1) Includes common shares issued under stock option and employee share purchase plans
(2) Common shares issued under the DRIP and stock option plan. The 2% discount offered on common share issuances under the DRIP was reinstated effective December
1, 2020.
(3) Common share dividends reinvested under the DRIP
On November 18, 2021 and February 10, 2022, Fortis declared a dividend of $0.535 per common share payable on March 1, 2022 and
June 1, 2022, respectively. The payment of dividends is at the discretion of the Board and depends on the Corporation's financial condition
and other factors.
29 FORTIS INC.
2021 Annual Report
Management Discussion and Analysis
Contractual Obligations
Contractual Obligations
As at December 31, 2021
($ millions)
Long-term debt:
Principal (1)
Interest
Finance leases (2)
Other obligations (3)
Other commitments: (4)
Waneta Expansion capacity agreement
Gas and fuel purchase obligations
Renewable power purchase agreements
Power purchase obligations
ITC easement agreement
Debt collection agreement
Renewable energy credit purchase agreements
Other
Total
Year 1
Year 2
Year 3
Year 4
Year 5
Thereafter
25,482
15,859
1,202
532
2,525
2,464
1,918
1,783
366
109
87
158
52,485
1,628
1,275
1,750
982
35
168
53
787
122
288
13
3
17
951
34
106
54
446
122
254
13
3
16
892
34
101
55
252
122
194
13
3
11
101
859
34
36
56
169
122
184
13
3
8
2,595
836
35
37
58
121
122
185
13
3
6
66
4,162
7
3,281
7
3,434
6
1,591
4
4,015
18,133
11,339
1,030
84
2,249
689
1,308
678
301
94
29
68
36,002
(1) Amounts not reduced by unamortized deferred financing and discount costs of $147 million. Additional information is provided in Note 14 in the 2021 Annual
Financial Statements.
(2) Additional information is provided in Note 15 in the 2021 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 26 in the 2021 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 $4.0 billion for 2022 and approximately $20.0 billion over the five-year 2022-2026 Capital Plan.
See "Capital Plan" on page 31.
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.
Development projects at ITC may result in payments to developers that are contingent on the projects reaching certain milestones indicating
that the projects are financially viable. It is reasonably possible that ITC will be required to make these contingent development payments up
to a maximum amount of $88 million upon financial close of the projects. In the event it becomes probable that these payments will be
made, the liability and the corresponding intangible asset would be recognized.
UNS Energy has joint generation performance guarantees with participants at San Juan, Four Corners, and Luna, with agreements
expiring in 2022 through 2046, and at 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 Navajo, participants would seek financial recovery from the defaulting party. There is no maximum amount under
these guarantees, except for a maximum of $318 million for Four Corners. As at December 31, 2021, there was no obligation under these
guarantees.
Central Hudson is a participant in an investment with other utilities to jointly develop, own and operate electric transmission projects in New
York State. Central Hudson's maximum commitment is $83 million, for which it has issued a parental guarantee. As at December 31, 2021,
there was no obligation under this guarantee.
As at December 31, 2021, FortisBC Holdings Inc., a non-regulated holding company, had $69 million of parental guarantees outstanding to
support storage optimization activities at Aitken Creek.
30 FORTIS INC.
2021 Annual Report
Management Discussion and Analysis
Off-Balance Sheet Arrangements
With the exception of letters of credit outstanding of $115 million as at December 31, 2021 and the unrecorded commitments in the table
above, the Corporation had no off-balance sheet arrangements.
Capital Structure and Credit Ratings
Fortis requires ongoing access to capital and, therefore, targets a consolidated long-term capital structure that will enable it to maintain
investment-grade credit ratings. The regulated utilities maintain their own capital structures in line with those reflected in customer rates.
Consolidated Capital Structure
As at December 31
Debt (1)
Preference shares
Common shareholders' equity and non-controlling interests (2)
2021
2020
($ millions)
25,784
1,623
19,293
46,700
(%)
55.2
3.5
41.3
100.0
($ millions)
24,581
1,623
18,661
44,865
(%)
54.8
3.6
41.6
100.0
(1)
(2)
Includes long-term debt and finance leases, including current portion, and short-term borrowings, net of cash
Includes shareholders equity, net of preference shares, and non-controlling interests. Non-controlling interests represented 3.5% as at December 31, 2021
(December 31, 2020 - 3.5%)
Outstanding Share Data
As at February 10, 2022, the Corporation had issued and outstanding 474.9 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 converted as at February 10, 2022, an additional 2.8 million common shares would be issued and
outstanding.
Credit Ratings
The Corporation's credit ratings shown below reflect its low 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, 2021
S&P
DBRS Morningstar
Moody's
Rating
A-
BBB+
A (low)
A (low)
Baa3
Baa3
Type
Corporate
Unsecured debt
Corporate
Unsecured debt
Issuer
Unsecured debt
Outlook
Stable
Stable
Stable
In January 2022, S&P revised Central Hudson's outlook to negative from stable in consideration of the PSC's order on the company's general
rate application, projected elevated capital expenditures, and the resulting impact on the company's financial measures.
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 $3.6 billion were slightly lower than the 2021 Capital Plan of $3.8 billion as disclosed in the 2020 MD&A. The reduction
reflected: (i) a lower-than-planned U.S.-to-Canadian dollar exchange rate; and (ii) the timing of Capital Expenditures, including delays at the
Wataynikaneyap Transmission Power Project and at Caribbean Utilities due to the COVID-19 Pandemic. This decrease was partially offset by
higher-than-anticipated Capital Expenditures at ITC, largely reflecting various incremental projects as well as restoration costs following a
derecho storm in the Midwestern U.S. in December 2021.
31
FORTIS INC.
2021 Annual Report
Management Discussion and Analysis
2021 Capital Expenditures (1)
Regulated Utilities
($ millions, except as indicated)
ITC
UNS
Energy
Central
Hudson
FortisBC
Energy
Fortis
Alberta
FortisBC
Electric
Other
Electric
Generation
Transmission
Distribution
Other (3)
Total
(%)
—
939
—
107
1,046
29
177
161
205
167
710
20
1
33
160
97
291
8
—
200
203
72
475
13
—
—
320
69
389
11
18
44
43
29
134
4
62
211
187
39
499
14
Total
Regulated
Utilities
258
1,588
1,118
580
3,544
99
Non-
Regulated (2)
—
—
—
20
20
1
Total
258
1,588
1,118
600
(%)
7
45
31
17
3,564
100
100
(1) See "Non-U.S. GAAP Financial Measures" on page 24
(2) Energy Infrastructure segment
(3)
Includes facilities, equipment, vehicles and information technology assets
Capital Expenditures of $600 million in 2021 were focused on delivering cleaner energy to customers.
Forecast 2022 Capital Expenditures (1)(2)
($ millions, except as indicated)
Generation
Transmission
Distribution
Other
Total
(%)
ITC
—
948
—
50
998
25
UNS
Energy
85
243
244
132
704
18
Regulated Utilities
FortisB
C
Energy
Central
Hudson
Fortis
Alberta
FortisB
C
Electric
Other
Electric
Total
Regulated
Utilities
Non-
Regulated
9
—
—
45
184
106
344
9
270
185
167
622
16
—
358
87
445
11
15
14
98
29
156
4
162
205
193
61
621
15
271
1,725
1,262
632
3,890
98
60
—
—
17
77
2
Total
331
1,725
1,262
649
(%)
8
44
32
16
3,967
100
100
(1) Represents a forward-looking non-GAAP financial measure calculated in the same manner as Capital Expenditures. See "Non-U.S. GAAP Financial Measures" on page
24.
(2) Excludes the non-cash equity component of AFUDC
2022-2026 Capital Plan (1)
($ billions)
Five-year capital plan
2022
4.0
2023
3.8
2024
4.0
2025
4.0
2026
4.2
Total (2) (3)
20.0
(1) Capital Plan is a forward-looking non-GAAP financial measure calculated in the same manner as Capital Expenditures. See "Non-U.S. GAAP Financial Measures" on
page 24.
(2) Reflects an assumed U.S.:CAD foreign exchange rate of 1.25. 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 $450 million over the five-year planning period
(3) Excludes the non-cash equity component of AFUDC
In comparison to the prior five-year plan totaling $19.6 billion as disclosed in the 2020 MD&A, the 2022-2026 Capital Plan reflects $1.0 billion
of additional capital investments at the Corporation's regulated utilities, largely reflecting customer growth, enhancements to transmission
reliability and capacity, and investments in cleaner energy. This growth is tempered by $600 million associated with the lower assumed
foreign exchange rate of 1.25, down from a rate of 1.32 assumed in the Corporation's previous five-year plan.
The Capital Plan is low risk and highly executable, with 99% of planned expenditures to occur at the regulated utilities and only 15% related
to Major Capital Projects. The composition of the 2022-2026 Capital Plan includes 27% related to growth, 56% sustaining and 17% for other
areas. Geographically, 53% of planned expenditures are expected in the U.S., including 25% at ITC, with 43% in Canada and the remaining 4%
in the Caribbean.
32 FORTIS INC.
2021 Annual Report
Management Discussion and Analysis
The investments included in the 2022-2026 Capital Plan are summarized as follows:
Planned capital expenditures are based on detailed forecasts of energy demand, labour and material costs, general economic conditions,
foreign exchange rates and other factors. These could change and cause actual expenditures to differ from forecast or plan. While the
Corporation does not expect the COVID-19 Pandemic to impact its overall five-year Capital Plan, the timing of forecast capital expenditures
will continue to be evaluated. Depending on the length and severity of the pandemic, including any impact of supply chain disruptions,
certain planned expenditures may shift within the 2022-2026 Capital Plan.
Midyear Rate Base (1)
($ billions)
ITC
UNS Energy
Central Hudson
FortisBC Energy
FortisAlberta
FortisBC Electric
Other Electric
Total
2021
9.5
5.8
2.2
5.2
3.8
1.5
3.1
31.1
2022
10.1
6.5
2.4
5.4
4.0
1.5
3.6
33.5
2026
12.6
8.0
3.1
7.1
4.7
1.8
4.3
41.6
(1) Simple average of Rate Base at beginning and end of the year
Total midyear Rate Base is forecast to grow to $41.6 billion by 2026 under the five-year Capital Plan, representing a CAGR of approximately 6%,
which is supportive of continuing growth in earnings and dividends.
33 FORTIS INC.
2021 Annual Report
FIVE-YEAR CAPITAL PLAN33%30%7%6%6%4%5%9%DistributionTransmissionTransmission supporting cleaner energyRNG/LNGCleaner GenerationTraditional GenerationInformation TechnologyOther
Management Discussion and Analysis
Major Capital Projects (1)
($ millions)
ITC (2)
Multi-Value Regional Transmission Projects
34.5 to 69kV Transmission Conversion Project
UNS Energy
Vail-to-Tortolita Project
Oso Grande Generating Facility
FortisBC Energy
Lower Mainland Intermediate Pressure System Upgrade
Eagle Mountain Woodfibre Gas Line Project (3)
Transmission Integrity Management Capabilities Project
Inland Gas Upgrade Project
Okanagan Capacity Upgrade
Tilbury 1B Project
Tilbury LNG Storage Expansion
AMI Project
Other Electric
Wataynikaneyap Transmission Power Project (4)
Total
Pre-
2021
Actual
2021
Forecast
2022
2023-
2026
Expected
Completion
642
445
—
554
411
—
21
59
9
20
10
—
178
68
37
21
39
16
—
9
69
7
9
6
—
81
68
58
—
—
—
10
79
16
33
8
5
73
77
182
—
—
350
212
65
185
322
449
375
177
458
248
606
109
2,399
2023
Post-2026
2025
2021
2021
2026
Post-2026
2025
2024
Post-2026
Post-2026
Post-2026
2024
Includes applicable AFUDC
(1)
(2) Pre-2021 capital expenditures are from the date of the ITC acquisition on October 14, 2016
(3) Net of forecast customer contributions
(4) Fortis' share of estimated capital spending. Under the funding framework, Fortis will be funding its equity component only.
Multi-Value Regional Transmission Projects
Four regional electric transmission projects that have been identified by MISO to address system capacity needs and reliability in various
states. Three projects were completed pre-2021. The fourth project is expected to be placed in service in 2023.
34.5 to 69kV Transmission Conversion Project
Multiple projects designed to convert the 34.5kV system to 69kV operating voltage. Projects include construction of new 69kV lines, rebuild of
existing 34.5kV lines to 69kV, and substation conversions. In service dates range from pre-2021 to post-2026.
Vail-to-Tortolita Project
Construction and upgrades to connect existing TEP substations to a new 230kV line within TEP’s service territory. Construction is expected to
begin in 2023 with an in service date of 2025.
Oso Grande Generating Facility
In May 2021, construction of UNS Energy's 250 MW wind-powered electric generating facility was completed.
Lower Mainland Intermediate Pressure System Upgrade
Addresses system capacity and pipeline condition issues for the gas supply system in the Lower Mainland of British Columbia. The project has
been completed, with the final pipeline segment replaced in 2021. Final allowable project costs are subject to review by the BCUC.
Eagle Mountain Woodfibre Gas Line Project
Gas line expansion to a proposed LNG site in Squamish, British Columbia. FortisBC Energy's proposed pipeline expansion remains contingent
on Woodfibre LNG Limited making a final decision to proceed with construction of the LNG facility.
Transmission Integrity Management Capabilities Project
This project improves gas line safety and transmission system integrity, including gas line modifications and looping. In February 2021,
FortisBC Energy filed a CPCN application with the BCUC for the coastal transmission system section of this project.
Inland Gas Upgrades Project
Gas line modifications and replacements to enable in-line integrity inspection capabilities. In January 2020, the CPCN application was
approved by the BCUC.
34 FORTIS INC.
2021 Annual Report
Management Discussion and Analysis
Okanagan Capacity Upgrade
Construction of a new section of pipeline and associated facilities to address expected load growth in the Okanagan region. In November
2020, FortisBC Energy filed a CPCN application with the BCUC for this project.
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. The project received an Order in Council from the Government of British Columbia in 2017. In February
2020, an initial project scope was filed with regulators to begin the federal impact assessment and provincial environmental assessment
required to further expand the Tilbury site. Engineering design and related studies will continue in 2022.
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. In December 2020, FortisBC Energy filed a CPCN application for this project with the BCUC, and if
approved, the project is expected to begin in 2022.
AMI Project
Replacement of residential and small commercial meters with advanced meters and installation of bypass valves to support the safety,
resiliency, and efficient operation of the gas distribution system. In May 2021, FortisBC Energy filed a CPCN application with the BCUC for this
project.
Wataynikaneyap Transmission Power Project
Construction of a 1,800 kilometre, OEB-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. The project is expected 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.
ITC - Lake Erie Connector
Proposed 1,000 MW, bi-directional, high-voltage direct current underwater transmission line to directly link the markets of the Ontario IESO
and PJM Interconnection, LLC. The project would enable transmission customers to more efficiently access energy, capacity and renewable
energy credit opportunities in both markets. The project is fully permitted in the U.S. and Canada and continues to advance through
regulatory, operational and economic milestones. In 2021, the Canada Infrastructure Bank announced it would fund 40% of the approximate
$1.7 billion project and the Ontario government authorized IESO to commence contract negotiations. Negotiation of transmission service
agreements is required to advance to the construction phase. Completion would take approximately four years from the commencement of
construction.
ITC - MISO LRTP
A comprehensive effort by MISO is underway to identify and construct the regional transmission required in the MISO region to support the
ongoing evolution of the electric industry. ITC has a large footprint in the MISO region, specifically including but not limited to wind-rich
regions in Iowa and Minnesota. MISO is currently requesting FERC authorization for cost allocation and finalizing planning for an initial
tranche of LRTP projects.
UNS Energy - TEP 2020 IRP
Outlines the resource energy transition required at TEP to meet its customers' energy needs through 2035 as it exits coal-fired resources by
2032 and replaces it with wind and solar resources as part of a cleaner energy portfolio that will reduce carbon emissions 80 percent by 2035.
This plan supports reliable and affordable service from sustainable resources and is expected to provide capital investment opportunities that
extends beyond the Capital Plan. The IRP may be impacted by various federal and state energy policies, including policies currently under
consideration.
FortisBC Energy - LNG
Pursuit of additional LNG infrastructure opportunities in British Columbia, including 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 relatively close to international shipping lanes. FortisBC Energy continues to have discussions with
potential export customers.
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 investments across our jurisdictions.
35 FORTIS INC.
2021 Annual Report
Management Discussion and Analysis
BUSINESS RISKS
Fortis has established an ERM program to identify and evaluate risks by both severity of impact and probability of occurrence. Materiality
thresholds are reviewed and, if necessary, updated annually. Financial risks, as well as risks that may impact the safety of employees,
customers or the general public, as well as reputational risks, are evaluated. Systems of internal controls are used to monitor and manage
identified risks. The ERM program at the subsidiary level is overseen by each subsidiary's board of directors and any material risks identified are
communicated to Fortis management and form part of Fortis' ERM program. The Fortis Board, through the audit committee, oversees Fortis’
ERM program ensuring that management has an effective risk management system to support strategic planning.
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, 2021. Regulatory jurisdictions
include five Canadian provinces, nine 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 and the underlying 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 in setting rates.
The ability to recover the actual cost of service and earn the approved ROE or ROA typically depends on achieving the forecasts established in
the rate-setting process. Failure to do so could have a Material Adverse Effect. For those utilities subject to PBR mechanisms, rates reflect
assumed inflation rates and productivity improvement factors, and variances therefrom could have a Material Adverse Effect. FortisAlberta's
PBR mechanism gives rise to added risk that incremental incurred capital expenditures may not be approved for recovery in rates.
For transmission operations, the underlying elements of FERC-established formula rates can be, and have been, challenged by third parties
which could result in, and has resulted in, lowered rates and customer refunds. These underlying elements include the ROE, ROE adders for
independent transmission ownership and deemed capital structure, as well as operating and capital expenditures.
Additionally, 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.
The political and economic environments as well as their effect on energy laws and governmental energy policies have had, and may
continue to have, negative impacts on regulatory decisions. While Fortis is well positioned to maintain constructive regulatory relationships
through local management teams and boards comprised mostly of independent local members, it cannot predict future legislative or
regulatory changes, whether caused by economic, political or other factors, or its ability to respond thereto in an effective and timely manner,
or the resulting compliance costs. Any of the foregoing potential regulatory changes could have a Material Adverse Effect.
Climate Change and Physical Risks
The provision of electric and gas service is subject to risks, including severe weather and natural disasters, wars, terrorism, critical equipment
failure and other catastrophic events within and outside the Corporation's service territories. Resultant service disruption and repair and
replacement costs 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.
Climate change is predicted to lead to more frequent and intense weather events, changing air temperatures and changing seasonal
variations, and the Corporation expects that regulatory responses to such changes will occur in the coming years (see "Environmental
Regulation" on page 37). Severe weather impacts the Corporation's service territories, primarily in the form of thunderstorms, flooding,
wildfires, hurricanes and snow or ice storms. Increased frequency of extreme weather events could increase the cost of providing service
through increased repairs and use of contingency plans. Changes in precipitation that 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. Extreme weather
conditions in general require system backup and can contribute to increased system stress, including service interruptions. Changing air
temperatures could also result in system stress and decreased efficiency of operating facilities over time. Longer-term climate change
impacts, such as sustained higher temperatures, higher sea levels and larger storm surges, could result in service disruption, repair and
replacement costs, and costs associated with strengthened design standards and systems.
36 FORTIS INC.
2021 Annual Report
Management Discussion and Analysis
The electricity and gas systems are designed to service customers under various contingencies in accordance with good utility practice. 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. The
impacts of climate change and the transition to a cleaner energy future will require the Corporation's utilities to effectively manage evolving
regulatory and legislative requirements, new resiliency standards, the integration of new technologies and impacts on customer demand and
rates. Failure to do so may disrupt the ability of the utilities to provide safe and cost-effective service, which could cause reputational harm
and other impacts. Any of the foregoing potential impacts of climate change could have a Material Adverse Effect.
The operation of transmission and distribution assets has the potential to cause fires, mainly as a result of equipment failure, falling trees and
lightning strikes to lines or equipment. Also, certain utilities operate in remote and mountainous terrain that can be difficult to access for
timely repairs and maintenance, or otherwise face risk of loss or damage from forest fires, floods, washouts, landslides, earthquakes,
avalanches and other acts of nature.
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, and other accidents and issues that can lead to service disruption, spills and commensurate environmental liability, or other liability.
Generating equipment and facilities are subject to risks, including equipment breakdown and flood and fire damage, that may result in the
uncontrolled release of water, interruption of fuel supply, lower-than-expected operational efficiency or performance, and service disruption.
There is no assurance that generating equipment and facilities will continue to operate in accordance with expectations and climate changes
may increase the frequency of such failures occurring.
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 held responsible for a fire.
Electricity and gas systems require ongoing maintenance, improvement and replacement. Service disruption, other effects and liability
caused by the failure to properly implement or complete approved maintenance and capital expenditures, the occurrence of significant
unforeseen equipment failures, or the inability to recover requisite costs in customer rates, could result in loss. Any of the foregoing potential
impacts of physical risk could have a Material Adverse Effect.
Environmental Regulation
The Corporation's businesses are subject to environmental risks and environmental laws and regulations, including those which: (i) impose
limitations or restrictions on the discharge of pollutants into the air, soil and water; (ii) establish standards for the management, treatment,
storage, transportation and disposal of hazardous wastes; and/or (iii) impose obligations to investigate and remediate contamination.
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.
Liabilities relating to contamination investigation and remediation, and 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 or whether it resulted from non-compliance with applicable
environmental laws. Under some environmental laws, such liabilities may be joint and several, meaning that a party can be held responsible
for more than its share of the liability involved or even the entire liability. These liabilities could lead to litigation and administrative
proceedings that could result in substantial monetary judgments for clean-up costs, damages, fines and/or penalties. To the extent not fully
covered by insurance, these costs could have a Material Adverse Effect.
The Corporation's businesses have incurred substantial expenses for environmental compliance, and they anticipate continuing to do so in
the future. In particular, the management of GHG emissions is a major concern due to new and emerging federal, state and provincial GHG
laws, regulations and guidelines. Future legislation relating to GHG emissions could impact generation assets, operations, energy supply,
operational costs, reporting obligations and other material aspects of the Corporation's business.
The Corporation's businesses continue to develop compliance strategies and assess the impact of emerging legislative changes, but
significant uncertainties remain. Increased compliance costs or additional operating restrictions from revised or additional regulation could
have a Material Adverse Effect.
37
FORTIS INC.
2021 Annual Report
Management Discussion and Analysis
Pandemics and Public Health Crises, including the COVID-19 Pandemic
The Corporation could be negatively impacted by a widespread outbreak of communicable diseases or other public health crises that cause
economic and/or other disruptions, including the disruption of global supply chains. The outbreak of communicable diseases, as well as
efforts to reduce the health impacts and control disease spread can lead to worldwide 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 42).
There continues to be uncertainty surrounding the duration and severity of the COVID-19 Pandemic, particularly with respect to the
emergence of new variants of the virus, the long-term efficacy and global distribution of COVID-19 vaccines, the impact of vaccine mandates
and isolation requirements on labour availability, potential government action to mitigate public health effects, disruptions to the global
supply chain, and other factors beyond the Corporation's control. An extended period of economic or supply chain disruption could have a
Material Adverse Effect.
Growth
Fortis has a history of growth through acquisitions and organic growth from capital investment in existing service territories. Acquisitions
include inherent risks that some or all of the expected benefits may fail to materialize, or may not occur within the time periods anticipated,
and material unexpected costs may arise.
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 described under "Capital Plan" on page 31. Projects, particularly Major Capital Projects, are subject to risks of delay
and cost overruns during construction caused by inflation, commodity price fluctuations, supply and labour costs, 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. These risks could impact the successful execution of a project by preventing the project from proceeding,
delaying its completion, increasing its projected costs or negatively impacting its financing.
Cybersecurity
As operators of critical energy infrastructure, the Corporation's utilities face the risk of cybercrime, which has increased in frequency, scope
and potential impact in recent years. 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 electric generation, transmission and distribution facilities,
including gas facilities; (ii) provide customers with billing, consumption and load settlement information, where applicable; and (iii) support
financial and general operations.
Information and operations technology systems may be vulnerable to unauthorized access due to hacking, computer viruses, acts of war or
terrorism, acts of vandalism and other causes. This can result in the disruption of energy service and other business operations, system failures
and grid disturbances, property damage, corruption or unavailability of critical data, and the misappropriation and/or disclosure of sensitive,
confidential and proprietary business, customer and employee information.
A material cybersecurity breach 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 damage. 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.
Technology Advances
The emergence of initiatives designed to reduce GHG emissions and control or limit the effects of climate change has increased the incentive
for the development of new technologies that produce power, enable more efficient storage of energy and reduce power consumption.
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.
38 FORTIS INC.
2021 Annual Report
Management Discussion and Analysis
Weather Variability and Seasonality
Electricity consumption varies significantly in response to climate change and seasonal weather changes (see "Climate Change and Physical
Risks" on page 36). In central and western Canada, Arizona and New York State, 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.
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.
Hydroelectric generation is sensitive to rainfall levels.
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. Both the discontinuance of key regulatory mechanisms and
their absence at other Fortis entities could result in significant and prolonged weather variations from seasonal norms having a Material
Adverse Effect.
Natural Gas Competitiveness
Approximately 22% of the Corporation's revenue is derived from the delivery of natural gas. A decrease in the competitiveness of natural gas
due to pricing, government policy or other factors could have a Material Adverse Effect.
In British Columbia, which accounts for 83% of the Corporation's natural gas revenue, natural gas primarily competes with electricity for space
and hot water heating. Upfront capital costs for gas service continue to present competitive challenges for natural gas compared to electricity
service. If gas becomes less competitive, 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, whereby system costs must be recovered from a smaller customer and
sales base, leading to reductions in competitiveness.
Government policy could also impact the competitiveness of natural gas in British Columbia. In October 2021, the provincial government
released an update to its economic and climate action plan, including a series of actions designed to achieve GHG emission reduction targets
and the transition to a low-carbon economy. As all levels of government become more active in the development of policies to address
climate change, any resultant changes to energy policy may impact the competitiveness of natural gas relative to non-carbon based energy
sources.
There are other competitive challenges that are impacting the penetration of natural gas into new housing stock such as green attributes of
the energy source and the type of housing stock being built. In addition, 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.
Commodity Price Volatility
Purchased power 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 (see "Business Unit Performance" on page 20); and (ii) price-risk management strategies such as the use of derivative
contracts that effectively fix costs (see "Financial Instruments - Derivatives" on page 45).
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. These 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 generated 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, which could have a Material Adverse Effect.
39 FORTIS INC.
2021 Annual Report
Management Discussion and Analysis
Required Approvals
The acquisition, ownership and operation of electric and gas businesses require numerous licences, permits, agreements, orders, certificates
and other approvals from various levels of government, regulators, government agencies, Indigenous Peoples and/or third parties. The
external environment has become more complex with heightened expectations from permitting agencies, local municipalities and
Indigenous Peoples to be able to review and provide feedback on projects, largely driven by policy responses to climate change. There is no
assurance that: (i) all of these 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 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, Alberta and Ontario. 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, such as 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 TransAlta Utilities Corporation. To
acquire these permits, FortisAlberta requires approval 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.
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.
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.
UNS Energy, Central Hudson, FortisBC Energy, Aitken Creek and Fortis may be exposed to credit risk from non‑performance by counterparties
to derivatives. Credit risk is managed by net settling payments, when possible, and dealing only with counterparties that have investment-
grade credit ratings. At UNS Energy and Central Hudson, certain contractual arrangements require counterparties to post collateral.
There is no assurance that management strategies will continue to be effective. Significant counterparty defaults could have a Material
Adverse Effect.
40 FORTIS INC.
2021 Annual Report
Management Discussion and Analysis
Interest Rates
Generally, the market price of the Corporation's common shares is inversely sensitive to interest rate changes. Additionally, allowed ROEs are
exposed to changes in long-term interest rates such that a low interest rate environment could reduce allowed ROEs. If interest rates rise,
regulatory lag may cause delays in any compensatory ROE increases. Borrowings under variable-rate credit facilities and long-term debt, as
well as new debt issuances, are also exposed to interest rate changes.
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 future 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.
Foreign Exchange Exposure
The reporting currency of ITC, UNS Energy, Central Hudson, Caribbean Utilities, FortisTCI, BECOL 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.
Fortis has limited this U.S. dollar currency exposure through hedging. As at December 31, 2021, US$2.2 billion (2020 - US$2.3 billion) of
corporately issued U.S. dollar-denominated long-term debt had been designated as an effective hedge of foreign net investments, leaving
US$10.8 billion (2020 - US$10.2 billion) in foreign net investments unhedged. Fortis has also entered into foreign exchange contracts to
manage a portion of its exposure to foreign currency risk.
Given only partial hedging, consolidated earnings and cash flow continue to be impacted by exchange rate fluctuations. On average, Fortis
estimates that a five-cent increase or decrease in the U.S. dollar relative to the Canadian dollar exchange rate of US$1.00=CA$1.25 as at
December 31, 2021 would increase or decrease average annual EPS by approximately six cents, which reflects the Corporation's hedging
program.
The Corporation's $20.0 billion five-year Capital Plan for 2022 through 2026 also includes exposure to foreign exchange. 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 $450 million over the five-year planning period.
There is no assurance that existing hedging strategies will continue to be effective and any resultant financial impacts could have a Material
Adverse Effect.
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.
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 27.
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.
41
FORTIS INC.
2021 Annual Report
Management Discussion and Analysis
Talent Management
The delivery of safe, reliable and cost-effective service depends on the attraction, development and retention of skilled workforces. 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 could have a
Material Adverse Effect.
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 the regulator disallows full recovery in 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.
Market disruptions, significant declines in the market values of investments held to meet plan obligations, discount rate changes, participant
demographics, and changes in laws and regulations may require additional plan funding. Significant increases in plan expenses and funding
requirements 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 reduce sales both directly and through reduced capital spending,
particularly that related to new customer growth, which would affect Rate Base growth. A severe and prolonged economic downturn could
have a Material Adverse Effect, including making it more difficult for customers to pay their bills.
Reputation, Relationships and Stakeholder Activism
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.
Additionally, external stakeholders, including shareholders and investors, are increasingly challenging utilities regarding climate change,
sustainability, diversity, returns including ROEs, 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 maintain or respond
to stakeholder activism could have a Material Adverse Effect.
Legal, Administrative and Other Proceedings
These 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
Critical Accounting Estimates
General
The preparation of the 2021 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.
42 FORTIS INC.
2021 Annual Report
Management Discussion and Analysis
Regulatory Assets and Liabilities
As at December 31, 2021, Fortis recognized regulatory assets of $3.6 billion (2020 - $3.6 billion) and regulatory liabilities of $3.2 billion (2020 -
$3.1 billion).
Regulatory assets represent future revenues and/or receivables associated with certain costs incurred that will be, or are expected to be,
recovered from customers in future periods through the rate-setting process. Regulatory liabilities represent: (i) future reductions or
limitations of increases in revenue associated with amounts that will be, or are expected to be, refunded to customers through the rate-
setting process; or (ii) obligations to provide future service that customers have paid for in advance.
The recognition of regulatory assets and liabilities and the period(s) of settlement are often estimates based on past, existing or expected
regulatory orders in relation to the nature of the underlying amounts, and are subject to regulatory approval. There is no assurance that actual
settlement amounts and the related settlement periods will not be materially different from those estimated. Differences arising from the
regulator's orders would be recognized in accordance with those orders, whereby any amounts disallowed would be immediately
recognized in earnings with the remainder recognized in earnings in accordance with their inclusion in customer rates.
Employee Future Benefits
Key Estimates and Assumptions
Years ended December 31
($ millions, except as indicated)
Funded status: (1)
Benefit obligation (2)
Plan assets
Net benefit cost (2)
Key assumptions: (weighted average %)
Discount rate: (3)
During the year
As at December 31
Expected long-term rate of return on plan assets (4)
Rate of compensation increase
Health care cost trend increase rate (5)
Defined Benefit
Pension Plans
OPEB Plans
2021
(3,922)
3,722
(200)
64
2.60
3.00
5.40
3.30
—
2020
(3,995)
3,528
(467)
67
3.16
2.63
5.52
3.34
—
2021
(747)
440
(307)
35
2.60
2.97
4.88
—
4.49
2020
(789)
391
(398)
32
3.22
2.64
5.28
—
4.61
(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
(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 2022 rate is 5.75% and is assumed to decrease over the next 11 years to the ultimate rate of 4.49% in 2032 and thereafter.
Sensitivity Analysis
Year ended December 31, 2021
($ millions)
Defined benefit pension plans:
Net benefit cost
Projected benefit obligation
OPEB plans:
Net benefit cost
Accumulated benefit obligation
Rate of Return
1% change
Discount Rate
1% change
Health Care Costs
Trend Rate
1% change
Increase
Decrease
Increase
Decrease
Increase
Decrease
(33)
32
(4)
—
28
(75)
4
—
(48)
(520)
(10)
(112)
65
649
12
135
n/a
n/a
16
100
n/a
n/a
(14)
(91)
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.
At FortisAlberta, cash contributions are expensed and reflected in customer rates with any difference between the cash contributions and the
net benefit cost deferred as a regulatory asset/liability. 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.
43 FORTIS INC.
2021 Annual Report
Management Discussion and Analysis
Depreciation and Amortization
As at December 31, 2021, Fortis recognized property, plant and equipment and intangible assets of $39.2 billion (2020 - $37.3 billion)
representing 68% of total assets (2020 - 67%). Depreciation and amortization of these assets totalled $1.4 billion for 2021 (2020 - $1.4 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, 2021, this regulatory liability
was $1.2 billion (2020 - $1.2 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, 2021, Fortis recognized goodwill of $11.7 billion (2020 - $11.8 billion), representing 20% of total assets (2020 - 21%). The
decrease in goodwill was due to the impact of foreign exchange associated with the translation of U.S. dollar-denominated goodwill.
Goodwill at each of the Corporation's 11 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 necessary, 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, 2021, deferred income tax liabilities, current income tax payable included in accounts payable, deferred income taxes
included in regulatory assets, and deferred income taxes included in regulatory liabilities totalled $3.6 billion, $31 million, $1.8 billion and
$1.3 billion, respectively (2020 - $3.3 billion, current income tax receivable of $72 million, $1.7 billion and $1.4 billion, respectively). Income tax
expense was $234 million in 2021 (2020 - $231 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".
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 2013 to 2021
taxation years are still open for audit in Canadian jurisdictions, and its 2011 to 2021 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's financial statements (see "Business Risks -
Taxation" on page 41).
44 FORTIS INC.
2021 Annual Report
Management Discussion and Analysis
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 - Indigenous Peoples' Land Claims" on page 40, for which no amounts have been accrued
because the outcomes currently cannot be reasonably determined. Further information is provided in Note 26 in the 2021 Annual Financial
Statements.
While Fortis currently believes that these matters are unlikely to have a Material Adverse Effect, there is no assurance that this will be the case.
FINANCIAL INSTRUMENTS
Long-Term Debt and Other
As at December 31, 2021, the carrying value of long-term debt, including the current portion, was $25.5 billion (2020 - $24.5 billion) compared
to an estimated fair value of $28.8 billion (2020 - $29.1 billion). Since Fortis does not intend to settle long-term debt prior to maturity, the
excess of fair value over carrying value does not represent an actual liability.
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.
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, 2021, unrealized losses of
$20 million (2020 - $73 million) were recognized as regulatory assets and unrealized gains of $52 million (2020 - $17 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 holds gas swap contracts to manage its exposure to changes in natural gas prices, capture natural gas price spreads, and
manage the financial risk posed by physical transactions. Fair values are 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 2021, unrealized
gains of $21 million (2020 - $3 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 $112 million and terms of one to three years expiring at varying
dates through January 2024. 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 2021, unrealized gains of $17 million (2020 - unrealized
losses of $9 million) were recognized in other income, net.
45 FORTIS INC.
2021 Annual Report
Management Discussion and Analysis
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 November 2022 and have a combined notional amount of $161 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 2021, unrealized losses of $11 million (2020 - unrealized gains of $11 million) were recognized in other income, net.
Interest rate swaps
In 2021, ITC entered into interest rate swaps with a total notional value of US$375 million to manage the interest rate risk associated with the
refinancing of long-term debt due in November 2022. The swaps have five-year terms, include mandatory early termination provisions, and
will be terminated no later than the effective date of November 15, 2022. Fair value was measured using a discounted cash flow method
based on LIBOR rates. Unrealized gains and losses associated with the changes in fair value are recognized in other comprehensive income,
will be reclassified to earnings as a component of interest expense over the life of the debt, and were not material for 2021.
Other investments
ITC and Central Hudson hold investments in trust associated with supplemental retirement benefit plans for select employees. These
investments include mutual funds and money market accounts, which are recorded at fair value based on quoted market prices in active
markets. Gains and losses are recognized in other income, net. In 2021, unrealized gains of $9 million (2020 - $7 million) were recognized in
other income, net.
Derivative Fair Values
The following table presents derivative assets and liabilities that are accounted for at fair value on a recurring basis.
($ millions)
As at December 31, 2021
Assets (2)
Energy contracts subject to regulatory deferral
Energy contracts not subject to regulatory deferral
Foreign exchange contracts, total return and interest rate swaps
Other investments
Liabilities (3)
Energy contracts subject to regulatory deferral
Energy contracts not subject to regulatory deferral
As at December 31, 2020
Assets (2)
Energy contracts subject to regulatory deferral
Energy contracts not subject to regulatory deferral
Foreign exchange contracts and total return swaps
Other investments
Liabilities (3)
Energy contracts subject to regulatory deferral
Energy contracts not subject to regulatory deferral
Level 1 (1)
Level 2 (1)
Level 3 (1)
Total
—
—
23
137
160
—
—
—
—
—
16
126
142
—
—
—
78
16
2
—
96
(46)
(3)
(49)
38
6
—
—
44
(94)
(12)
(106)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
78
16
25
137
256
(46)
(3)
(49)
38
6
16
126
186
(94)
(12)
(106)
(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) Current portion is included in accounts receivable and other current assets, with the remainder included in other assets
(3) Current portion is included in accounts payable and other current liabilities, with the remainder included in other liabilities
46 FORTIS INC.
2021 Annual Report
Management Discussion and Analysis
Derivative Volumes
As at December 31
Energy contracts subject to regulatory deferral (1)
Electricity swap contracts (GWh)
Electricity power purchase contracts (GWh)
Gas swap contracts (PJ)
Gas supply contract premiums (PJ)
Energy contracts not subject to regulatory deferral (1)
Wholesale trading contracts (GWh)
Gas swap contracts (PJ)
(1) Energy contracts settle on various dates through 2029
SELECTED ANNUAL FINANCIAL INFORMATION
Years ended December 31
($ millions, except as indicated)
Revenue
Net earnings
Common Equity Earnings
EPS: ($)
Basic
Diluted
Total assets
Long-term debt (excluding current portion)
Dividends declared: ($)
Per common share
Per first preference share:
Series F
Series G
Series H (1)
Series I (2)
Series J
Series K
Series M (3)
2021
509
731
151
144
1,886
29
2020
8,935
1,389
1,209
2.60
2.60
55,481
23,113
1.965
1.2250
1.0983
0.5003
0.4987
1.1875
0.9823
0.9783
2021
9,448
1,405
1,231
2.61
2.61
57,659
23,707
2.080
1.2250
1.0983
0.4588
0.3926
1.1875
0.9823
0.9783
2020
522
2,781
156
203
1,588
36
2019
8,783
1,852
1,655
3.79
3.78
53,404
21,501
1.855
1.2250
1.0983
0.6250
0.7771
1.1875
0.9823
1.0133
(1)
(2)
(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.
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.
The annual dividend per share was reset to $0.9783 for the five-year period from December 1, 2019 up to but excluding December 1, 2024.
2021/2020
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 14, "Operating Results" on page 19, and "Financial Position" on page 26.
2020/2019
The increase in revenue reflected: (i) overall higher flow-through costs in customer rates; (ii) Rate Base growth; (iii) higher electricity sales
driven by favourable weather in Arizona; and (iv) a $40 million favourable base ROE adjustment at ITC related to prior periods as a result of the
May 2020 FERC Decision. The increase was partially offset by: (i) a $91 million favourable base ROE adjustment at ITC in 2019 related to prior
periods as a result of the November 2019 FERC decision; and (ii) lower short-term wholesale sales at UNS Energy.
The decrease in Common Equity Earnings reflected significant one-time items: (i) a $484 million gain on the disposition of the Waneta
Expansion in April 2019; and (ii) the $56 million net impact associated with the reversal of prior period liabilities as a result of the November
2019 and May 2020 FERC Decisions at ITC.
47
FORTIS INC.
2021 Annual Report
Management Discussion and Analysis
Excluding the significant one-time items, the Corporation delivered higher earnings of $94 million in 2020 reflecting: (i) Rate Base growth of
8.2%; (ii) increased retail electricity sales at UNS Energy, driven largely by weather, and (iii) higher earnings from Belize, mainly from increased
hydroelectric production. Earnings were also favourably impacted by mark-to-market accounting of natural gas derivatives at Aitken Creek.
This growth was tempered by: (i) the delay in TEP's general rate application, resulting in approximately $1 billion of Rate Base not reflected in
customer rates in 2020; and (ii) the impact of the COVID-19 Pandemic, reflecting lower sales in the Caribbean and higher net operational
expenses, including increased credit loss expense, largely at Central Hudson and UNS Energy.
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 $1.2 billion common equity issuance in the fourth quarter of 2019.
The increase in total assets was due to 2020 capital expenditures, partially offset by unfavourable foreign exchange on the translation of
U.S. dollar-denominated assets.
FOURTH QUARTER RESULTS
Sales
(Gwh, except as indicated)
Regulated Utilities
UNS Energy
Retail Electricity
Wholesale Electricity
Gas (PJ)
Central Hudson
Electricity
Gas (PJ)
FortisBC Energy (PJ)
FortisAlberta
FortisBC Electric
Other Electric
Non-Regulated
Energy Infrastructure
2021
2,206
1,749
5
1,203
6
74
4,147
927
2,449
13
2020
2,345
1,871
5
1,200
7
67
4,138
894
2,362
103
Variance
(139)
(122)
—
3
(1)
7
9
33
87
(90)
The decrease in electricity sales was driven by: (i) UNS Energy, due to lower retail electricity sales resulting from milder weather and lower
wholesale sales; and (ii) BECOL, due to lower hydroelectric production in Belize caused by variations in rainfall levels. The decrease was
partially offset by higher electricity sales in the Caribbean reflecting the continued recovery from the impacts of the COVID-19 Pandemic in
2020.
The increase in gas volumes was due to higher consumption by residential and commercial customers at FortisBC Energy due to colder
temperatures.
Revenue and Common Equity Earnings
Revenue
2021
2020
Variance
2021
Earnings
2020
Variance
($ millions, except as indicated)
Regulated Utilities
ITC
UNS Energy
Central Hudson
FortisBC Energy
FortisAlberta
FortisBC Electric
Other Electric
Non-regulated
Energy Infrastructure
Corporate and Other
Total
Weighted average number of common shares outstanding (# millions)
Basic EPS ($)
48 FORTIS INC.
2021 Annual Report
418
540
283
592
156
133
401
60
—
2,583
419
525
242
476
139
117
381
47
—
2,346
(1)
15
41
116
17
16
20
13
—
237
103
109
33
39
78
23
14
29
40
(31)
328
473.7
0.69
45
35
74
33
13
32
27
(37)
331
465.8
0.71
(6)
(12)
4
4
(10)
1
(3)
13
6
(3)
7.9
(0.02)
Management Discussion and Analysis
The increase in revenue was driven by: (i) overall higher flow-through costs, mainly at FortisBC Energy and Central Hudson; (ii) Rate Base
growth; (iii) higher electricity sales in the Caribbean reflecting the impact of the COVID-19 Pandemic in 2020; and, (iv) unrealized gains on the
mark-to-market of natural gas derivatives at Aitken Creek. New customer rates and higher transmission revenue at TEP also contributed to the
increase. These factors were partially offset by the unfavourable impact of foreign exchange.
The decrease in Common Equity Earnings was driven by: (i) lower earnings in Arizona, due to the reduction in sales as noted above, and lower
gains on certain investments that support retirement benefits, partially offset by higher transmission revenue; (ii) the timing of earnings at
FortisAlberta, due the reversal of income tax expense in the fourth quarter of 2020; (iii) the operation of regulatory mechanisms at Central
Hudson; and, (iv) higher non-recoverable costs at ITC. Lower earnings in Belize and the impact of foreign exchange also unfavourably
impacted earnings for the quarter. The decrease in earnings was partially offset by growth in Rate Base, the finalization of Central Hudson's
rate application with retroactive application to July 1, 2021, and the favourable impact of mark-to-market accounting at Aitken Creek.
The decrease in basic EPS reflects lower Common Equity Earnings and an increase in the weighted average number of common shares
outstanding, largely associated with the Corporation's DRIP.
Cash Flows
($ millions)
Cash and cash equivalents, beginning of period
Cash from (used in):
Operating activities
Investing activities
Financing activities
Effect of exchange rate changes on cash and cash equivalents
Cash and cash equivalents, end of period
2021
225
717
(985)
174
—
131
2020
494
700
(1,235)
308
(18)
249
Variance
(269)
17
250
(134)
18
(118)
Operating Activities
Operating Cash Flow increased during the quarter due to: (i) Rate Base growth; (ii) new customer rates at TEP effective January 1, 2021; and,
(iii) favourable changes in regulatory deferrals due to the timing of flow-through costs in customer rates. These increases were largely offset
by an upfront payment received by FortisAlberta in the fourth quarter of 2020 associated with a long-term energy retailer agreement, and the
lower foreign exchange rate in 2021.
Investing Activities
The variance reflects lower capital expenditures in accordance with the Corporation's 2021 Capital Plan.
Financing Activities
See "Cash Flow Summary" on page 28.
SUMMARY OF QUARTERLY RESULTS
Quarter ended
December 31, 2021
September 30, 2021
June 30, 2021
March 31, 2021
December 31, 2020
September 30, 2020
June 30, 2020
March 31, 2020
Revenue
($ millions)
2,583
2,196
2,130
2,539
2,346
2,121
2,077
2,391
Common
Equity
Earnings
($ millions)
328
295
253
355
331
292
274
312
Basic EPS
Diluted EPS
($)
0.69
0.63
0.54
0.76
0.71
0.63
0.59
0.67
($)
0.69
0.62
0.54
0.76
0.71
0.63
0.59
0.67
Generally, within each calendar year, quarterly results fluctuate primarily 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.
49 FORTIS INC.
2021 Annual Report
Management Discussion and Analysis
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 timing and significance of any regulatory decisions; (iv) changes in
the U.S.-to-Canadian dollar exchange rate; (v) any acquisitions and dispositions; (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.
December 2021/December 2020
See "Fourth Quarter Results" on page 48.
September 2021/September 2020
Common Equity Earnings and basic EPS were relatively consistent with the same period in 2020. Growth in Common Equity Earnings was
tempered by a lower U.S.-to-Canadian dollar exchange rate, unfavourably impacting earnings by $13 million.
Excluding the impact of foreign exchange, Common Equity Earnings increased by $16 million due to: (i) Rate Base growth; (ii) higher sales,
largely associated with favourable weather, and the timing of expenditures at FortisAlberta; (iii) continued recovery in the Caribbean from
economic conditions experienced in 2020 associated with the COVID-19 Pandemic; and (iv) an adjustment related to the amortization of
interest rate swaps at ITC. New customer rates effective January 1, 2021 at TEP also contributed to results. The increase in earnings was
partially offset by: (i) lower sales in Arizona due to cooler weather; (ii) realized losses on natural gas contracts at Aitken Creek; and (iii) the delay
in Central Hudson's general rate application. The change in basic EPS also reflected an increase in the weighted average number of common
shares outstanding, largely associated with the DRIP.
June 2021/June 2020
Common Equity Earnings decreased by $21 million and basic EPS decreased by $0.05 due primarily to: (i) a lower U.S.-to-Canadian dollar
exchange rate, resulting in a $24 million unfavourable variance; and (ii) significant one-time items totalling $14 million recognized in the
second quarter of 2020. The significant items included an adjustment to ITC's base ROE, partially offset by the finalization of U.S. tax reform
and associated regulations.
Excluding the impact of foreign exchange and the one-time items, Common Equity Earnings increased by $17 million due to: (i) Rate Base
growth; (ii) higher earnings in Arizona driven by warmer weather and new customer rates at TEP, partially offset by higher operating
expenses; and (iii) higher earnings in the Caribbean, reflecting the continued recovery from economic conditions experienced in 2020
associated with the COVID-19 Pandemic. This growth was partially offset by a lower income tax recovery at Corporate and the impact of
mark-to-market accounting of natural gas derivatives at Aitken Creek. The change in basic EPS also reflected an increase in weighted average
number of common shares outstanding, largely associated with the DRIP.
March 2021/March 2020
Common Equity Earnings increased by $43 million and basic EPS increased by $0.09, due primarily to Rate Base growth, new customer rates
at TEP effective January 1, 2021 and higher hydroelectric production in Belize. The impact of losses on retirement investments and foreign
exchange contracts recognized in March 2020 at UNS Energy and Corporate, respectively, also favourably impacted the year-over-year
change. The increase was partially offset by higher operating expenses mainly related to planned generation maintenance at UNS Energy and
unfavourable foreign exchange. The change in basic EPS also reflected an increase in the weighted average number of common shares
outstanding, largely associated with the 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 2021 or 2020.
Inter-company transactions between non-regulated and regulated entities not eliminated on consolidation include the lease of gas storage
capacity and gas sales by Aitken Creek to FortisBC Energy. These transactions did not have a material impact on consolidated earnings,
financial position or cash flows.
As at December 31, 2021, accounts receivable included $22 million due from Belize Electricity (2020 - $28 million).
Fortis periodically provides short-term financing, the impacts of which are eliminated on consolidation, to subsidiaries to support
capital expenditures, acquisitions and seasonal working capital requirements. In October 2021, Fortis entered into a non-revolving term credit
facility with UNS Energy to lend a maximum of US$175 million, maturing December 2022. As at December 31, 2021, inter-segment loans of
$126 million were outstanding related to this agreement. Interest charged on inter-segment loans was not material in 2021 and 2020.
50 FORTIS INC.
2021 Annual Report
Management Discussion and Analysis
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, 2021, 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, 2021.
Internal Controls 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 of directors,
management and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with 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, 2021, 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, 2021, the
Corporation's ICFR was effective.
During the year ended December 31, 2021, 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
The Corporation's long-term outlook remains unchanged. Fortis continues to enhance shareholder value through the execution of its Capital
Plan, the balance and strength of its diversified portfolio of utility businesses, and growth opportunities within and proximate to its service
territories. While uncertainty exists due to the COVID-19 Pandemic, the Corporation does not currently expect it to have a material financial
impact in 2022.
Fortis is executing on the transition to a cleaner energy future and is on plan to achieve its corporate-wide target to reduce carbon emissions
by 75% by 2035. Upon achieving this target, 99% of the Corporation's assets will be focused on energy delivery and renewable, carbon-free
generation.
The Corporation's $20 billion five-year Capital Plan is expected to increase midyear Rate Base from $31.1 billion in 2021 to $41.6 billion by
2026, translating into a five-year CAGR of approximately 6%. Above and beyond the five-year Capital Plan, Fortis continues to pursue
additional energy infrastructure opportunities.
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 MISO's long-range transmission plan; natural gas
resiliency investments in pipelines and LNG infrastructure in British Columbia; the fully permitted, cross-border, Lake Erie Connector electric
transmission project in Ontario; and the acceleration of cleaner energy infrastructure investments across our jurisdictions.
Fortis expects long-term growth in Rate Base will support earnings and dividend growth. Fortis is targeting average annual dividend growth
of approximately 6% through 2025. This dividend growth guidance is premised on the assumptions listed under "Forward-Looking
Information".
51
FORTIS INC.
2021 Annual Report
Management Discussion and Analysis
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: targeted average
annual dividend growth through 2025; forecast capital expenditures for 2022-2026; the expectation that the COVID-19 Pandemic will not have a material financial
impact in 2022 and will not impact the five-year capital plan; forecast Rate Base and Rate Base growth for 2022 through 2026; the expectation that long-term growth in
Rate Base will support earnings and dividend growth; the expectation that Fortis is well positioned to capitalize on evolving industry opportunities, including additional
investment opportunities beyond the Capital Plan; the 2035 carbon emission reduction target, how that target is expected to be achieved and the projected asset mix
upon achieving the target; the expected timing of updates on climate scenario analysis work; the expected timing for achieving new board diversity targets; the expected
timing, outcome and impact of regulatory decisions; the expected or potential funding sources for operating expenses, interest costs and capital plans; 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 expected consolidated fixed-term debt maturities and repayments over the next five years; 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 2022; the expected uses of proceeds from debt
financings; the targeted capital structure; and the nature and expected timing, benefits and costs of certain capital projects including the Multi-Value Regional
Transmission Projects, Transmission Conversion Project, Vail-to-Tortolita Project, Lower Mainland Intermediate Pressure System Upgrade, Okanagan Capacity Upgrade,
Eagle Mountain Woodfibre Gas Line Project, Transmission Integrity Management Capabilities Project, Inland Gas Upgrades Project, Tilbury 1B Project, Tilbury LNG
Storage Expansion, AMI Project, Wataynikaneyap Transmission Power Project and additional opportunities beyond the capital plan.
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: no material impact from the COVID-19 Pandemic; reasonable regulatory
decisions and the expectation of regulatory stability; the successful execution of the five-year 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; the Board exercising its discretion to declare dividends, taking
into account the financial performance and condition of the Corporation; no significant variability in interest rates; 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 2022 include, but are
not limited to: uncertainty regarding the outcome of regulatory proceedings at the Corporation's utilities; risks associated with climate change, physical risks and service
disruption, including cybersecurity risk; risks related to environmental laws and regulations; the impact of weather variability and seasonality on heating and cooling
loads, gas distribution volumes and hydroelectric generation; risks associated with the competitiveness of natural gas; the impact of pandemics and public health crises,
including the COVID-19 Pandemic; risks associated with capital projects and the impact on the Corporation's continued growth; risks associated with commodity price
volatility and supply of purchased power; and interest rate and foreign exchange risks.
All forward-looking information herein is given as of February 10, 2022. 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.
52 FORTIS INC.
2021 Annual Report
Management Discussion and Analysis
GLOSSARY
2021 Annual Financial Statements:
the Corporation's audited
consolidated financial statements and notes thereto for the year ended
December 31, 2021
Actual Payout Ratio: dividends per common share divided by basic EPS
COS: cost of service
COVID-19 Pandemic: declared by the World Health Organization in March
2020 as a result of a novel coronavirus
Adjusted Basic EPS: Adjusted Common Equity Earnings divided by the
basic weighted average number of common shares outstanding
CRMP: Cybersecurity Risk Management Program
CPCN: Certificate of Public Convenience and Necessity
Adjusted Common Equity Earnings: net earnings attributable to
common equity shareholders adjusted as shown under "Non-U.S. GAAP
Financial Measures" on page 24
DBRS Morningstar: DBRS Limited
DCP: disclosure controls and procedures
Adjusted Payout Ratio: dividends per common share divided by Adjusted
Basic EPS as shown under "Non-U.S. GAAP Financial Measures" on page 24
AESO: Alberta Electric System Operator
AFUDC: allowance for funds used during construction
DRIP: dividend reinvestment plan
EPS: earnings per common share
ERM: enterprise risk management
FERC: Federal Energy Regulatory Commission
Aitken Creek: Aitken Creek Gas Storage ULC, a direct 93.8%-owned
subsidiary of FortisBC Holdings Inc.
Fortis: Fortis Inc.
AMI: Advanced Metering Infrastructure
AUC: Alberta Utilities Commission
BCUC: British Columbia Utilities Commission
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
BECOL: Belize Electric Company Limited, an
subsidiary of Fortis
indirect wholly owned
FortisBC Energy: FortisBC Energy Inc., an indirect wholly owned subsidiary
of Fortis, together with its subsidiaries
Belize Electricity: Belize Electricity Limited, in which Fortis indirectly holds a
33% equity interest
FortisOntario: FortisOntario Inc., a direct wholly owned subsidiary of Fortis,
together with its subsidiaries
Board: Board of Directors of the Corporation
CAGR(s): compound average 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 2021 Annual Financial
Statements, as well as Fortis' 39% share of capital spending for the
Wataynikaneyap Transmission Power Project. See "Non-US GAAP Financial
Measures" on page 24
Capital Plan: forecast Capital Expenditures. Represents a non-U.S. GAAP
financial measure calculated in the same manner as Capital Expenditures
FortisTCI: FortisTCI Limited, an indirect wholly owned subsidiary of Fortis,
together with its subsidiary
Four Corners: Four Corners Generating Station, Units 4 and 5
FX: foreign exchange associated with the translation of U.S. dollar-
denominated amounts. Foreign exchange is 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
GWh: gigawatt hour(s)
Caribbean Utilities: Caribbean Utilities Company, Ltd., an
indirect
approximately 60%-owned (as at December 31, 2021) subsidiary of Fortis,
together with its subsidiary
ICFR: internal controls over financial reporting
IESO: Independent Electricity System Operator
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
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
Common Equity Earnings: net earnings attributable to common equity
shareholders
LIBOR: London Interbank Offered Rate
LNG: liquefied natural gas
Corporation: Fortis Inc.
53 FORTIS INC.
2021 Annual Report
Management Discussion and Analysis
LRTP: MISO Long Range Transmission Plan
SEDAR: Canadian System for Electronic Document Analysis and Retrieval
Luna: Luna Energy Facility
kV: kilovolt
Springerville: Springerville Generating Station
Sundt: H. Wilson Sundt Generating Station
Major Capital Projects: projects, other than ongoing maintenance
projects, individually costing $200 million or more
TEP: Tucson Electric Power Company, a direct wholly owned subsidiary of
UNS Energy
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,
liquidity, on a
consolidated basis
financial position or
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
May 2020 FERC Decision: a FERC order issued in May 2020, on rehearing
of the FERC's November 2019 decision, increasing the base ROE for ITC's
MISO Subsidiaries from that determined in November 2019
UNS Energy: UNS Energy Corporation, an indirect wholly owned subsidiary
of Fortis, together with its subsidiaries, including TEP, UNS Electric, Inc. and
UNS Gas, Inc.
MD&A: the Corporation's management discussion and analysis for the year
ended December 31, 2021
U.S.: United States of America
U.S. GAAP: accounting principles generally accepted in the U.S.
Waneta Expansion: Waneta Expansion hydroelectric generation facility, in
which Fortis held a 51% controlling interest prior to April 2019
Wataynikaneyap Partnership: Wataynikaneyap
Partnership
Power
Limited
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
OEB: Ontario Energy Board
OPEB: other post-employment benefits
Operating Cash Flow: cash from operating activities
PBR: performance-based rate-setting
PJ: petajoule(s)
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
RNG: renewable natural gas
ROA: rate of return on Rate Base
ROE: rate of return on common equity
RTO: regional transmission organization
S&P: Standard & Poor's Financial Services LLC
San Juan: San Juan Generating Station Unit 1
54 FORTIS INC.
2021 Annual Report
Consolidated Financial Statements
Table of Contents
Management's Report on Internal Control over Financial Reporting .......
55 NOTE 9
Other Assets ..........................................................................
Report of Independent Registered Public Accounting Firm
NOTE 10 Property, Plant and Equipment .............................................
("PCAOB ID No. 01208") - Opinion on the Financial Statements ..........
56 NOTE 11 Intangible Assets ...................................................................
Report of Independent Registered Public Accounting Firm - Opinion on
NOTE 12 Goodwill ................................................................................
Internal Control over Financial Reporting ............................................
58 NOTE 13 Accounts Payable and Other Current Liabilities .....................
Consolidated Balance Sheets ...................................................................
59 NOTE 14 Long-Term Debt ....................................................................
Consolidated Statements of Earnings ......................................................
60 NOTE 15 Leases ....................................................................................
Consolidated Statements of Comprehensive Income ..............................
60 NOTE 16 Other Liabilities ......................................................................
Consolidated Statements of Cash Flows ..................................................
61 NOTE 17 Earnings Per Common Share .................................................
Consolidated Statements of Changes in Equity .......................................
62 NOTE 18 Preference Shares ..................................................................
Notes to Consolidated Financial Statements
NOTE 19 Accumulated Other Comprehensive Income ........................
NOTE 1
Description of Business ...........................................................
63 NOTE 20 Stock-Based Compensation Plans .........................................
NOTE 2
Regulation ..............................................................................
64 NOTE 21 Other Income, Net .................................................................
NOTE 3
Summary of Significant Accounting Policies ..........................
66 NOTE 22 Income Taxes .........................................................................
NOTE 4
Segmented Information .........................................................
72 NOTE 23 Employee Future Benefits ......................................................
NOTE 5
Revenue ..................................................................................
74 NOTE 24 Supplementary Cash Flow Information .................................
NOTE 6
Accounts Receivable and Other Current Assets ......................
75 NOTE 25 Fair Value of Financial Instruments and Risk Management ....
NOTE 7
Inventories ..............................................................................
75 NOTE 26 Commitments and Contingencies ........................................
77
77
79
79
79
80
83
84
85
85
86
86
89
90
91
95
95
99
NOTE 8
Regulatory Assets and Liabilities .............................................
76
MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Management of Fortis Inc. and its subsidiaries (the "Corporation") is responsible for establishing and maintaining adequate internal control over
financial reporting ("ICFR"). The Corporation's ICFR is designed by, or under the supervision of, the Corporation's President and Chief Executive Officer
("CEO") and Executive Vice President, Chief Financial Officer ("CFO") and effected by the Corporation's board of directors, management and other
personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external
purposes in accordance with accounting principles generally accepted in the United States of America. 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 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 its CEO and CFO, assessed the effectiveness of the Corporation's ICFR as of December 31, 2021, 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, 2021, the Corporation's ICFR was effective.
The Corporation's ICFR as of December 31, 2021 has been audited by Deloitte LLP, an Independent Registered Public Accounting Firm, which also
audited the Corporation's consolidated financial statements for the year ended December 31, 2021. Deloitte LLP issued an unqualified opinion for
both audits.
February 10, 2022
David G. Hutchens
Jocelyn H. Perry
President and Chief Executive Officer, Fortis Inc.
Executive Vice President, Chief Financial Officer, Fortis Inc.
St. John's, Canada
55 FORTIS INC.
2021 Annual Report
Consolidated Financial Statements
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and the Board of Directors of Fortis Inc.
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Fortis Inc. and subsidiaries (the "Corporation") as of December 31, 2021 and 2020,
the related consolidated statements of earnings, comprehensive income, cash flows and changes in equity for each of the two years in the period
ended December 31, 2021, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements
present fairly, in all material respects, the financial position of the Corporation as of December 31, 2021 and 2020, and the results of its operations and
its cash flows for each of the two years in the period ended December 31, 2021, in conformity with accounting principles generally accepted in the
United States of America.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) ("PCAOB"), the
Corporation's internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control - Integrated Framework
(2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 10, 2022, expressed an
unqualified opinion on the Corporation's internal control over financial reporting.
Basis for Opinion
These financial statements are the responsibility of the Corporation's management. Our responsibility is to express an opinion on the Corporation's
financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with
respect to the Corporation in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange
Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included
performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing
procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the
financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as
evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current-period audit of the financial statements that were communicated
or required to be communicated to the audit committee and that (1) relate to accounts or disclosures that are material to the financial statements
and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way
our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate
opinions on the critical audit matters or on the accounts or disclosures to which they relate.
Assessment for Impairment of Goodwill - Refer to Notes 3 and 12 to the financial statements
Critical Audit Matter Description
The Corporation assesses goodwill for impairment annually as well as whenever any event or other change indicates that the fair value of a reporting
unit may be below its carrying value. Management has determined that there is no impairment based on its current annual assessment.
Management's assessment utilizes the income approach which is based on underlying estimates and assumptions with varying degrees of
uncertainty. Those with the highest degree of subjectivity and impact are the assumed growth rates and discount rates. Auditing these estimates and
assumptions required a high degree of audit judgment and effort, including the need to involve a fair value specialist.
How the Critical Audit Matter was Addressed in the Audit
Our audit procedures related to the growth rate and discount rate used by management to estimate the fair value of more recently acquired
reporting units included the following:
• Evaluating the effectiveness of controls over the estimated fair value of the reporting units, including the review and approval of the growth rate
and discount rate selected by management.
• Evaluating management's ability to accurately forecast the growth rate by:
• Assessing the methodology used in management's determination of the growth rate; and
• Comparing management's assumptions to historical data and available market trends.
• With the assistance of a fair value specialist, evaluating the reasonableness of the discount rate by:
• Testing the source information underlying the determination of the discount rate; and
• Developing a range of independent estimates and comparing those to the discount rate selected by management.
56 FORTIS INC.
2021 Annual Report
Consolidated Financial Statements
Impact of Rate Regulation on the financial statements - Refer to Notes 2, 3 and 8 to the financial statements
Critical Audit Matter Description
The Corporation's regulated utilities are subject to rate regulation and annual earnings oversight by various federal, state and provincial regulatory
authorities who have jurisdiction in the United States and Canada. Rates and resultant earnings of the Corporation's regulated utilities are determined
under cost of service regulation, with some using performance-based rate-setting mechanisms. The regulation of rates is premised on the full
recovery of prudently incurred costs and a reasonable rate of return on asset value ("ROA") or common shareholders' equity ("ROE"). Regulatory
decisions can have an impact on the timely recovery of costs and the regulator-approved ROE and/or ROA. Accounting for the economics of rate
regulation impacts multiple financial statement line items and disclosures, such as property, plant, and equipment; regulatory assets and liabilities;
operating revenues and expenses; income taxes; and depreciation expense.
We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions
about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the potential impact of future regulatory
orders on the financial statements. Management judgments include assessing the likelihood of recovery of costs incurred or a refund to customers
through the rate-setting process. While the Corporation's regulated utilities have indicated they expect to recover costs from customers through
regulated rates, there is a risk that the respective regulatory authority will not approve full recovery of the costs incurred and a reasonable ROE and/or
ROA. Auditing these matters required especially subjective judgment and specialized knowledge of accounting for rate regulation due to its inherent
complexities across different jurisdictions.
How the Critical Audit Matter was Addressed in the Audit
Our audit procedures related to the likelihood of recovery of costs incurred or a refund to customers through the rate-setting process, included the
following, among others:
• Evaluating the effectiveness of controls over the monitoring and evaluation of regulatory developments that may affect the likelihood of
recovering costs in future rates or of a future reduction in rates.
• Assessing relevant regulatory orders, regulatory statutes and interpretations as well as procedural memorandums, utility and intervener filings,
and other publicly available information to evaluate the likelihood of recovery in future rates or of a future reduction in rates and the ability to
earn a reasonable ROA or ROE.
• For regulatory matters in progress, inspecting the regulated utilities' filings for any evidence that might contradict management's assertions. We
obtained an analysis from management and letters from internal and external legal counsel, as appropriate, regarding cost recoveries or a future
reduction in rates.
• Evaluating the Corporation's disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
Deloitte LLP
Chartered Professional Accountants
St. John's, Canada
February 10, 2022
We have served as the Corporation's auditor since 2017.
57
FORTIS INC.
2021 Annual Report
Consolidated Financial Statements
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and the Board of Directors of Fortis Inc.
Opinion on Internal Control over Financial Reporting
We have audited the internal control over financial reporting of Fortis Inc. and subsidiaries (the "Corporation") as of December 31, 2021, based on
criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway
Commission ("COSO"). In our opinion, the Corporation maintained, in all material respects, effective internal control over financial reporting as of
December 31, 2021, based on criteria established in Internal Control - Integrated Framework (2013) issued by COSO.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) ("PCAOB"), the
consolidated financial statements as of and for the year ended December 31, 2021, of the Corporation and our report dated February 10, 2022,
expressed an unqualified opinion on those financial statements.
Basis for Opinion
The Corporation's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the
effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control over Financial
Reporting. Our responsibility is to express an opinion on the Corporation's internal control over financial reporting based on our audit. We are a public
accounting firm registered with the PCAOB and are required to be independent with respect to the Corporation in accordance with the U.S. federal
securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included
obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the
design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary
in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control over Financial Reporting
A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial
reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A
company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in
reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that
transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles,
and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the
company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the
company's assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting 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.
Deloitte LLP
Chartered Professional Accountants
St. John's, Canada
February 10, 2022
58 FORTIS INC.
2021 Annual Report
Consolidated Financial Statements
CONSOLIDATED BALANCE SHEETS
FORTIS INC.
As at December 31 (in millions of Canadian dollars)
ASSETS
Current assets
Cash and cash equivalents
Accounts receivable and other current assets (Note 6)
Prepaid expenses
Inventories (Note 7)
Regulatory assets (Note 8)
Total current assets
Other assets (Note 9)
Regulatory assets (Note 8)
Property, plant and equipment, net (Note 10)
Intangible assets, net (Note 11)
Goodwill (Note 12)
Total assets
LIABILITIES AND EQUITY
Current liabilities
Short-term borrowings (Note 14)
Accounts payable and other current liabilities (Note 13)
Regulatory liabilities (Note 8)
Current installments of long-term debt (Note 14)
Total current liabilities
Regulatory liabilities (Note 8)
Deferred income taxes (Note 22)
Long-term debt (Note 14)
Finance leases (Note 15)
Other liabilities (Note 16)
Total liabilities
Commitments and contingencies (Note 26)
Equity
Common shares (1)
Preference shares (Note 18)
Additional paid-in capital
Accumulated other comprehensive (loss) income (Note 19)
Retained earnings
Shareholders' equity
Non-controlling interests
Total equity
Total liabilities and equity
2021
131
1,511
116
478
492
2,728
955
3,097
37,816
1,343
11,720
57,659
247
2,570
357
1,628
4,802
2,865
3,627
23,707
333
1,409
36,743
14,237
1,623
10
(40)
3,458
19,288
1,628
20,916
57,659
$
$
$
$
2020
249
1,369
102
422
470
2,612
670
3,118
35,998
1,291
11,792
55,481
132
2,321
441
1,254
4,148
2,662
3,344
23,113
331
1,599
35,197
13,819
1,623
11
34
3,210
18,697
1,587
20,284
55,481
$
$
$
$
(1) No par value. Unlimited authorized shares. 474.8 million and 466.8 million issued and
outstanding as at December 31, 2021 and 2020, respectively
Approved on Behalf of the Board
See accompanying Notes to Consolidated Financial Statements
Douglas J. Haughey,
Maura J. Clark,
Director
Director
59 FORTIS INC.
2021 Annual Report
Consolidated Financial Statements
CONSOLIDATED STATEMENTS OF EARNINGS
FORTIS INC.
For the years ended December 31 (in millions of Canadian dollars, except per share amounts)
Revenue (Note 5)
Expenses
Energy supply costs
Operating expenses
Depreciation and amortization
Total expenses
Operating income
Other income, net (Note 21)
Finance charges
Earnings before income tax expense
Income tax expense (Note 22)
Net earnings
Net earnings attributable to:
Non-controlling interests
Preference equity shareholders
Common equity shareholders
Earnings per common share (Note 17)
Basic
Diluted
2021
9,448
2,951
2,523
1,505
6,979
2,469
173
1,003
1,639
234
1,405
111
63
1,231
1,405
2.61
2.61
$
$
$
$
$
$
See accompanying Notes to Consolidated Financial Statements
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
For the years ended December 31 (in millions of Canadian dollars)
Net earnings
Other comprehensive loss
Unrealized foreign currency translation losses, net of hedging activities and income tax expense
of $2 million and $3 million, respectively
Other, net of income tax expense (recovery) of $3 million and $(9) million, respectively
Comprehensive income
Comprehensive income attributable to:
Non-controlling interests
Preference equity shareholders
Common equity shareholders
See accompanying Notes to Consolidated Financial Statements
2021
1,405
(93)
8
(85)
1,320
100
63
1,157
1,320
$
$
$
$
60 FORTIS INC.
2021 Annual Report
2020
8,935
2,562
2,437
1,428
6,427
2,508
154
1,042
1,620
231
1,389
115
65
1,209
1,389
2.60
2.60
2020
1,389
(311)
(27)
(338)
1,051
79
65
907
1,051
$
$
$
$
$
$
$
$
$
$
Consolidated Financial Statements
CONSOLIDATED STATEMENTS OF CASH FLOWS
FORTIS INC.
For the year ended December 31 (in millions of Canadian dollars)
2021
2020
Operating activities
Net earnings
Adjustments to reconcile net earnings to net cash provided by operating activities:
Depreciation - property, plant and equipment
Amortization - intangible assets
Amortization - other
Deferred income tax expense (Note 22)
Equity component, allowance for funds used during construction (Note 21)
Other
Change in working capital (Note 24)
Cash from operating activities
Investing activities
Additions to property, plant and equipment
Additions to intangible assets
Contributions in aid of construction
Other
Cash used in investing activities
Financing activities
Proceeds from long-term debt, net of issuance costs (Note 14)
Repayments of long-term debt and finance leases
Borrowings under committed credit facilities
Repayments under committed credit facilities
Net change in short-term borrowings
Issue of common shares, net of costs, and dividends reinvested
Dividends
Common shares, net of dividends reinvested
Preference shares
Subsidiary dividends paid to non-controlling interests
Other
Cash from financing activities
Effect of exchange rate changes on cash and cash equivalents
Change in cash and cash equivalents
Cash and cash equivalents, beginning of year
Cash and cash equivalents, end of year
Supplementary Cash Flow Information (Note 24)
See accompanying Notes to Consolidated Financial Statements
$
1,405
$
1,389
1,313
136
56
147
(77)
71
(144)
2,907
(3,189)
(197)
93
(195)
(3,488)
1,324
(634)
5,082
(4,749)
115
60
(608)
(63)
(58)
(18)
451
12
(118)
249
131
$
1,282
131
15
226
(78)
170
(434)
2,701
(3,857)
(182)
68
(161)
(4,132)
3,470
(1,251)
5,648
(5,299)
(413)
58
(786)
(65)
(65)
30
1,327
(17)
(121)
370
249
$
61
FORTIS INC.
2021 Annual Report
Consolidated Financial Statements
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
FORTIS INC.
For the years ended December 31
(in millions of Canadian dollars,
except share numbers)
Common
Shares
(# millions)
Common
Shares
Preference
Shares
(Note 18)
Additional
Paid-In
Capital
Accumulated
Other
Comprehensive
Income (Loss)
(Note 19)
Retained
Earnings
Non-
Controlling
Interests
Total
Equity
As at December 31, 2020
466.8 $ 13,819 $
1,623 $
11 $
34 $
3,210 $
1,587 $ 20,284
Net earnings
Other comprehensive loss
Common shares issued
Subsidiary dividends paid to non-
controlling interests
Dividends declared on common
shares ($2.08 per share)
Dividends on preference shares
Other
—
—
8.0
—
—
—
—
—
—
418
—
—
—
—
—
—
—
—
—
—
—
—
—
(2)
—
—
—
1
—
(74)
—
—
—
—
—
1,294
—
—
—
(983)
(63)
—
111
(11)
—
1,405
(85)
416
(58)
(58)
—
—
(1)
(983)
(63)
—
As at December 31, 2021
474.8 $ 14,237 $
1,623 $
10 $
(40) $
3,458 $
1,628 $ 20,916
As at December 31, 2019
463.3 $
13,645 $
1,623 $
11 $
336 $
2,916 $
1,582 $ 20,113
Net earnings
Other comprehensive loss
Common shares issued
Advances to non-controlling
interests
Subsidiary dividends paid to non-
controlling interests
Dividends declared on common
shares ($1.965 per share)
Dividends on preference shares
Other
—
—
3.5
—
—
—
—
—
—
—
174
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(3)
—
—
—
—
3
—
(302)
—
—
—
—
—
—
1,274
—
—
—
—
(915)
(65)
—
115
(36)
—
(13)
(65)
—
—
4
1,389
(338)
171
(13)
(65)
(915)
(65)
7
As at December 31, 2020
466.8 $
13,819 $
1,623 $
11 $
34 $
3,210 $
1,587 $ 20,284
See accompanying Notes to Consolidated Financial Statements
62 FORTIS INC.
2021 Annual Report
Notes to Consolidated Financial Statements
For the years ended December 31, 2021 and 2020
1. DESCRIPTION OF BUSINESS
Fortis Inc. ("Fortis" or the "Corporation") is a well-diversified North American regulated electric and gas utility holding company. Entities within the
reporting segments that follow operate with substantial autonomy.
Regulated Utilities
ITC: ITC Investment Holdings Inc., ITC Holdings Corp. and the electric transmission operations of its regulated operating subsidiaries, which include
International Transmission Company ("ITCTransmission"), Michigan Electric Transmission Company, LLC ("METC"), ITC Midwest LLC ("ITC Midwest"), and
ITC Great Plains, LLC. Fortis owns 80.1% of ITC and an affiliate of GIC Private Limited owns a 19.9% minority interest.
ITC owns and operates high-voltage transmission lines in Michigan's lower peninsula and portions of Iowa, Minnesota, Illinois, Missouri, Kansas and
Oklahoma.
UNS Energy: UNS Energy Corporation, which primarily includes Tucson Electric Power Company ("TEP"), UNS Electric, Inc. ("UNS Electric") and UNS Gas,
Inc. ("UNS Gas").
UNS Energy's largest operating subsidiary, TEP, and UNS Electric are vertically integrated regulated electric utilities. They generate, transmit and
distribute electricity to retail customers in southeastern Arizona, including the greater Tucson metropolitan area in Pima County and parts of
Cochise County, as well as in Santa Cruz and Mohave counties. TEP also sells wholesale electricity to other entities in the western United States.
Together they own generating capacity of 3,485 megawatts ("MW"), including 53 MW of solar capacity and 252 MW of wind capacity. Several
generating assets in which they have an interest are jointly owned.
UNS Gas is a regulated gas distribution utility serving retail customers in Arizona's Mohave, Yavapai, Coconino, Navajo and Santa Cruz counties.
Central Hudson: CH Energy Group, Inc., which primarily includes Central Hudson Gas & Electric Corporation. Central Hudson is a regulated electric and
gas transmission and distribution utility that serves portions of New York State's Mid-Hudson River Valley and owns gas-fired and hydroelectric
generating capacity totalling 65 MW.
FortisBC Energy: FortisBC Energy Inc., which is the largest regulated distributor of natural gas in British Columbia, provides transmission and
distribution services in over 135 communities. FortisBC Energy obtains natural gas supplies primarily from northeastern British Columbia and Alberta
on behalf of most customers.
FortisAlberta: FortisAlberta Inc. is a regulated electricity distribution utility operating in a substantial portion of southern and central Alberta. It is not
involved in the direct sale of electricity.
FortisBC Electric: FortisBC Inc. is an integrated regulated electric utility operating in the southern interior of British Columbia. It owns four hydroelectric
generating facilities with a combined capacity of 225 MW. It also provides operating, maintenance and management services relating to five
hydroelectric generating facilities in British Columbia that are owned by third parties.
Other Electric: Eastern Canadian and Caribbean utilities, as follows: Newfoundland Power Inc. ("Newfoundland Power"); Maritime Electric Company,
Limited ("Maritime Electric"); FortisOntario
in Wataynikaneyap Power Limited Partnership
("Wataynikaneyap Partnership"); an approximate 60% controlling interest in Caribbean Utilities Company, Ltd. ("Caribbean Utilities"); FortisTCI Limited
and Turks and Caicos Utilities Limited (collectively, "FortisTCI"); and a 33% equity investment in Belize Electricity Limited ("Belize Electricity").
Inc. ("FortisOntario"); a 39% equity
investment
Newfoundland Power is an integrated regulated electric utility and the principal distributor of electricity on the island portion of Newfoundland and
Labrador with a generating capacity of 143 MW, of which 97 MW is hydroelectric. Maritime Electric is an integrated regulated electric utility and
the principal distributor of electricity on Prince Edward Island ("PEI") with on-Island generating capacity of 130 MW. FortisOntario consists of three
regulated electric utilities that provide service to customers in Fort Erie, Cornwall, Gananoque, Port Colborne and the District of Algoma in Ontario
with a generating capacity of 5 MW. Wataynikaneyap Partnership is a partnership between 24 First Nations communities, Fortis and Algonquin Power
& Utilities Corp. with a mandate to connect remote First Nations communities to the electricity grid in Ontario through the development of new
transmission lines.
Caribbean Utilities is an integrated regulated electric utility and the sole electricity provider on Grand Cayman with a diesel-powered generating
capacity of 161 MW. FortisTCI consists of two integrated regulated electric utilities that provide electricity to certain Turks and Caicos Islands and has a
diesel-powered generating capacity of 94 MW. Belize Electricity is an integrated electric utility and the principal distributor of electricity in Belize.
63 FORTIS INC.
2021 Annual Report
Notes to Consolidated Financial Statements
For the years ended December 31, 2021 and 2020
1. DESCRIPTION OF BUSINESS (cont'd)
Non-Regulated
Energy Infrastructure: Long-term contracted generation assets in Belize and the Aitken Creek natural gas storage facility ("Aitken Creek") in British
Columbia. Generation assets in Belize consist of three hydroelectric generating facilities with a combined generating capacity of 51 MW, held through
the Corporation's indirectly wholly owned subsidiary Belize Electric Company Limited ("BECOL"). The output is sold to Belize Electricity under 50-
year power purchase agreements ("PPAs"). Fortis indirectly owns 93.8% of Aitken Creek, with the remainder owned by BP Canada Energy Company.
Aitken Creek is the only underground natural gas storage facility in British Columbia and has a working gas capacity of 77 billion cubic feet.
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, including net corporate expenses of Fortis and non-regulated holding company expenses.
2. REGULATION
General
The earnings of the Corporation's regulated utilities are determined under cost of service ("COS") regulation, with some using performance-based rate
setting ("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 regulatory deemed or targeted capital structure applied to an approved regulatory asset value
("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 rate of return on common shareholders' equity
("ROE") and/or rate of return on rate base assets ("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 reflected in customer rates.
The Corporation's regulated utilities, where applicable, are permitted by their respective regulators to flow through to customers, without markup, the
cost of natural gas, fuel and/or purchased power through base customer rates and/or the use of rate stabilization and other mechanisms (Note 8).
64 FORTIS INC.
2021 Annual Report
Notes to Consolidated Financial Statements
For the years ended December 31, 2021 and 2020
2. REGULATION (cont'd)
Nature of Regulation
Regulated Utility
ITC (2)
Regulatory Authority
Federal Energy Regulatory
Commission ("FERC")
TEP
Arizona Corporation Commission
("ACC") (4)
UNS Electric
UNS Gas
Central Hudson (6)
FERC
ACC
ACC
New York State Public Service
Commission ("PSC")
FortisBC Energy
British Columbia Utilities Commission
("BCUC")
FortisBC Electric
BCUC
FortisAlberta
Alberta Utilities Commission ("AUC")
Newfoundland Power
Newfoundland and Labrador Board of
Commissioners of Public Utilities
Allowed
Common
Equity
(%)
60.0
53.0
(5)
52.8
50.8
50.0
38.5
40.0
37.0
45.0
Allowed ROE (1)
(%)
2021
10.77
9.15
(5)
9.50
9.75
9.00
8.75
9.15
8.50
8.50
2020 Significant Features
10.77 Cost-based formula rates, with annual true-
up mechanism (3)
Incentive adders
9.75 COS regulation
Historical test year
(5) Formula transmission rates
9.50
9.75
8.80 COS regulation
Future test year
8.75 COS regulation with formula components
and incentives (7)
9.15 Future test year
8.50 PBR (8)
8.50 COS regulation
Future test year
9.35 COS regulation
Future test year
Maritime Electric
Island Regulatory and Appeals
Commission
40.0
9.35
FortisOntario (9)
Ontario Energy Board
40.0
8.52-9.30
8.52-9.30 COS regulation with incentive mechanisms
Caribbean Utilities (10)
Utility Regulation and Competition
Office
N/A
6.00-8.00
6.75-8.75 COS regulation
Rate-cap adjustment mechanism
based on published consumer price indices
FortisTCI (11)
Government of the Turks and Caicos
Islands
N/A 15.00-17.50
15.00-17.50 COS regulation
Historical test year
Includes the allowed common equity and base ROE plus incentive adders for ITCTransmission, METC, and ITC Midwest. See "Significant Regulatory Developments" below
(1) ROA for Caribbean Utilities and FortisTCI
(2)
(3) Annual true-up collected or refunded in rates within a two-year period
(4) Effective January 1, 2021, an approved ROE of 9.15% with a 0.20% return on the fair value increment. The common equity component of capital structure for 2020 was 50%
(5) The allowed common equity component for FERC transmission rates is formulaic, and is updated annually based on TEP's actual equity ratio. See "Significant Regulatory Developments"
below
(6) Allowed common equity percentage is updated annually on July 1st. See "Significant Regulatory Developments" below
(7) Formula and incentives have been set through 2024. See "Significant Regulatory Developments" below
(8) FortisAlberta is subject to PBR including mechanisms for flow-through costs and capital expenditures not otherwise recovered through customer rates. FortisAlberta's current PBR term expires
as of December 31, 2022. See "Significant Regulatory Developments" below
(9) Two of FortisOntario's utilities follow COS regulation with incentive mechanisms, while the remaining utility is subject to a 35-year franchise agreement expiring in 2033
(10) Operates under licences from the Government of the Cayman Islands. Its exclusive transmission and distribution licence is for an initial 20-year period, expiring in April 2028, with a provision
for automatic renewal. Its non-exclusive generation licence is for a 25-year term, expiring in November 2039
(11) Operates under 50-year licences from the Government of the Turks and Caicos Islands, which expire in 2036 and 2037
Significant Regulatory Developments
ITC
Transmission Incentives: In April 2021, FERC issued a supplemental notice of proposed rulemaking ("NOPR") on transmission incentives modifying the
proposal in the initial NOPR released in March 2020. The supplemental NOPR proposes to eliminate the 50-basis point regional transmission
organization ("RTO") ROE incentive adder for existing RTO members that have been members longer than three years, like ITC. In June 2021, ITC filed
its comments on the supplemental NOPR supporting the continuation of the ROE incentive adder for RTO members. The timeline for FERC to issue a
final rule in this proceeding as well as the likely outcome and potential impacts to Fortis cannot be determined at this time.
65 FORTIS INC.
2021 Annual Report
Notes to Consolidated Financial Statements
For the years ended December 31, 2021 and 2020
2. REGULATION (cont'd)
UNS Energy
FERC Rate Case: In 2019, FERC issued an order accepting formula transmission rates proposed by TEP, subject to refund following hearing and
settlement procedures. A settlement in principle was reached in August 2021, and a settlement agreement including an ROE of 9.79% was filed with
FERC in December 2021. Until conclusion of the proceeding, customer rates continue to be charged under the 2019 FERC order and remain subject to
refund pending the final order. The timing and outcome of this proceeding remains unknown.
Central Hudson
General Rate Application: In November 2021, the PSC approved a three-year rate plan for Central Hudson with retroactive application to July 1, 2021,
including an ROE of 9.0%, and a common equity component of capital structure of 50% declining by 1% annually to 48% in the third rate year. The
three-year rate plan also reflects the use of existing regulatory balances and other measures to reduce customer bill impacts, the recovery of finance
charges which had not been billed to customers since the second quarter of 2020, as well as initiatives to support New York State's climate goals.
FortisBC Energy and FortisBC Electric
Generic Cost of Capital ("GCOC") Proceeding: In January 2021, the BCUC announced the initiation of a GCOC proceeding including a review of the
common equity component of capital structure and the allowed ROE. The timing and outcome of this proceeding, including the effective date of any
change in the cost of capital for 2022 or beyond, remains unknown.
FortisAlberta
2022 GCOC Proceeding: In March 2021, the AUC concluded the 2022 GCOC proceeding and extended the existing allowed ROE of 8.5% using a 37%
equity component of capital structure through 2022.
2023 COS Application: The final year of FortisAlberta's second PBR term is 2022. In June 2021, the AUC issued a decision confirming the approach to
be adopted by Alberta distribution utilities for the COS rebasing year in 2023. In November 2021, FortisAlberta filed its 2023 COS application and a
decision is expected in the third quarter of 2022.
2023/2024 GCOC Proceeding: In January 2022, the AUC initiated proceedings to establish the cost of capital parameters for 2023 and to consider a
formula-based approach to setting the allowed ROE for 2024 and beyond. The AUC is considering extending the existing allowed ROE of 8.5% using a
37% equity component of capital structure through 2023. Comments on this proposal are due in February 2022 and a decision is expected in the first
quarter of 2022. The GCOC proceeding for 2024 and beyond is expected to commence in the third quarter of 2022, with a decision expected in 2023.
Third PBR Term: In July 2021, the AUC issued a decision confirming that Alberta distribution utilities will be subject to a third PBR term commencing
in 2024 with going-in rates based on the 2023 COS rebasing. The AUC also initiated a new proceeding to consider the design of the third PBR term.
FortisAlberta will submit comments with respect to the design of the third PBR term in 2022 and a decision from the AUC is expected in 2023.
Independent System Operator Tariff Proceeding: In April 2021, the AUC issued a decision confirming that distribution facility owners, such as
FortisAlberta, will no longer be permitted to earn a return on contributions made to the Alberta Electric System Operator ("AESO") on a prospective
basis from the date of the decision. Contributions made prior to that date are not impacted. The decision did not have a material financial impact on
the Corporation in 2021 and it is not expected to materially impact future periods. In January 2022, the Alberta Court of Appeal granted a full appeal
on this matter. In doing so, the Alberta Court of Appeal also permitted a related appeal regarding the legality of the AUC's AESO customer
contribution policy. FortisAlberta will fully participate in the appeal regarding the legality of the AESO customer contribution policy and will closely
monitor the preceding related to earned returns on future AESO contributions.
3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation
These consolidated financial statements have been prepared and presented in accordance with accounting principles generally accepted in the
United States of America ("U.S. GAAP") for rate-regulated entities, and are in Canadian dollars unless otherwise indicated.
These consolidated financial statements include the accounts of the Corporation and its subsidiaries. They reflect the equity method of accounting for
entities in which Fortis has significant influence, but not control, and proportionate consolidation for assets that are jointly owned with non-affiliated
entities. Intercompany transactions have been eliminated, except for transactions between non-regulated and regulated entities in accordance with
U.S. GAAP for rate-regulated entities.
Cash and Cash Equivalents
Cash and cash equivalents include cash, cash held in margin accounts, and short-term deposits with initial maturities of three months or less from the
date of deposit.
66 FORTIS INC.
2021 Annual Report
Notes to Consolidated Financial Statements
For the years ended December 31, 2021 and 2020
3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (cont'd)
Allowance for Credit Losses
Fortis and its subsidiaries recognize an allowance for credit losses to reduce accounts receivable for amounts estimated to be uncollectible. The
allowance for credit losses is estimated based on historical collection patterns, sales, and current and forecast economic and other conditions.
Accounts receivable are written off in the period in which they are deemed uncollectible.
Inventories
Inventories, consisting of materials and supplies, gas, fuel and coal in storage, are measured at the lower of weighted average cost and net realizable
value.
Regulatory Assets and Liabilities
Regulatory assets and liabilities arise as a result of the utility rate-setting process and are subject to regulatory approval. 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.
Certain remaining recovery and settlement periods are those expected by management and the actual periods could differ based on regulatory
approval.
Investments
Investments accounted for using the equity method are reviewed annually for potential impairment in value. Impairments are recognized when
identified.
Property, Plant and Equipment
Property, plant and equipment ("PPE") are recognized at cost less accumulated depreciation. Contributions in aid of construction by customers and
governments are recognized as a reduction in the cost of, and are amortized in a manner consistent with, the related PPE.
Depreciation rates of the Corporation's regulated utilities include a provision for estimated future removal costs not identified as a legal obligation.
The provision is recognized as a long-term regulatory liability (Note 8) against which actual removal costs are netted when incurred.
The Corporation's regulated utilities derecognize PPE on disposal or when no future economic benefits are expected from their use. Upon
derecognition, any difference between cost and accumulated depreciation, net of salvage proceeds, is charged to accumulated depreciation. No gain
or loss is recognized.
Through methodologies established by their respective regulators, the Corporation's regulated utilities capitalize: (i) overhead costs that are not
directly attributable to specific PPE but relate to the overall capital expenditure plan; and (ii) an allowance for funds used during construction
("AFUDC"). The debt component of AFUDC for 2021 totalled $39 million (2020 - $41 million) and is reported as a reduction of finance charges and the
equity component is reported as other income (Note 21). Both components are recorded to earnings through depreciation expense over the
estimated service lives of the applicable PPE.
At FortisAlberta, through December 31, 2020, the cost of PPE includes contributions to AESO toward funding the construction of transmission facilities
(Note 2).
Excluding UNS Energy and Central Hudson, PPE includes inventory held for the development, construction and betterment of other assets. As
required by its regulators, UNS Energy and Central Hudson recognize such items as inventory until used and reclassifies them to PPE once put into
service.
Repairs and maintenance costs are charged to earnings in the period incurred. Replacements and betterments that extend the useful lives of PPE are
capitalized.
PPE is depreciated using the straight-line method based on the estimated service lives of the assets. Depreciation rates for regulated PPE are
approved by the respective regulators. Depreciation rates for 2021 ranged from 0.9% to 39.8% (2020 - 0.9% to 39.8%). The weighted average
composite rate of depreciation, before reduction for amortization of contributions in aid of construction, was 2.6% for 2021 (2020 – 2.5%).
67
FORTIS INC.
2021 Annual Report
Notes to Consolidated Financial Statements
For the years ended December 31, 2021 and 2020
3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (cont'd)
The service life ranges and weighted average remaining service life of PPE as at December 31 were as follows.
(years)
Distribution
Electric
Gas
Transmission
Electric
Gas
Generation
Other
2021
2020
Service Life
Ranges
Weighted
Average
Remaining
Service Life
5-80
18-95
20-90
10-85
5-95
3-70
32
38
42
35
23
13
Service Life
Ranges
5-80
18-95
20-90
10-85
1-85
2-70
Weighted
Average
Remaining
Service Life
32
38
43
35
24
14
Intangible Assets
Intangible assets are recorded at cost less accumulated amortization. Their useful lives are assessed to be either indefinite or finite.
Intangible assets with indefinite useful lives are not amortized and are tested for impairment annually, either individually or, where the particular entity
also has goodwill, at the reporting unit level in conjunction with goodwill impairment testing. An annual review is completed to determine whether
the indefinite life assessment continues to be supportable. If not, the resultant changes are made prospectively.
Intangible assets with finite lives are amortized using the straight-line method based on the estimated service lives of the assets. Amortization rates for
regulated intangible assets are approved by the respective regulators and ranged from 1.0% to 33.0% for 2021 (2020 – 1.0% to 33.0%).
The service life ranges and weighted average remaining service life of finite-life intangible assets as at December 31 were as follows.
(years)
Computer software
Land, transmission and water rights
Other
2021
2020
Service Life
Ranges
3-15
34-90
10-100
Weighted
Average
Remaining
Service Life
4
55
11
Service Life
Ranges
3-15
43-90
10-100
Weighted
Average
Remaining
Service Life
4
56
12
The Corporation's regulated utilities derecognize intangible assets on disposal or when no future economic benefits are expected from their use.
Upon derecognition any difference between the cost and accumulated amortization of the asset, net of salvage proceeds, is charged to accumulated
amortization. No gain or loss is recognized.
Impairment of Long-Lived Assets
The Corporation reviews the valuation of PPE, intangible assets with finite lives, and other long-term assets when events or changes in circumstances
indicate that the total undiscounted cash flows expected to be generated by the asset may be below carrying value. If that is determined to be the
case, the asset is written down to estimated fair value and an impairment loss is recognized.
68 FORTIS INC.
2021 Annual Report
Notes to Consolidated Financial Statements
For the years ended December 31, 2021 and 2020
3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (cont'd)
Goodwill
Goodwill represents the excess of the purchase price over the fair value of the identifiable net assets related to business acquisitions.
Goodwill at each of the Corporation's 11 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 necessary, 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.
Deferred Financing Costs
Issue costs, discounts and premiums are recognized against, and amortized over the life of, the related long-term debt.
Employee Future Benefits
Fortis and each subsidiary maintain one or a combination of defined benefit pension plans and defined contribution pension plans, as well as other post-
employment benefit ("OPEB") plans, including certain health and dental coverage and life insurance benefits, for qualifying members. The costs of defined
contribution pension plans are expensed as incurred.
For defined benefit pension and OPEB plans, the projected or accumulated benefit obligation and net benefit costs are actuarially determined using the
projected benefits method prorated on service and management's best estimate of expected plan investment performance, salary escalation, retirement ages
of employees and, for OPEB plans, expected health care costs. Discount rates reflect market interest rates on high‑quality bonds with cash flows that match the
timing and amount of expected pension or OPEB payments.
Defined benefit pension and OPEB plan assets are recognized at fair value. For the purpose of determining defined benefit pension cost, FortisBC Energy and
Newfoundland Power use the market-related value whereby investment returns in excess of, or below, expected returns are recognized in the asset value over
a period of three years.
The excess of any cumulative net actuarial gain or loss over 10% of the greater of: (i) the projected or accumulated benefit obligation; and (ii) the fair value or
market-related value, as applicable, of plan assets at the beginning of the fiscal year, along with unamortized past service costs, are deferred and amortized over
the average remaining service period of active employees.
The net funded or unfunded status of defined benefit pension and OPEB plans, measured as the difference between the fair value of the plan assets and the
projected or accumulated benefit obligation, is recognized on the Corporation's consolidated balance sheets.
For most of the Corporation's regulated utilities, any difference between defined benefit pension or OPEB plan costs ordinarily recognized under U.S. GAAP and
those recovered from customers in current rates is subject to deferral account treatment and is expected to be recovered from, or refunded to, customers in
future rates (Note 8).
For most of the Corporation's regulated utilities, any unamortized balances related to net actuarial gains and losses, past service costs and transitional
obligations associated with defined benefit pension or OPEB plans, as applicable, which would otherwise be recognized in accumulated other comprehensive
income, are subject to deferral account treatment (Note 8).
Leases
A right-of-use asset and lease liability is recognized for all leases with a lease term greater than 12 months. The right-of-use asset and liability are both
measured at the present value of future lease payments, excluding variable payments that are based on usage or performance. Future lease payments include
both lease components (e.g., rent, real estate taxes and insurance costs) and non-lease components (e.g., common area maintenance costs), which Fortis
accounts for as a single lease component. The present value is calculated using the rate implicit in the lease or a lease-specific secured interest rate based on
the remaining lease term. Renewal options are included in the lease term when it is reasonably certain that the option will be exercised.
Finance leases are depreciated over the lease term, except where: (i) ownership of the asset is transferred at the end of the lease term, in which case
depreciation is over the estimated service life of the underlying asset; and (ii) the regulator has approved a different recovery methodology for rate-setting
purposes, in which case the timing of the expense recognition will conform to the regulator's requirements.
69 FORTIS INC.
2021 Annual Report
Notes to Consolidated Financial Statements
For the years ended December 31, 2021 and 2020
3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (cont'd)
Revenue Recognition
Most revenue is derived from energy sales and the provision of transmission services to customers based on regulator-approved tariff rates. Most contracts
have a single performance obligation, being the delivery of energy or the provision of transmission services. No component of the transaction price is allocated
to unsatisfied performance obligations. Energy sales are generally measured in kilowatt hours, gigajoules or transmission load delivered. The billing of energy
sales is based on customer meter readings, which occur systematically throughout each month. The billing of transmission services at ITC is based on peak
monthly load.
FortisAlberta is a distribution company and is required by its regulator to arrange and pay for transmission services with the AESO. This includes the collection
of transmission revenue from its customers, which occurs through the transmission component of its regulator-approved rates. FortisAlberta reports
transmission revenue and expenses on a net basis.
Electricity, gas and transmission service revenue includes an estimate for unbilled energy consumed or service provided since the last meter reading that has
not been billed at the end of the reporting period. Sales estimates generally reflect an analysis of historical consumption in relation to key inputs, such as
current energy prices, population growth, economic activity, weather conditions and system losses. Unbilled revenue accruals are adjusted in the periods
actual consumption becomes known.
Generation revenue from non-regulated operations is recognized on delivery at contracted fixed or market rates.
Variable consideration is estimated at the most likely amount and reassessed at each reporting date until the amount is known. Variable consideration,
including amounts subject to a future regulatory decision, is recognized as a refund liability until entitlement is probable.
Revenue excludes sales and municipal taxes collected from customers.
The Corporation has elected not to assess or account for any significant financing components associated with revenue billed in accordance with equal
payment plans as the period between the transfer of energy to customers and the customers' payment is less than one year.
Revenue is disaggregated by geography, regulatory status, and substantially autonomous utility operations (Note 5). This represents the level of disaggregation
used by the Corporation's President and Chief Executive Officer ("CEO") to allocate resources and evaluate performance.
Stock-Based Compensation
Compensation expense related to stock options is measured at the grant date using the Black-Scholes fair value option-pricing model and each grant is
amortized to compensation expense as a single award evenly over the four-year vesting period, with the offsetting entry to additional paid-in capital.
Fortis satisfies stock option exercises by issuing common shares from treasury. Upon exercise, proceeds are credited to capital stock at the option prices and
the fair value of the options, as previously recognized, is reclassified from additional paid-in capital to capital stock.
Fortis recognizes liabilities associated with its directors' Deferred Share Unit ("DSU"), Performance Share Unit ("PSU") and Restricted Share Unit ("RSU") Plans.
DSUs and PSUs, as well as RSUs issued through 2019 represent cash-settled awards. Effective January 1, 2020, new RSU issuances represent cash or share-settled
awards, depending on settlement elections and the share ownership requirements of the executive. The fair value of these liabilities is based on the five-day
volume weighted average price ("VWAP") of the Corporation's common shares at the end of each reporting period. The VWAP as at December 31, 2021 was
$61.08 (2020 - $52.36). The fair value of the PSU liability is also based on the expected payout probability, based on historical performance in accordance with
the defined metrics of each grant and management's best estimate.
Compensation expense is recognized on a straight-line basis over the vesting period, which for the PSU and RSU Plans is over the lesser of three years or the
period to retirement eligibility and for the DSU Plan is at the time of grant. Forfeitures are accounted for as they occur.
Foreign Currency Translation
Assets and liabilities of the Corporation's foreign operations, all of which have a U.S. dollar functional currency, are translated at the exchange rate in effect at
the balance sheet date and the resultant unrealized translation gains and losses are recognized in accumulated other comprehensive income. The exchange
rate as at December 31, 2021 was US$1.00=CA$1.26 (2020 – US$1.00=CA$1.27).
Revenue and expenses of the Corporation's foreign operations are translated at the average exchange rate for the reporting period, which was
US$1.00=CA$1.25 for 2021 (2020 - US$1.00=CA$1.34).
Monetary assets and liabilities denominated in foreign currencies are translated at the exchange rate prevailing at the balance sheet date. Revenue and
expenses denominated in foreign currencies are translated at the exchange rate prevailing at the transaction date. Translation gains and losses are recognized
in earnings.
Translation gains and losses on foreign currency-denominated debt that is designated as an effective hedge of foreign net investments are recognized in other
comprehensive income.
70 FORTIS INC.
2021 Annual Report
Notes to Consolidated Financial Statements
For the years ended December 31, 2021 and 2020
3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (cont'd)
Derivatives and Hedging
Derivatives Not Designated as Hedges
Derivatives not designated as hedges are used by: (i) Fortis, to manage cash flow risk associated with forecast U.S. dollar cash inflows and forecast
future cash settlements of DSU, PSU and RSU obligations; (ii) UNS Energy, to meet forecast load and reserve requirements; and (iii) Aitken Creek, to
manage commodity price risk, capture natural gas price spreads, and manage the financial risk of physical transactions. These derivatives are
measured at fair value with changes thereto recognized in earnings.
Derivatives not designated as hedges are also used by UNS Energy, Central Hudson and FortisBC Energy to reduce energy price risk associated with
purchased power and gas requirements. The settled amounts of these derivatives are generally included in regulated rates, as permitted by the
respective regulators. These derivatives are measured at fair value with changes recognized as regulatory assets or liabilities for recovery from, or
refund to, customers in future rates (Note 8).
Derivatives that meet the normal purchase or normal sale scope exception are not measured at fair value and settled amounts are recognized in
earnings as energy supply costs.
Derivatives Designated as Hedges
Fortis, ITC and UNS Energy use cash flow hedges, from time to time, to manage interest rate risk. Unrealized gains and losses are initially recognized in
accumulated other comprehensive income and reclassified to earnings when the underlying hedged transaction affects earnings.
The Corporation's earnings from, and net investments in, foreign subsidiaries and certain equity-accounted investments are exposed to fluctuations in
the U.S. dollar-to-Canadian dollar exchange rate. The Corporation has hedged a portion of this exposure through U.S. dollar-denominated debt at the
corporate level. Exchange rate fluctuations associated with the translation of this debt and the foreign net investments are recognized in accumulated
other comprehensive income.
Presentation of Derivatives
The fair value of derivatives is recognized as current or long-term assets and liabilities depending on the timing of settlements and resulting cash
flows. Derivatives under master netting agreements and collateral positions are presented on a gross basis. Cash flows associated with the settlement
of all derivatives are presented in operating activities in the consolidated statements of cash flows.
Income Taxes
The Corporation and its taxable subsidiaries follow the asset and liability method of accounting for income taxes. Current income tax expense or
recovery is recognized for the estimated income taxes payable or receivable in the current year.
Deferred income tax assets and liabilities are recognized for temporary differences between the tax and accounting basis of assets and liabilities, as
well as for the benefit of losses available to be carried forward to future years for tax purposes that are "more likely than not" to be realized. They are
measured using enacted income tax rates and laws in effect when the temporary differences are expected to be recovered or settled. The effect of a
change in income tax rates on deferred income tax assets and liabilities is recognized in earnings in the period when the change occurs. Valuation
allowances are recognized when it is "more likely than not" that all of, or a portion of, a deferred income tax asset will not be realized.
Customer rates at ITC, UNS Energy, Central Hudson and Maritime Electric reflect current and deferred income tax. Customer rates at FortisAlberta
reflect current income tax. Customer rates at FortisBC Energy, FortisBC Electric, Newfoundland Power and FortisOntario reflect current income tax and,
for certain regulatory balances, deferred income tax. Caribbean Utilities, FortisTCI and BECOL are not subject to income tax.
Differences between the income tax expense or recovery recognized under U.S. GAAP and reflected in current customer rates, which is expected to
be recovered from, or refunded to, customers in future rates, are recognized as regulatory assets or liabilities (Note 8).
Fortis does not recognize deferred income taxes on temporary differences related to investments in foreign subsidiaries where it intends to
indefinitely reinvest earnings. The difference between the carrying values of these foreign investments and their tax bases, resulting from
unrepatriated earnings and currency translation adjustments, is approximately $4.1 billion as at December 31, 2021 (2020 - $3.4 billion). If such
earnings are repatriated, the Corporation may be subject to income taxes and foreign withholding taxes. The determination of the amount of
unrecognized deferred income tax liabilities on such amounts is impractical.
Tax benefits associated with actual or expected income tax positions are recognized when the "more likely than not" recognition threshold is met. The
tax benefits are measured at the largest amount of benefit that is greater than 50% likely to be realized upon settlement.
Income tax interest and penalties are recognized as income tax expense when incurred.
71
FORTIS INC.
2021 Annual Report
Notes to Consolidated Financial Statements
For the years ended December 31, 2021 and 2020
3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (cont'd)
Asset Retirement Obligations
The Corporation's subsidiaries have asset retirement obligations ("AROs") associated with certain generation, transmission, distribution and
interconnection assets, including land and environmental remediation and/or asset removal. These assets and related licences, permits, rights-of-way
and agreements are reasonably expected to effectively exist and operate in perpetuity due to their nature. Consequently, where the final date and
cost of remediation and/or removal of the noted assets cannot be reasonably determined, AROs have not been recognized.
Otherwise, AROs are recognized at fair value in the period incurred as an increase in PPE and long-term other liabilities (Note 16) if a reasonable
estimate of fair value can be determined. Fair value is estimated as the present value of expected future cash outlays, discounted at a credit-adjusted
risk-free interest rate. The increase in the liability due to the passage of time is recognized through accretion and the capitalized cost is depreciated
over the useful life of the asset. Accretion and depreciation expense are deferred as a regulatory asset or liability based on regulatory recovery of these
costs. Actual settlement costs are recognized as a reduction in the accrued liability.
Contingencies
Fortis and its subsidiaries are subject to various legal proceedings and claims that arise in the normal course of business. Management makes
judgments regarding the future outcome of contingent events and recognizes a loss based on its best estimate when it is determined that such loss,
or range of loss, is probable and can be reasonably estimated. Legal fees are expensed as incurred. When a loss is recoverable in future rates, a
regulatory asset is also recognized.
Management regularly reviews current information to determine whether recognized provisions should be adjusted and new provisions are required.
However, estimating probable losses requires considerable judgment about potential actions by third parties and matters are often resolved over
long periods of time. Actual outcomes may differ materially from the amounts recognized.
Use of Accounting Estimates
The preparation of these consolidated financial statements in accordance with U.S. GAAP requires management to make estimates and judgments,
including those arising from matters dependent upon the finalization of regulatory proceedings, that affect the reported amounts of assets, liabilities,
revenues, expenses, gains and losses. 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 being recognized in the period they become
known. Actual results may differ significantly from these estimates.
Future Accounting Pronouncements
The Corporation considers the applicability and impact of all Accounting Standards Updates ("ASUs") issued by the Financial Accounting Standards
Board. Any ASUs not included in these consolidated financial statements were assessed and determined to be either not applicable to the
Corporation or are not expected to have a material impact on the consolidated financial statements.
4. SEGMENTED INFORMATION
General
Fortis segments its business based on regulatory jurisdiction and service territory, as well as the information used by its CEO in deciding how to
allocate resources. Segment performance is evaluated principally on net earnings attributable to common equity shareholders.
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 2021 or 2020.
The lease of gas storage capacity and gas sales from Aitken Creek to FortisBC Energy of $38 million in 2021 (2020 - $25 million) are inter-company
transactions between non-regulated and regulated entities, which were not eliminated on consolidation.
As at December 31, 2021, accounts receivable included $22 million due from Belize Electricity (2020 - $28 million).
Fortis periodically provides short-term financing, the impacts of which are eliminated on consolidation, to subsidiaries to support capital expenditures,
acquisitions and seasonal working capital requirements. In October 2021, Fortis entered into a non-revolving term credit facility with UNS Energy to
lend a maximum of US$175 million, maturing December 2022. As at December 31, 2021, inter-segment loans of $126 million were outstanding
related to this agreement. Interest charged on inter-segment loans was not material in 2021 and 2020 .
72
FORTIS INC.
2021 Annual Report
Notes to Consolidated Financial Statements
For the years ended December 31, 2021 and 2020
4. SEGMENTED INFORMATION (cont'd)
Regulated
UNS
Central
ITC Energy Hudson
FortisBC
Energy Alberta
Fortis FortisBC
Other
Electric Electric
Non-Regulated
Energy
Inter-
segment
structure and Other eliminations
Infra- Corporate
Sub-
total
Total
1,691
—
466
2,334
919
648
1,000
285
498
1,715
713
355
291
934
42
300
156
520
94
—
345
422
41
120
51
292
—
—
91
126
34
46
21
93
—
—
281
366
12
144
48
186
1
—
644
—
157
231
256
2
106
11
141
—
—
468
136
128
1,498
895
201
9,350
2,948
2,453
65
139
5
73
12
59
—
—
181
221
5
71
21
134
16
—
1,485
2,464
141
860
320
1,425
111
—
98
3
33
17
45
1
—
8
38
—
—
—
—
37
3
(40)
31
143
(94)
(58)
—
63
—
—
—
9,448
2,951
2,523
—
—
—
—
—
—
—
—
1,505
2,469
173
1,003
234
1,405
111
63
426
292
93
185
141
59
118
1,314
38
(121)
—
1,231
1,046
710
291
475
389
134
321
3,366
20
—
—
3,386
7,755
21,020
1,746
11,126
570
4,356
913
8,135
228
5,201
235
2,540
246
4,357
11,693
56,735
27
777
—
295
—
11,720
(148) 57,659
1,744
—
438
2,260
847
627
295
1,011
40
324
179
548
99
—
330
456
40
125
69
302
—
—
953
232
503
90
128
31
48
20
91
—
—
1,385
468
341
237
339
8
142
29
176
1
—
596
—
148
212
236
2
104
1
133
—
—
424
119
117
1,485
893
194
8,847
2,559
2,368
61
127
5
72
4
56
—
—
183
215
10
77
21
127
15
—
1,408
2,512
136
892
323
1,433
115
—
88
3
30
16
39
5
—
5
39
—
—
—
—
39
4
(43)
13
150
(97)
(83)
—
65
—
—
—
—
—
—
—
—
—
—
—
8,935
2,562
2,437
1,428
2,508
154
1,042
231
1,389
115
65
449
302
91
175
133
56
112
1,318
39
(148)
—
1,209
1,182
1,200
339
471
420
135
273
4,020
19
—
—
4,039
7,810
20,358
1,758
10,802
574
3,939
913
7,695
228
5,084
235
2,441
247
4,261
11,765
54,580
27
745
—
209
—
11,792
(53) 55,481
($ millions)
Year ended
December 31, 2021
Revenue
Energy supply costs
Operating expenses
Depreciation and
amortization
Operating income
Other income, net
Finance charges
Income tax expense
Net earnings
Non-controlling interests
Preference share dividends
Net earnings attributable to
common equity
shareholders
Additions to property, plant
and equipment and
intangible assets
As at December 31, 2021
Goodwill
Total assets
Year ended
December 31, 2020
Revenue
Energy supply costs
Operating expenses
Depreciation and
amortization
Operating income
Other income, net
Finance charges
Income tax expense
Net earnings
Non-controlling interests
Preference share dividends
Net earnings attributable to
common equity
shareholders
Additions to property, plant
and equipment and
intangible assets
As at December 31, 2020
Goodwill
Total assets
73 FORTIS INC.
2021 Annual Report
Notes to Consolidated Financial Statements
For the years ended December 31, 2021 and 2020
5. REVENUE
($ millions)
Electric and gas revenue
United States
ITC
UNS Energy
Central Hudson
Canada
FortisBC Energy
FortisAlberta
FortisBC Electric
Newfoundland Power
Maritime Electric
FortisOntario
Caribbean
Caribbean Utilities
FortisTCI
Total electric and gas revenue
Other services revenue (1)
Revenue from contracts with customers
Alternative revenue (2)
Other revenue
Total revenue
2021
1,694
2,071
962
1,645
622
404
701
223
211
248
89
8,870
382
9,252
(18)
214
9,448
2020
1,726
2,019
941
1,336
580
358
707
215
222
238
77
8,419
325
8,744
64
127
8,935
Includes $260 million and $227 million from regulated operations for 2021 and 2020, respectively
(1)
(2) 2020 includes a $40 million favourable base ROE adjustment associated with the May 2020 FERC decision, which set the all-in ROE for ITC's subsidiaries operating in the Midcontinent
Independent System Operator, Inc. "MISO" region at 10.77%
Revenue from Contracts with Customers
Electric and gas revenue includes revenue from the sale and/or delivery of electricity and gas, transmission revenue, and wholesale electric revenue,
all based on regulator-approved tariff rates including the flow through of commodity costs.
Other services revenue includes: (i) management fee revenue at UNS Energy for the operation of Springerville Units 3 and 4; (ii) revenue from storage
optimization activities at Aitken Creek; and (iii) revenue from other services that reflect the ordinary business activities of Fortis' utilities.
Alternative Revenue
Alternative revenue programs allow utilities to adjust future rates in response to past activities or completed events if certain criteria are met.
Alternative revenue is recognized on an accrual basis with a corresponding regulatory asset or liability until the revenue is settled. Upon settlement,
revenue is not recognized as revenue from contracts with customers but rather as settlement of the regulatory asset or liability. The significant
alternative revenue programs of Fortis' utilities are summarized as follows.
ITC's formula rates include an annual true-up mechanism that compares actual revenue requirements to billed revenue, and any under- or over-
collections are accrued as a regulatory asset or liability and reflected in future rates within a two-year period (Note 8). The formula rates do not require
annual regulatory approvals, although inputs remain subject to legal challenge.
UNS Energy's lost fixed-cost recovery mechanism ("LFCR") surcharge recovers lost fixed costs, as measured by a reduction in non-fuel revenue,
associated with energy efficiency savings and distributed generation. To recover the LFCR regulatory asset, UNS Energy is required to file an annual
LFCR adjustment request with the ACC for the LFCR revenue recognized in the prior year. The recovery is subject to a year-over-year cap of 2% of total
retail revenue. UNS Energy's demand side management surcharge, which is approved by the ACC annually, compensates for the costs to design and
implement cost-effective energy efficiency and demand response programs until such costs, along with a performance incentive, are reflected in
non-fuel base rates.
FortisBC Energy and FortisBC Electric have an earnings sharing mechanism that provides for a 50/50 sharing of variances from the allowed ROE. This
mechanism is in place until the expiry of the current multi-year rate plan in 2024. Additionally, variances between forecast and actual customer-use
rates and industrial and other customer revenue are captured in a revenue stabilization account and a flow-through deferral account to be refunded
to, or received from, customers in rates within two years.
Other Revenue
Other revenue primarily includes gains or losses on energy contract derivatives, as well as regulatory deferrals at FortisBC Energy and FortisBC Electric
reflecting cost recovery variances from forecast.
74 FORTIS INC.
2021 Annual Report
2020
595
571
(64)
1,102
72
195
1,369
2020
(35)
(36)
(6)
14
(1)
(64)
2020
297
101
24
422
Notes to Consolidated Financial Statements
For the years ended December 31, 2021 and 2020
6. ACCOUNTS RECEIVABLE AND OTHER CURRENT ASSETS
($ millions)
Trade accounts receivable
Unbilled accounts receivable
Allowance for credit losses
Income tax receivable
Other (1)
2021
621
701
(53)
1,269
—
242
1,511
(1) Consists mainly of customer billings for non-core services, gas mitigation costs and collateral deposits for gas purchases, and the fair value of derivative instruments (Note 25)
Allowance for Credit Losses
The allowance for credit losses changed as follows.
2021
(64)
(7)
—
18
—
(53)
2021
318
131
29
478
($ millions)
Balance, beginning of year
Credit loss expensed
Credit loss deferral
Write-offs, net of recoveries
Foreign exchange
Balance, end of year
7. INVENTORIES
($ millions)
Materials and supplies
Gas and fuel in storage
Coal inventory
75 FORTIS INC.
2021 Annual Report
Notes to Consolidated Financial Statements
For the years ended December 31, 2021 and 2020
8. REGULATORY ASSETS AND LIABILITIES
($ millions)
Regulatory assets
Deferred income taxes (Notes 3 and 22)
Employee future benefits (Notes 3 and 23)
Deferred energy management costs (1)
Rate stabilization and related accounts (2)
Deferred lease costs (3)
Manufactured gas plant site remediation deferral (Note 16)
Generation early retirement costs (4)
Derivatives (Notes 3 and 25)
Other regulatory assets (5)
Total regulatory assets
Less: Current portion
Long-term regulatory assets
Regulatory liabilities
Deferred income taxes (Notes 3 and 22)
Future cost of removal (Note 3)
Employee future benefits (Notes 3 and 23)
Rate stabilization and related accounts (2)
Renewable energy surcharge (6)
Energy efficiency liability (7)
Derivatives (Notes 3 and 25)
Other regulatory liabilities (5)
Total regulatory liabilities
Less: Current portion
Long-term regulatory liabilities
2021
1,806
388
384
339
127
96
48
20
381
3,589
(492)
3,097
1,289
1,217
196
116
107
83
52
162
3,222
(357)
2,865
2020
1,697
588
334
213
122
107
55
73
399
3,588
(470)
3,118
1,361
1,206
43
104
100
83
17
189
3,103
(441)
2,662
(1) Deferred Energy Management Costs: Certain regulated subsidiaries provide energy management services to facilitate customer energy efficiency
programs where the related expenditures have been deferred as a regulatory asset and are being amortized, and recovered from customers
through rates, on a straight-line basis over periods ranging from two to 10 years.
(2) Rate Stabilization and Related Accounts: Rate stabilization accounts mitigate the earnings volatility otherwise caused by variability in the cost of
fuel, purchased power and natural gas above or below a forecast or predetermined level, and by weather-driven volume variability. At certain
utilities, revenue decoupling mechanisms minimize the earnings impact of reduced energy consumption as energy efficiency programs are
implemented. Resultant deferrals are recovered from, or refunded to, customers in future rates as approved by the respective regulators.
Related accounts include the annual true-up mechanism at ITC (Note 5).
(3) Deferred Lease Costs: Deferred lease costs at FortisBC Electric primarily relate to the Brilliant Power Purchase Agreement ("BPPA") (Note 15). The
depreciation of the asset under finance lease and interest expense on the finance lease obligation are not being fully recovered in current
customer rates since these rates only reflect the cash payments required under the BPPA. The annual differences are being deferred as a regulatory
asset, which is expected to be recovered from customers in future rates over the term of the lease, which expires in 2056.
(4) Generation Early Retirement Costs: TEP and the co-owners of Navajo Generating Station ("Navajo") retired Navajo in 2019, with related
decommissioning activities continuing through 2054. TEP also retired Sundt Generating Facility Units 1 and 2 ("Sundt") in 2019. In 2020, the ACC
approved the recovery of the retirement costs of Navajo and Sundt over a 10-year period.
(5) Other Regulatory Assets and Liabilities: Comprised of regulatory assets and liabilities individually less than $40 million.
(6) Renewable Energy Surcharge: Under the ACC's Renewable Energy Standard ("RES"), UNS Energy is required to increase its use of renewable energy
each year until it represents at least 15% of its total annual retail energy requirements by 2025. The cost of carrying out the plan is recovered from
retail customers through a RES surcharge. Any RES surcharge collections above or below the costs incurred to implement the plans are deferred as
a regulatory liability or asset.
76 FORTIS INC.
2021 Annual Report
Notes to Consolidated Financial Statements
For the years ended December 31, 2021 and 2020
8. REGULATORY ASSETS AND LIABILITIES (cont'd)
The ACC measures RES compliance through Renewable Energy Credits ("RECs"). Each REC represents one kilowatt hour generated from renewable
resources. When UNS Energy purchases renewable energy, the premium paid above the market cost of conventional power equals the REC
recoverable through the RES surcharge. When RECs are purchased, UNS Energy records their cost as long-term other assets (Note 9) with a
corresponding regulatory liability to reflect the obligation to use the RECs for future RES compliance. When RECs are utilized for RES compliance,
energy supply costs and revenue are recognized in an equal amount.
(7) Energy Efficiency Liability: The energy efficiency liability primarily relates to Central Hudson's Energy Efficiency Program, established to fund
environmental policies associated with energy conservation programs as approved by its regulator.
Regulatory assets not earning a return: (i) totalled $1,727 million and $1,678 million as at December 31, 2021 and 2020, respectively; (ii) are primarily
related to deferred income taxes and employee future benefits; and (iii) generally do not represent a past cash outlay as they are offset by related
liabilities that, likewise, do not incur a carrying cost for rate-making purposes. Recovery periods vary or are yet to be determined by the respective
regulators.
9. OTHER ASSETS
($ millions)
Employee future benefits (Note 23)
Supplemental Executive Retirement Plan ("SERP")
RECs (Note 8)
Other investments
Equity investment - Belize Electricity
Deferred compensation plan
Operating leases (Note 15)
Derivatives
Equity investment - Wataynikaneyap Partnership
Other
2021
259
165
112
86
80
42
40
40
12
119
955
2020
66
155
106
66
80
36
40
4
12
105
670
ITC, UNS Energy and Central Hudson provide additional post-employment benefits through SERPs and deferred compensation plans for directors and
officers. The assets held to support these plans are reported separately from the related liabilities (Note 16). Most plan assets are held in trust and
funded mainly through life insurance policies and mutual funds. Assets in mutual and money market funds are recorded at fair value on a recurring
basis (Note 25).
10. PROPERTY, PLANT AND EQUIPMENT
Cost
12,321
5,838
17,104
2,453
7,014
4,362
1,759
339
51,190
Accumulated
Depreciation
Net Book
Value
(3,359)
(1,504)
(3,610)
(756)
(2,691)
(1,454)
—
—
(13,374)
8,962
4,334
13,494
1,697
4,323
2,908
1,759
339
37,816
($ millions)
2021
Distribution
Electric
Gas
Transmission
Electric
Gas
Generation
Other
Assets under construction
Land
77
FORTIS INC.
2021 Annual Report
Notes to Consolidated Financial Statements
For the years ended December 31, 2021 and 2020
10. PROPERTY, PLANT AND EQUIPMENT (cont'd)
($ millions)
2020
Distribution
Electric
Gas
Transmission
Electric
Gas
Generation
Other
Assets under construction
Land
Cost
11,921
5,546
15,888
2,360
6,441
4,178
2,012
326
48,672
Accumulated
depreciation
Net Book Value
(3,223)
(1,422)
(3,413)
(719)
(2,550)
(1,347)
—
—
(12,674)
8,698
4,124
12,475
1,641
3,891
2,831
2,012
326
35,998
Electric distribution assets are those used to distribute electricity at lower voltages (generally below 69 kilovolts ("kV")). These assets include poles,
towers and fixtures, low-voltage wires, transformers, overhead and underground conductors, street lighting, meters, metering equipment and other
related equipment. Gas distribution assets are those used to transport natural gas at low pressures (generally below 2,070 kilopascals ("kPa")) or a
hoop stress of less than 20% of standard minimum yield strength. These assets include distribution stations, telemetry, distribution pipe for mains and
services, meter sets and other related equipment.
Electric transmission assets are those used to transmit electricity at higher voltages (generally at 69 kV and higher). These assets include poles, wires,
switching equipment, transformers, support structures and other related equipment. Gas transmission assets are those used to transport natural gas
at higher pressures (generally at 2,070 kPa and higher) or a hoop stress of 20% or more of standard minimum yield strength. These assets include
transmission stations, telemetry, transmission pipe and other related equipment.
Generation assets are those used to generate electricity. These assets include hydroelectric and thermal generation stations, gas and combustion
turbines, coal-fired generating stations, dams, reservoirs, photovoltaic systems, wind resources and other related equipment.
Other assets include buildings, equipment, vehicles, inventory, information technology assets and assets associated with natural gas storage at Aitken
Creek.
As at December 31, 2021, assets under construction largely reflect ongoing transmission projects at ITC and UNS Energy.
The cost of PPE under finance lease as at December 31, 2021 was $323 million (2020 - $322 million) and related accumulated depreciation was
$113 million (2020 - $111 million) (Note 15).
Jointly Owned Facilities
UNS Energy and ITC hold undivided interests in jointly owned generating facilities and transmission systems, are entitled to their pro rata share of the
PPE, and are proportionately liable for the associated operating costs and liabilities. As at December 31, 2021, interests in jointly owned facilities
consisted of the following.
($ millions, except as indicated)
Transmission Facilities
Springerville Common Facilities
San Juan Unit 1 ("San Juan")
Springerville Coal Handling Facilities
Four Corners Units 4 and 5 ("Four Corners")
Gila River Common Facilities
Luna Energy Facility ("Luna")
Ownership
(%)
1.0-80.0
86.0
50.0
83.0
7.0
50.0
33.3
Cost
958
504
361
264
243
109
76
2,515
Accumulated
Depreciation
Net Book
Value
(290)
(262)
(340)
(120)
(102)
(38)
(4)
(1,156)
668
242
21
144
141
71
72
1,359
78 FORTIS INC.
2021 Annual Report
Notes to Consolidated Financial Statements
For the years ended December 31, 2021 and 2020
11. INTANGIBLE ASSETS
($ millions)
2021
Computer software
Land, transmission and water rights
Other
Assets under construction
2020
Computer software
Land, transmission and water rights
Other
Assets under construction
Cost
952
941
113
78
2,084
932
898
114
77
2,021
Accumulated
Amortization
Net Book
Value
(518)
(154)
(69)
—
(741)
(524)
(142)
(64)
—
(730)
434
787
44
78
1,343
408
756
50
77
1,291
Included in the cost of land, transmission and water rights as at December 31, 2021 was $137 million (2020 - $136 million) not subject to amortization.
Amortization expense was $136 million for 2021 (2020 - $131 million). Amortization is estimated to average approximately $82 million for each of the
next five years.
12. GOODWILL
($ millions)
Balance, beginning of year
Foreign currency translation impacts (1)
Balance, end of year
2021
11,792
(72)
11,720
2020
12,004
(212)
11,792
(1) Relates to the translation of goodwill associated with the acquisitions of ITC, UNS Energy, Central Hudson, Caribbean Utilities and FortisTCI, whose functional currency is the U.S. dollar
No goodwill impairment was recognized by the Corporation in 2021 or 2020.
13. ACCOUNTS PAYABLE AND OTHER CURRENT LIABILITIES
($ millions)
Trade accounts payable
Employee compensation and benefits payable
Gas and fuel cost payable
Dividends payable
Accrued taxes other than income taxes
Customer and other deposits
Interest payable
Derivatives (Note 25)
Income taxes payable
Employee future benefits (Note 23)
Manufactured gas plant site remediation (Note 16)
Other
79 FORTIS INC.
2021 Annual Report
2021
774
283
269
259
238
222
218
43
31
26
13
194
2,570
2020
707
248
188
241
224
214
215
56
—
26
31
171
2,321
Notes to Consolidated Financial Statements
For the years ended December 31, 2021 and 2020
14. LONG-TERM DEBT
($ millions)
ITC
Secured U.S. First Mortgage Bonds -
4.31% weighted average fixed rate (2020 - 4.31%)
Secured U.S. Senior Notes -
3.90% weighted average fixed rate (2020 - 4.00%)
Unsecured U.S. Senior Notes -
3.61% weighted average fixed rate (2020 - 3.61%)
Unsecured U.S. Shareholder Note -
6.00% fixed rate (2020 - 6.00%)
UNS Energy
Unsecured U.S. Tax-Exempt Bonds - 4.34% weighted
average fixed and variable rate (2020 - 4.34%)
Unsecured U.S. Fixed Rate Notes -
3.62% weighted average fixed rate (2020 - 3.86%)
Central Hudson
Unsecured U.S. Promissory Notes - 3.83% weighted
average fixed and variable rate (2020 - 3.94%)
FortisBC Energy
Unsecured Debentures -
Maturity Date
2024-2055
2040-2055
2022-2043
2028
2029-2030
2023-2051
2022-2060
4.61% weighted average fixed rate (2020 - 4.72%)
2026-2050
FortisAlberta
Unsecured Debentures -
4.49% weighted average fixed rate (2020 - 4.49%)
2024-2052
FortisBC Electric
Secured Debentures -
8.80% fixed rate (2020 - 8.80%)
Unsecured Debentures -
4.77% weighted average fixed rate (2020 - 4.87%)
Other Electric
Secured First Mortgage Sinking Fund Bonds -
5.61% weighted average fixed rate (2020 - 5.61%)
Secured First Mortgage Bonds -
5.31% weighted average fixed rate (2020 - 5.66%)
Unsecured Senior Notes -
4.45% weighted average fixed rate (2020 - 4.45%)
Unsecured U.S. Senior Loan Notes and Bonds -
2023
2035-2050
2022-2060
2025-2061
2041-2048
4.36% weighted average fixed and variable rate (2020 - 4.41%)
2022-2049
2023-2044
2039
2023-2028
Corporate and Other
Unsecured U.S. Senior Notes and Promissory Notes -
3.82% weighted average fixed rate (2020 - 3.81%)
Unsecured Debentures -
6.50% fixed rate (2020 - 6.50%)
Unsecured Senior Notes -
2.52% weighted average fixed rate (2020 - 2.85%)
Long-term classification of credit facility borrowings
Fair value adjustment - ITC acquisition
Total long-term debt (Note 25)
Less: Deferred financing costs and debt discounts
Less: Current installments of long-term debt
80 FORTIS INC.
2021 Annual Report
2021
2,736
1,011
4,108
252
359
2,780
1,177
3,145
2,360
25
760
627
260
152
609
2,509
200
1,000
1,305
107
25,482
(147)
(1,628)
23,707
2020
2,755
923
4,136
253
362
2,704
1,078
2,995
2,360
25
785
634
220
152
648
2,685
200
500
980
119
24,514
(147)
(1,254)
23,113
Notes to Consolidated Financial Statements
For the years ended December 31, 2021 and 2020
14. LONG-TERM DEBT (cont'd)
Most long-term debt at the Corporation's regulated utilities is redeemable at the option of the respective utility at the greater of par or a specified
price, together with accrued and unpaid interest. Security, if provided, is typically through a fixed or floating first charge on specific assets of the utility.
The Corporation's unsecured debentures and senior notes are redeemable at the option of Fortis at the greater of par or a specified price together
with accrued and unpaid interest.
Certain long-term debt agreements have covenants that provide that the Corporation shall not 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%.
Long-Term Debt Issuances in 2021
ITC
Series A secured senior notes (1)
UNS Energy
Unsecured senior notes
Central Hudson
Unsecured senior notes
Unsecured senior notes
FortisBC Energy
Unsecured debentures
Maritime Electric
Secured first mortgage bonds
Fortis
Unsecured senior notes
Month
Issued
August
May
March
October
April
December
May
Interest
Rate
(%)
Maturity
Amount
($ millions)
Use of
Proceeds
2.90
3.25
3.29
3.22
2.42
3.40
2.18
2051 US
75
2051 US
325
2051 US
2051 US
75
55
2031
150
2051
40
(2)
(3)(4)
(3)(4)
(3)(5)
(5)
(5)
2028
500
(3)(4)(5)
(1) US$75 million Series B secured senior notes were priced at 3.05% with issuance expected in May 2022
(2) Fund or refinance a portfolio of eligible green projects
(3) General corporate purposes
(4) Repay maturing long-term debt
(5) Repay credit facility borrowings
In January 2022, ITC issued 30-year US$150 million secured first mortgage bonds at 2.93%. The net proceeds are expected to be used to repay credit
facility borrowings, fund or refinance a portfolio of eligible green projects, fund capital expenditures and for other general corporate purposes.
In January 2022, Central Hudson issued 5-year US$50 million unsecured senior notes at 2.37% and 7-year US$60 million unsecured senior notes at
2.59%. The net proceeds are expected to be used to repay maturing long-term debt and for general corporate purposes.
Long-Term Debt Repayments
The consolidated requirements to meet principal repayments and maturities in each of the next five years and thereafter are as follows.
($ millions)
2022
2023
2024
2025
2026
Thereafter
Total
1,628
1,275
1,750
101
2,595
18,133
25,482
In December 2020, 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 May 2021, the Corporation issued $500 million
unsecured senior notes as shown above and, as at December 31, 2021, $1.5 billion remained available under the short-form base shelf prospectus.
81
FORTIS INC.
2021 Annual Report
Notes to Consolidated Financial Statements
For the years ended December 31, 2021 and 2020
14. LONG-TERM DEBT (cont'd)
Credit Facilities
($ millions)
Total credit facilities
Credit facilities utilized:
Short-term borrowings (1)
Long-term debt (including current portion) (2)
Letters of credit outstanding
Credit facilities unutilized
Regulated
Utilities
3,466
(247)
(1,019)
(70)
2,130
Corporate
and Other
1,380
—
(286)
(45)
1,049
2021
4,846
(247)
(1,305)
(115)
3,179
2020
5,581
(132)
(980)
(130)
4,339
(1) The weighted average interest rate was approximately 0.6% (2020 - 0.8%).
(2) The weighted average interest rate was approximately 0.9% (2020 - 0.9%). The current portion was $888 million (2020 - $651 million).
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 total
facilities. Approximately $4.6 billion of the total credit facilities are committed facilities with maturities ranging from 2022 through 2026.
Consolidated credit facilities of approximately $4.8 billion as at December 31, 2021 are itemized below. In April 2021, the Corporation's unsecured
$500 million revolving one-year term committed credit facility expired and was not renewed. In October 2021, UNS Energy terminated a
US$150 million revolving credit facility and entered into an arrangement with Fortis (Note 4).
($ millions)
Unsecured committed revolving credit facilities
Amount
Maturity
Regulated utilities
ITC (1)
UNS Energy
Central Hudson
FortisBC Energy
FortisAlberta
FortisBC Electric
Other Electric
Other Electric
Corporate and Other
Other facilities
Regulated utilities
Central Hudson - uncommitted credit facility
FortisBC Energy - uncommitted credit facility
FortisBC Electric - unsecured demand overdraft facility
Other Electric - unsecured demand facilities
Other Electric - unsecured demand facility and emergency standby loan
Corporate and Other - unsecured non-revolving facility
US
US
US
US
US
US
900
375
200
700
250
150
215
70
1,350
30
55
10
20
60
30
2024
2026
2025
2026
2026
2026
(2)
2025
(3)
n/a
2023
n/a
n/a
2022
n/a
(1)
ITC also has a US$400 million commercial paper program, under which US$155 million was outstanding as at December 31, 2021 (2020 - US$67 million) , as reported in short-term
borrowings.
(2) $50 million in 2024, $65 million in 2024 and $100 million in 2026
(3) $50 million in 2023 and $1.3 billion in 2026
82 FORTIS INC.
2021 Annual Report
Notes to Consolidated Financial Statements
For the years ended December 31, 2021 and 2020
15. LEASES
The Corporation and its subsidiaries lease office facilities, utility equipment, land, and communication tower space with remaining terms of up to 20
years, with optional renewal terms. Certain lease agreements include rental payments adjusted periodically for inflation or require the payment of real
estate taxes, insurance, maintenance, or other operating expenses associated with the leased premises.
The Corporation's subsidiaries also have finance leases related to generating facilities with remaining terms of up to 34 years.
Leases were presented on the consolidated balance sheets as follows.
($ millions)
Operating leases
Other assets
Accounts payable and other current liabilities
Other liabilities
Finance leases (1)
Regulatory assets
PPE, net
Accounts payable and other current liabilities
Finance leases
2021
40
(8)
(32)
127
210
(4)
(333)
2020
40
(7)
(33)
122
211
(2)
(331)
(1) FortisBC Electric has a finance lease for the BPPA (Note 8), which relates to the sale of the output of the Brilliant hydroelectric plant, and for the Brilliant Terminal Station ("BTS"), which relates
to the use of the station. Both agreements expire in 2056. In exchange for the specified take-or-pay amounts of power, the BPPA requires semi-annual payments based on a return on capital,
which includes the original and ongoing capital cost, and related variable power purchase costs. The BTS requires semi-annual payments based on a charge related to the recovery of the
capital cost of the BTS, and related variable operating costs.
The components of lease expense were as follows.
2021
8
2
32
19
61
Operating
Leases
Finance
Leases
8
7
6
5
3
20
49
(9)
40
(8)
32
35
34
34
34
35
1,030
1,202
(865)
337
(4)
333
2020
10
14
34
20
78
Total
43
41
40
39
38
1,050
1,251
(874)
377
(12)
365
($ millions)
Operating lease cost
Finance lease cost:
Amortization
Interest
Variable lease cost
Total lease cost
As at December 31, 2021, the present value of minimum lease payments was as follows.
($ millions)
2022
2023
2024
2025
2026
Thereafter
Less: Imputed interest
Total lease obligations
Less: Current installments
83 FORTIS INC.
2021 Annual Report
Notes to Consolidated Financial Statements
For the years ended December 31, 2021 and 2020
15. LEASES (cont'd)
Supplemental lease information follows.
($ millions, except as indicated)
Weighted average remaining lease term (years)
Operating leases
Finance leases
Weighted average discount rate (%)
Operating leases
Finance leases
Cash payments related to lease liabilities
Operating cash flows used for operating leases
Operating cash flows used for finance leases
Financing cash flows used for finance leases
Investing cash flows used for finance leases
16. OTHER LIABILITIES
($ millions)
Employee future benefits (Note 23)
AROs (Note 3)
Customer and other deposits
Stock-based compensation plans (Note 20)
Manufactured gas plant site remediation (1)
Deferred compensation plan (Note 9)
Mine reclamation obligations (2)
Retail energy contract (3)
Operating leases
Derivatives (Note 25)
Other
2021
2020
10
34
3.8
5.1
(8)
—
(2)
—
2021
740
184
99
96
83
50
44
40
32
7
34
1,409
10
35
4.0
5.1
(10)
(2)
(25)
(87)
2020
905
130
132
86
69
43
47
46
33
50
58
1,599
(1) Environmental regulations require Central Hudson to investigate sites at which it or its predecessors once owned and/or operated manufactured
gas plants and, if necessary, remediate those sites. Costs are accrued based on the amounts that can be reasonably estimated. As at December 31,
2021, an obligation of $91 million was recognized, including a current portion of $8 million recognized in accounts payable and other current
liabilities (Note 13). Central Hudson has notified its insurers that it intends to seek reimbursement where insurance coverage exists. Differences
between actual costs and the associated rate allowances are deferred as a regulatory asset for future recovery (Note 8).
(2) TEP pays ongoing reclamation costs related to two coal mines that supply generating facilities in which it has an ownership interest but does not
operate. Costs are deferred as a regulatory asset and recovered from customers as permitted by the regulator. TEP's share of the reclamation costs
is estimated to be $56 million upon expiry of the coal agreements between 2022 and 2031. The present value of the estimated future liability is
shown in the table above.
(3) In 2020, FortisAlberta entered into an eight-year agreement with an existing retail energy provider to continue to act as its default retailer to eligible
customers under the regulated retail option. As part of this agreement FortisAlberta received an upfront payment which is being amortized to
revenue over the life of the agreement.
84 FORTIS INC.
2021 Annual Report
Notes to Consolidated Financial Statements
For the years ended December 31, 2021 and 2020
17. EARNINGS PER COMMON SHARE
Diluted earnings per share ("EPS") was calculated using the treasury stock method for stock options.
2021
2020
Net Earnings
to Common
Shareholders
($ millions)
1,231
—
1,231
Weighted
Average
Shares
(# millions)
470.9
0.5
471.4
EPS
($)
2.61
—
2.61
Net Earnings
to Common
Shareholders
($ millions)
1,209
—
1,209
Weighted
Average
Shares
(# millions)
464.8
0.6
465.4
EPS
($)
2.60
—
2.60
Basic EPS
Potential dilutive effect of stock options
Diluted EPS
18. PREFERENCE SHARES
Authorized
An unlimited number of first preference shares and second preference shares, without nominal or par value.
Issued and Outstanding
First Preference Shares
Series F
Series G
Series H
Series I
Series J
Series K
Series M
2021
Number
of Shares
(thousands)
5,000
9,200
7,665
2,335
8,000
10,000
24,000
66,200
Amount
($ millions)
122
225
188
57
196
244
591
1,623
2020
Number
of Shares
(thousands)
5,000
9,200
7,665
2,335
8,000
10,000
24,000
66,200
Characteristics of the first preference shares are as follows.
Reset
Amount
($ millions)
122
225
188
57
196
244
591
1,623
Right to
First Preference Shares (1) (2)
Perpetual fixed rate
Series F
Series J
Fixed rate reset (3) (4)
Series G
Series H (5)
Series K
Series M
Floating rate reset (4) (6)
Series I
Series L
Series N
Initial
Annual
Dividend
Redemption
Redemption
Convert on
Yield
Dividend
(%)
($)
Yield
(%)
and/or Conversion
Value
a One-For-
Option Date
($)
One Basis
4.90
4.75
5.25
4.25
4.00
4.10
2.10
—
—
1.2250
1.1875
1.0983
0.4588
0.9823
0.9783
—
—
—
—
—
2.13
1.45
2.05
2.48
1.45
—
—
Currently Redeemable
Currently Redeemable
September 1, 2023
June 1, 2025
March 1, 2024
December 1, 2024
June 1, 2025
—
—
25.00
25.00
25.00
25.00
25.00
25.00
25.00
—
—
—
—
—
Series I
Series L
Series N
Series H
Series K
Series M
(1) Holders are entitled to receive a fixed or floating cumulative quarterly cash dividend as and when declared by the Board of Directors of the Corporation, 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 for the First Preference Shares, Series H was reset from $0.6250 to $0.4588 for the five-year period from June 1, 2020 up to but excluding June 1, 2025.
(6) The floating quarterly dividend rate will be reset every quarter based on the then current three‑month Government of Canada Treasury Bill rate plus the applicable reset dividend yield.
85 FORTIS INC.
2021 Annual Report
Notes to Consolidated Financial Statements
For the years ended December 31, 2021 and 2020
18. PREFERENCE SHARES (cont'd)
On June 1, 2020, 267,341 First Preference Shares, Series H were converted on a one-for-one basis into First Preference Shares, Series I, and 907,577 First
Preference Shares, Series I were converted on a one-for-one basis into First Preference Shares, Series H.
On the liquidation, dissolution or winding-up of Fortis, holders of common shares are entitled to participate ratably in any distribution of assets of
Fortis, subject to the rights of holders of first and second preference shares, and any other class of shares of the Corporation entitled to receive the
assets of the Corporation on such a distribution, in priority to or ratably with the holders of the common shares.
19. ACCUMULATED OTHER COMPREHENSIVE INCOME
($ millions)
2021
Unrealized foreign currency translation gains (losses)
Net investments in foreign operations
Hedges of net investments in foreign operations
Income tax expense
Other
Cash flow hedges (Note 25)
Unrealized employee future benefits (losses) gains (Note 23)
Income tax recovery (expense)
Accumulated other comprehensive income
2020
Unrealized foreign currency translation gains (losses)
Net investments in foreign operations
Hedges of net investments in foreign operations
Income tax expense
Other
Cash flow hedges (Note 25)
Unrealized employee future benefits losses (Note 23)
Income tax recovery
Accumulated other comprehensive income
Opening
Balance
Net Change
Ending
Balance
377
(299)
(6)
72
(4)
(49)
15
(38)
34
713
(359)
(3)
351
17
(38)
6
(15)
336
(104)
23
(2)
(83)
(1)
13
(3)
9
(74)
(336)
60
(3)
(279)
(21)
(11)
9
(23)
(302)
273
(276)
(8)
(11)
(5)
(36)
12
(29)
(40)
377
(299)
(6)
72
(4)
(49)
15
(38)
34
20. STOCK-BASED COMPENSATION PLANS
Stock Options
Officers and certain key employees of Fortis and its subsidiaries are eligible for grants of options to purchase common shares of the Corporation.
Options are exercisable for a period of 10 years from the grant date, expire no later than three years after the death or retirement of the optionee, and
vest evenly over a four-year period on each anniversary of the grant date.
86 FORTIS INC.
2021 Annual Report
Notes to Consolidated Financial Statements
For the years ended December 31, 2021 and 2020
20. STOCK-BASED COMPENSATION PLANS (cont'd)
The following options were granted in 2021 and 2020.
Options granted (thousands)
Exercise price ($) (1)
Grant date fair value ($)
Valuation assumptions:
Dividend yield (%) (2)
Expected volatility (%) (3)
Risk-free interest rate (%) (4)
Weighted average expected life (years) (5)
(1) Five-day VWAP immediately preceding the grant date
(2) Reflects average annual dividend yield up to the grant date and the weighted average expected life of the options
(3) Reflects historical experience over a period equal to the weighted average expected life of the options
(4) Government of Canada benchmark bond yield at the grant date that covers the weighted average expected life of the options
(5) Reflects historical experience
The following table summarizes information related to stock options for 2021.
2021
431
50.33
4.91
3.8
20.0
0.9
5.0
2020
686
58.40
4.20
3.7
15.8
1.2
5.2
(thousands, except as indicated)
Options outstanding, beginning of year
Granted
Exercised
Vested
Cancelled/Forfeited
Options outstanding, end of year
Options vested, end of year (2)
Total Options
Non-vested Options (1)
Weighted
Average
Exercise Price
($)
Number of
Options
3,262
431
(777)
n/a
—
2,916
1,428
45.26
50.33
40.80
n/a
—
47.20
42.76
Weighted
Average
Grant Date
Fair Value
($)
3.81
4.91
n/a
3.67
—
4.20
Number of
Options
1,772
431
n/a
(715)
—
1,488
(1) As at December 31, 2021, there was $6 million of unrecognized compensation expense related to stock options not yet vested, which is expected to be recognized over a weighted average
period of approximately three years.
(2) As at December 31, 2021, the weighted average remaining term of vested options was six years with an aggregate intrinsic value of $26 million.
The following table summarizes additional stock option information.
($ millions)
Stock options exercised:
Cash received for exercise price
Intrinsic value realized by employees
2021
32
11
2020
32
15
DSU Plan
Directors of the Corporation who are not officers are eligible for grants of DSUs representing the equity portion of their annual compensation.
Directors can further elect to receive credit for their quarterly cash retainer in a notional account of DSUs in lieu of cash. The Corporation may also
determine that special circumstances justify the grant of additional DSUs to a director.
87
FORTIS INC.
2021 Annual Report
Notes to Consolidated Financial Statements
For the years ended December 31, 2021 and 2020
20. STOCK-BASED COMPENSATION PLANS (cont'd)
Each DSU vests at the grant date, has an underlying value equivalent to that of one common share of the Corporation, is entitled to commensurate
notional common share dividends, and is settled in cash.
The following table summarizes information related to DSUs.
Number of units (thousands)
Beginning of year
Granted
Notional dividends reinvested
Paid out
End of year
2021
147
30
6
—
183
2020
165
25
6
(49)
147
The accrued liability has been recognized at the respective December 31st VWAP (Note 3) and included in other liabilities (Note 16). The accrued
liability, compensation expense and cash payout were not material for 2021 or 2020.
PSU Plans
Senior management of the Corporation and its subsidiaries, and all ITC employees, are eligible for grants of PSUs representing a component of their
long-term compensation.
Each PSU vests over a three-year period, has an underlying value equivalent to that of one common share of the Corporation, is entitled to
commensurate notional common share dividends, and is settled in cash. At the end of the three-year vesting period, cash payouts are the product of:
(i) the numbers of units vested; (ii) the VWAP of the Corporation's common shares for the five trading days prior to the vesting date; and (iii) a payout
percentage that may range from 0% to 200%.
The payout percentage is based on the Corporation's performance over the three-year vesting period, mainly determined by: (i) the Corporation's
total shareholder return as compared to a predefined peer group of companies; and (ii) the Corporation's cumulative EPS, or for subsidiaries the
Company's cumulative net income, as compared to the target established at the time of the grant.
The following table summarizes information related to PSUs.
Number of units (thousands)
Beginning of year
Granted
Notional dividends reinvested
Paid out
Cancelled/forfeited
End of year
Additional information ($ millions)
Compensation expense recognized
Compensation expense unrecognized (1)
Cash payout
Accrued liability as at December 31 (2)
Aggregate intrinsic value as at December 31 (3)
2021
1,976
587
60
(697)
(28)
1,898
74
33
50
132
165
2020
2,118
586
71
(735)
(64)
1,976
58
32
54
108
140
(1) Relates to unvested PSUs and is expected to be recognized over a weighted average period of two years
(2) Recognized at the respective December 31st VWAP and included in accounts payable and other current liabilities and in other liabilities (Notes 13 and 16)
(3) Relates to outstanding PSUs and reflects a weighted average contractual life of one year
88 FORTIS INC.
2021 Annual Report
Notes to Consolidated Financial Statements
For the years ended December 31, 2021 and 2020
20. STOCK-BASED COMPENSATION PLANS (cont'd)
RSU Plans
Senior management of the Corporation and its subsidiaries, and all ITC employees, are eligible for grants of RSUs representing a component of their
long-term compensation.
Each RSU vests over a three-year period or immediately upon retirement eligibility of the holder, has an underlying value equivalent to that of one
common share of the Corporation, is entitled to commensurate notional common share dividends, and is settled in cash or, beginning with the 2020
grant, common shares of the Corporation. Effective January 1, 2020, new RSU issuances may be settled in cash, common shares, or an equal
proportion of cash and common shares depending on an executives' settlement election and whether their share ownership requirements have
been met.
The following table summarizes information related to RSUs.
Number of units (thousands)
Beginning of year
Granted
Notional dividends reinvested
Paid out
Cancelled/forfeited
End of year
Additional information ($ millions)
Compensation expense recognized
Compensation expense unrecognized (1)
Cash payout
Accrued liability as at December 31 (2)
Aggregate intrinsic value as at December 31 (3)
2021
1,048
378
32
(371)
(27)
1,060
26
17
21
46
63
(1) Relates to unvested RSUs and is expected to be recognized over a weighted average period of two years
(2) Recognized at the respective December 31st VWAP and included in accounts payable and other current liabilities and in long-term other liabilities (Notes 13 and 16)
(3) Relates to outstanding RSUs and reflects a weighted average contractual life of one year
21. OTHER INCOME, NET
($ millions)
Equity component of AFUDC
Non-service benefit cost
Derivative gains
Equity income
Interest income
Other
2021
77
45
30
7
5
9
173
2020
1,050
356
37
(355)
(40)
1,048
20
15
19
39
54
2020
78
31
13
20
13
(1)
154
89 FORTIS INC.
2021 Annual Report
Notes to Consolidated Financial Statements
For the years ended December 31, 2021 and 2020
22. INCOME TAXES
Deferred Income Tax Assets and Liabilities
The significant components of deferred income tax assets and liabilities consisted of the following.
($ millions)
Gross deferred income tax assets
Regulatory liabilities
Tax loss and credit carryforwards
Employee future benefits
Other
Valuation allowance
Net deferred income tax asset
Gross deferred income tax liabilities
PPE
Regulatory assets
Intangible assets
Net deferred income tax liability
Unrecognized Tax Benefits
($ millions)
Beginning of year
Additions related to current year
Adjustments related to prior years (1)
End of year
2021
560
556
169
91
1,376
(23)
1,353
(4,571)
(283)
(126)
(4,980)
(3,627)
2021
33
2
(33)
2
2020
527
494
175
116
1,312
(22)
1,290
(4,253)
(263)
(118)
(4,634)
(3,344)
2020
36
3
(6)
33
(i) UNS Energy received approval from the Internal Revenue Service to change its accounting method related to an uncertain tax position which resulted in a decrease in uncertain tax benefits..
Unrecognized tax benefits, if recognized, would reduce income tax expense by $1 million in 2021. Fortis has not recognized interest expense in 2021
and 2020 related to unrecognized tax benefits.
Income Tax Expense
($ millions)
Canadian
Earnings before income tax expense
Current income tax
Deferred income tax
Total Canadian
Foreign
Earnings before income tax expense
Current income tax
Deferred income tax
Total Foreign
Income tax expense
2021
427
84
(35)
49
1,212
3
182
185
234
2020
333
20
(16)
4
1,287
(15)
242
227
231
Income tax expense differs from the amount that would be expected to be generated by applying the enacted combined Canadian federal and
provincial statutory income tax rate to earnings before income tax expense.
90 FORTIS INC.
2021 Annual Report
Notes to Consolidated Financial Statements
For the years ended December 31, 2021 and 2020
22. INCOME TAXES (cont'd)
The following is a reconciliation of consolidated statutory taxes to consolidated effective taxes.
($ millions, except as indicated)
Earnings before income tax expense
Combined Canadian federal and provincial statutory income tax rate (%)
Expected federal and provincial taxes at statutory rate
Decrease resulting from:
Foreign and other statutory rate differentials
AFUDC
Effects of rate-regulated accounting:
Difference between depreciation claimed for income tax and accounting purposes
Items capitalized for accounting purposes but expensed for income tax purposes
Other
Income tax expense
Effective tax rate (%)
Income Tax Carryforwards
($ millions)
Canadian
Capital loss
Non-capital loss
Other tax credits
Unrecognized
Foreign
Federal and state net operating loss
Other tax credits
Total income tax carryforwards recognized
2021
1,639
30.0
492
(157)
(16)
(47)
(13)
(25)
234
14.3
Expiring Year
n/a
2028-2041
2026-2041
2022-2041
2023-2041
2020
1,620
30.0
486
(145)
(20)
(56)
(26)
(8)
231
14.3
2021
15
308
2
325
(15)
310
3,070
90
3,160
3,470
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 2013 to 2021 taxation years are still
open for audit in Canadian jurisdictions, and its 2011 to 2021 taxation years are still open for audit in United States jurisdictions.
23. EMPLOYEE FUTURE BENEFITS
For defined benefit pension and OPEB plans, the benefit obligation and fair value of plan assets are measured as at December 31.
For the Corporation's Canadian and Caribbean subsidiaries, actuarial valuations to determine funding contributions for pension plans are required at
least every three years. The most recent valuations were as of December 31, 2018 for FortisBC Energy and FortisBC Electric (plan covering unionized
employees); December 31, 2019 for the remaining FortisBC Electric plans, Newfoundland Power, FortisAlberta and FortisOntario; December 31, 2020
for the Corporation; and December 31, 2021 for Caribbean Utilities.
ITC, UNS Energy and Central Hudson perform annual actuarial valuations as their funding requirements are based on maintaining minimum annual
targets, all of which have been met.
The Corporation's investment policy is to ensure that the defined benefit pension and OPEB plan assets, together with expected contributions, are
invested in a prudent and cost-effective manner to optimally meet the liabilities of the plans. The investment objective is to maximize returns in order
to manage the funded status of the plans and minimize the Corporation's cost over the long term, as measured by both cash contributions and
recognized expense.
91
FORTIS INC.
2021 Annual Report
Notes to Consolidated Financial Statements
For the years ended December 31, 2021 and 2020
23. EMPLOYEE FUTURE BENEFITS (cont'd)
Allocation of Plan Assets
(weighted average %)
2021 Target
Allocation
Equities
Fixed income
Real estate
Cash and other
Fair Value of Plan Assets
47
46
6
1
100
2021
48
45
6
1
100
($ millions)
2021
Equities
Fixed income
Real estate
Private equities
Cash and other
2020
Equities
Fixed income
Real estate
Private equities
Cash and other
Level 1 (1)
Level 2 (1)
Level 3 (1)
749
219
—
—
10
978
713
197
—
—
8
918
1,271
1,642
—
—
15
2,928
1,163
1,580
17
—
17
2,777
—
—
235
21
—
256
—
—
204
20
—
224
(1) See Note 25 for a description of the fair value hierarchy.
The following table reconciles the changes in the fair value of plan assets that have been measured using Level 3 inputs.
($ millions)
Balance, beginning of year
Return (loss) on plan assets
Foreign currency translation
Purchases, sales and settlements
Balance, end of year
2021
224
32
—
—
256
2020
48
45
6
1
100
Total
2,020
1,861
235
21
25
4,162
1,876
1,777
221
20
25
3,919
2020
229
(2)
(1)
(2)
224
92 FORTIS INC.
2021 Annual Report
Notes to Consolidated Financial Statements
For the years ended December 31, 2021 and 2020
23. EMPLOYEE FUTURE BENEFITS (cont'd)
Funded Status
($ millions)
Change in benefit obligation (1)
Balance, beginning of year
Service costs
Employee contributions
Interest costs
Benefits paid
Actuarial (gains) losses
Past service credits/plan amendments
Foreign currency translation
Balance, end of year (2)
Change in value of plan assets
Balance, beginning of year
Actual return on plan assets
Benefits paid
Employee contributions
Employer contributions
Foreign currency translation
Balance, end of year
Funded status
Balance sheet presentation
Other assets (Note 9)
Other current liabilities (Note 13)
Other liabilities (Note 16)
Defined Benefit
Pension Plans
2021
3,995
109
18
98
(170)
(111)
(2)
(15)
3,922
3,528
291
(158)
18
55
(12)
3,722
(200)
204
(13)
(391)
(200)
2020
3,632
98
17
113
(162)
350
—
(53)
3,995
3,208
444
(155)
17
62
(48)
3,528
(467)
58
(13)
(512)
(467)
OPEB Plans
2021
2020
789
35
2
19
(25)
(70)
—
(3)
747
391
48
(21)
2
22
(2)
440
(307)
55
(13)
(349)
(307)
712
32
2
22
(27)
62
(3)
(11)
789
343
55
(27)
2
28
(10)
391
(398)
8
(13)
(393)
(398)
(1) Amounts reflect projected benefit obligation for defined benefit pension plans and accumulated benefit obligation for OPEB plans.
(2) The accumulated benefit obligation, which excludes assumptions about future salary levels, for defined benefit pension plans was $3,586 million as at December 31, 2021 (2020 - $3,679
million).
For those defined benefit pension plans for which the projected benefit obligation exceeded the fair value of plan assets as at December 31, 2021, the
obligation was $2,188 million compared to plan assets of $1,799 million (2020 - $3,290 million and $2,777 million, respectively).
For those defined benefit pension plans for which the accumulated benefit obligation exceeded the fair value of plan assets as at December 31, 2021,
the obligation was $1,243 million compared to plan assets of $1,063 million (2020 - $3,037 million and $2,741 million, respectively).
For those OPEB plans for which the accumulated benefit obligation exceeded the fair value of plan assets as at December 31, 2021, the obligation was
$398 million compared to plan assets of $36 million (2020 - $589 million and $183 million, respectively).
Net Benefit Cost (1)
($ millions)
Service costs
Interest costs
Expected return on plan assets
Amortization of actuarial losses (gains)
Amortization of past service credits/plan amendments
Regulatory adjustments
Defined Benefit
Pension Plans
OPEB Plans
2021
109
98
(177)
36
(1)
(1)
64
2020
98
113
(176)
33
(1)
—
67
2021
35
19
(19)
(2)
(1)
3
35
2020
32
22
(19)
(5)
(2)
4
32
(1) The non-service benefit cost components of net periodic benefit cost are included in other income, net in the consolidated statements of earnings.
93 FORTIS INC.
2021 Annual Report
Notes to Consolidated Financial Statements
For the years ended December 31, 2021 and 2020
23. EMPLOYEE FUTURE BENEFITS (cont'd)
The following table summarizes the accumulated amounts of net benefit cost that have not yet been recognized in earnings or comprehensive
income and shows their classification on the consolidated balance sheets.
($ millions)
Unamortized net actuarial losses (gains)
Unamortized past service costs
Income tax recovery
Accumulated other comprehensive income
Net actuarial losses (gains)
Past service credits
Other regulatory deferrals
Regulatory assets (Note 8)
Regulatory liabilities (Note 8)
Net regulatory assets (liabilities)
Defined Benefit
Pension Plans
2021
33
1
(8)
26
260
(5)
10
265
376
(111)
265
2020
2021
2020
OPEB Plans
42
1
(10)
33
517
(7)
13
523
523
—
523
(5)
7
—
2
(81)
(6)
14
(73)
12
(85)
(73)
(1)
7
(1)
5
12
(8)
18
22
65
(43)
22
The following table summarizes the components of net benefit cost recognized in comprehensive income or as regulatory assets or liabilities.
($ millions)
Current year net actuarial (gains) losses
Amortization of actuarial losses
Income tax expense (recovery)
Total recognized in comprehensive income
Current year net actuarial (gains) losses
Past service credits/plan amendments
Amortization of actuarial (losses) gains
Amortization of past service credits
Foreign currency translation
Regulatory adjustments
Defined Benefit
Pension Plans
2021
(10)
1
2
(7)
(220)
—
(35)
2
(2)
(3)
Total recognized in regulatory (liabilities) assets
(258)
Significant Assumptions
(weighted average %)
Discount rate during the year (1)
Discount rate as at December 31
Expected long-term rate of return on plan assets (2)
Rate of compensation increase
Health care cost trend increase as at December 31 (3)
Defined Benefit
Pension Plans
2021
2.60
3.00
5.40
3.30
—
2020
2021
2020
OPEB Plans
9
1
(2)
8
69
—
(31)
2
(7)
(2)
31
2020
3.16
2.63
5.52
3.34
—
(4)
—
1
(3)
(95)
—
2
2
—
(4)
(95)
2021
2.60
2.97
4.88
—
4.49
OPEB Plans
1
—
—
1
25
(3)
5
3
—
(1)
29
2020
3.22
2.64
5.28
—
4.61
ITC and UNS Energy use the split discount rate methodology for determining current service and interest costs. All other subsidiaries use the single discount rate approach.
(1)
(2) Developed by management using best estimates of expected returns, volatilities and correlations for each class of asset. Best estimates are based on historical performance, future
expectations and periodic portfolio rebalancing among the diversified asset classes.
(3) The projected 2022 weighted average health care cost trend rate is 5.75% and is assumed to decrease over the next 11 years to the weighted average ultimate health care cost trend rate of
4.49% in 2032 and thereafter.
94 FORTIS INC.
2021 Annual Report
Notes to Consolidated Financial Statements
For the years ended December 31, 2021 and 2020
23. EMPLOYEE FUTURE BENEFITS (cont'd)
Expected Benefit Payments
($ millions)
2022
2023
2024
2025
2026
2027-2031
Defined Benefit
Pension Payments
$
168
172
176
181
189
1,019
$
OPEB
Payments
28
29
30
32
33
175
During 2022, the Corporation expects to contribute $49 million for defined benefit pension plans and $27 million for OPEB plans.
In 2021, the Corporation expensed $44 million (2020 - $42 million) related to defined contribution pension plans.
24. SUPPLEMENTARY CASH FLOW INFORMATION
($ millions)
Cash paid (received) for
Interest
Income taxes
Change in working capital
Accounts receivable and other current assets
Prepaid expenses
Inventories
Regulatory assets - current portion
Accounts payable and other current liabilities
Regulatory liabilities - current portion
Non-cash investing and financing activities
Accrued capital expenditures
Common share dividends reinvested
Contributions in aid of construction
2021
986
(13)
(88)
(15)
(56)
(99)
164
(50)
(144)
432
356
13
2020
1,027
(26)
(84)
(15)
(36)
(49)
(100)
(150)
(434)
400
114
13
25. FAIR VALUE OF FINANCIAL INSTRUMENTS AND RISK MANAGEMENT
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.
The Corporation records all derivatives at fair value, with certain exceptions including those derivatives that qualify for the normal purchase and
normal sale exception. Fair values reflect estimates based on current market information about the derivatives as at the balance sheet dates. The
estimates cannot be determined with precision as they involve uncertainties and matters of judgment and, therefore, may not be relevant in
predicting the Corporation's future consolidated earnings or cash flow.
Cash flow associated with the settlement of all derivatives is included in operating activities on the consolidated statements of cash flows.
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.
95 FORTIS INC.
2021 Annual Report
Notes to Consolidated Financial Statements
For the years ended December 31, 2021 and 2020
25. FAIR VALUE OF FINANCIAL INSTRUMENTS AND RISK MANAGEMENT (cont'd)
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.
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, 2021, unrealized losses of $20 million (2020 -
$73 million) were recognized as regulatory assets and unrealized gains of $52 million (2020 - $17 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 holds gas swap contracts to manage its exposure to changes in natural gas prices, capture natural gas price spreads, and manage the
financial risk posed by physical transactions. Fair values are 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 2021, unrealized gains of
$21 million (2020 - $3 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 $112 million and terms of one to three years expiring at varying dates
through January 2024. 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 2021, unrealized gains of $17 million (2020 - unrealized losses of
$9 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 November 2022 and have a combined notional amount of $161 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 2021,
unrealized losses of $11 million (2020 - unrealized gains of $11 million) were recognized in other income, net.
Interest Rate Swaps
In 2021, ITC entered into interest rate swaps with a total notional value of US$375 million to manage the interest rate risk associated with the
refinancing of long-term debt due in November 2022. The swaps have five-year terms, include mandatory early termination provisions, and will be
terminated no later than the effective date of November 15, 2022. Fair value was measured using a discounted cash flow method based on LIBOR
rates. Unrealized gains and losses associated with the changes in fair value are recognized in other comprehensive income, will be reclassified to
earnings as a component of interest expense over the life of the debt, and were not material for 2021.
Other Investments
ITC and Central Hudson hold investments in trust associated with supplemental retirement benefit plans for select employees. These investments
include mutual funds and money market accounts, which are recorded at fair value based on quoted market prices in active markets. Gains and losses
are recognized in other income, net. In 2021, unrealized gains of $9 million (2020 - $7 million) were recognized in other income, net.
96 FORTIS INC.
2021 Annual Report
Notes to Consolidated Financial Statements
For the years ended December 31, 2021 and 2020
25. FAIR VALUE OF FINANCIAL INSTRUMENTS AND RISK MANAGEMENT (cont'd)
Recurring Fair Value Measures
The following table presents derivative assets and liabilities that are accounted for at fair value on a recurring basis.
($ millions)
As at December 31, 2021
Assets
Energy contracts subject to regulatory deferral (2) (3)
Energy contracts not subject to regulatory deferral (2)
Foreign exchange contracts, total return and interest rate swaps (2)
Other investments (4)
Liabilities
Energy contracts subject to regulatory deferral (3) (5)
Energy contracts not subject to regulatory deferral (5)
As at December 31, 2020
Assets
Energy contracts subject to regulatory deferral (2) (3)
Energy contracts not subject to regulatory deferral (2)
Foreign exchange contracts and total return swaps (2)
Other investments (4)
Liabilities
Energy contracts subject to regulatory deferral (3) (5)
Energy contracts not subject to regulatory deferral (5)
Level 1 (1)
Level 2 (1)
Level 3 (1)
Total
—
—
23
137
160
—
—
—
—
—
16
126
142
—
—
—
78
16
2
—
96
(46)
(3)
(49)
38
6
—
—
44
(94)
(12)
(106)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
78
16
25
137
256
(46)
(3)
(49)
38
6
16
126
186
(94)
(12)
(106)
(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.
Included in accounts receivable and other current assets or other assets
(2)
(3) Unrealized gains and losses arising from changes in fair value of these contracts are deferred as a regulatory asset or liability for recovery from, or refund to, customers in future rates as
permitted by the regulators, with the exception of long-term wholesale trading contracts and certain gas swap contracts.
Included in other assets
Included in accounts payable and other current liabilities or other liabilities
(4)
(5)
Energy Contracts
The Corporation has elected gross presentation for its derivative contracts under master netting agreements and collateral positions, which apply only
to its energy contracts. The following table presents the potential offset of counterparty netting.
($ millions)
As at December 31, 2021
Derivative assets
Derivative liabilities
As at December 31, 2020
Derivative assets
Derivative liabilities
Gross Amount
Recognized In
Balance Sheet
Counterparty
Netting of
Energy Contracts
Cash Collateral
Received/Posted
Net Amount
94
(49)
44
(106)
25
(25)
26
(26)
7
—
10
(9)
62
(24)
8
(71)
97
FORTIS INC.
2021 Annual Report
Notes to Consolidated Financial Statements
For the years ended December 31, 2021 and 2020
25. FAIR VALUE OF FINANCIAL INSTRUMENTS AND RISK MANAGEMENT (cont'd)
Volume of Derivative Activity
As at December 31, 2021, the Corporation had various energy contracts that will settle on various dates through 2029. The volumes related to
electricity and natural gas derivatives are outlined below.
Energy contracts subject to regulatory deferral (1)
Electricity swap contracts (GWh)
Electricity power purchase contracts (GWh)
Gas swap contracts (PJ)
Gas supply contract premiums (PJ)
Energy contracts not subject to regulatory deferral (1)
Wholesale trading contracts (GWh)
Gas swap contracts (PJ)
(1) GWh means gigawatt hours and PJ means petajoules
Credit Risk
2021
509
731
151
144
1,886
29
2020
522
2,781
156
203
1,588
36
For cash equivalents, accounts receivable and other current assets, and long-term other receivables, credit risk is generally limited to the carrying
value on the consolidated balance sheets. The Corporation's subsidiaries generally have a large and diversified customer base, which minimizes the
concentration of credit risk. Policies in place to minimize credit risk include requiring customer deposits, prepayments and/or credit checks for certain
customers, performing disconnections and/or using third-party collection agencies for overdue accounts.
ITC has a concentration of credit risk as approximately 70% of its revenue is derived from three customers. The 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 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.
UNS Energy, Central Hudson, FortisBC Energy, Aitken Creek and the Corporation may be exposed to credit risk in the event of non‑performance by
counterparties to derivatives. Credit risk is managed by net settling payments, when possible, and dealing only with counterparties that have
investment-grade credit ratings. At UNS Energy and Central Hudson, certain contractual arrangements require counterparties to post collateral.
The value of derivatives in net liability positions under contracts with credit risk-related contingent features that, if triggered, could require the posting
of a like amount of collateral was $59 million as at December 31, 2021 (2020 - $88 million).
Hedge of Foreign Net Investments
The reporting currency of ITC, UNS Energy, Central Hudson, Caribbean Utilities, FortisTCI, Belize Electric Company Limited 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 has limited this exposure through hedging.
As at December 31, 2021, US$2.2 billion (2020 - US$2.3 billion) of corporately issued U.S. dollar-denominated long-term debt has been designated as
an effective hedge of net investments, leaving approximately US$10.8 billion (2020 - US$10.2 billion) unhedged. Exchange rate fluctuations associated
with the hedged net investment in foreign subsidiaries and the debt serving as the hedge are recognized in accumulated other comprehensive
income.
Financial Instruments Not Carried at Fair Value
Excluding long-term debt, the consolidated carrying value of the Corporation's remaining financial instruments approximates fair value, reflecting
their short-term maturity, normal trade credit terms and/or nature.
As at December 31, 2021, the carrying value of long-term debt, including current portion, was $25.5 billion (2020 - $24.5 billion) compared to an
estimated fair value of $28.8 billion (2020 - $29.1 billion).
98 FORTIS INC.
2021 Annual Report
Notes to Consolidated Financial Statements
For the years ended December 31, 2021 and 2020
26. COMMITMENTS AND CONTINGENCIES
As at December 31, 2021, unconditional minimum purchase obligations were as follows.
($ millions)
Waneta Expansion capacity agreement (1)
Gas and fuel purchase obligations (2)
Renewable PPAs (3)
Power purchase obligations (4)
ITC easement agreement (5)
Debt collection agreement (6)
Renewable energy credit purchase agreements (7)
Other (8)
Total
2,525
2,464
1,918
1,783
366
109
87
158
Year 1
Year 2
Year 3
Year 4
Year 5
Thereafter
53
787
122
288
13
3
17
66
54
446
122
254
13
3
16
7
55
252
122
194
13
3
11
7
56
169
122
184
13
3
8
6
58
121
122
185
13
3
6
4
2,249
689
1,308
678
301
94
29
68
9,410
1,349
915
657
561
512
5,416
(1) FortisBC Electric is a party to an agreement to purchase capacity from the Waneta Expansion hydroelectric generating facility for forty-years, beginning April 2015.
(2) FortisBC Energy ($1,686 million): includes contracts for the purchase of gas, renewable gas, gas transportation and storage services, expiring in 2062. FortisBC Energy's gas purchase
obligations are based on gas commodity indices that vary with market prices and the obligations are based on index prices as at December 31, 2021. The renewable gas supply
obligations disclosed reflect the contracted price per GJ between the Corporation and the suppliers.
UNS Energy ($670 million): includes long-term contracts for the purchase and delivery of coal to fuel generating facilities, the purchase of gas transportation services to meet load
requirements, the purchase of transmission services for purchased power, as well as natural gas commodity agreements based on projected market prices as of December 31,
2021. Amounts paid for coal depend on actual quantities purchased and delivered. Certain contracts have price adjustment clauses that will affect future costs. These contracts
have various expiry dates through 2040.
(3) TEP and UNS Electric are party to renewable PPAs, with expiry dates from 2027 through 2051, that require TEP and UNS Electric to purchase 100% of the output of certain
renewable energy generating facilities and RECs associated with the output delivered once commercial operation is achieved. Amounts are the estimated future payments.
(4) Maritime Electric ($815 million): includes an energy purchase agreement and transmission capacity contract for 30MW of capacity to PEI with New Brunswick Power, expiring
December 2026 and November 2032, respectively. The agreements entitle Maritime Electric to approximately 4.55% of the output of New Brunswick Power's Point Lepreau nuclear
generating station and require Maritime Electric to pay its share of the station's capital operating costs for the life of the unit.
FortisOntario ($544 million): an agreement with Hydro-Québec for the supply of up to 145 MW of capacity and a minimum of 537 GWh of associated energy annually through
December 2030.
FortisBC Electric ($276 million): includes an agreement with BC Hydro to purchase up to 200 MW of capacity and 1,752 GWh of associated energy annually for a 20-year term
beginning October 1, 2013.
UNS Energy ($118 million): an agreement with Salt River Project Agricultural Improvement and Power District to purchase up to 300 MW of capacity, power and ancillary services
through 2023. TEP will pay monthly capacity charges and variable power charges.
(5) ITC is party to an agreement with Consumers Energy, the primary customer of METC, which provides METC with an easement for transmission purposes and rights-of-way,
leasehold interests, fee interests and licenses associated with the land over which its transmission lines cross. The agreement expires in December 2050, subject to 10 potential 50-
year renewals thereafter unless METC gives notice of non-renewal at least one year in advance.
(6) Maritime Electric is party to a debt collection agreement with PEI Energy Corporation for the initial capital cost of the submarine cables and associated parts of the New Brunswick
transmission system interconnection. Payments under the agreement, which expires in February 2056, are collected in customer rates.
(7) UNS Energy and Central Hudson are party to renewable energy credit purchase agreements, mainly for the purchase of environmental attributions from retail customers with solar
installations or other renewable generation. Payments are primarily made at contractually agreed-upon intervals based on metered energy production.
(8)
Includes AROs and joint-use asset and shared service agreements.
Other Commitments
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.
99 FORTIS INC.
2021 Annual Report
Notes to Consolidated Financial Statements
For the years ended December 31, 2021 and 2020
26. COMMITMENTS AND CONTINGENCIES (cont'd)
Development projects at ITC may result in payments to developers that are contingent on the projects reaching certain milestones indicating that the
projects are financially viable. It is reasonably possible that ITC will be required to make these contingent development payments up to a maximum
amount of $88 million upon financial close of the projects. In the event it becomes probable that these payments will be made, the liability and the
corresponding intangible asset would be recognized.
UNS Energy has joint generation performance guarantees with participants at San Juan, Four Corners, and Luna, with agreements expiring in 2022
through 2046, and at 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 Navajo, participants would seek
financial recovery from the defaulting party. There is no maximum amount under these guarantees, except for a maximum of $318 million for Four
Corners. As at December 31, 2021, there was no obligation under these guarantees.
Central Hudson is a participant in an investment with other utilities to jointly develop, own and operate electric transmission projects in New York
State. Central Hudson's maximum commitment is $83 million, for which it has issued a parental guarantee. As at December 31, 2021, there was no
obligation under this guarantee.
As at December 31, 2021, FortisBC Holdings Inc. ("FHI") had $69 million of parental guarantees outstanding to support storage optimization activities
at Aitken Creek.
Contingency
In April 2013 FHI and Fortis were named as defendants in an action in the British Columbia Supreme Court by the Coldwater Indian Band ("Band")
regarding interests in a pipeline right-of-way on reserve lands. The pipeline was transferred by FHI (then Terasen Inc.) to Kinder Morgan Inc. in 2007.
The Band seeks cancellation of the right-of-way and damages for wrongful interference with the Band's use and enjoyment of reserve lands. In May
2016 the Federal Court dismissed the Band's application for judicial review of the ministerial consent. In September 2017 the Federal Court of Appeal
set aside the Minister's consent and returned the matter to the Minister for redetermination. No amount has been accrued as the outcome cannot yet
be reasonably determined.
100 FORTIS INC.
2021 Annual Report