ONE S T RONG COMPAN Y
T HROUGHOU T NORT H A MERICA
Newfoundland
& Labrador
Prince Edward
Island
Ontario
New York
British Columbia
Alberta
Minnesota
Iowa
Michigan
Illinois
Kansas
Missouri
Arizona
Oklahoma
Turks and
Caicos Islands
Cayman Islands
Belize
Regulated Electric
Regulated Gas
FERC-Regulated
Electric Transmission
Long-Term Contracted
Hydro Generation
Natural Gas Storage Facility
FORT IS HAS T HREE
DIS T INC T CHA R AC T ERIS T IC S
First, we are an energy delivery business.
Electricity poles, wires and natural gas lines comprise 93% of our total
assets. Our focus on energy delivery is foundational to Fortis. We invest in
transmission and distribution infrastructure to safely deliver energy from
cleaner sources to customers.
Second, we are diverse from a regulatory and
a geographic perspective.
Fortis is virtually 100% regulated and we operate in 17 jurisdictions.
We are one of the most geographically diverse utility businesses on the
continent, with each of our utilities operating under distinct regulatory
regimes. We touch nearly every corner of North America.
Third, our utility leadership is local.
Fortis utilities operate close to their customers and regulators. Our local
teams have the authority and independence to deliver what’s most
important in their communities. While our utilities operate separately,
together as a larger family of companies we drive operational excellence,
innovation and sustainability.
Together, these three defining characteristics form a company that:
• is flexible and responsive to customers;
• minimizes overall business risk;
• delivers financial scale and strategic direction while empowering our
utilities to innovate and grow; and,
• creates a durable competitive advantage that supports the growth
of long-term shareholder value.
1
REPORT TO SHAREHOLDERS FOR T IS QUICK FACT S
10
UTILITY
OPERATIONS
in Canada, the U.S. and
the Caribbean
1.3
MILLION
gas utility customers
EMPLOYEES STRONG
9,000
$53
2
MILLION
BILLION
in total assets
electric utility customers
$25
BILLION
market cap
(as of December 31, 2019)
46
CONSECUTIVE YEARS
of dividend payment increases
Based in
ST. JOHN’S
Newfoundland & Labrador
T S X / N Y SE: F T S
Unless otherwise specified, all financial
information is referenced in Canadian dollars.
The key to a successful year is making careful decisions every day.
Choices that make sense – not just for now, but for the future.
At Fortis, tomorrow is our responsibility today.
REP ORT TO S H A REHOL DER S
At Fortis we leverage the experience of our group of utilities
to improve service for our customers, deliver superior financial
performance for our shareholders and drive sustainability for the
communities we serve. Our industry is evolving rapidly and our
utilities are finding innovative ways to ensure they deliver cleaner
energy to customers in a safe, reliable and affordable manner.
The strong operational and financial performance of your
company in 2019 is evidence that our strategy is working.
A N INDU S T RY L E A DE R IN S A F E T Y, RE L I A BIL I T Y A ND S ECURI T Y
Fortis continues to outperform industry averages
for safety and reliability. The all-injury frequency
rate (“AIFR”) is an indicator of safety performance
and represents the number of injuries for every
200,000 hours worked. In 2019 the Fortis AIFR was
1.45, while the Canadian and U.S. comparable industry
average rates were 1.59 and 1.78, respectively.
Our culture of safety is embedded in our operations
and we consistently seek opportunities to improve.
Fortis utilities regularly develop and share best
practices with each other to support a healthy and
safe workplace.
Fortis measures electricity reliability and uses
the average hours of interruption per customer
served as an indicator of performance. In 2019 the
average at Fortis was 1.84 hours, outperforming
the Canadian and U.S. combined industry average
of 3.65 hours.
Fortis has developed a cybersecurity strategy
based on the fundamental pillars of a cyber risk
management program, increased information
sharing and building an enhanced culture of security.
The program mirrors the structure of our enterprise
risk management framework and focuses on key
risks including: asset and identity management,
threat and vulnerability analysis, situational awareness,
information sharing, incident response, and supply
chain and insider threats. Through board and
management oversight, this strategy results in
effective enterprise risk management and protects
customers and stakeholders.
A L L- I NJ U RY FR EQ U E N CY R ATE (1)
ELECTRICIT Y CUSTO M ER
E L ECTR I C IT Y CU STO M E R
AV E R AG E O UTAG E D U R ATI O N (2)
AVERAG E OUTAG E DU RATIO N
2 . 0
1 . 0
0
2 0 1 5
2 0 1 6
2 0 1 7
2 0 1 8
2 0 1 9
Fortis
U.S. Bureau of Labor Statistics Average
(for the period 2015-2018)
Canadian Electricity Association Average
(for the period 2015-2018)
(1) Injuries per 200,000 hours worked
4
1 .7 8
1 . 59
H O U R S
5 . 0
4 . 0
3 . 0
2 . 0
1 . 0
0
2 0 1 5
2 0 1 6
2 0 1 7
2 0 1 8
20 1 9
Fortis
Canadian Electricity Association & U.S. Energy
Information Administration Average(3)
(2) Based on weighted average of Fortis’ customer count in each jurisdiction
(3) 2019 industry comparator will be available later in 2020.
FORTIS INC. 2019 ANNUAL REPORT S T RONG F IN A NCI A L P E RFORM A NCE
In 2019 net earnings attributable to common equity
shareholders were $1,655 million, or $3.79 per
common share, compared to $1,100 million,
or $2.59 per common share, for 2018. We achieved
adjusted net earnings of $1,115 million, or $2.55 per
common share, in 2019 compared to $1,066 million,
or $2.51 per common share in 2018.
We delivered a one-year total shareholder return
of 22.7% in 2019. Over a 20-year period, Fortis has
delivered a total shareholder return of 1,363%
and an average annualized total return of 14.3%.
In comparison, over the same 20-year period,
the S&P/TSX Composite and S&P/TSX Capped
Utilities indices delivered total returns of 237%
and 729%, respectively. Very few other companies
have consistently delivered such strong performance
for shareholders.
Our 6.1% quarterly dividend increase on
December 1, 2019 to $0.4775 per share, or $1.91
on an annualized basis, marked 46 consecutive
years of annual common share dividend payment
increases. This is one of the longest records for
annual common share dividend increases by a
Canadian public corporation.
With a strong foundation and confidence in future
opportunities, we extended our 6% average annual
dividend growth guidance to 2024.
S U PE R I O R 2 0 -Y E AR TOTAL S HAR E H O L D E R R E TU R N
Fortis
S&P/TSX Capped Utilities Index
S&P/TSX Composite Index
Fortis Total
Shareholder Returns
(Average Annual)
Note: Cumulative 20-year total shareholder return as at December 31, 2019
5
REPORT TO SHAREHOLDERS 6 % AV E R A GE A NNU A L D I V ID E ND
GROW TH GUIDANCE E XTENDED TO 2024
46 YEARS O F CO N SECUTIVE D IVI D EN D I N CREASES
Dividend Payments
Forecast Dividend Payments
$2.50
$2.00
$1.50
$1.00
$0.50
MORE F IN A NCI A L F L E X IBIL I T Y
We greatly enhanced our financial flexibility
in 2019.
net proceeds to repay debt, including short-term
borrowings and US$400 million of long-term debt.
First, we sold our interest in the Waneta Expansion
Hydroelectric Project in British Columbia for
approximately $1 billion. We recognized a gain on
the sale of approximately $0.5 billion and used the
Second, Fortis issued $1.2 billion of common shares
late in 2019, the net proceeds of which were used
to repay debt, including short-term borrowings and
US$500 million of long-term debt.
6
FORTIS INC. 2019 ANNUAL REPORT
REC ORD CA P I TA L IN V E S T ME N T S
Our largest utility, ITC Holdings Corp., advanced
work on several significant transmission projects,
including completion of a new 174-kilometre
transmission line to facilitate the integration of
wind energy for use by electricity customers across
the U.S. Midwest.
At Tucson Electric Power (“TEP”), the first
five of ten reciprocating internal combustion
engine generators began operation in 2019.
The remaining generators are scheduled to come
online in early 2020. The 192 megawatts (“MW”)
of efficient fast-ramping natural gas generation
will support the expansion of TEP’s wind and
solar energy resources while providing safe,
reliable and affordable service for customers.
WE DE P L OY E D REC ORD
CA P I TA L E X P E NDI T URE S
OF $ 3.8 BIL L ION IN 2019.
ITC Holdings Corp.
7
REPORT TO SHAREHOLDERS 2019 marked another year of important milestones
for the Wataynikaneyap Transmission Power
Project in Northwestern Ontario. This project
is 51% owned by our First Nations partners
and will see the construction of approximately
1,800 kilometres of transmission lines to connect
17 remote First Nations communities to the
Ontario power grid for the first time.
Tucson Electric Power employees
8
The engineering, procurement and construction
contract was awarded, the project achieved financial
close and the Notice to Proceed was issued.
In addition, Wataynikaneyap Power celebrated
the graduation of the fourth round of Line Crew
Ground Support Training. The 15-week certificate
program prepares Indigenous students for
employment opportunities with the Wataynikaneyap
Transmission Power Project.
The Fortis $18.8 billion five-year capital plan
for the period 2020 to 2024 is driven by grid
modernization, delivering cleaner energy to
customers, electrification, and the expansion
of our natural gas operations at FortisBC. Over
the past five years, our midyear utility rate base has
grown to $28 billion, representing average annual
growth of 7%, excluding utility acquisitions.
Over the next five years we expect similar growth,
with midyear rate base to increase by about
$10 billion to over $38 billion by 2024.
FortisBC is poised to be our fastest-growing
Canadian utility in the coming years. The utility
has more than one million natural gas customers
and is the largest distributor of natural gas in
British Columbia. It has earmarked $1.1 billion in its
five-year capital plan for major integrity projects,
including two significant system upgrades to its
natural gas infrastructure. The utility also plans to
spend $100 million on renewable gas projects and to
encourage the use of natural gas for transportation.
FORTIS INC. 2019 ANNUAL REPORT T HROUGHOU T OUR GROUP OF U T IL I T IE S ,
OUR T E A MS A RE C OL L EC T I V E LY AC CE L E R AT ING
T HE PACE OF INNOVAT ION.
Throughout our group of utilities, our teams are
collectively accelerating the pace of innovation.
Our investment in Energy Impact Partners (“EIP”)
is one of the ways we are embracing new ideas
and leading the way in our sector. EIP is a sizeable
strategic investment fund that brings together
a global coalition of utilities and emerging
technology companies that are shaping the
future of our industry. Through EIP, we have
access to the latest innovations, positioning us
to better serve customers.
We have leveraged the EIP relationship across
our family of utilities. As an example, Maritime
Electric, our utility in Prince Edward Island,
is collaborating with Urbint, an emerging
technology company identified through EIP.
They are using artificial intelligence to prioritize
the replacement of higher-risk electricity
poles, creating efficiencies and improving
safety and reliability.
FortisBC supplies the marine industry with natural gas.
9
REPORT TO SHAREHOLDERS RE DUCING CA RB ON E MIS S IONS
At Fortis, sustainability and reducing our carbon
footprint are at the forefront of everything we do.
Our assets primarily consist of electricity poles,
wires and natural gas lines. We own a small amount
of fossil fuel-based generation, limiting our impact
on the environment. We remain focused on a cleaner
energy future through delivery of more renewable
energy to our customers. The generation owned
by Fortis is primarily within the operations of TEP.
The utility is taking great strides in reducing its carbon
intensity and recently announced the construction
of the 250 MW Oso Grande Wind Project, which will
become TEP’s largest renewable energy resource.
In 2021 TEP will have enough renewable energy
resources on its system to supply nearly 30% of its
retail sales – almost a decade ahead of its 2030 goal.
Our team in Arizona is not stopping there. TEP is now
collaborating with the University of Arizona and the
local community to set new carbon emission reduction
goals in line with the Paris Agreement on climate
change. TEP’s coal-based generation now represents
less than 5% of the total rate base of all Fortis utilities,
far less than many other utilities in our sector.
FortisBC has set a goal to reduce greenhouse gas
emissions associated with customers’ energy use
by 30% by the year 2030. To achieve this objective,
FortisBC will triple investment in energy efficiency
projects, increase renewable gas supply, and focus
on low and zero-carbon vehicles and transportation
infrastructure. The utility is targeting to have 15%
of its gas supply from renewable sources by 2030,
and recently participated at the United Nations
Climate Change Conference as part of the
Canadian delegation.
ITC sets the standard for how an energy delivery
company can combat climate change. ITC is a
large transmission company and a central player
in the shift to renewables that is occurring in
the U.S. The utility has already connected over
6,800 MW of wind energy and over the next
five years expects to connect another 2,000 MW
of wind and 600 MW of solar energy across
its footprint.
I N 2 0 2 1 T U C S O N E L E C T R I C P O W E R W I L L H AV E
E N O U G H R E N E WA B L E E N E R G Y R E S O U R C E S O N I T S
S Y S T E M T O S U P P LY N E A R LY 3 0 % O F I T S R E TA I L
SALES – ALMOST A DECADE AHEAD OF ITS 2030 GOAL.
The increased use of renewable energy is driving
innovation and growth. At Fortis we remain steadfast
in our commitment to reducing our carbon footprint
as we realize the full potential of the cleaner energy
transformation that is taking place.
In 2019 we expanded our sustainability disclosure
and reported new indicators related to employees,
natural gas operations and water use. We also
provided information on our efforts to support
the United Nations Sustainable Development Goals.
Fortis is recognized as a leader in sustainability and
was named one of the Best 50 Corporate Citizens
in Canada by Corporate Knights, an organization
dedicated to encouraging responsible business
practices. Additionally, Fortis ranked number one
in terms of having the largest three-year carbon
emissions reduction and 24th overall out of 242
companies surveyed.
As well, Fortis received an upgraded rating of AA
from MSCI, a leading environmental, social and
corporate governance (“ESG”) advisory group that
rates a company’s ability to manage ESG risks relative
to its peers. The current AA rating is up three levels
from the company’s initial rating of BB in 2015.
INCL U S ION A ND DI V E R S I T Y
There was a purposeful effort in 2019 to advance
inclusion and diversity across the entire Fortis group
of companies. We believe in employees feeling
comfortable coming to work and doing their jobs,
free from any form of judgment. When people can
be their authentic selves they are happier, and that
allows them to reach their full potential. An inclusion
and diversity framework was finalized and CEOs at
all Fortis companies signed a declaration committing
to inclusion and diversity efforts.
head office, 42% of our directors elected in 2019
and approximately one-third of executives throughout
the Fortis group of companies.
An area we have focused on in recent years is gender
diversity. Females represent 60% of employees at
Work on our inclusion and diversity efforts will
continue in 2020 and beyond.
FortisAlberta employees showing their support for inclusion and diversity.
1 2
FORTIS INC. 2019 ANNUAL REPORT OUR C OMMUNI T Y ROOT S RUN DE E P
Our decentralized model supports Fortis utilities
being heavily involved in their local communities.
They are leaders in the communities in which they
operate, with their efforts focused on the areas most
needed in their local communities. Total community
investments attributed to Fortis and our utilities in
2019 were more than $12 million.
A great example of community support comes from our
utility Central Hudson Gas & Electric, which provided
nearly $900,000 to fund community initiatives in 2019.
Activities included an employee-led campaign for
the local agencies of the United Way and sponsorship
of community events that support non-profit
programs and promote the local economy. During
the past decade, Central Hudson has contributed
approximately $10 million to local community groups.
Central Hudson employees pull a Boeing 757 12 feet in 10.36 seconds at New York
Stewart International Airport. The Pull the Plane competition, hosted by the
United Way of the Dutchess-Orange Region, raised approximately US$50,000.
E X ECU T I V E T E A M CH A NGE S
Over the past several years, Fortis and our utilities have
placed significant focus on talent management and
the development of our leadership team, and 2019
was no exception. During the year we broadened the
responsibilities of the following executives.
James P. Laurito’s role was expanded to Executive
Vice President, Business Development and Chief
Technology Officer. Jim has extensive knowledge of
the North American utility business, including the latest
technology and innovation trends and opportunities.
Jim assumed responsibility for technology after the
retirement of Phonse J. Delaney as Executive Vice
President, Chief Information Officer. Phonse’s career
with the Fortis group of companies spanned more than
30 years and included his role as President and Chief
Executive Officer of FortisAlberta. We thank Phonse
for his expertise and we wish him well in retirement.
David G. Hutchens’ role was also expanded with his
appointment as Chief Operating Officer. He was previously
Executive Vice President, Western Utility Operations.
In this newly created role, Dave’s responsibilities have
been broadened to include operational oversight of
our 10 utilities across Canada, the United States and
the Caribbean as we execute on our large capital plan.
He also continues to serve as Chief Executive Officer
of UNS Energy Corporation in Arizona.
Remembering Ida J. Goodreau
We are deeply saddened by the passing of Ida J. Goodreau
in 2019. Ida served as Chair of the Governance and
Nominating Committee of the Fortis Board of Directors
and Chair of the Board of Directors of FortisBC. She was an
international business leader, a mentor and a cherished
colleague who provided years of thoughtful leadership
to Fortis. She is greatly missed by the Fortis family.
1 3
REPORT TO SHAREHOLDERS P O S I T IONE D FOR F U T URE S UC CE S S
Thank you to our 9,000 employees for continuing to
work safely and for delivering exceptional service
to our customers. The success of Fortis is the result
of your hard work.
We also thank our shareholders for your continued
support. We will continue to be a champion of progress,
realizing the full potential of the move to cleaner
energy while remaining steadfast in our commitment
to deliver safe, reliable and secure energy.
We believe Fortis is getting stronger. We are thinking
long term as we drive your company forward, ensuring
a successful Fortis for years to come.
On behalf of the Board of Directors,
Douglas J. Haughey
Chair of the Board
Fortis Inc.
Barry V. Perry
President and CEO
Fortis Inc.
Left to right: Douglas Haughey, Chair of the Board, and Barry Perry,
President and CEO
1 5
REPORT TO SHAREHOLDERS F IN A NCI A L HIGHL IGH T S
(1) Results were impacted by a full-year’s contribution from UNS Energy, completion of the Waneta Expansion and gains on the sale of non-core assets. Adjusted net earnings
exclude the gains on sale of non-core assets and other non-operating items.
(2) Results were impacted by accretion associated with the acquisition of ITC in October 2016 and Aitken Creek in April 2016, as well as associated acquisition-related costs.
Adjusted net earnings exclude acquisition-related costs and other non-operating items.
(3) Results were impacted by a full-year’s contribution from ITC and Aitken Creek. Adjusted net earnings exclude the impact of U.S. tax reform and other non-operating items.
(4) Results were tempered by the ongoing impact of U.S. tax reform and a reduced independence incentive adder at ITC. Adjusted net earnings exclude certain
non-operating items.
(5) Results were impacted by a gain on disposition of the Waneta Expansion and a favourable adjustment associated with a regulatory order at ITC. Adjusted net earnings
exclude the gain on disposition, the favourable regulatory adjustment and other non-operating items.
(6) Non-GAAP measure
All financial information is presented in Canadian dollars. Information is for the fiscal years ended December 31.
1 6
FORTIS INC. 2019 ANNUAL REPORT HIGHLY REGUL AT E D, L OW-RIS K A ND DI V E R S IF IE D U T IL I T Y B U S INE S S
RE G UL A TED
CUSTOMERS
PEAK DEMAND
ELECTRIC
GAS
TOTAL
MIDYEAR CAPITAL
ELECTRIC
(#)
GAS
(#)
EMPLOYEES
(#)
ELECTRIC
(MW)
GAS
(TJ)
SALES
(GWh)
VOLUMES
(PJ)
EARNINGS
($M)
ASSETS
($B)
RATE BASE
($B)
PROGRAM
($M)
2 020F (1)
ITC (2)
–
–
707
22,815
–
–
UNS Energy
526,000
160,000
2,103
3,179
118
18,354
Central Hudson
300,000
80,000
1,065
1,1 09
148
4,963
–
16
22
85
471
19.8
9.5
976
292
10.2
5.8
1,390
FortisBC (3)
179,000
1,041,000
2,411
696
1,352
3,326
227
219
FortisAlberta
568,000
Other Electric (4)
463,000
–
–
1,1 11
2,642
1,453
2,138
–
–
16,887
9,366
–
–
131
106
3.7
9.6
4.8
4.2
2.1
292
6.4
648
3.7
3.2
436
566
2,036,000
1,281,000
8,850
32,579
1,618
52,896
265
1,304
52.3
30.7
4,308
(1) Forecast
(2) Data reflects 100% of ITC’s operations except for earnings, which represent the Corporation’s 80.1% ownership interest. ITC has no retail customers.
(3) Includes FortisBC Energy and FortisBC Electric.
(4) Data reflects 100% of Caribbean Utilities’ operations except earnings, which represent the Corporation’s 60% ownership interest. Also includes Newfoundland Power,
Maritime Electric, FortisOntario, a 39% equity investment in Wataynikaneyap Power Limited Partnership, Fortis Turks and Caicos, and a 33% equity investment
in Belize Electricity.
99% REGULATED UTILITIES
Electric
82%
ASSETS
(1) Comprising of investments in British Columbia and Belize.
Gas
17%
Non-Regulated
Energy Infrastructure (1)
1%
TOTA L A S S E T S OF $ 53 BIL L ION
A S OF DECE MBE R 3 1, 2019
1 7
REPORT TO SHAREHOLDERS Management Discussion and Analysis
Dated February 12, 2020
This MD&A has been prepared
in accordance with National
Instrument 51-102 – Continuous Disclosure Obligations. It should be
read in conjunction with the 2019 Annual Financial Statements
is subject to the cautionary statement and disclaimer
and
provided under “Forward-Looking
Information” on page 58.
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
US GAAP (except for indicated Non-US GAAP Financial Measures)
and, unless otherwise specified, is presented in Canadian dollars
based, as applicable, on the following US-to-Canadian dollar
exchange rates: (i) average of 1.33 and 1.30 for the years ended
December 31, 2019 and 2018, respectively; (ii) 1.30 and 1.36 as at
December 31, 2019 and 2018, respectively; and (iii) 1.32 for all
forecast periods. Certain terms used in this MD&A are defined in
the “Glossary” on page 59.
ABOUT FORTIS
Fortis (TSX/NYSE: FTS) is
a well-diversified
leader
in the North American
regulated electric and
gas utility industry, with
revenue of $8.8 billion and
total assets of $53 billion
as at December 31, 2019.
Regulated utilities account
for 99% of the Corporation’s
assets with the remainder
primarily attributable to non-
regulated energy infrastructure.
The Corporation’s 9,000
employees serve 3.3 million
utility customers in five Canadian provinces, nine US states and
three Caribbean countries. As at December 31, 2019, 66% of the
Corporation’s assets were located outside Canada and 60% of 2019
revenue was derived from foreign operations.
Jocelyn Perry, EVP, CFO, Fortis
Contents
About Fortis ....................................................................................................................... 18
Significant Items.............................................................................................................. 20
Performance at a Glance ........................................................................................... 20
The Industry ....................................................................................................................... 23
Operating Results ........................................................................................................... 24
Business Unit Performance ...................................................................................... 25
ITC ...................................................................................................................................... 25
UNS Energy .................................................................................................................. 26
Central Hudson ......................................................................................................... 26
FortisBC Energy ......................................................................................................... 27
FortisAlberta ................................................................................................................ 27
FortisBC Electric ........................................................................................................ 28
Other Electric .............................................................................................................. 28
Energy Infrastructure ............................................................................................. 28
Corporate and Other ............................................................................................. 29
Non-US GAAP Financial Measures ....................................................................... 29
Regulatory Highlights .................................................................................................. 30
Financial Position ............................................................................................................ 32
Liquidity and Capital Resources ............................................................................ 33
Cash Flow Requirements .................................................................................... 33
Cash Flow Summary .............................................................................................. 34
Contractual Obligations....................................................................................... 36
Capital Structure and Credit Ratings ........................................................... 36
Capital Plan .................................................................................................................. 37
Business Risks .................................................................................................................... 40
Accounting Matters ...................................................................................................... 48
Financial Instruments ................................................................................................... 51
Long-term Debt and Other ............................................................................... 51
Derivatives .................................................................................................................... 52
Selected Annual Financial Information ............................................................ 54
Fourth Quarter Results ................................................................................................ 55
Summary of Quarterly Results ............................................................................... 56
Related-Party Transactions........................................................................................ 57
Management’s Evaluation of Controls and Procedures ......................... 57
Outlook ................................................................................................................................. 58
Forward-Looking Information ................................................................................ 58
Glossary ................................................................................................................................ 59
Condensed Consolidated Financial Statements ........................................ 61
18
FORTIS INC. 2019 ANNUAL REPORT
Total Assets at December 31, 2019
Gas
17%
Non-Regulated
Energy
Infrastructure
1%
US
63%
Canada
34%
Caribbean
3%
Electric
82%
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. 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); 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 is comprised of Aitken Creek (natural gas storage facility – British Columbia), BECOL (three hydroelectric
generation facilities – Belize) and the Waneta Expansion up to its disposition in April 2019 (see “Significant Items” on page 20).
Fortis has a unique operating model with a small head 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 most have a board of directors with a majority of independent
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 using sustainable practices while delivering long-term
profitable growth to shareholders. Management is focused on achieving growth through the execution of the consolidated capital plan and
the pursuit of additional investment opportunities within and proximate to existing service territories (see “Capital Plan” on page 37).
Additional information about the Corporation’s business and reporting units is provided in Note 1 in the 2019 Annual Financial Statements.
19
FORTIS INC. 2019 ANNUAL REPORTManagement Discussion and Analysis SIGNIFICANT ITEMS
Disposition
On April 16, 2019, Fortis sold its 51% ownership interest in the 335-MW Waneta Expansion for proceeds of $995 million. A gain on disposition
of $577 million ($484 million after tax), net of expenses, was recognized in the Corporate and Other segment.
Fortis used the net proceeds to repay credit facility borrowings and repurchase, via a tender offer, US$400 million of its outstanding 3.055%
unsecured senior notes due in 2026. The reduced earnings from the Waneta Expansion were offset by lower finance charges and a gain on
repayment of the 3.055% notes.
Common Equity Offering
In the fourth quarter of 2019, the Corporation issued approximately 22.8 million common shares at a price of $52.15 per share for gross
proceeds of $1,190 million ($1,167 million net of commissions). The net proceeds were used to redeem US$500 million of its outstanding
2.10% unsecured senior notes due October 4, 2021, to repay credit facility borrowings and for general corporate purposes.
November 2019 FERC Order
In November 2019 FERC issued an order reducing the base ROE for ITC’s MISO Subsidiaries to 9.88%, up to a maximum of 12.24% with
incentive adders. Including incentive adders, this implies an all-in ROE for ITC’s MISO Subsidiaries of 10.63% compared to the previous all-in
ROE of 11.07%. The net impact was a $63 million increase in earnings, comprised of $83 million related to the net reversal of liabilities
established in prior periods, partially offset by $20 million related to the 2019 impact of the reduced ROE. See “Regulatory Highlights” on
page 30 for further information.
PERFORMANCE AT A GLANCE
Key Financial Metrics
($ 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) See “Non-US GAAP Financial Measures” on page 29
TSR (1) (%)
Fortis
1-Year
22.7
(1) Total annualized shareholder return per Bloomberg, as at December 31, 2019
Earnings and EPS
2019
1,655
1,115
3.79
2.55
1.8275
48.2
71.7
436.8
2,663
3,818
5-Year
10.8
2018
1,100
1,066
2.59
2.51
1.7250
66.6
68.7
424.7
2,604
3,218
10-Year
10.6
Variance
555
49
1.20
0.04
0.1025
(18.4)
3.0
12.1
59
600
20-Year
14.3
The $555 million increase in Common Equity Earnings reflects significant one-time items, Rate Base growth driven by the Corporation’s
capital plan at the regulated utilities and favourable foreign exchange, partially offset by the impact of weather in Belize and Arizona,
regulatory decisions at ITC and one-time positive tax adjustments primarily recognized in 2018.
The significant one-time items were a $484 million gain on the disposition of the Waneta Expansion and an $83 million favourable adjustment
resulting from the November 2019 FERC Order (see “Regulatory Highlights” on page 30), which resulted in the 2019 net reversal of liabilities
established in prior years.
20
FORTIS INC. 2019 ANNUAL REPORTManagement Discussion and Analysis
The regulated utilities delivered positive financial results reflecting Rate Base growth, driven by ITC, lower operating expenses, primarily at
FortisAlberta, and favourable foreign exchange. This growth was tempered by: (i) a lower ROE at ITC due to the November 2019 FERC Order
and lower ROE incentive adders effective April 2018; (ii) lower earnings contribution from UNS Energy due to lower retail sales, driven by
cooler weather, and higher costs associated with Rate Base growth not yet reflected in rates; and (iii) lower earnings contribution from
the Energy Infrastructure segment due to lower hydroelectric production in Belize and lower realized margins at Aitken Creek.
The one-time positive tax adjustments recognized in 2018 related to an election to file a consolidated state tax return and the designation
of net assets related to the Waneta Expansion as held for sale totalling $30 million and $14 million, respectively. In addition, the finalization
of US tax reform regulations associated with base-erosion and anti-abuse tax resulted in the recognition of income tax expense of
$12 million in 2019.
Finally, a 12.1 million increase in the weighted average number of common shares outstanding associated with the Corporation’s
(i) $1.2 billion common equity issuance in the fourth quarter of 2019 (see “Significant Items” on page 20), (ii) ATM Program, and (iii) DRIP and
share purchase plan, resulted in a $0.07 decrease in basic EPS.
Adjusted Common Equity Earnings and Adjusted Basic EPS increased by $49 million and $0.04, respectively. Refer to “Non-US GAAP Financial
Measures” on page 29 for a reconciliation of these measures. The change in Adjusted Basic EPS is illustrated in the chart below.
2019 Adjusted EPS Drivers
$0.04
$0.04
$0.02
$0.05
$2.51
$(0.06)
$(0.02)
$2.55
$(0.03)
2018
Actual
Adjusted
EPS
Western
Canadian
Electric &
Gas (1)
ITC
(2)
Central
Hudson
(3)
Foreign
Exchange
(4)
Energy
Infrastructure
(5)
UNS
Energy
(6)
Corporate
and Other
(7)
2019
Actual
Adjusted
EPS
(1) Includes FortisBC Energy, FortisBC Electric and FortisAlberta. Driven primarily by Rate Base growth and lower operating expenses
(2) Driven by Rate Base growth, partially offset by a lower 2019 ROE due to the November 2019 FERC Order
(3) Driven by Rate Base growth
(4) Average FX of $1.33 for 2019 compared to $1.30 for 2018
(5) Driven primarily by reduced hydroelectric production at Belize due to lower rainfall
(6) Driven primarily by higher costs associated with Rate Base growth not yet reflected in customer rates and lower retail sales due mainly to unfavourable weather
(7) Weighted average shares of 436.8 million in 2019 compared to 424.7 million in 2018, partially offset by favourable foreign exchange contracts and higher income tax recoveries
21
FORTIS INC. 2019 ANNUAL REPORTManagement Discussion and Analysis Dividends and TSR
Fortis paid a dividend of $0.4775 per common share in the fourth quarter of 2019, up from $0.45 paid in each of the previous four quarters.
The total 2019 dividend paid per common share was $1.8275, up $0.1025 or nearly 6.0% from 2018 and in line with the Corporation’s dividend
guidance. The Actual Payout Ratio was 48.2% in 2019 compared to 66.6% in 2018 and an annual average of 61.4% over the five-year period
of 2015 through 2019. The decrease in the 2019 Actual Payout Ratio was driven by the gain on disposition of the Waneta Expansion (see
“Significant Items” on page 20).
Fortis has increased its common share dividend for 46 consecutive years. Growth of dividends and the market price of the Corporation’s
common shares have together yielded a 1-year, 5-year, 10-year and 20-year TSR of 22.7%, 10.8%, 10.6% and 14.3%, respectively.
In September 2019 Fortis extended its targeted average annual dividend per common share growth of approximately 6% through 2024.
46 Years of Common Share Dividend Increases
73
74
75
76
77
78
79
80
81
82
83
84
85
86
87
88
89
90
91
92
93
94
95
96
97
98
99
00
01
02
03
04
05
06
07
08
09
10
11
12
13
14
15
16
17
18
19
Dividend Payments
Operating Cash Flow
The $59 million increase was due to higher cash earnings, driven by Rate Base growth at the regulated utilities, led by ITC. The increase was
partially offset by: (i) unfavourable changes due to the normal operation of long-term regulatory deferrals at ITC; (ii) unfavourable changes
in working capital, due primarily to timing differences, partially offset by income tax refunds received in 2019; and (iii) lower cash earnings
from the Energy Infrastructure segment (see “Business Unit Performance – Energy Infrastructure” on page 28).
Capital Expenditures
Capital expenditures in 2019 were $3.8 billion, $0.6 billion higher than in 2018 and $0.5 billion lower than forecast in the Q3 2019 MD&A.
The $0.6 billion increase over the prior year was driven by higher spending at the US regulated utilities. The $0.5 billion decrease from forecast
was due to: (i) a $0.3 billion delayed payment related to the construction of the Oso Grande Wind Project as the performance obligations
were not fulfilled until January 2020; (ii) a revised forecast and timeline related to the Southline Transmission Project resulting in $0.1 billion
being deferred until 2021; and (iii) revisions to various smaller projects resulting in $0.1 billion being deferred until 2021. See “Capital Plan”
on page 37 for further information.
The Corporation’s five-year 2020–2024 capital plan is targeted at $18.8 billion, approximately $0.5 billion higher than the $18.3 billion capital
plan disclosed in the Q3 2019 MD&A. The increase reflects the shift in spending that was originally planned for December 2019 but was made
in January 2020 related to UNS Energy’s Oso Grande Wind Project, as well as the timing of other spend that shifted to 2021.
Funding of the capital plan is expected to be primarily through Operating Cash Flow, utility debt and common equity from the
Corporation’s DRIP.
The five-year capital plan is expected to increase midyear Rate Base from $28.0 billion in 2019 to $34.5 billion by 2022 and $38.4 billion
by 2024, representing three- and five-year CAGRs of 7.2% and 6.5%, respectively. These CAGRs are supportive of continuing growth in
earnings and dividends.
22
FORTIS INC. 2019 ANNUAL REPORTManagement Discussion and Analysis Projected Rate Base Growth
$32.5
$34.5
$36.8
$38.4
$28.0
$30.7
s
n
o
i
l
l
i
B
$
2019A
2020F
2021F
2022F
2023F
2024F
Canadian and Caribbean
US
Beyond the base capital plan, Fortis continues to pursue additional energy infrastructure opportunities. Key opportunities not yet included
in the five-year capital plan include: further expansion of liquefied natural gas infrastructure in British Columbia; the fully permitted,
cross-border, Lake Erie connector electric transmission project in Ontario; and the acceleration of cleaner energy goals in Arizona.
THE INDUSTRY
The North American energy industry continues to transform. There is a heightened focus on the impacts of climate change and the need for
cleaner energy and energy conservation initiatives to preserve the environment for future generations. The effects of climate change,
coupled with technological advancements, have rapidly shifted customer expectations for cleaner energy. The trend toward renewables and
natural gas as a key part of the energy mix, as well as the increasing affordability of cleaner energy, is driving opportunity in the utility sector.
Changing energy policies at the federal, state and provincial levels are creating volatility in certain jurisdictions by introducing uncertainty
around environmental, tax and trade regulation. The regulatory and compliance operating environment is also evolving and becoming
increasingly complex. These changes are creating additional opportunities to expand investment in new generation sources, including
natural gas, solar and wind, as well as infrastructure to interconnect renewable energy sources to the grid. Investment opportunities in
storage are also growing with the proliferation of variable renewable generation sources and decreasing costs of storage technology. The
Corporation’s utilities are well positioned and actively involved in pursuing these opportunities.
New technology is driving change across all service territories. Energy delivery systems are being upgraded with advanced meters, improved
controls and more capable operational technology, providing utilities with detailed usage data. 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.
While some of these new technologies challenge the traditional role of utilities as one-way service providers, they also offer strategic
investment opportunities for improving and expanding service. The proliferation of information and operational technology, along with the
exponential growth in data and grid interconnections, is driving the need for increased cyber and physical security systems.
Meaningful customer engagement is increasingly important for utilities as customer expectations change and competition for customer
attention becomes more intense. Customers want to make informed energy choices and become active participants in the delivery of their
energy services. They also expect personalized service, customized service offerings and more real-time, digital communication.
Fortis is well positioned to capitalize on evolving industry opportunities. Its decentralized structure and customer-focused business culture
support the efforts required to meet changing customer expectations and to work with policy makers and regulators on energy and service
solutions that are financially sustainable. Fortis is also a strategic partner in the Energy Impact Partners utility coalition, which is a strategic
private entity fund that invests in emerging technologies, products, services and business models across the full electricity supply chain.
By leveraging these strengths and partnerships, Fortis expects to remain at the forefront of this ever-changing industry.
23
FORTIS INC. 2019 ANNUAL REPORTManagement Discussion and Analysis
OPERATING RESULTS
($ millions)
Revenue
Energy Supply Costs
Operating Expenses
Depreciation and Amortization
Gain on Disposition
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
Revenue
2019
8,783
2,520
2,452
1,350
577
138
1,035
289
1,852
130
67
1,655
1,852
2018
8,390
2,495
2,287
1,243
–
60
974
165
1,286
120
66
1,100
1,286
Variance
FX
113
30
34
14
–
1
10
4
22
2
–
20
22
Other
280
(5)
131
93
577
77
51
120
544
8
1
535
544
The increase was due primarily to: (i) Rate Base growth at the regulated utilities, led by ITC; (ii) overall higher flow-through costs in customer
rates; (iii) favourable foreign exchange of $113 million; and (iv) a $91 million favourable adjustment associated with the November 2019
FERC Order (see “Regulatory Highlights” on page 30). The increase was partially offset by: (i) lower revenue contribution from the Energy
Infrastructure segment due primarily to the disposition of the Waneta Expansion and reduced hydroelectric production in Belize due to
lower rainfall; and (ii) lower retail sales at UNS Energy due to weather.
Energy Supply Costs
Energy supply costs were comparable to 2018. A reclassification of finance lease costs of $29 million from energy supply costs to finance
charges, due to the adoption of a new lease standard (see “Accounting Matters – New Accounting Policies” on page 48), was offset by overall
higher commodity costs.
Operating Expenses
The increase was due primarily to general inflationary and employee-related cost increases, including higher stock-based compensation
costs driven by an increase in the Corporation’s share price and overall performance.
Depreciation and Amortization
The increase was due primarily to continued investment in energy infrastructure at the Corporation’s regulated utilities.
Gain on Disposition
See “Significant Items” on page 20.
Other Income, Net
The increase was due primarily to: (i) favourable foreign exchange contracts; (ii) higher AFUDC equity earnings at UNS Energy; and (iii) an
$11 million gain on the repayment of US$400 million of debt via a tender offer (see “Significant Items” on page 20).
Finance Charges
The increase was due primarily to: (i) overall higher operating utility debt levels to support the capital plan; and (ii) the reclassification of finance
lease interest of $29 million to finance charges from energy supply costs. The increase was partially offset by: (i) lower finance charges due
to the repayment of debt (see “Significant Items” on page 20); and (ii) the reversal of interest of $16 million as a result of the November 2019
FERC Order (see “Regulatory Highlights” on page 30).
24
FORTIS INC. 2019 ANNUAL REPORTManagement Discussion and Analysis
Income Tax Expense
The increase was driven by: (i) tax on the disposition of the Waneta Expansion (see “Significant Items” on page 20); (ii) $44 million of favourable
deferred income tax liability remeasurements in 2018 arising from an election to file a consolidated state income tax return and the
designation of net assets related to the Waneta Expansion as held for sale; and (iii) the recognition of income tax expense of $12 million
in 2019 related to the finalization of US tax reform regulations associated with base-erosion and anti-abuse tax, partially offset by higher
valuation allowances released in 2019 compared to 2018.
Net Earnings
See “Performance at a Glance – Earnings and EPS” on page 20.
BUSINESS UNIT PERFORMANCE
Common Equity Earnings
Years Ended December 31
($ millions)
Regulated Utilities
ITC
UNS Energy
Central Hudson
FortisBC Energy
FortisAlberta
FortisBC Electric
Other Electric (2)
Non-Regulated
Energy Infrastructure
Corporate and Other
Common Equity Earnings
2019
471
292
85
165
131
54
106
1,304
18
333
1,655
2018
361
293
74
155
120
56
105
1,164
72
(136)
1,100
Variance
FX (1)
Other
9
6
2
–
–
–
1
18
1
1
20
101
(7)
9
10
11
(2)
–
122
(55)
468
535
(1)
The reporting currency of ITC, UNS Energy, Central Hudson, Caribbean Utilities, FortisTCI and BECOL is the US dollar. The reporting currency of Belize Electricity is the Belizean dollar,
which is pegged to the US dollar at BZ$2.00=US$1.00. The Corporate and Other segment includes certain transactions denominated in US dollars.
(2) Comprised of the utility operations in eastern Canada and the Caribbean: Newfoundland Power; Maritime Electric; FortisOntario; Caribbean Utilities; FortisTCI; and Belize Electricity.
ITC
($ millions)
Revenue (1)
Earnings (1)
2019
1,761
471
2018
1,504
361
Variance
FX
35
9
Other
222
101
(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, net of foreign exchange, was due primarily to a $91 million favourable adjustment to revenue associated with the
November 2019 FERC Order (see “Regulatory Highlights” on page 30). Higher flow-through costs in customer rates and growth in Rate Base
also contributed to the increase in revenue, partially offset by a reduction in the ROE incentive adders.
Earnings
The increase, net of foreign exchange, was due primarily to the November 2019 FERC Order that resulted in a $63 million increase in earnings,
comprised of $83 million related to the net reversal of liabilities established in prior periods, partially offset by $20 million related to the 2019
impact of the reduced ROE. Growth in Rate Base, lower business development costs and a lower effective tax rate also contributed to the
earnings increase, partially offset by a reduction in the ROE incentive adders and higher non-recoverable expenses.
25
FORTIS INC. 2019 ANNUAL REPORTManagement Discussion and Analysis
UNS Energy
Retail electricity sales (GWh)
Wholesale electricity sales (GWh) (1)
Gas sales (PJ)
Revenue ($ millions)
Earnings ($ millions)
(1) Primarily short-term wholesale sales
Sales
2019
10,431
7,923
16
2,212
292
2018
10,600
6,806
13
2,202
293
Variance
FX
–
–
–
46
6
Other
(169)
1,117
3
(36)
(7)
The decrease in retail electricity sales was due to reduced air conditioning load as a result of cooler-than-normal temperatures in the
spring and summer months compared to warmer-than-normal temperatures for the same periods in 2018.
The increase in wholesale electricity sales was due primarily to higher short-term wholesale sales reflecting an increase in system capacity
related to Gila River Unit 2. Revenue from short-term wholesale sales is primarily returned to customers through regulatory deferral
mechanisms and, therefore, does not materially impact earnings.
The increase in gas volumes was due primarily to heating load as a result of cooler temperatures in the winter months.
Revenue
The decrease, net of foreign exchange, was due primarily to the flow through of lower energy supply costs and lower retail sales. The
decrease in revenue was partially offset by higher flow-through costs related to Springerville Units 3 and 4 and higher short-term
wholesale sales.
Earnings
The decrease, net of foreign exchange, was due primarily to higher depreciation and interest expense associated with Rate Base growth
not yet reflected in customer rates, and lower retail sales. The decrease was partially offset by higher AFUDC earnings, lower operating
costs associated with scheduled outages and maintenance, and a lower effective tax rate.
Central Hudson
Electricity sales (GWh)
Gas sales (PJ)
Revenue ($ millions)
Earnings ($ millions)
Sales
2019
4,963
22
917
85
2018
5,118
24
924
74
Variance
FX
–
–
24
2
Other
(155)
(2)
(31)
9
The decrease in electricity sales was due primarily to lower average consumption as a result of warmer temperatures in winter months that
decreased heating load and cooler temperatures in summer months that decreased air conditioning load. Gas volumes were comparable
to 2018.
Changes in electricity sales and gas volumes at Central Hudson are subject to regulatory revenue decoupling mechanisms and, therefore,
do not materially impact earnings.
Revenue
The decrease, net of foreign exchange, was due primarily to the flow through of lower energy supply costs and lower electricity sales,
partially offset by Rate Base growth.
Earnings
The increase, net of foreign exchange, was primarily due to Rate Base growth and higher storm restoration costs in 2018.
26
FORTIS INC. 2019 ANNUAL REPORTManagement Discussion and Analysis
FortisBC Energy
Gas sales (PJ)
Revenue ($ millions)
Earnings ($ millions)
Sales
2019
227
1,331
165
2018
212
1,187
155
Variance
15
144
10
The increase was due primarily to higher average residential and commercial consumption as a result of colder temperatures in 2019
that increased heating load and higher consumption by transportation customers.
Revenue
The increase was due primarily to a higher cost of natural gas and other flow-through costs recovered from customers, the recovery
of gas storage and transportation costs related to a third-party pipeline incident that occurred in the fourth quarter of 2018, and
Rate Base growth.
Earnings
The increase 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 the delivery. Due to regulatory deferral mechanisms, changes in consumption levels and commodity costs do
not materially impact earnings.
FortisAlberta
Energy deliveries (GWh)
Revenue ($ millions)
Earnings ($ millions)
Deliveries
2019
16,887
598
131
2018
17,154
579
120
Variance
(267)
19
11
The decrease was due primarily to lower average consumption by oil and gas customers along with lower average residential
consumption as a result of cooler temperatures in 2019 that decreased air conditioning load in the summer months. The decrease in
energy deliveries was partially offset by higher average commercial consumption due to customer additions.
As more than 80% 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.
Revenue
The increase was due primarily to Rate Base growth and customer additions, partially offset by a favourable capital tracker revenue true-up
in 2018 related to capital expenditures in 2016 and 2017.
Earnings
The increase was due primarily to lower operating expenses, driven by reduced labour costs, and Rate Base growth. The increase was
partially offset by the 2018 capital tracker revenue true-up and a higher effective tax rate.
27
FORTIS INC. 2019 ANNUAL REPORTManagement Discussion and Analysis
FortisBC Electric
Electricity sales (GWh)
Revenue ($ millions)
Earnings ($ millions)
Sales
2019
3,326
418
54
2018
3,250
408
56
Variance
76
10
(2)
The increase was due primarily to higher consumption by industrial customers.
Revenue
The increase was due primarily to higher electricity sales, higher revenue related to a customer load growth regulatory mechanism and
overall higher flow-through costs. The increase was partially offset by lower surplus power sales and the loss of revenue associated with the
provision of operating, maintenance and management services to the Waneta Expansion (see “Significant Items” on page 20).
Earnings
The decrease was due primarily to the loss of revenue associated with the Waneta Expansion, partially offset by Rate Base growth.
Other Electric
Electricity sales (GWh)
Revenue ($ millions)
Earnings ($ millions)
Sales
2019
9,366
1,467
106
2018
9,314
1,412
105
Variance
FX
–
7
1
Other
52
48
–
The increase was due primarily to overall higher average consumption in the Caribbean and customer additions.
Revenue
The increase, net of foreign exchange, was due primarily to the flow through of higher energy supply costs and higher electricity sales,
partially offset by business interruption insurance proceeds recognized in 2018 at FortisTCI related to Hurricane Irma.
Earnings
Earnings, net of foreign exchange, were comparable to 2018. Higher electricity sales and Rate Base growth were offset by FortisTCI’s insurance
proceeds recognized in 2018.
Energy Infrastructure
Electricity sales (GWh)
Revenue ($ millions)
Earnings ($ millions)
Sales
2019
144
82
18
2018
853
184
72
Variance
FX
–
1
1
Other
(709)
(103)
(55)
Electricity sales decreased by 541 GWh due to the disposition of the Waneta Expansion (see “Significant Items” on page 20), with the
remaining decrease due to lower hydroelectric production in Belize reflecting lower rainfall.
Revenue and Earnings
The decreases in revenue and earnings reflected: (i) lower hydroelectric production in Belize; (ii) the disposition of the Waneta Expansion;
(iii) lower realized margins at Aitken Creek; and (iv) the unfavourable impact of mark-to-market accounting of natural gas derivatives at
Aitken Creek, with unrealized losses of $15 million during 2019 compared to $10 million during 2018.
Aitken Creek is subject to commodity price risk, as it purchases and holds natural gas in storage to earn a profit margin from its ultimate sale.
Aitken Creek mitigates this risk by using derivatives to materially lock in the profit margin that will be realized upon the sale of natural gas.
The fair value accounting of these derivatives creates timing differences and the resulting earnings volatility can be significant.
28
FORTIS INC. 2019 ANNUAL REPORTManagement Discussion and Analysis
Corporate and Other
($ millions)
Net income (expenses)
2019
333
2018
(136)
Variance
FX
1
Other
468
The increase in net income was driven by: (i) a net after-tax gain of $484 million on the disposition of the Waneta Expansion (see “Significant
Items” on page 20); (ii) lower finance charges associated with the disposition, along with a gain on the repayment of debt; (iii) favourable
changes associated with foreign exchange contracts in 2019 compared to 2018; and (iv) lower tax expense due to higher valuation
allowances released in 2019 compared to 2018, partially offset by the recognition of base-erosion and anti-abuse tax in 2019 as a result
of the finalization of the related US tax reform regulations. The increase was also partially offset by lower income tax recovery due to the
remeasurement of deferred tax liabilities recognized during 2018: (i) $30 million resulting from the election to file a consolidated state
income tax return; and (ii) $14 million associated with the designation of the net assets of the Waneta Expansion as held for sale.
NON-US GAAP FINANCIAL MEASURES
Adjusted Common Equity Earnings, Adjusted Basic EPS and Adjusted Payout Ratio are Non-US GAAP Financial Measures and may not be
comparable with similar measures used by other entities. They are presented because management and external stakeholders use them
in evaluating the Corporation’s financial performance and prospects.
Net earnings attributable to common equity shareholders (i.e., Common Equity Earnings) and basic EPS are the most directly comparable
US GAAP measures to Adjusted Common Equity Earnings and Adjusted Basic EPS, respectively. The Actual Payout Ratio calculated using
Common Equity Earnings is the most comparable US GAAP measure to the Adjusted Payout Ratio.
Adjusted Common Equity Earnings and Adjusted Basic EPS reflect items that management excludes in its key decision-making processes and
evaluation of operating results, and are reconciled as follows.
Non-US GAAP Reconciliation
Years Ended December 31
($ millions, except as shown)
Common Equity Earnings
Adjusting items:
Gain on disposition (1)
November 2019 FERC Order (2)
US tax reform (3)
Unrealized loss on mark-to-market of derivatives (4)
Consolidated state income tax election (5)
Assets held for sale (5)
Adjusted Common Equity Earnings
Adjusted Basic EPS ($)
2019
1,655
(484)
(83)
12
15
–
–
1,115
2.55
2018
1,100
–
–
–
10
(30)
(14)
1,066
2.51
Variance
555
(484)
(83)
12
5
30
14
49
0.04
(1) See “Significant Items” on page 20, included in the Corporate and Other segment
(2) See “Regulatory Highlights” on page 30, included in the ITC segment
(3) The finalization of US tax reform regulations associated with base-erosion and anti-abuse tax, included in the Corporate and Other segment
(4) Represents timing differences related to the accounting of natural gas derivatives at Aitken Creek, included in the Energy Infrastructure segment
(5) Remeasurement of deferred income tax liabilities, included in the Corporate and Other segment
29
FORTIS INC. 2019 ANNUAL REPORTManagement Discussion and Analysis
REGULATORY HIGHLIGHTS
Regulation
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.
Under PBR mechanisms, formulae are generally applied that incorporate 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 US are regulated federally by FERC. Remaining utility operations in the US and Canada are regulated by state
or provincial regulators. Utility operations in the Caribbean are regulated by government authorities.
Additional information about regulation and the regulatory matters discussed below is provided in Note 2 in the 2019 Annual Financial
Statements. Also refer to “Business Risks – Regulation” on page 40.
ITC
Incentive Adder Complaint
In April 2018 a third-party complaint was filed with FERC challenging the independence incentive adders that are included in transmission
rates charged by ITC’s MISO Subsidiaries. The adder allowed up to 0.50% or 1.00% to be added to the authorized ROE, subject to any
ROE cap established by FERC. In October 2018 FERC issued an order reducing the adders to 0.25%, effective April 20, 2018. This equated
to a 0.25% decrease in ROE, down from the approximate 0.50% that ITC was earning in rates previously approved by FERC. ITC began
reflecting the 0.25% adder in transmission rates in November 2018. ITC’s MISO Subsidiaries sought rehearing of this order in 2018, which
was denied by FERC. In September 2019 ITC’s MISO Subsidiaries filed an appeal in the US Court of Appeal. The final resolution of this matter
is not expected to have a material impact on the Corporation’s earnings or cash flows.
ROE Complaints
Two third-party complaints requested that the base ROE for MISO transmission owners, including ITC’s MISO Subsidiaries, be found to
no longer be just or reasonable. The complaints cover two consecutive 15-month periods from November 2013 through February 2015
(the “Initial Refund Period” or “Initial Complaint”) and February 2015 through May 2016 (the “Second Refund Period” or “Second Complaint”).
In June 2016 the presiding ALJ issued an initial decision on the Second Complaint, recommending a base ROE of 9.70%, up to a maximum
of 10.68% with incentive adders. Pending an order from FERC, an estimated regulatory liability of $206 million (US$151 million) had been
recognized as at December 31, 2018 based on the ALJ’s initial decision.
In September 2016 FERC ordered that the base ROE for the Initial Refund Period be set at 10.32%, down from 12.38%, up to a maximum
of 11.35% with incentive adders. The resultant rates applied prospectively from September 2016 until an approved ROE was established
for the Second Refund Period. The total refund for the Initial Complaint as a result of the September 2016 FERC order was $158 million
(US$118 million), including interest, and was paid in 2017.
The November 2019 FERC Order determined that the base ROE for the Initial Complaint and from September 2016 onward be 9.88%, up to
a maximum of 12.24% with incentive adders. FERC also dismissed the Second Complaint, resulting in a ROE for that period of 12.38% plus
incentive adders with no refund required. In addition, as a ROE complaint had not been filed for the period of May 2016 to September 2016,
the ROE for that period continued to be 12.38% plus incentive adders with no refund required. The regulated utilities in the MISO region,
including ITC, sought rehearing of this order on the basis that it will not allow utilities to earn a reasonable rate of return on investment. In
January 2020 FERC issued an order granting the rehearing for further consideration, effectively extending FERC’s review.
30
FORTIS INC. 2019 ANNUAL REPORTManagement Discussion and Analysis As at December 31, 2019, a regulatory liability of $91 million (US$70 million) was recognized related to the impact of the November 2019
FERC Order on the Initial Refund Period and for the period from September 2016 to December 2019. Additionally, the regulatory liability
of $206 million (US$151 million) as at December 31, 2018, related to the Second Complaint, was reversed in 2019. The net impact of the
November 2019 FERC Order was an increase in revenue and a decrease in interest expense resulting in an increase in net earnings of
$79 million of which Fortis’ share was $63 million. The favourable impact was comprised of: (i) $83 million related to the net reversal
of liabilities established in prior periods; partially offset by (ii) $20 million related to the 2019 impact of a reduced ROE.
Based on the outcome of the request for rehearing, it is possible the ROE and refunds could materially change from those recognized in 2019.
Notices of Inquiry
In March 2019 FERC issued a NOI seeking comments on whether and how to improve its electric transmission incentives policy. The outcome
may impact the existing incentive adders that are included in transmission rates charged by transmission owners, including ITC. Also in
March 2019, FERC issued a second NOI seeking comments on whether and how recent policies concerning the determination of the base
ROE for electric utilities should be modified. The comment period for both NOI proceedings has ended. The outcome may impact ITC’s
future ROE and incentive adders.
UNS Energy
General Rate Application
In April 2019 TEP filed a general rate application with the Arizona Corporation Commission requesting an increase in non-fuel revenue of
US$99 million, effective May 1, 2020, with electricity rates based on a 2018 historical test year. Intervenor testimony in relation to TEP’s revenue
requirement and rate design was filed in October 2019. The application, adjusted for rebuttal testimony filed by TEP in November 2019,
includes a request to increase TEP’s allowed ROE to 10.00% from 9.75% and the equity component of its capital structure to 53% from 50%
on a Rate Base of US$2.7 billion. Hearings before the ALJ commenced in January and a decision is expected by mid-2020.
FortisBC Energy and FortisBC Electric
In March 2019 FortisBC Energy and FortisBC Electric filed applications with the BCUC requesting approval of a multi-year rate plan and PBR
methodology for 2020–2024. A decision is expected in mid-2020.
FortisAlberta
Second-Term Performance-Based Rate-Setting Proceeding
The AUC has ongoing proceedings to review regulatory applications for rebasing inputs included in PBR rates for 2018–2022, including
anomaly-related adjustments and approved changes to depreciation parameters.
In January 2020 the AUC issued two decisions: (i) confirming that changes to depreciation parameters will be incorporated into
incremental funding mechanisms; and (ii) establishing new criteria for anomaly-related adjustments. PBR utilities in Alberta are permitted
to file depreciation studies by July 2020 and were required to submit their intent to file an anomaly-related adjustment application by
February 7, 2020. FortisAlberta does not anticipate filing a depreciation study in 2020 and did notify the AUC of its intent to file an
anomaly-related adjustment application.
Generic Cost of Capital Proceeding
In December 2018 the AUC initiated a generic cost of capital proceeding to consider a formula-based approach to setting the allowed ROE
beginning in 2021 and whether any process changes are necessary for determining capital structure in years in which a ROE formula is in
place. In April 2019 the AUC determined that a traditional non-formulaic approach for assessing ROE and deemed capital structure would
be used in 2021, with consideration of a formula-based approach for determining the allowed ROE for 2022 and subsequent years. Expert
evidence was filed in January 2020 with an oral hearing scheduled for April 2020. An AUC decision is expected later in 2020.
31
FORTIS INC. 2019 ANNUAL REPORTManagement Discussion and Analysis 2018 Alberta Independent System Operator Tariff Application
In September 2019 the AUC issued a decision that addressed, among other things, a proposal to change how the AESO’s customer
contribution policy is accounted for between distribution facility owners, such as FortisAlberta, and transmission facility owners. The decision
prevents any future investment by FortisAlberta under the policy and directs that the unamortized customer contributions of approximately
$400 million as at December 31, 2017, which form part of FortisAlberta’s Rate Base, be transferred to the incumbent transmission facility
owner in FortisAlberta’s service area.
In October 2019 FortisAlberta filed evidence to oppose the decision. Implementation of the order has been suspended and the decision
remains under review by the AUC. It is expected that the decision will remain under review through the first quarter of 2020. The likely
outcome of this process and potential impacts, if any, cannot be determined at this time.
FINANCIAL POSITION
Significant Changes between December 31, 2019 and 2018
Balance Sheet Account
Assets held for sale
Regulatory assets
(including current and long-term)
Increase (Decrease)
FX
($ millions)
–
(55)
Other
($ millions)
(766)
363
Property, plant and equipment, net
Goodwill
Short-term borrowings
(974)
(527)
(2)
2,205
1
454
Other liabilities
(32)
340
Explanation
Due to the disposition of the Waneta Expansion.
Due primarily to the operation of rate stabilization accounts and the normal deferral
of derivative losses, energy management costs, income tax expense and employee
future benefits.
Due primarily to capital expenditures, partially offset by depreciation.
The other increase was not significant.
Due primarily to the issuance of commercial paper at ITC and short-term borrowings
at UNS Energy.
Due primarily to higher employee future benefits mainly at FortisBC Energy, and
finance lease reclassifications and the balance sheet recognition of operating leases in
accordance with the new lease standard (see “New Accounting Policies” on page 48).
The increase was also due to higher derivative balances and asset retirement obligations
primarily at UNS Energy.
Regulatory liabilities
(130)
(138)
Due primarily to the ROE complaints liability at ITC and lower deferred taxes.
(including current and long-term)
Deferred income tax liabilities
Long-term debt
(including current portion)
Finance leases
(including current portion)
(70)
(791)
353
(1,103)
(12)
(193)
Shareholders’ equity
(585)
2,583
Due primarily to the timing differences related to capital expenditures.
Due primarily to the repayment of Corporate debt (see “Significant Items” on page 20),
partially offset by the issuance of debt at the regulated utilities.
Due primarily to the purchase of Gila River Unit 2, partially offset by the recognition of
a finance lease for Springerville Common Facilities at TEP. The decrease was also due to
reclassifications to other liabilities as noted above.
Due primarily to: (i) the issuance of common shares (see “Significant Items” on page 20);
and (ii) Common Equity Earnings for 2019, less dividends declared on common shares.
Non-controlling interests
(75)
(266)
Due primarily to the disposition of the Waneta Expansion.
32
FORTIS INC. 2019 ANNUAL REPORTManagement Discussion and Analysis
LIQUIDITY AND CAPITAL RESOURCES
Cash Flow Requirements
At the subsidiary level, it is expected that operating and interest costs will be paid from Operating Cash Flows, with varying levels of
residual cash flows available for capital expenditures and/or dividend payments to Fortis. 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 capital expenditures is expected to be derived from borrowings under the Corporation’s
committed credit facility, proceeds from the DRIP and issuances of common shares, preference shares and long-term debt. Depending
on the timing of subsidiary dividend receipts, borrowings under the Corporation’s credit facility may be required periodically to support
debt servicing and dividend payments.
Within this dynamic, the subsidiaries pay dividends to Fortis and receive equity injections from Fortis when required, and both Fortis and
its subsidiaries initially borrow through their committed credit facilities and periodically replace these borrowings with long-term debt.
Financing needs also arise periodically for acquisitions.
Credit facilities are syndicated primarily with large banks in Canada and the US, with no one bank holding more than 20% of the total
facilities. Approximately $5.1 billion of the total credit facilities are committed with maturities ranging from 2020 through 2024. Available
credit facilities are summarized in the following table.
Credit Facilities
As at December 31
($ 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
4,209
(512)
(640)
(64)
2,993
Corporate
and Other
1,381
–
–
(50)
1,331
2019
5,590
(512)
(640)
(114)
4,324
2018
5,165
(60)
(1,066)
(119)
3,920
(1) Additional information about these credit facilities is provided in Note 15 in the 2019 Annual Financial Statements.
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.
In December 2018 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 $2.5 billion. In December 2018 Fortis re-established
its ATM Program, which allowed the issuance of up to $500 million of common shares from treasury to the public at the Corporation’s
discretion, effective until January 2021.
During 2019 the Corporation issued approximately 4.1 million common shares under its ATM Program at an average price of $52.16 per
share. The gross proceeds of $212 million ($209 million net of commissions) were used primarily to fund capital expenditures. Also in 2019,
the Corporation issued approximately 22.8 million common shares under a common equity offering at a price of $52.15 per share for gross
proceeds of $1,190 million ($1,167 million net of commissions). See “Significant Items” on page 20. Following this issuance, the Corporation
terminated the ATM Program. As at December 31, 2019, $1,098 million remained available under the short-form base shelf prospectus.
33
FORTIS INC. 2019 ANNUAL REPORTManagement Discussion and Analysis
As at December 31, 2019: (i) consolidated fixed-term debt maturities/repayments are expected to average $945 million annually over
the next five years; (ii) approximately 80% of the Corporation’s consolidated long-term debt, excluding credit facility borrowings, had
maturities beyond five years; and (iii) available credit facilities were $5.6 billion with $4.3 billion unutilized.
This combination of available credit facilities and manageable annual debt maturities/repayments provides flexibility in the timing of
access to capital markets. Given current credit ratings and capital structures, the Corporation and its subsidiaries expect to continue to
have reasonable access to long-term capital in 2020.
Fortis and its subsidiaries were in compliance with debt covenants as at December 31, 2019 and are expected to remain compliant in 2020.
Cash Flow Summary
Summary of Cash Flows
Years Ended December 31
($ millions)
Cash, beginning of year
Cash provided by (used in):
Operating activities
Investing activities
Financing activities
Effect of exchange rate changes on cash and cash equivalents
Cash and change in cash associated with assets held for sale
Cash, end of year
Operating Activities
See “Performance at a Glance – Operating Cash Flow” on page 22.
Investing Activities
2019
332
2,663
(2,768)
154
(26)
15
370
2018
327
2,604
(3,252)
644
24
(15)
332
Variance
5
59
484
(490)
(50)
30
38
Cash used in investing activities reflects a higher capital spending level in 2019. See “Performance at a Glance – Capital Expenditures”
on page 22 and “Capital Plan” on page 37. Cash used in investing activities was partially offset by proceeds from the disposition of the
Waneta Expansion.
Financing Activities
Cash flows related to financing activities will fluctuate from year to year as a result of changes in the subsidiaries’ capital expenditures, the
amount of Operating Cash Flows available to fund those capital expenditures and the amount of funding required from debt and common
equity issuances.
In the fourth quarter of 2019, the Corporation issued approximately 22.8 million common shares at a price of $52.15 per share for gross
proceeds of $1,190 million ($1,167 million net of commissions). The net proceeds were used to redeem US$500 million of its outstanding
2.10% unsecured senior notes due October 4, 2021, to repay credit facility borrowings and for general corporate purposes.
Net proceeds from the disposition of the Waneta Expansion were used to repay credit facility borrowings and repurchase, via a tender offer,
US$400 million of its outstanding 3.055% unsecured senior notes due in 2026.
34
FORTIS INC. 2019 ANNUAL REPORTManagement Discussion and Analysis
Debt Financing
Long-Term Debt Issuances
Year ended December 31, 2019
($ millions, except %)
ITC
Secured notes
Unsecured term loan credit agreement (4)
Secured notes
First mortgage bonds
Central Hudson
Unsecured notes
Unsecured notes
FortisBC Energy
Unsecured debentures
FortisTCI
Unsecured non-revolving term loan
Caribbean Utilities
Unsecured notes
Unsecured notes
Unsecured notes
Month
Issued
January
June
July
August
October
October
August
February
May
August
August
Interest
Rate
(%)
Maturity
Amount
Use of
Proceeds
4.55
(5)
4.65
3.30
3.89
3.99
2.82
(7)
4.14
4.14
3.83
2049
2021
2049
2049
2049
2059
2049
2025
2049
2049
2039
US 50
US 200
US 50
US 75
US 50
US 50
200
US
5
US 40
US 20
US 20
(1) (2) (3)
(6)
(1) (2) (3)
(1) (2) (3)
(2) (3) (6)
(2) (3) (6)
(1)
(2) (3)
(1) (3) (6)
(2) (3) (6)
(2) (3) (6)
(1) Repay credit facility borrowings
(2) Finance capital expenditures
(3) General corporate purposes
(4)
Maximum amount of borrowings under this agreement was US$400 million; in January 2020 the remaining US$200 million was drawn to repay outstanding commercial
paper balances
(5) Floating rate of a one-month LIBOR plus a spread of 0.60%
(6) Repay maturing long-term debt
(7) Floating rate of a one-month LIBOR plus a spread of 1.75%
In January 2020 ITC entered into an unsecured term loan credit agreement, due in January 2021, under which the maximum amount of
US$75 million was borrowed. The proceeds were used to repay credit facility borrowings.
Common Equity Financing
Common Equity Issuances and Dividends Paid
Years Ended December 31
($ millions, except as indicated)
Number of common shares issued (1) (# millions)
Amount of common shares issued (2)
Non-cash issuances (3)
Cash proceeds from common shares issued
Dividends paid per common share ($)
Total dividends paid
Non-cash DRIP
Cash dividends paid
2019
34.8
1,756
(314)
1,442
1.8275
793
(299)
494
2018
7.4
307
(273)
34
1.7250
731
(272)
459
Variance
27.4
1,449
(41)
1,408
0.1025
62
(27)
35
(1) Mainly related to the Corporation’s issuance of shares in the fourth quarter of 2019, DRIP and ATM Program
(2) Net of commissions of $26 million (2018 – $nil)
(3) Related to DRIP and stock options
On February 12, 2020, Fortis declared a dividend of $0.4775 per common share payable on June 1, 2020. The payment of dividends is at the
discretion of the Board of Directors and depends on the Corporation’s financial condition and other factors.
35
FORTIS INC. 2019 ANNUAL REPORTManagement Discussion and Analysis
Contractual Obligations
Contractual Obligations
As at December 31, 2019
($ millions)
Long-term debt:
Principal (1)
Interest
Finance leases (2)
Other obligations
Other commitments (3)
Waneta Expansion capacity agreement
Gas and fuel purchase obligations
Power purchase obligations
Renewable PPAs
Build-transfer agreement – Oso Grande
ITC easement agreement
Renewables energy credit purchase agreements
Debt collection agreement
Other
Total
Year 1
Year 2
Year 3
Year 4
Year 5 Thereafter
Due
22,320
15,483
1,359
450
2,628
2,398
1,743
1,513
438
401
124
116
299
690
929
56
134
51
606
244
104
438
13
26
3
36
872
910
121
120
52
424
183
104
–
13
18
3
26
1,146
879
33
94
53
349
168
104
–
13
17
3
24
1,553
846
33
20
54
255
163
103
–
13
10
3
25
1,106
786
33
19
55
140
119
103
–
13
10
3
29
16,953
11,133
1,083
63
2,363
624
866
995
–
336
43
101
159
49,272
3,330
2,846
2,883
3,078
2,416
34,719
(1) Total is not reduced by unamortized deferred financing and discount costs of $129 million.
(2) Additional information is provided in Note 16 in the 2019 Annual Financial Statements.
(3) Additional information is provided in Note 29 in the 2019 Annual Financial Statements.
Other Contractual Obligations
The Corporation’s regulated utilities are obligated to provide service to customers within their respective service territories. Consolidated
capital expenditures are forecast to be approximately $4.3 billion for 2020 and approximately $18.8 billion over the five-year period from 2020
through 2024. See “Capital Plan” on page 37.
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. In October 2019 the Wataynikaneyap Partnership entered into loan agreements to finance the project
during construction. In the event a lender under such construction 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.
As at December 31, 2019, FortisBC Holdings Inc., a non-regulated holding company, had $78 million of parental guarantees outstanding to
support storage optimization activities at Aitken Creek.
Off-Balance Sheet Arrangements
With the exception of letters of credit outstanding of $114 million as at December 31, 2019 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 (1)
(%)
As at December 31
Debt (2)
Preference shares
Common shareholders’ equity and minority interest (3)
2019
53.1
3.8
43.1
100.0
2018
57.0
3.8
39.2
100.0
(1) Reflects the repayment of debt using proceeds from the disposition of the Waneta Expansion and the $1.2 billion common equity offering (see “Significant Items” on page 20)
(2) Includes long-term debt and finance leases, including current portion, and short-term borrowings, net of cash
(3) Includes minority interest of 3.7% as at December 31, 2019 (December 31, 2018 – 4.5%)
36
FORTIS INC. 2019 ANNUAL REPORTManagement Discussion and Analysis
Outstanding Share Data
As at February 12, 2020, the Corporation had issued and outstanding 463.5 million common shares and the following First Preference Shares:
5.0 million Series F; 9.2 million Series G; 7.0 million Series H; 3.0 million Series I; 8.0 million Series J; 10.0 million Series K; and 24.0 million Series M.
Only the common shares of the Corporation have voting rights. The Corporation’s first preference shares do not have voting rights unless and
until Fortis fails to pay eight quarterly dividends, whether or not consecutive or declared.
If all outstanding stock options were converted as at February 12, 2020, an additional 3.2 million common shares would be issued
and outstanding.
Credit Ratings
The Corporation’s credit ratings shown below reflect its low risk profile, diversity of operations, the stand-alone nature and financial
separation of each regulated subsidiary, and level of holding company debt.
Credit Ratings
As at December 31, 2019
S&P
DBRS Morningstar
Moody’s
Rating
A–
BBB+
BBB (high)
BBB (high)
Baa3
Baa3
Type
Corporate
Unsecured debt
Corporate
Unsecured debt
Issuer
Unsecured debt
Outlook
Negative
Stable
Stable
Capital Plan
Capital investment in energy infrastructure is required to ensure the continued and enhanced performance, reliability and safety of the
electricity and gas systems, and to meet customer growth. See “Performance at a Glance – Capital Expenditures” on page 22.
2019 Capital Expenditures (1)
($ millions, except %)
Generation
Transmission
Distribution
Other (3)
Total
(%)
Regulated Utilities
ITC
–
951
–
197
1,148
31
UNS
Energy
442
83
255
135
915
24
Central
Hudson
2
55
174
86
317
8
FortisBC
Energy
–
194
191
78
463
12
Fortis
Alberta
–
–
385
38
423
11
FortisBC
Electric
29
18
42
17
106
3
Total
Other Regulated
Non-
Electric
57
146
160
30
393
10
Utilities Regulated (2)
530
1,447
1,207
581
3,765
99
6
–
–
47
53
1
Total
536
1,447
1,207
628
3,818
100
(%)
14
38
32
16
100
(1) Reflects cash outlay for property, plant and equipment and intangible assets as shown on the consolidated statements of cash flows in the 2019 Annual Financial Statements, as
well as Fortis’ share of development costs and capital spending for the Wataynikaneyap Transmission Power Project of $98 million
(2) Includes Energy Infrastructure and Corporate and Other segments
(3) Includes facilities, equipment, vehicles and information technology assets, as well as AESO transmission-related capital expenditures at FortisAlberta
Planned capital expenditures are based on detailed forecasts of energy demand, labour and material costs, general economic conditions,
foreign exchange rates and other factors. These could change and cause actual expenditures to differ from forecast or plan.
Forecast 2020 Capital Expenditures (1)
($ millions, except %)
Generation
Transmission
Distribution
Other
Total
(%)
Regulated Utilities
UNS
Energy
715
189
274
212
1,390
32
Central
Hudson
1
44
167
80
292
7
FortisBC
Energy
–
221
153
133
507
12
Fortis
Alberta
–
–
365
71
436
10
FortisBC
Electric
33
4
77
27
141
3
ITC
–
914
–
62
976
22
(1) Excludes the non-cash equity component of AFUDC
Total
Other Regulated
Electric
120
254
158
34
566
13
Non-
Utilities Regulated
11
–
–
21
869
1,626
1,194
619
4,308
99
32
1
Total
880
1,626
1,194
640
4,340
100
(%)
20
37
28
15
100
37
FORTIS INC. 2019 ANNUAL REPORTManagement Discussion and Analysis
Five-Year Capital Plan (1)
($ billions)
(1) Excludes the non-cash equity component of AFUDC
2020
4.3
2021
3.8
2022
3.8
2023
3.7
2024
3.2
Total
18.8
The Corporation’s five-year 2020–2024 capital plan of $18.8 billion is $0.5 billion higher than the $18.3 billion capital plan disclosed in the
Q3 2019 MD&A due to a $0.5 billion shift in spending to 2020 and 2021 (see “Performance at a Glance – Capital Expenditures” on page 22).
The $18.8 billion five-year capital plan is $1.5 billion higher than the $17.3 billion for 2019–2023, as disclosed in the 2018 annual MD&A,
largely due to: (i) expected grid enhancements and cleaner energy resources at ITC and Caribbean Utilities; (ii) expected expansion of the
Tilbury LNG site at FortisBC Energy; (iii) an increase in the forecast foreign exchange rate from US$1.00=CAD$1.28 to US$1.00=CAD$1.32;
and (iv) the above-noted shift in spending from 2019 to 2020 and 2021.
The capital plan is low risk and highly executable, with 99% of planned expenditures to occur at the regulated utilities and only 20%
related to Major Capital Projects. Geographically, 55% of planned expenditures are expected in the US, including 26% at ITC, with 41% in
Canada and the remaining 4% in the Caribbean.
Nature of Capital Expenditures
(%)
Growth (1)
Sustaining (2)
Other (3)
Total
Actual
2019
23
60
17
100
Forecast
2020
Five-Year Plan
2020–2024
25
62
13
100
28
59
13
100
(1) Relates to the connection of new customers and infrastructure upgrades required to meet load growth, including AESO transmission-related investment at FortisAlberta
(2) Relates to the continued and enhanced performance, reliability and safety of generation, transmission and distribution assets
(3) Facilities, equipment, vehicles, information technology and other assets
Midyear Rate Base (1)
($ billions)
ITC
UNS Energy
Central Hudson
FortisBC Energy
FortisAlberta
FortisBC Electric
Other Electric
Total
Actual
2019
8.7
5.1
1.9
4.5
3.5
1.3
3.0
28.0
Forecast
2020
Forecast
2024
9.5
5.8
2.1
5.0
3.7
1.4
3.2
30.7
12.0
6.9
2.8
6.6
4.3
1.5
4.3
38.4
(1) Simple average of Rate Base at beginning and end of the year
Total midyear Rate Base is forecast to grow to $38.4 billion by 2024 under the five-year capital plan, representing a CAGR of 6.5%, which is
supportive of continuing growth in earnings and dividends.
Major Capital Projects (1)
($ millions)
ITC (2)
UNS Energy
FortisBC Energy
Other Electric
Total
Project
Multi-Value Regional Transmission Projects
34.5 to 69 kV Transmission Conversion Project
Gila River Unit 2
Southline Transmission Project
Oso Grande Wind Project
Lower Mainland Intermediate Pressure System Upgrade
Eagle Mountain Woodfibre Gas Line Project (3)
Transmission Integrity Management Capabilities Project
Inland Gas Upgrades Project
Tilbury 1B Project
Wataynikaneyap Transmission Power Project (4)
Pre-
2019
581
225
–
–
–
208
–
–
3
–
25
1,042
Actual
2019
Forecast
2020
2021–2024
Expected
Completion
44
127
212
–
65
180
–
13
6
8
98
753
11
92
–
19
453
72
–
23
57
37
230
994
265
176
–
373
–
–
350
494
262
315
271
2,506
2023
Post-2024
2019
Post-2024
2020
2020
2023
Post-2024
Post-2024
2024
2023
(1) Includes applicable AFUDC
(2) Pre-2019 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, including deferred development costs. Under the funding framework, Fortis will be funding its equity component only.
38
FORTIS INC. 2019 ANNUAL REPORTManagement Discussion and Analysis
Multi-Value Regional Transmission Projects
Consists of four regional electric transmission projects that have been identified by MISO to address system capacity needs and reliability in
various states. Three projects have been completed, one in 2018 and two in 2019. The fourth project is expected to be placed in service in 2023.
34.5 to 69kV Transmission Conversion Project
Consists of multiple capital initiatives designed to construct new 69-kV lines, and upgrade existing 34.5-kV lines to 69 kV, with in-service dates
ranging from 2019 to post-2024.
Gila River Unit 2
In 2017 UNS Energy entered into a 20-year tolling PPA that included a three-year option to purchase Gila River Unit 2. The purchase of
Gila River Unit 2 was completed in December 2019 and replaces the early retirement of coal-fired generation.
Southline Transmission Project
UNS Energy continues to evaluate the cost and timelines associated with the different phases of this project. The first phase, referred to as
“Vail-to-Tortolita”, is a joint effort between Western Area Power Administration and TEP that will result in new construction and upgrades to
connect existing TEP substations. Construction of this phase is expected to commence in 2020.
The second phase of the project relates to the construction of a 600-MW transmission line across southern New Mexico and southern
Arizona. The line will improve regional reliability and facilitate the connection of renewable energy resources to the grid, including the
Oso Grande Wind Project. UNS Energy expects to purchase a 250-MW ownership in the project. The timing, share and cost of this phase of
the project will depend on subscription of the remaining wind available at Oso Grande.
Oso Grande Wind Project
Relates to the construction of a 750-MW wind-powered electric generating facility that will complement UNS Energy’s existing renewable
solar generation portfolio, of which UNS Energy will own 250 MW. Construction on Oso Grande commenced in the third quarter of 2019
and in January 2020 UNS Energy took ownership of its share under a build-transfer contract. Construction is expected to be completed for
operation by December 2020.
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 Burnaby
and Coquitlam sections of the project were gasified during 2018 and 2019. A short pipeline segment in South Vancouver will be replaced
in 2020. Final allowable project costs are subject to review by the BCUC.
Eagle Mountain Woodfibre Gas Line Project
Consists of a pipeline expansion to a proposed LNG site in Squamish, British Columbia. Cost estimates are subject to final project scoping
and determination of customer capital contributions. An Order in Council from the Government of British Columbia effectively exempts the
project from further regulatory approval. FortisBC Energy and Woodfibre LNG Limited have entered into a pre-execution work agreement
enabling FortisBC Energy to incur project feasibility and development costs.
Transmission Integrity Management Capabilities Project
Project to improve gas line safety and transmission system integrity, including gas line modifications and looping. In December 2018 a
regulatory deferral account was approved by the BCUC to capture approximately $40 million of development costs to be incurred through
2020 to enable the filing for a CPCN.
Inland Gas Upgrades Project
Relates to gas line modifications and replacements to enable in-line integrity inspection capabilities. In January 2020 the CPCN application
was approved by the BCUC.
Tilbury 1B Project
Consists of construction of additional liquefaction and dispensing in support of optimizing the existing investment in Tilbury Phase 1A
Expansion Project. The project has received an Order in Council from the Government of British Columbia. Pre-front-end engineering design
and related studies will continue in 2020.
39
FORTIS INC. 2019 ANNUAL REPORTManagement Discussion and Analysis Wataynikaneyap Transmission Power Project
Consists of the construction of a $1.6 billion, 1,800 kilometre, OEB-regulated transmission line to connect 17 remote First Nations communities
in Northwestern Ontario to the main electricity grid. FortisOntario is responsible for construction management and operation of the
transmission line. The initial phase to connect the Pikangikum First Nation was fully funded by the Canadian government and completed in
late 2018. In the fourth quarter of 2019, the project received financial close and a notice to proceed for construction was issued. The project
is targeted for completion by the end of 2023.
Additional Investment Opportunities
Fortis is pursuing additional investment opportunities within existing service territories that are not yet included in the base five-year capital plan.
ITC – Lake Erie Connector
Relates to a proposed 1,000 MW, bi-directional, high-voltage direct current underwater transmission line to directly link the markets of the
Ontario Independent Electricity System Operator 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 major application process is complete.
The project continues to advance through regulatory, operational and economic milestones. Ongoing activities include completing project
cost refinements and securing transmission service agreements. Completion would take approximately three years from the commencement
of construction.
FortisBC Energy – LNG
Relates to FortisBC’s 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. Fortis continues to have discussions with
potential export customers.
Other Opportunities
Includes incremental regulated transmission investment, contracted transmission and grid modernization projects at ITC; renewable energy
investments, energy storage projects, grid modernization, infrastructure resiliency, and transmission investments at UNS Energy; and further
gas infrastructure opportunities at FortisBC Energy.
BUSINESS RISKS
Fortis has established an ERM process to help identify and evaluate risks by both severity of impact and probability of occurrence. Materiality
thresholds are reviewed and, if necessary, updated annually. Non-financial risks that may impact the safety of employees, customers or the
general public, as well as reputational risks, are also evaluated. Systems of internal controls are established to monitor and manage identified
risks. The ERM process at the subsidiary level is overseen by each subsidiary’s board 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 strategic objectives are achieved.
A summary of the Corporation’s current significant business risks follows.
Regulation
Regulated utility assets represented approximately 99% of the Corporation’s total assets as at December 31, 2019. Regulatory jurisdictions
include five Canadian provinces, nine US states and three Caribbean countries, as well as FERC regulation for transmission assets in the US.
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.
40
FORTIS INC. 2019 ANNUAL REPORTManagement Discussion and Analysis 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.
Under FortisAlberta’s PBR mechanism there is an 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 assumed ROE and
deemed capital structure as well as operating and capital expenditures. These challenges could have a Material Adverse Effect. Recent
challenges are described under “Regulatory Highlights – ITC” on page 30.
Additionally, the US 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
US federal energy matters. Such changes could have a Material Adverse Effect.
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 resulting compliance costs. These dynamics could have a Material Adverse Effect.
Climate Change and Physical Risks
The provision of electric and gas service is subject to customary industry 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, changing seasonal variations,
and regulatory responses (see “Environmental Matters” on page 46), each of which could have a Material Adverse Effect. Severe weather
impacts the Corporation’s service territories, primarily when thunderstorms, flooding, wildfires, hurricanes and snow or ice storms occur.
Increased frequency of extreme weather events could increase the cost of providing service. 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 efficiencies over time to operating facilities.
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, each of which
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.
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.
The operation of transmission and distribution assets is subject to risks, including the potential to cause fires, mainly as a result of equipment
failure, falling trees and lightning strikes to lines or equipment. 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 with a potential Material Adverse Effect.
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
with a Material Adverse Effect.
41
FORTIS INC. 2019 ANNUAL REPORTManagement Discussion and Analysis 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, and such claims, if successful, could have a Material Adverse Effect.
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, or the occurrence of significant
unforeseen equipment failures despite maintenance programs, or the inability to recover requisite costs in customer rates, could have a
Material Adverse Effect.
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 may necessitate the acceleration of these standards, processes and procedures. Failure to do so may disrupt
the ability of the utilities to safely provide service, which could cause reputational harm and other impacts with a Material Adverse Effect.
Interest Rates
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. A low interest rate environment could reduce allowed ROEs.
Alternatively, 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.
Weather Variability and Seasonality
Electricity consumption varies significantly in response to climate change and seasonal weather changes. 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 the gas is used for space heating by
residential customers. The earnings of the Corporation’s gas utilities and Aitken Creek 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.
Growth
Fortis has a history of growth through acquisitions and organic growth from capital expenditures 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 37. Projects, particularly Major Capital Projects, are subject to risks of delay
and cost overruns during construction caused by inflation, 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 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.
42
FORTIS INC. 2019 ANNUAL REPORTManagement 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 consolidated 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. Although Fortis has a robust talent management program,
there is no assurance it will be able to continue to attract sufficient and appropriate talent. Significant failures in these regards could have
a Material Adverse Effect.
Tax Laws
Fortis and its subsidiaries are subject to changes in income tax rates and other tax legislation in Canada, the US and other international
jurisdictions. These changes could have a Material Adverse Effect. Although income taxes at the regulated utilities are generally recovered in
customer rates, regulatory lag can result in recovery delays or non-recovery for certain periods. A variety of other impacts are also possible.
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.
The nature, timing or impact of any future changes in tax laws cannot be predicted. Additionally, certain aspects of US tax reform are still
subject to interpretation and clarification, including proposed regulations regarding certain hybrid arrangements.
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. Their ability to operate effectively is dependent upon developing and maintaining complex information
systems and infrastructure that support the operation of electric generation, transmission and distribution facilities, including gas facilities;
provide customers with billing, consumption and load settlement information, where applicable; and support financial and general operations.
Despite risk-based cybersecurity programs that have been implemented and are continuously monitored for effectiveness, information and
operations technology systems may be vulnerable to unauthorized access due to hacking, 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 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 or 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 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.
43
FORTIS INC. 2019 ANNUAL REPORTManagement Discussion and Analysis 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 US dollar. The earnings and cash flows from, and net investments in, these entities are exposed to fluctuations in the
US dollar-to-Canadian dollar exchange rate.
Fortis has limited this exposure through hedging. As at December 31, 2019, US$2.2 billion (December 31, 2018 – US$3.4 billion) of corporately
issued US dollar-denominated long-term debt had been designated as an effective hedge of foreign net investments, leaving US$9.7 billion
(December 31, 2018 – US$8.0 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 flows continue to be impacted by exchange rate fluctuations. On average,
Fortis estimates that a five-cent increase or decrease in the US dollar relative to the Canadian dollar exchange rate of US$1.00=CAD$1.33 as
at December 31, 2019 would increase or decrease annual EPS by approximately six cents, which reflects the Corporation’s hedging program.
There is no assurance that existing hedging strategies will continue to be effective. They could also have the effect of limiting or reducing the
Corporation’s total returns if management’s expectations concerning future events or market conditions prove to be incorrect, in which case
the costs associated with the hedging strategies may outweigh their benefits.
Natural Gas Competitiveness
Approximately 19% of the Corporation’s revenue is derived from natural gas. A decrease in the competitiveness of natural gas due to pricing
or other factors could have a Material Adverse Effect.
In British Columbia, which accounts for 79% 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, and leading to further reductions in competitiveness.
Government policy could also impact the competitiveness of natural gas in British Columbia. The provincial government has introduced
changes to energy policy, including GHG emission reduction targets and a consumption tax on carbon-based fuels, but has not yet
introduced a carbon tax on imported electricity generated through the combustion of carbon-based fuels. The impact of these changes
to energy policy may have a material impact on the competitiveness of natural gas relative to non-carbon based energy sources or other
energy sources.
In addition, all levels of government have become more active in the development of policies to address climate change. For example,
municipal governments have developed policies and bylaws to support the transition to a lower-carbon economy. Government policy may
put upward pressure on the cost of natural gas and potentially affect its competitiveness. Government policy may also impose limitations
on energy sources permitted to be used in new and existing developments.
Reliability Standards
The Energy Policy Act requires owners, operators and users of the bulk electric system in the US 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 from customer rates of related costs including
potentially significant penalties.
General Economic Conditions
Fluctuations in general economic conditions, 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 despite compensatory regulatory measures, including making it more difficult for customers to pay their bills.
44
FORTIS INC. 2019 ANNUAL REPORTManagement Discussion and Analysis Access to Capital
Ongoing access to cost-effective capital is required to fund, among other things, capital expenditures and the repayment of maturing debt.
Operating Cash Flows may not be sufficient to fund the repayment of all outstanding liabilities when due or 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 such 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 and credit ratings. 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 33.
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 25); and (ii) price-risk management strategies such as the use of derivative
contracts that effectively fix costs (see “Financial Instruments – Derivatives” on page 52).
There is no assurance that current regulator-approved mechanisms will continue to exist in the future. Additionally, despite these mechanisms,
severe and prolonged commodity price increases could result in rates that customers are unable to pay and/or could affect consumption and
thus sales growth. These could have a Material Adverse Effect.
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 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.
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 rather than being generated. 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 have a Material Adverse Effect.
45
FORTIS INC. 2019 ANNUAL REPORTManagement Discussion and Analysis 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 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 that may affect the facilities. A divergence in the interests of TEP and those of the joint owners
or operators could have a Material Adverse Effect.
Wataynikaneyap Partnership is a partnership, owned 51% by 24 First Nations communities and 49% by a partnership between Fortis (80%)
and Algonquin Power & Utilities Corp. (20%), 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.
Environmental Matters
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 at the electric businesses 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 the gas businesses primarily relate to gas and propane leaks and other accidents involving these substances.
The key environmental risks for hydroelectric generation operations include the creation of artificial water flows that may disrupt natural
habitats and dam failures.
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, and 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.
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.
Some coal-fired generation facilities utilized by UNS Energy have closed before the end of their useful lives due to economic conditions
and/or recent or expected changes in environmental regulations, including those relating to GHG emissions. Early closures have necessitated
regulatory relief to recover any remaining net book values and decommissioning costs, and potential accelerated depreciation could cause
rate pressure. Significant unrecovered costs or rate pressures could have a Material Adverse Effect.
46
FORTIS INC. 2019 ANNUAL REPORTManagement Discussion and Analysis 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 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 actual damage, liabilities or business interruption will be fully covered; (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 could have a Material Adverse Effect.
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 and/or third parties. There is no assurance that:
(i) all of these 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.
Reputation, Relationships and Stakeholder Activism
The Corporation’s operations and growth prospects require strong relationships with key stakeholders, including governments and agencies,
Indigenous communities, landowners, and environmental organizations. Inadequately managing expectations and issues important to
stakeholders, including those arising during construction, could affect the Corporation’s reputation as well as have a significant impact on
its operations and infrastructure development.
Additionally, external stakeholders 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.
Indigenous Peoples’ Land Claims
The Corporation’s British Columbia utilities provide service to customers on Indigenous Peoples’ lands and maintain facilities on lands that are
subject to Indigenous Peoples’ land claims. A treaty negotiation process involving Indigenous Peoples and the Governments of British Columbia
and Canada is underway, but the basis for potential settlements is unclear and not all Indigenous Peoples are participating in the process.
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 process 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.
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.
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.
47
FORTIS INC. 2019 ANNUAL REPORTManagement Discussion and Analysis ACCOUNTING MATTERS
New Accounting Policies
Leases
Effective January 1, 2019, the Corporation adopted ASU No. 2016-02, Leases, that requires lessees to recognize a right-of-use asset and lease
liability for all leases with a lease term greater than 12 months, along with additional disclosures.
At lease inception, 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.
Fortis applied the transition provisions of the new standard as of the adoption date and did not retrospectively adjust prior periods in
accordance with the modified retrospective approach. Fortis elected a package of implementation options, referred to as practical
expedients, that allowed it to not reassess: (i) whether existing contracts, including land easements, are or contain a lease; (ii) the classification
of existing leases; or (iii) the initial direct costs for existing leases. Fortis also utilized the hindsight practical expedient to determine the lease
term. Upon adoption, Fortis did not identify or record an adjustment to the opening balance of retained earnings, and there was no impact
on net earnings or cash flows.
Hedging
Effective January 1, 2019, the Corporation adopted ASU No. 2017-12, Targeted Improvements to Accounting for Hedging Activities, which
better aligns risk management activities and financial reporting for hedging relationships through changes to designation, measurement,
presentation and disclosure guidance. Adoption did not have a material impact on the 2019 Annual Financial Statements.
Fair Value Measurement Disclosures
Effective January 1, 2019, the Corporation adopted ASU No. 2018-13, Changes to the Disclosure Requirements for Fair Value Measurement, which
improves the effectiveness of financial statement note disclosures by clarifying what is required and important to users of the financial
statements. The adoption of this ASU removed the following disclosures for all periods presented: (i) the amount of, and reasons for, transfers
between level 1 and level 2 of the fair value hierarchy; (ii) the policy for the timing of transfers between levels; and (iii) the valuation processes
for level 3 fair value measurements.
Pensions and Other Post-Retirement Plan Disclosures
Effective December 31, 2019, the Corporation early adopted, on a retrospective basis, ASU No. 2018-14, Changes to the Disclosure Requirements
for Defined Benefit Plans, which modifies the disclosure requirements for employers with defined pension or other post-retirement
plans and clarifies disclosure requirements. In particular, it removed the following disclosures: (i) the amounts in accumulated other
comprehensive income expected to be recognized as components of net period benefit costs over the next fiscal period; and (ii) the effects
of a one-percentage-point change on the assumed health care costs and the change in rates on service cost, interest cost and the benefit
obligation for post-retirement health care benefits.
48
FORTIS INC. 2019 ANNUAL REPORTManagement Discussion and Analysis Future Accounting Pronouncements
Income Taxes
ASU No. 2019-12, Simplifying the Accounting for Income Taxes, issued in December 2019, is effective for Fortis January 1, 2021, with early
adoption permitted. Principally, it improves consistent application of, and clarifies, existing income tax guidance. Fortis is assessing the
impact that adoption will have on its consolidated financial statements.
Critical Accounting Estimates
General
The preparation of the 2019 Annual Financial Statements required management to make estimates and judgments that affect the reported
amounts of, and disclosures related to, assets, liabilities, revenues, expenses, gains, losses and contingencies. Management evaluates
these estimates on an ongoing basis based upon historical experience, current conditions, and assumptions believed to be reasonable
at the time they are made, with any adjustments recognized in the period they become known. Actual results may differ significantly from
these estimates.
Regulatory Assets and Liabilities
As at December 31, 2019, Fortis recognized regulatory assets of $3.4 billion (December 31, 2018 – $3.1 billion) and regulatory liabilities of
$3.4 billion (December 31, 2018 – $3.6 billion).
Regulatory assets represent future revenues and/or receivables associated with incurred costs that will be, or are expected to be, recovered
from customers in future periods through the rate-setting process. Regulatory liabilities represent: (i) future reductions or limitations of
increases in revenue associated with amounts that will be, or are expected to be, refunded to customers through the rate-setting process;
or (ii) an obligation to provide future service that customers have paid for in advance.
The recognition of regulatory assets and liabilities and the period(s) of settlement are often estimates based on past, existing or expected
regulatory orders in relation to the nature of the underlying amounts and are subject to regulatory approval. Historically, actual settlement
amounts and periods have generally not differed materially from those estimated, but there is no assurance that this will always be the case.
Differences arising from the regulator’s orders would be recognized in accordance with those orders, whereby any amounts disallowed would
be immediately recognized in earnings with the remainder recognized in earnings in accordance with their inclusion in customer rates.
Employee Future Benefits
Key Estimates and Assumptions
Years Ended December 31
Funded status (1) ($ millions)
Benefit obligation (2)
Plan assets
Net benefit cost (2) ($ millions)
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
2019
(3,632)
3,208
(424)
65
4.05
3.20
5.78
3.33
–
2018
(3,207)
2,830
(377)
83
3.56
4.07
5.80
3.35
–
2019
(712)
343
(369)
28
4.10
3.25
5.50
–
4.62
2018
(655)
293
(362)
34
3.57
4.13
5.48
–
4.61
(1) Periodic actuarial valuations determine funding contributions for the pension plans and US 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 2020 rate is 6.15% and is assumed to decrease over the next 12 years to the ultimate rate of 4.62% in 2031 and thereafter.
49
FORTIS INC. 2019 ANNUAL REPORTManagement Discussion and Analysis
Sensitivity Analysis
Year Ended December 31, 2019
($ 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 Cost
Trend Rate –
1% change
Increase
Decrease
Increase
Decrease
Increase
Decrease
(25)
25
(3)
n/a
23
(80)
3
n/a
(29)
(482)
(7)
(100)
55
612
10
128
n/a
n/a
24
104
n/a
n/a
(18)
(83)
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.
Depreciation and Amortization
As at December 31, 2019, Fortis recognized property, plant and equipment and intangible assets of $35.2 billion (December 31, 2018 – $34.0 billion)
representing 66% of total assets (December 31, 2018 – 64%). Depreciation and amortization totalled $1.4 billion for 2019 (2018 – $1.2 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 asset 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, 2019, this regulatory liability
was $1.2 billion (December 31, 2018 – $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, 2019, Fortis recognized goodwill of $12.0 billion (December 31, 2018 – $12.5 billion), representing 22% of total assets
(December 31, 2018 – 24%).
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 for certain reporting units 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. Otherwise, the primary method for estimating fair value of the
reporting units is the income approach, whereby net cash flow projections are discounted using an enterprise value method. 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.
50
FORTIS INC. 2019 ANNUAL REPORTManagement Discussion and Analysis
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, 2019, deferred income tax liabilities, current income tax receivable included in accounts receivable, deferred income taxes
included in regulatory assets, and deferred income taxes included in regulatory liabilities totalled $3.0 billion, $35 million, $1.6 billion and
$1.4 billion, respectively (December 31, 2018 – $2.7 billion, $91 million, $1.5 billion and $1.6 billion, respectively). Income tax expense was
$289 million in 2019 (2018 – $165 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/liabilities reflect temporary differences between the tax and accounting basis of assets/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. To the extent future tax recovery is not assessed as “more likely than not”,
a valuation allowance is recognized in earnings when created or adjusted.
At the regulated utilities, differences between the tax expense/recovery normally recognized under US GAAP and that reflected in
customer rates, which is expected to be recovered from/refunded to customers in future rates, are recognized as regulatory assets/liabilities.
These regulatory assets/liabilities 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.
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. See “Financial Instruments – Derivatives” on page 52.
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 47, for which no amounts have been
accrued because the outcomes currently cannot be reasonably determined. Further information is provided in Note 29 in the 2019
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, 2019, the carrying value of long-term debt, including the current portion, was $22.3 billion (December 31, 2018 – $24.2 billion)
compared to an estimated fair value of $25.3 billion (December 31, 2018 – $25.1 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.
51
FORTIS INC. 2019 ANNUAL REPORTManagement Discussion and Analysis Derivatives
Fortis generally limits derivative usage to those qualifying as accounting, economic or cash flow hedges, or those that are otherwise 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 and commodity swaps 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/losses associated with changes in the fair value of these energy contracts are deferred as a regulatory asset/liability for
recovery from/refund to customers in future rates, as permitted by the regulators. As at December 31, 2019, unrealized losses of $119 million
(December 31, 2018 – $57 million) were recognized as regulatory assets and unrealized gains of $2 million (December 31, 2018 – $9 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 utilizing independent third-party
information, where possible.
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/losses associated with changes in the fair value of these energy contracts are recognized in revenue. During 2019 unrealized
losses of $16 million (2018 – unrealized losses of $12 million) were recognized in revenue.
Total Return Swaps
The Corporation holds total return swaps to manage the cash flow risk associated with forecasted future cash settlements of certain
stock-based compensation obligations. The swaps have a combined notional amount of $111 million and terms of one to three years
expiring in January 2020, 2021 and 2022. Fair values are measured using an income valuation approach based on forward pricing curves.
During 2019 unrealized gains of $11 million (2018 – unrealized gains of less than $1 million) were recognized in other income, net.
Foreign Exchange Contracts
The Corporation holds US dollar foreign exchange contracts to help mitigate exposure to volatility of foreign exchange rates. The contracts
expire in 2020 and have a combined notional amount of $166 million. Fair values are measured using independent third-party information.
During 2019 unrealized gains of $11 million (2018 – unrealized losses of $11 million) were recognized in other income, net.
Interest Rate Swaps
During 2019 ITC entered into forward-starting interest rate swaps to manage the interest rate risk associated with the refinancing of long-term
debt due in June 2021. The swaps have a combined notional value of $260 million and five-year terms with a mandatory early termination
provision. The swaps will be terminated no later than the effective date of November 2020. Fair value was measured using a discounted cash
flow method based on LIBOR rates. Unrealized gains and losses associated with changes in fair value are recognized in other comprehensive
income, will be reclassified to earnings as a component of interest expense over the life of the debt, and were not material for 2019.
52
FORTIS INC. 2019 ANNUAL REPORTManagement Discussion and Analysis Other Investments
ITC, UNS Energy and Central Hudson hold investments in trust associated with supplemental retirement benefit plans for select employees.
These investments consist of mutual funds and money market accounts, which are recorded at fair value based on quoted market prices in
active markets. Gains/losses on these funds are recognized in other income, net and were not material for 2019 and 2018.
Derivative Fair Values
($ millions)
As at December 31, 2019
Assets (2)
Energy contracts subject to regulatory deferral
Energy contracts not subject to regulatory deferral
Foreign exchange contracts, interest rate and total
return swaps
Other investments
Liabilities (3)
Energy contracts subject to regulatory deferral
Energy contracts not subject to regulatory deferral
As at December 31, 2018
Assets (2)
Energy contracts subject to regulatory deferral
Energy contracts not subject to regulatory deferral
Other investments
Liabilities (3)
Energy contracts subject to regulatory deferral
Energy contracts not subject to regulatory deferral
Foreign exchange contracts, interest rate and total
return swaps
Level 1(1)
Level 2(1)
Level 3(1)
Total
–
–
14
121
135
(1)
–
(1)
–
–
155
155
–
–
(8)
(8)
22
8
4
–
34
(138)
(12)
(150)
33
13
–
46
(86)
(1)
(1)
(88)
–
–
–
–
–
–
–
–
8
3
–
11
(3)
–
–
(3)
22
8
18
121
169
(139)
(12)
(151)
41
16
155
212
(89)
(1)
(9)
(99)
(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
measurement. At December 31, 2019, all level 3 assets and liabilities transferred to level 2 because observable market data became available.
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.
(2)
Derivative Volumes (1)
As at December 31
Energy contracts subject to regulatory deferral
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
Wholesale trading contracts (GWh)
Gas swap contracts (PJ)
(1) Energy contracts settle on various dates through 2029.
2019
628
3,198
168
241
1,855
43
2018
774
651
203
266
1,440
37
53
FORTIS INC. 2019 ANNUAL REPORTManagement Discussion and Analysis
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 (1)
Series H
Series I (2)
Series J
Series K (3)
Series M (4)
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
0.9821
1.0135
2018
8,390
1,286
1,100
2.59
2.59
53,051
23,159
1.750
1.2250
1.0345
0.6250
0.7116
1.1875
1.0000
1.0250
2017
8,301
1,125
963
2.32
2.31
47,822
20,691
1.650
1.2250
0.9708
0.6250
0.5262
1.1875
1.0000
1.0250
(1)
The annual dividend per share was reset from $0.9708 to $1.0983 for the five-year period from September 1, 2018 up to but excluding September 1, 2023.
(2) Floating quarterly dividend rate is reset every quarter based on the then current three-month Government of Canada Treasury Bill rate plus the applicable reset dividend yield.
(3) The annual dividend per share was reset from $1.0000 to $0.9823 for the five-year period from March 1, 2019 up to but excluding March 1, 2024.
(4)
The annual dividend per share was reset from $1.0250 to $0.9783 for the five-year period from December 1, 2019 up to but excluding December 1, 2024.
2019/2018
For a discussion of the changes in revenue, net earnings, Common Equity Earnings, EPS, total assets and long-term debt refer to “Performance
at a Glance” on page 20, “Operating Results” on page 24, and “Financial Position” on page 32.
2018/2017
The 2018/2017 increase in revenue reflects: (i) higher wholesale electricity sales at UNS Energy driven by an increase in system capacity; and
(ii) the flow through in 2018 customer rates of higher overall energy supply costs. The increase was partially offset by: (i) the recovery of lower
income tax expense due to US tax reform; (ii) mark-to-market accounting adjustments for natural gas derivatives at Aitken Creek; and (iii) a
change in presentation of certain revenues to a net basis upon implementation of ASC 606, Revenue from Contracts with Customers, in 2018.
The 2018/2017 increase in earnings primarily reflects growth at both the regulated and non-regulated businesses, as well as lower income tax
expense, partially offset by one-time favourable adjustments recognized in 2017. Earnings in 2018 were also tempered by the ongoing impact
of US tax reform and a lower ROE incentive adder at ITC effective April 2018.
The 2018/2017 increase in EPS reflects the above-noted earnings increases, partially offset by a 9.2 million increase in the weighted average
number of common shares outstanding associated with the Corporation’s DRIP.
The 2018/2017 increase in total assets was due to the impact of 2018 capital expenditures and foreign exchange on the translation of
US dollar-denominated assets.
54
FORTIS INC. 2019 ANNUAL REPORTManagement Discussion and Analysis
FOURTH QUARTER RESULTS
Sales
Fourth quarters ended December 31
Regulated Utilities
UNS Energy
Retail electricity (GWh)
Wholesale electricity (GWh)
Gas (PJ)
Central Hudson
Electricity (GWh)
Gas (PJ)
FortisBC Energy (PJ)
FortisAlberta (GWh)
FortisBC Electric (GWh)
Other Electric (GWh)
Non-Regulated
Energy Infrastructure (GWh)
2019
2018
Variance
2,223
1,814
5
1,188
6
71
4,279
888
2,427
14
2,225
2,526
5
1,250
7
63
4,343
839
2,450
85
(2)
(712)
–
(62)
(1)
8
(64)
49
(23)
(71)
The decrease in wholesale electricity sales was due primarily to a decrease in system capacity at Gila River Unit 2 resulting from an outage.
The increase in gas volumes at FortisBC Energy was due to higher average consumption by residential and commercial customers due to
colder temperatures that increased heating load and higher consumption by transportation customers.
Revenue and Common Equity Earnings
Fourth quarters ended December 31
Revenue
Common Equity Earnings
2019
2018
Variance
2019
2018
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
Inter-segment eliminations
Total
500
510
226
428
150
112
381
19
–
–
390
541
234
371
140
111
372
50
–
(3)
2,326
2,206
110
(31)
(8)
57
10
1
9
(31)
–
3
120
171
38
30
77
33
12
22
6
(43)
–
346
447.1
0.77
92
27
24
72
22
13
22
22
(33)
–
261
427.5
0.61
79
11
6
5
11
(1)
–
(16)
(10)
–
85
19.6
0.16
Weighted average number of common shares outstanding (millions)
Basic EPS ($)
The increase in revenue was driven by the $91 million favourable adjustment to revenue at ITC associated with the November 2019 FERC
Order (see “Regulatory Highlights” on page 30) and higher revenue at FortisBC Energy due to overall higher flow-through costs. The increase
was partially offset by lower revenue at UNS Energy due to lower short-term wholesale sales and lower revenue in the Energy Infrastructure
segment due to the disposition of the Waneta Expansion in April 2019 (see “Significant Items” on page 20) and lower hydroelectric
production in Belize.
The increase in Common Equity Earnings was due primarily to the November 2019 FERC Order at ITC, along with Rate Base growth at the
regulated utilities.
The increase in basic EPS reflects higher Common Equity Earnings, partially offset by a 19.6 million increase in the weighted average number
of common shares outstanding associated with the Corporation’s common equity offering (see “Significant Items” on page 20), DRIP and
ATM Program.
55
FORTIS INC. 2019 ANNUAL REPORTManagement Discussion and Analysis
Cash Flows
Fourth quarters ended December 31
($ millions)
Cash, beginning of period
Cash provided by (used in):
Operating activities
Investing activities
Financing activities
Foreign exchange
Cash associated with assets held for sale
Cash, end of period
Operating Activities
2019
228
634
(1,104)
627
(15)
–
370
2018
195
537
(999)
598
16
(15)
332
Variance
33
97
(105)
29
(31)
15
38
The variance was due to higher cash earnings at the regulated subsidiaries, led by ITC, partially offset by unfavourable changes in working capital
due primarily to timing differences.
Investing Activities
The variance reflects higher capital spending, mainly at UNS Energy, in accordance with the Corporation’s capital plan.
Financing Activities
The variance reflects the issuance of common shares and redemption of Corporate debt (see “Cash Flow Summary” on page 34).
SUMMARY OF QUARTERLY RESULTS
Quarter Ended
December 31, 2019
September 30, 2019
June 30, 2019
March 31, 2019
December 31, 2018
September 30, 2018
June 30, 2018
March 31, 2018
Revenue
($ millions)
2,326
2,051
1,970
2,436
2,206
2,040
1,947
2,197
Common Equity
Earnings
($ millions)
346
278
720
311
261
276
240
323
Basic EPS
($)
0.77
0.64
1.66
0.72
0.61
0.65
0.57
0.77
Diluted EPS
($)
0.77
0.63
1.66
0.72
0.61
0.65
0.57
0.76
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 US are generally highest in the second and third quarters due
to the use of air conditioning and other cooling equipment.
Generally, from one calendar year to the next, quarterly results reflect: (i) continued organic growth driven by the Corporation’s capital plan;
(ii) acquisitions and dispositions; (iii) any significant temperature fluctuations from seasonal norms; (iv) the timing and significance of any
regulatory decisions; (v) for revenue, the flow through in customer rates of commodity costs; and (vi) for EPS, increases in the weighted
average number of common shares outstanding.
December 2019/December 2018
See “Fourth Quarter Results” on page 55.
September 2019/September 2018
Common Equity Earnings increased by $2 million and basic EPS decreased by $0.01, due mainly to Rate Base growth at the regulated utilities,
led by ITC, tempered by: (i) the unfavourable impact of the mark-to-market accounting of natural gas derivatives at Aitken Creek; (ii) lower
hydroelectric production in Belize; and (iii) for EPS, an 11.8 million increase in the weighted average number of common shares outstanding
due to the ATM Program and DRIP.
56
FORTIS INC. 2019 ANNUAL REPORTManagement Discussion and Analysis
June 2019/June 2018
Common Equity Earnings increased by $480 million and basic EPS increased by $1.09, due mainly to: (i) a $484 million gain on the disposition
of the Waneta Expansion; (ii) the favourable impact of the mark-to-market accounting of natural gas derivatives at Aitken Creek; (iii) Rate Base
growth at the regulated utilities, led by ITC; and (iv) favourable foreign exchange of $7 million. The increase was tempered by: (i) lower
retail sales, driven by weather, and higher depreciation and interest expense at UNS Energy; (ii) lower earnings contribution from the
Energy Infrastructure segment due to lower hydroelectric production in Belize; (iii) lower realized margins at Aitken Creek; and (iv) for EPS,
a 9.3 million increase in the weighted average number of common shares outstanding due to the ATM Program and DRIP.
March 2019/March 2018
Common Equity Earnings decreased by $12 million and basic EPS decreased by $0.05, due mainly to: (i) a favourable $30 million
remeasurement of deferred income tax liabilities in 2018 resulting from an election to file a consolidated state income tax return, which offset
earnings growth in 2019. Earnings growth was driven by: (i) strong performance at the regulated utilities due primarily to Rate Base growth;
(ii) increased earnings at Central Hudson associated with its rate order effective July 1, 2018; (iii) higher electricity and gas sales at UNS Energy
due largely to weather; and (iv) favourable foreign exchange of $9 million. The increase was tempered by: (i) lower earnings contribution
from the Energy Infrastructure segment due to lower realized margins and higher unrealized losses on the mark-to-market accounting of
natural gas derivatives at Aitken Creek, along with lower hydroelectric production in Belize; (ii) a lower ROE incentive adder at ITC; and (iii) for
EPS, a 7.5 million increase in the weighted average number of common shares outstanding due mainly to the DRIP.
RELATED-PARTY 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 2019 or 2018. Inter-company balances, transactions and profit are eliminated on
consolidation, except for certain inter-company transactions between non-regulated and regulated entities in accordance with accounting
standards for rate-regulated entities. These related-party transactions include: (i) the lease of gas storage capacity and gas sales by
Aitken Creek to FortisBC Energy; and (ii) the sale of capacity by the Waneta Expansion to FortisBC Electric up to the April 16, 2019 disposition
of the Waneta Expansion. These transactions, which are not eliminated on consolidation, did not have a material impact on consolidated
earnings, financial position or cash flows.
The Corporation periodically provides short-term financing to subsidiaries to support capital expenditures, acquisitions and seasonal working
capital requirements. As at December 31, 2019, there were inter-segment loans outstanding of $279 million (December 31, 2018 – $nil),
payable on demand with a weighted average interest rate of 2.48%. Total interest charged in 2019 was $2 million.
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 US securities
laws. As of December 31, 2019, 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
United States securities laws. Based on that evaluation, the CEO and CFO concluded that such DCP are effective as of December 31, 2019.
Internal Control over Financial Reporting
ICFR is designed by, or under the supervision of, the Corporation’s CEO and CFO and effected by the Corporation’s board 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 US 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, 2019, 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, 2019, the
Corporation’s ICFR was effective.
During the year ended December 31, 2019, 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.
57
FORTIS INC. 2019 ANNUAL REPORTManagement Discussion and Analysis OUTLOOK
Over the long term, Fortis is well positioned 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.
The Corporation’s $18.8 billion five-year capital plan is expected to increase Rate Base from $28.0 billion in 2019 to $34.5 billion by 2022 and
$38.4 billion by 2024, translating into three- and five-year CAGRs of 7.2% and 6.5%, respectively. The five-year capital plan reflects the
continuation of key industry trends including grid modernization and the delivery of cleaner energy. Beyond the base capital plan, Fortis
continues to pursue additional energy infrastructure opportunities. Key opportunities not yet included in the five-year capital plan include:
further expansion of LNG infrastructure in British Columbia; the fully permitted, cross-border, Lake Erie connector electric transmission project
in Ontario; and the acceleration of cleaner energy goals in Arizona.
Fortis expects long-term growth in Rate Base to support continuing growth in earnings and dividends. Fortis is targeting average annual
dividend growth of approximately 6% through 2024. This dividend guidance takes into account many factors, including the expectation of
reasonable outcomes for regulatory proceedings at the Corporation’s utilities, the successful execution of the five-year capital plan, and
management’s continued confidence in the strength of the Corporation’s diversified portfolio of utilities and record of operational excellence.
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 2024; forecast capital
expenditures for 2020 and the period 2020 through 2024, and potential funding sources for the capital plan; forecast Rate Base for 2020 and 2024; the
expectation that Fortis will remain at the forefront of the industry by leveraging its strengths and partnerships; expected timing, outcome and impact
of regulatory filings and decisions; 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 its ability to pay dividends in the
foreseeable future; 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 throughout 2020; the nature,
timing, benefits and expected costs of certain capital projects including the Multi-Value Regional Transmission Projects, Transmission Conversion
Project, Southline Transmission Project, Oso Grande Wind Project, Transmission Integrity Management Capabilities Project, Inland Gas Upgrades
Project, Wataynikaneyap Transmission Power Project and additional opportunities beyond the base plan, including the Lake Erie Connector Project;
the expectation that the adoption of future accounting pronouncements will not have a material adverse impact; and the expectation that capital
investment will support growth in earnings and dividends.
Certain material factors or assumptions have been applied in drawing the conclusions contained in the forward-looking information, including,
without limitation: reasonable regulatory decisions and the expectation of regulatory stability; the implementation of the five-year capital plan;
no material capital project or financing cost overruns; 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.
Forward-looking information involves significant risks, uncertainties and assumptions. 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 2020 include,
but are not limited to: uncertainty regarding the outcome of regulatory proceedings at the Corporation’s utilities; risks associated with climate change
and physical risks; the impact of fluctuations in interest rates; the impact of weather variability and seasonality on heating and cooling loads, gas
distribution volumes and hydroelectric generation; and risks associated with acquisitions and capital projects.
All forward-looking information herein is given as of February 12, 2020. 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.
58
FORTIS INC. 2019 ANNUAL REPORTManagement Discussion and Analysis GLOSSARY
2019 Annual Financial Statements: the Corporation’s audited
consolidated financial statements and notes thereto for the year
ended December 31, 2019
Common Equity Earnings: net earnings attributable to common
equity shareholders
Actual Payout Ratio: dividends per common share divided by
basic EPS
COS Regulation: cost of service regulation
Corporation: Fortis Inc.
Adjusted Basic EPS: Adjusted Common Equity Earnings divided by
the basic weighted average number of common shares outstanding
CPCN: Certificate of Public Convenience and Necessity
Adjusted Common Equity Earnings: net earnings attributable
to common equity shareholders adjusted as shown under
“Non-US GAAP Financial Measures” on page 29
Adjusted Payout Ratio: dividends per common share divided
by Adjusted Basic EPS as shown under “Non-US GAAP Financial
Measures” on page 29
AESO: Alberta Electric System Operator
AFUDC: allowance for funds used during construction
DBRS Morningstar: DBRS Limited
DCP: disclosure controls and procedures
DRIP: dividend reinvestment plan
EPS: earnings per common share
ERM: enterprise risk management
EVP: executive vice president
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.
ALJ: administrative law judge
ASU: Accounting Standards Update
ATM Program: at-the-market common equity program
AUC: Alberta Utilities Commission
BCUC: British Columbia Utilities Commission
BECOL: Belize Electric Company Limited, an indirect wholly owned
subsidiary of Fortis
Belize Electricity: Belize Electricity Limited,
indirectly holds a 33% equity interest
in which Fortis
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
Caribbean Utilities: Caribbean Utilities Company, Ltd., an indirect
approximately 60%-owned (as at December 31, 2019) subsidiary of
Fortis, together with its subsidiary
Central Hudson: CH Energy Group Inc., an indirect wholly owned
subsidiary of Fortis, together with its subsidiaries, including Central
Hudson Gas & Electric Corporation
CEO: Chief Executive Officer of Fortis
CFO: Chief Financial Officer of Fortis
FortisAlberta: FortisAlberta
subsidiary of Fortis
Inc., an
indirect wholly owned
FortisBC Electric: FortisBC
subsidiary of Fortis, together with its subsidiaries
Inc., an
indirect wholly owned
FortisBC Energy: FortisBC Energy Inc., an indirect wholly owned
subsidiary of Fortis, together with its subsidiaries
FortisOntario: FortisOntario Inc., a direct wholly owned subsidiary
of Fortis, together with its subsidiaries
FortisTCI: FortisTCI Limited, an indirect wholly owned subsidiary of
Fortis, together with its subsidiary
FX: foreign exchange associated with the translation of US dollar-
denominated amounts
GHG: greenhouse gas
Gila River Unit 2: UNS Energy’s Gila River natural gas generation
station unit 2
GWh: gigawatt hour(s)
ICFR: internal controls over financial reporting
ITC
Investment Holdings
ITC:
indirect 80.1%-owned
including
subsidiary of Fortis, together with
International Transmission Company, Michigan Electric Transmission
Company, LLC, ITC Midwest LLC, and ITC Great Plains, LLC
its subsidiaries,
Inc., an
59
FORTIS INC. 2019 ANNUAL REPORTManagement Discussion and Analysis
ITC’s MISO Subsidiaries: International Transmission Company,
Michigan Electric Transmission Company, LLC, and ITC Midwest LLC
ROA: rate of return on Rate Base
LIBOR: London Interbank Offered Rate
LNG: liquefied natural gas
kV: kilovolt
ROE: rate of return on common equity
S&P: Standard & Poor’s Financial Services LLC
SEDAR: Canadian System for Electronic Document Analysis and
Retrieval
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, financial position or
liquidity, on a consolidated basis
MD&A: the Corporation’s management discussion and analysis for
the year ended December 31, 2019
MISO: Midcontinent Independent System Operator, Inc.
TSR: total shareholder return, which is a measure of the return
in the form of share price
to common equity shareholders
reinvestment) over a
appreciation and dividends
specified time period in relation to the share price at the beginning
of the period
(assuming
TSX: Toronto Stock Exchange
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.
Moody’s: Moody’s Investor Services, Inc.
US: United States of America
MW: megawatt(s)
US GAAP: accounting principles generally accepted in the US
Newfoundland Power: Newfoundland Power Inc., a direct wholly
owned subsidiary of Fortis
Waneta Expansion: Waneta Expansion hydroelectric generation
facility, in which Fortis held a 51% controlling interest prior to
April 2019
Wataynikaneyap Partnership: Wataynikaneyap Power Limited
Partnership
NOI: notice of inquiry
Non-US GAAP Financial Measures: financial measures that do
not have a standardized meaning prescribed by US GAAP
November 2019 FERC Order: a FERC order issued in November
2019 that reduced the base ROE for ITC’s MISO Subsidiaries
NYSE: New York Stock Exchange
OEB: Ontario Energy Board
OPEB: other post-employment benefits
Operating Cash Flows: cash from operating activities
PBR: performance-based rate-setting
PJ: petajoule(s)
PPA: power purchase agreement
Q3 2019 MD&A: interim management discussion and analysis for
the three and nine months ended September 30, 2019
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
60
FORTIS INC. 2019 ANNUAL REPORTManagement Discussion and Analysis Financials
Table of Contents
Management’s Report on Internal Control
NOTE 10 Other Assets ......................................................................................................86
over Financial Reporting ..............................................................................................61
Report of Independent Registered Public Accounting Firm –
Opinion on the Financial Statements ..................................................................62
Report of Independent Registered Public Accounting Firm –
Opinion on Internal Control over Financial Reporting .............................64
NOTE 11 Property, Plant and Equipment ............................................................86
NOTE 12
Intangible Assets ............................................................................................88
NOTE 13 Goodwill ..............................................................................................................88
NOTE 14 Accounts Payable and Other Current Liabilities ........................88
Consolidated Balance Sheets ..........................................................................................65
NOTE 15 Long-Term Debt .............................................................................................89
Consolidated Statements of Earnings ........................................................................66
NOTE 16 Leases ....................................................................................................................92
Consolidated Statements of Comprehensive Income ....................................66
NOTE 17 Other Liabilities ...............................................................................................94
Consolidated Statements of Cash Flows ..................................................................67
NOTE 18 Common Shares.............................................................................................95
Consolidated Statements of Changes in Equity ..................................................68
NOTE 19 Earnings Per Common Share .................................................................95
Notes to Consolidated Financial Statements
NOTE 20 Preference Shares ..........................................................................................95
NOTE 1
Description of Business .............................................................................69
NOTE 21 Accumulated Other Comprehensive Income .............................97
NOTE 2
Regulation ..........................................................................................................70
NOTE 22 Stock-Based Compensation Plans ......................................................98
NOTE 3
Summary of Significant Accounting Policies ...............................74
NOTE 23 Disposition ......................................................................................................100
NOTE 4
Future Accounting Pronouncements ...............................................80
NOTE 24 Other Income, Net .....................................................................................101
NOTE 5
Segmented Information............................................................................80
NOTE 25
Income Taxes .................................................................................................101
NOTE 6
Revenue ...............................................................................................................82
NOTE 26 Employee Future Benefits .....................................................................103
NOTE 7
Accounts Receivable and Other Current Assets ........................83
NOTE 27 Supplementary Cash Flow Information .......................................108
NOTE 8
Inventories .........................................................................................................83
NOTE 28 Fair Value of Financial Instruments
NOTE 9
Regulatory Assets and Liabilities .........................................................84
and Risk Management ......................................................................108
NOTE 29 Commitments and Contingencies ..................................................112
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, 2019, 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, 2019, the Corporation’s ICFR was effective.
The Corporation’s ICFR as of December 31, 2019 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, 2019. Deloitte LLP issued an unqualified opinion for
both audits.
February 12, 2020
Barry V. Perry
President and Chief Executive Officer, Fortis Inc.
Jocelyn H. Perry
Executive Vice President, Chief Financial Officer, Fortis Inc.
St. John’s, Canada
61
FORTIS INC. 2019 ANNUAL REPORT 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, 2019 and
2018, 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, 2019, 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, 2019 and 2018, and the results of its operations
and its cash flows for each of the two years in the period ended December 31, 2019, 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, 2019, 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 12, 2020, 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 13 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 the reporting units included
the following, among others:
• 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.
62
FORTIS INC. 2019 ANNUAL REPORTFinancials Impact of Rate Regulation on the Financial Statements – Refer to Notes 2, 3 and 9 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 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 12, 2020
We have served as the Corporation’s auditor since 2017.
63
FORTIS INC. 2019 ANNUAL REPORTFinancials 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, 2019, 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, 2019, 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 at and for the year ended December 31, 2019, of the Corporation and our report dated February 12, 2020,
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 12, 2020
64
FORTIS INC. 2019 ANNUAL REPORTFinancials 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 7)
Prepaid expenses
Inventories (Note 8)
Regulatory assets (Note 9)
Assets held for sale (Note 23)
Total current assets
Other assets (Note 10)
Regulatory assets (Note 9)
Property, plant and equipment, net (Note 11)
Intangible assets, net (Note 12)
Goodwill (Note 13)
Total assets
LIABILITIES AND EQUITY
Current liabilities
Short-term borrowings (Note 15)
Accounts payable and other current liabilities (Note 14)
Regulatory liabilities (Note 9)
Current installments of long-term debt (Note 15)
Current installments of finance leases (Note 16)
Liabilities associated with assets held for sale (Note 23)
Total current liabilities
Other liabilities (Note 17)
Regulatory liabilities (Note 9)
Deferred income taxes (Note 25)
Long-term debt (Note 15)
Finance leases (Note 16)
Total liabilities
Commitments and contingencies (Note 29)
Equity
Common shares (Note 18) (1)
Preference shares (Note 20)
Additional paid-in capital
Accumulated other comprehensive income (Note 21)
Retained earnings
Shareholders’ equity
Non-controlling interests
Total equity
Total liabilities and equity
$
2019
370
1,297
88
394
425
–
2,574
620
2,958
33,988
1,260
12,004
$
2018
332
1,357
84
398
324
766
3,261
552
2,751
32,757
1,200
12,530
$ 53,404
$
53,051
$
512
2,378
572
690
24
–
4,176
1,446
2,786
2,969
21,501
413
33,291
13,645
1,623
11
336
2,916
18,531
1,582
20,113
$
60
2,289
656
926
252
69
4,252
1,138
2,970
2,686
23,159
390
34,595
11,889
1,623
11
928
2,082
16,533
1,923
18,456
$ 53,404
$
53,051
(1) No par value. Unlimited authorized shares; 463.3 million and 428.5 million
issued and outstanding as at December 31, 2019 and 2018, respectively
Approved on Behalf of the Board
See accompanying Notes to Consolidated Financial Statements
Douglas J. Haughey,
Director
Tracey C. Ball,
Director
65
FORTIS INC. 2019 ANNUAL REPORTFinancials
CONSOLIDATED STATEMENTS OF EARNINGS
FORTIS INC.
For the years ended December 31 (in millions of Canadian dollars, except per share amounts)
Revenue (Note 6)
Expenses
Energy supply costs
Operating expenses
Depreciation and amortization
Total expenses
Gain on disposition (Note 23)
Operating income
Other income, net (Note 24)
Finance charges
Earnings before income tax expense
Income tax expense (Note 25)
Net earnings
Net earnings attributable to:
Non-controlling interests
Preference equity shareholders
Common equity shareholders
Earnings per common share (Note 19)
Basic
Diluted
2019
$
8,783
2,520
2,452
1,350
6,322
577
3,038
138
1,035
2,141
289
$
1,852
$
130
67
1,655
$
1,852
$
$
3.79
3.78
See accompanying Notes to Consolidated Financial Statements
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
FORTIS INC.
For the years ended December 31 (in millions of Canadian dollars)
Net earnings
Other comprehensive (loss) income
Unrealized foreign currency translation (losses) gains, net of hedging activities and
income tax (expense) recovery of $(13) million and $11 million, respectively
Other, net of income tax recovery (expense) of $5 million and $(2) million, respectively
Comprehensive income
Comprehensive income attributable to:
Non-controlling interests
Preference equity shareholders
Common equity shareholders
See accompanying Notes to Consolidated Financial Statements
2019
$
1,852
(660)
(7)
(667)
$
1,185
$
55
67
1,063
$
1,185
2018
8,390
2,495
2,287
1,243
6,025
–
2,365
60
974
1,451
165
1,286
120
66
1,100
1,286
2.59
2.59
2018
1,286
985
6
991
2,277
244
66
1,967
2,277
$
$
$
$
$
$
$
$
$
$
66
FORTIS INC. 2019 ANNUAL REPORTFinancials
CONSOLIDATED STATEMENTS OF CASH FLOWS
FORTIS INC.
For the years ended December 31 (in millions of Canadian dollars)
2019
2018
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 25)
Equity component, allowance for funds used during construction (Note 24)
Gain on disposition (Note 23)
Other
Change in long-term regulatory assets and liabilities
Change in working capital (Note 27)
Cash from operating activities
Investing activities
Capital expenditures – property, plant and equipment
Capital expenditures – intangible assets
Contributions in aid of construction
Proceeds on disposition (Note 23)
Other
Cash used in investing activities
Financing activities
Proceeds from long-term debt, net of issuance costs (Note 15)
Repayments of long-term debt, net of extinguishment costs, 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 (Note 18)
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 change in cash associated with assets held for sale
Cash and cash equivalents, beginning of year
Cash and cash equivalents, end of year
Supplementary Cash Flow Information (Note 27)
See accompanying Notes to Consolidated Financial Statements
$
1,852
$
1,286
1,199
125
26
247
(74)
(583)
145
(106)
(168)
2,663
(3,499)
(221)
102
995
(145)
(2,768)
937
(1,676)
5,892
(6,290)
472
1,442
(494)
(67)
(73)
11
154
(26)
23
15
332
370
$
1,107
106
30
136
(64)
–
92
13
(102)
2,604
(3,032)
(186)
106
–
(140)
(3,252)
1,566
(563)
5,666
(5,523)
38
34
(459)
(66)
(85)
36
644
24
20
(15)
327
332
$
67
FORTIS INC. 2019 ANNUAL REPORTFinancials
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
Accumulated
Other
Common Common Preference Additional Comprehensive
FORTIS INC.
For the years ended December 31, 2019 and 2018
(in millions of Canadian dollars,
except share numbers)
As at December 31, 2018
Net earnings
Other comprehensive loss
Common shares issued
Subsidiary dividends paid to
non-controlling interests
Dividends declared on common shares
($1.855 per share)
Dividends declared on preference shares
Disposition (Note 23)
Other
Shares
(# millions)
Shares
(Note 18)
428.5 $ 11,889
–
–
1,756
–
–
34.8
Shares
(Note 20)
$ 1,623
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
As at December 31, 2019
463.3 $ 13,645
$ 1,623
As at December 31, 2017
Net earnings
Other comprehensive income
Common shares issued
Subsidiary dividends paid to
non-controlling interests
Dividends declared on common
shares ($1.75 per share)
Dividends declared on preference shares
Other
421.1 $ 11,582
–
–
307
–
–
7.4
$ 1,623
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
Paid-In
Capital
$
$
$
11
–
–
(5)
–
–
–
–
5
11
10
–
–
(1)
–
–
–
2
Non-
Income (Loss) Retained Controlling
Interests
(Note 21) Earnings
Total
Equity
$
928 $ 2,082
1,722
–
–
–
(592)
–
$ 1,923 $ 18,456
1,852
(667)
1,751
130
(75)
–
–
–
–
–
–
–
(73)
(73)
(821)
(67)
–
–
–
–
(318)
(5)
(821)
(67)
(318)
–
$
$
336 $ 2,916
$ 1,582 $ 20,113
61 $ 1,727
1,166
–
–
867
–
–
$ 1,746 $ 16,749
1,286
991
306
120
124
–
–
–
–
–
–
(85)
(85)
(745)
(66)
–
–
–
18
(745)
(66)
20
As at December 31, 2018
428.5 $ 11,889
$ 1,623
$
11
$
928 $ 2,082
$ 1,923 $ 18,456
See accompanying Notes to Consolidated Financial Statements
68
FORTIS INC. 2019 ANNUAL REPORTFinancials
Notes to Consolidated Financial Statements
For the years ended December 31, 2019 and 2018
1. DESCRIPTION OF BUSINESS
Fortis Inc. (“Fortis” or the “Corporation”) is principally a North American regulated electric and gas utility holding company. Entities within the
reporting segments that follow operate with substantial autonomy.
Regulated Utilities
ITC
Comprised of 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
Comprised of 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 3,143 megawatts (“MW”), including 59 MW of solar 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 includes primarily 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
Comprised of FortisBC Energy Inc., which is the largest regulated distributor of natural gas in British Columbia, providing 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
Comprised of FortisBC Inc., 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
in eastern Canada and the Caribbean, as
Comprised of utilities
(“Newfoundland Power”);
Maritime Electric Company, Limited (“Maritime Electric”); FortisOntario Inc. (“FortisOntario”); a 39% equity investment in Wataynikaneyap Power Limited
Partnership (“Wataynikaneyap Partnership”) (Note 10); 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”) (Note 10).
follows: Newfoundland Power
Inc.
69
FORTIS INC. 2019 ANNUAL REPORT
1.
DESCRIPTION OF BUSINESS (cont’d)
Regulated Utilities (cont’d)
Other Electric (cont’d)
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 140 MW. FortisOntario is comprised 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 of connecting remote First Nations communities to the electricity grid in Ontario through the development of new
transmission lines.
In January 2019 Fortis reduced its equity investment in Wataynikaneyap Partnership from 49% to 39% to facilitate the inclusion of two additional
First Nations communities into the partnership.
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 is comprised of two integrated regulated electric utilities that provide electricity to certain Turks and Caicos Islands
and has a diesel-powered generating capacity of 91 MW. Belize Electricity is an integrated electric utility and the principal distributor of
electricity in Belize.
Non-Regulated
Energy Infrastructure
Comprised of 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 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. The long-term
contracted generation assets in British Columbia, the Waneta Expansion hydroelectric generating facility (“Waneta Expansion”), were sold on
April 16, 2019 (Note 23).
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.
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”).
Under PBR mechanisms, formulae are generally applied that incorporate 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 9).
ITC
ITC is regulated by the Federal Energy Regulatory Commission (“FERC”) under the Federal Power Act (United States). Rates are set annually, using
FERC-approved cost-based formula rate templates, and remain in effect for one year, which provides timely cost recovery. An annual true-up
mechanism compares actual revenue requirements to billed revenues, and any variances are accrued and reflected in future rates within a two-year
period. The formula rates do not require annual FERC approvals, although inputs remain subject to legal challenge by customers with FERC. ITC’s
allowed ROE ranged from 9.88% up to a maximum of 12.24% with incentive adders on a capital structure of 60% common equity for 2019 and 2018,
reflecting the impact of a November 2019 order discussed below under “ROE Complaints”.
70
For the years ended December 31, 2019 and 2018FORTIS INC. 2019 ANNUAL REPORTNotes to Consolidated Financial Statements Incentive Adder Complaint
In April 2018 a third-party complaint was filed with FERC challenging the independence incentive adders that are included in transmission rates
charged by ITCTransmission, METC and ITC Midwest (collectively, “ITC’s MISO Subsidiaries”), which operate in the Midcontinent Independent System
Operator (“MISO”) region. The adder allowed up to 0.50% or 1.00% to be added to the authorized ROE, subject to any ROE cap established by FERC.
In October 2018 FERC issued an order reducing the adders to 0.25%, effective April 20, 2018. This equated to a 0.25% decrease in ROE, down from
the approximate 0.50% that ITC was earning in rates previously approved by FERC. ITC began reflecting the 0.25% adder in transmission rates in
November 2018. ITC’s MISO Subsidiaries sought rehearing of this order in 2018, which was denied by FERC. In September 2019 ITC’s MISO Subsidiaries
filed an appeal in the U.S. Court of Appeal. The final resolution of this matter is not expected to have a material impact on the Corporation’s earnings
or cash flows.
ROE Complaints
Two third-party complaints requested that the base ROE for MISO transmission owners, including ITC’s MISO Subsidiaries, be found to no longer be
just or reasonable. The complaints cover two consecutive 15-month periods from November 2013 through February 2015 (the “Initial Refund Period”
or “Initial Complaint”) and February 2015 through May 2016 (the “Second Refund Period” or “Second Complaint”).
In June 2016 the presiding Administrative Law Judge (“ALJ”) issued an initial decision on the Second Complaint, recommending a base ROE of 9.70%,
up to a maximum of 10.68% with incentive adders. Pending an order from FERC, an estimated regulatory liability of $206 million (US$151 million) had
been recognized as at December 31, 2018 based on the ALJ’s initial decision (Note 9).
In September 2016 FERC ordered that the base ROE for the Initial Refund Period be set at 10.32%, down from 12.38%, up to a maximum of 11.35%
with incentive adders. The resultant rates applied prospectively from September 2016 until an approved ROE was established for the Second Refund
Period. The total refund for the Initial Complaint as a result of the September 2016 FERC order was $158 million (US$118 million), including interest,
and was paid in 2017.
In November 2019 FERC issued a decision on ITC’s ROE Complaints (“November 2019 FERC Order”), which determined that the base ROE for
the Initial Complaint and from September 2016 onward be 9.88%, up to a maximum of 12.24% with incentive adders. FERC also dismissed the
Second Complaint, resulting in a ROE for that period of 12.38% plus incentive adders with no refund required. In addition, as a ROE complaint had not
been filed for the period of May 2016 to September 2016, the ROE for that period continued to be 12.38% plus incentive adders with no refund
required. The regulated utilities in the MISO region, including ITC, sought rehearing of this order on the basis that it will not allow utilities to earn
a reasonable rate of return on investment. In January 2020 FERC issued an order granting the rehearing for further consideration, effectively
extending FERC’s review.
As at December 31, 2019, a regulatory liability of $91 million (US$70 million) was recognized related to the impact of the November 2019 FERC Order
on the Initial Refund Period and for the period from September 2016 to December 2019 (Note 9). Additionally, the regulatory liability of $206 million
(US$151 million) as at December 31, 2018 (Note 9), related to the Second Complaint, was reversed in 2019. The net impact of the November 2019 FERC
Order was an increase in revenue and a decrease in interest expense resulting in an increase in net earnings of $79 million of which Fortis’ share was
$63 million. The favourable impact was comprised of: (i) $83 million related to the net reversal of liabilities established in prior periods; partially offset
by (ii) $20 million related to the 2019 impact of a reduced ROE.
Based on the outcome of the request for rehearing, it is possible the ROE and refunds could materially change from those recognized in 2019.
Notices of Inquiry
In March 2019 FERC issued a notice of inquiry (“NOI”) seeking comments on whether and how to improve its electric transmission incentives policy.
The outcome may impact the existing incentive adders that are included in transmission rates charged by transmission owners, including ITC. Also in
March 2019, FERC issued a second NOI seeking comments on whether and how recent policies concerning the determination of the base ROE for
electric utilities should be modified. The comment period for both NOI proceedings has ended. The outcome may impact ITC’s future ROE and
incentive adders.
UNS Energy
UNS Energy is regulated by the Arizona Corporation Commission (“ACC”) and certain activities are subject to regulation by FERC under the Federal
Power Act (United States). UNS Energy uses a historical test year to establish retail electricity and gas rates.
TEP’s rates reflect an allowed ROE of 9.75% on a capital structure of approximately 50% common equity. Effective August 1, 2016, UNS Electric’s rates
reflect an allowed ROE of 9.5% on a capital structure of 52.8% common equity. Effective May 1, 2012, UNS Gas’ rates reflect an allowed ROE of 9.75%
on a capital structure of 50.8% common equity.
71
FORTIS INC. 2019 ANNUAL REPORTNotes to Consolidated Financial Statements 2.
REGULATION (cont’d)
UNS Energy (cont’d)
General Rate Application
In April 2019 TEP filed a general rate application with the ACC requesting an increase in non-fuel revenue of US$99 million, effective May 1, 2020,
with electricity rates based on a 2018 historical test year. Intervenor testimony in relation to TEP’s revenue requirement and rate design was filed
in October 2019. The application, adjusted for rebuttal testimony filed by TEP in November 2019, includes a request to increase TEP’s allowed ROE
to 10.00% from 9.75% and the equity component of its capital structure to 53% from 50% on a rate base of US$2.7 billion. Hearings before the ALJ
commenced in January and a decision is expected by mid-2020.
Central Hudson
Central Hudson is regulated by the New York State Public Service Commission (“PSC”) and certain activities are subject to regulation by FERC under
the Federal Power Act (United States). Central Hudson uses a future test year to establish rates.
Pursuant to a three-year settlement agreement arising from a 2017 general rate application, Central Hudson’s rates reflect an allowed ROE of
8.8% on a capital structure of 48%, 49% and 50% common equity as of July 1, 2018, 2019 and 2020, respectively. Prior thereto, effective July 1, 2015,
Central Hudson’s allowed ROE was 9.0% on a capital structure of 48% common equity.
Central Hudson is also subject to an earnings sharing mechanism whereby the Company and its customers share equally earnings between 50 and
100 basis points above the allowed ROE. Earnings beyond that are primarily returned to customers.
FortisBC Energy and FortisBC Electric
FortisBC Energy and FortisBC Electric are regulated by the British Columbia Utilities Commission (“BCUC”) pursuant to the Utilities Commission Act
(British Columbia), and are subject to multi-year PBR plans whereby a going-in revenue requirement is first established and used to set initial rates
and thereafter a prescribed formula is applied annually to the previous year’s rates to establish new rates for the remainder of the multi-year period.
The PBR plans for the most recent term of 2014 through 2019 incorporate incentive mechanisms for improving operating and capital expenditure
efficiencies. Operation and maintenance expenses and base capital expenditures during the PBR period are subject to an incentive formula
reflecting incremental costs for inflation and half of customer growth, less a fixed productivity adjustment factor of 1.1% for FortisBC Energy
and 1.03% for FortisBC Electric each year. The approved PBR plans also include a 50/50 sharing of variances from the formula-driven operation
and maintenance expenses and capital expenditures over the PBR period, and a number of service quality measures designed to ensure
FortisBC Energy and FortisBC Electric maintain specified service levels.
FortisBC Energy is the benchmark utility in British Columbia, as designated by the BCUC, and effective January 1, 2016, its rates reflected an allowed
ROE of 8.75% on a capital structure of 38.5% common equity. Effective January 1, 2016, FortisBC Electric’s rates reflected an allowed ROE of 9.15% on
a capital structure of 40% common equity.
In March 2019 FortisBC Energy and FortisBC Electric filed applications with the BCUC requesting approval of a multi-year rate plan and PBR
methodology for 2020–2024. A decision is expected in mid-2020.
FortisAlberta
FortisAlberta is regulated by the Alberta Utilities Commission (“AUC”) pursuant to the Electric Utilities Act (Alberta), the Public Utilities Act (Alberta), the
Hydro and Electric Energy Act (Alberta) and the Alberta Utilities Commission Act (Alberta). FortisAlberta is subject to multi-year PBR plans for 2018–2022
whereby a going-in revenue requirement is first established and used to set initial rates and thereafter a prescribed formula is applied annually to the
previous year’s rates to establish new rates for the remainder of the multi-year period.
The PBR plans include mechanisms for the recovery or settlement of items determined to flow through directly to customers (“Y factor”) and the
recovery of costs related to capital expenditures that are not being recovered through the formula (“capital tracker” or “K-bar”). It also includes
a Z factor, a PBR re-opener, and an efficiency carry-over mechanism. The Z factor permits an application for recovery of costs, subject to certain
thresholds, related to significant unforeseen events. The PBR re-opener permits, subject to certain thresholds, an application to re-open and review
the PBR plan to address specific problems with its design or operation. The efficiency carry-over mechanism provides an efficiency incentive by
permitting the Company to continue to benefit from any efficiency gains achieved during the PBR term for two years following the end of that term.
Pursuant to generic cost of capital proceedings completed in 2018, FortisAlberta’s rates reflect an allowed ROE of 8.5% on a capital structure of 37%
common equity for 2018–2020, unchanged from 2017.
72
For the years ended December 31, 2019 and 2018FORTIS INC. 2019 ANNUAL REPORTNotes to Consolidated Financial Statements Second-Term Performance-Based Rate-Setting Proceeding
The AUC has ongoing proceedings to review regulatory applications for rebasing inputs included in PBR rates for 2018–2022, including anomaly-
related adjustments and approved changes to depreciation parameters.
In January 2020 the AUC issued two decisions: (i) confirming that changes to depreciation parameters will be incorporated into incremental funding
mechanisms; and (ii) establishing new criteria for anomaly-related adjustments. PBR utilities in Alberta are permitted to file depreciation studies
by July 2020 and were required to submit their intent to file an anomaly-related adjustment application by February 7, 2020. FortisAlberta does not
anticipate filing a depreciation study in 2020 and did notify the AUC of its intent to file an anomaly-related adjustment application.
Generic Cost of Capital Proceeding
In December 2018 the AUC initiated a generic cost of capital proceeding to consider a formula-based approach to setting the allowed ROE
beginning in 2021 and whether any process changes are necessary for determining capital structure in years in which a ROE formula is in place. In
April 2019 the AUC determined that a traditional non-formulaic approach for assessing ROE and deemed capital structure would be used in 2021,
with consideration of a formula-based approach for determining the allowed ROE for 2022 and subsequent years. Expert evidence was filed in
January 2020 with an oral hearing scheduled for April 2020. An AUC decision is expected later in 2020.
2018 Alberta Independent System Operator Tariff Application
In September 2019 the AUC issued a decision that addressed, among other things, a proposal to change how the Alberta Electric System Operator’s
customer contribution policy is accounted for between distribution facility owners, such as FortisAlberta, and transmission facility owners (“TFO”).
The decision prevents any future investment by FortisAlberta under the policy and directs that the unamortized customer contributions of
approximately $400 million as at December 31, 2017, which form part of FortisAlberta’s rate base, be transferred to the incumbent TFO in
FortisAlberta’s service area.
In October 2019 FortisAlberta filed evidence to oppose the decision. Implementation of the order has been suspended and the decision remains
under review by the AUC. It is expected that the decision will remain under review through the first quarter of 2020. The likely outcome of this
process and potential impacts, if any, cannot be determined at this time.
Other Electric
Newfoundland Power is regulated by the Newfoundland and Labrador Board of Commissioners of Public Utilities under the Public Utilities Act
(Newfoundland and Labrador) and uses a future test year to establish rates. Effective 2019 to 2020, and consistent with 2018, Newfoundland Power’s
rates reflect an allowed ROE of 8.5% on a capital structure of 45% common equity.
Maritime Electric is regulated by the Island Regulatory and Appeals Commission under the provisions of the Electric Power Act (PEI), the Renewable
Energy Act (PEI) and the Electric Power (Electricity Rate-Reduction) Amendment Act (PEI), and uses a future test year to establish rates. Effective March 1, 2019
for a three-year period, and consistent with 2018, Maritime Electric’s rates reflect an allowed ROE of 9.35% on a capital structure of 40% common equity.
FortisOntario’s three electric utilities are regulated by the Ontario Energy Board under the Electricity Act (Ontario) and the Ontario Energy Board Act
(Ontario). Two of FortisOntario’s utilities use a future test year to establish rates under five-year PBR plans whereby a going-in revenue requirement is
first established and used to set initial rates and thereafter a prescribed formula using inflationary factors less an efficiency target is applied annually
to the previous year’s rates to establish new rates for the remainder of the five-year period. The allowed ROEs ranged from 8.78% to 9.30% for both
2019 and 2018, on a capital structure of 40% common equity. FortisOntario’s remaining utility is subject to a 35-year franchise agreement, expiring in
2033, whereby rates are based on a price cap with commodity cost flow through and with the base revenue requirement adjusted annually for
inflation, load growth and customer growth.
Caribbean Utilities 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. It is regulated under a rate-cap adjustment mechanism based on published consumer price indices. The licences detail the role
of the Cayman Islands Utility Regulation and Competition Office, which oversees all licences, establishes and enforces licence standards, reviews
the rate-cap adjustment mechanism, and annually approves capital expenditures. Its allowed ROA for 2019 was in the range of 7.50% to 9.50%
(7.00% to 9.00% for 2018).
FortisTCI operates under 50-year licences from the Government of the Turks and Caicos Islands, which expire in 2036 and 2037. Rates reflect a
historical test year and a targeted allowed ROA of between 15.0% and 17.5% (the “Allowable Operating Profit”). The Allowable Operating Profit is
based on a calculated rate base, including interest on the cumulative amount by which actual operating profits fall short of the Allowable Operating
Profit (the “Cumulative Shortfall”). The calculated Allowable Operating Profit and Cumulative Shortfall are submitted to the Government annually.
The recovery of the Cumulative Shortfall is dependent on future sales volumes and expenses. The achieved ROAs at the utilities have been
significantly lower than those allowed as a result of the inability, due to economic and political factors, to increase rates to support significant
capital investment in recent years.
73
FORTIS INC. 2019 ANNUAL REPORTNotes to Consolidated Financial Statements 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 (“US 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, and a controlled variable interest entity up
to the date of its disposition on April 16, 2019 (Note 23). 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 US 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.
Allowance for Doubtful Accounts
Fortis and each subsidiary, other than ITC, maintain an allowance for doubtful accounts that is estimated based on a variety of factors, including
receivables aging, historical experience, specific events such as customer bankruptcy and economic conditions. ITC recognizes losses for uncollectible
accounts based upon their specific identification. 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) an obligation 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 asset removal costs not identified as a legal
obligation. The provision is recognized as a long-term regulatory liability (Note 9) against which actual asset removal costs are netted when incurred.
Most of 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 totalling $40 million (2018 – $31 million) is reported as a reduction of finance charges and the equity
component is reported as other income (Note 24). Both components are charged to earnings through depreciation expense over the estimated
service lives of the applicable PPE.
74
For the years ended December 31, 2019 and 2018FORTIS INC. 2019 ANNUAL REPORTNotes to Consolidated Financial Statements At FortisAlberta the cost of PPE includes required contributions to the Alberta Electric System Operator (“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 regulator, 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 2019 ranged from 0.9% to 35.0% (2018 – 0.9% to 34.6%). The weighted average
composite rate of depreciation, before reduction for amortization of contributions in aid of construction, was 2.6% for 2019 (2018 – 2.5%).
The service life ranges and weighted average remaining service life of the Corporation’s PPE as at December 31 were as follows.
(years)
Distribution
Electric
Gas
Transmission
Electric
Gas
Generation
Other
Intangible Assets
2019
Service Life
Ranges
Weighted Average
Remaining
Service Life
2018
Weighted Average
Remaining
Service Life
Service Life
Ranges
5–80
15–95
20–90
5–85
1–85
3–70
32
36
43
32
25
14
5–80
14–95
20–90
5–85
1–85
3–70
33
35
42
41
24
15
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 50.0% for 2019 (2018 – 1.0% to 50.0%).
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
2019
Weighted Average
Remaining
Service Life
4
58
12
Service Life
Ranges
3–10
43–90
10–100
2018
Weighted Average
Remaining
Service Life
4
57
13
Service Life
Ranges
3–10
36–90
10–100
Most of 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.
75
FORTIS INC. 2019 ANNUAL REPORTNotes to Consolidated Financial Statements
3.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (cont’d)
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 carrying value may not exceed the total undiscounted cash flows expected to be generated by the asset. If that is determined to be
the case, the asset is written down to estimated fair value and an impairment loss is recognized.
Goodwill
Goodwill represents the excess of the purchase price over the fair value of the identifiable net assets related to business acquisitions.
Impairment testing is performed if an event or change in circumstances indicates that the fair value of a reporting unit may be below its carrying
value. If so determined, goodwill is written down to estimated fair value and an impairment loss is recognized.
Otherwise, Fortis performs an annual assessment for each of the 11 reporting units having goodwill. The Corporation performs a qualitative
assessment for certain reporting units and if it is determined that it is not likely that fair value is less than carrying value then a quantitative estimate
of the fair value is not required. Otherwise, the primary method for estimating the fair value of the reporting units is the income approach, whereby
net cash flow projections are discounted using an enterprise value method. 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 method, the market approach along with a reconciliation of the total estimated fair value of all 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
US 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 9).
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 9).
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. Revenue is 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.
76
For the years ended December 31, 2019 and 2018FORTIS INC. 2019 ANNUAL REPORTNotes to Consolidated Financial Statements 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 certain.
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 6). 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, all representing cash-settled awards, at fair value at each reporting date until settlement. 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, 2019 was $53.97 (December 31, 2018 – $45.14). 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 US 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, 2019 was US$1.00=CAD$1.30 (December 31, 2018 – US$1.00=CAD$1.36).
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=CAD$1.33 for 2019 (2018 – US$1.00=CAD$1.30).
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.
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 US 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.
77
FORTIS INC. 2019 ANNUAL REPORTNotes to Consolidated Financial Statements 3.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (cont’d)
Derivatives and Hedging (cont’d)
Derivatives Not Designated as Hedges (cont’d)
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 thereto recognized as regulatory assets or liabilities for recovery
from, or refund to, customers in future rates (Note 9).
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
The Corporation, ITC and UNS Energy use cash flow hedges 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. Any hedge
ineffectiveness is immediately recognized in earnings.
The Corporation’s earnings from, and net investments in, foreign subsidiaries and equity-accounted investments are exposed to fluctuations
in the US dollar-to-Canadian dollar exchange rate. The Corporation has hedged a portion of this exposure through US 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 values of derivatives are 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, 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, for the 50-year term of its PPAs, BECOL are not subject
to income tax.
Differences between the income tax expense or recovery recognized under US GAAP and that 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 9).
At FortisAlberta the capital cost allowance pool for certain PPE for rate-setting purposes is different from that prescribed for Canadian tax filing
purposes. In a future reporting period yet to be determined, the difference may result in reported income tax expense exceeding that reflected
in customer rates.
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 $2.8 billion as at December 31, 2019 (December 31, 2018 – $2.3 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.
78
For the years ended December 31, 2019 and 2018FORTIS INC. 2019 ANNUAL REPORTNotes to Consolidated Financial Statements 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, right-of-ways
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 17) 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.
New Accounting Policies
Leases
Effective January 1, 2019, the Corporation adopted Accounting Standards Update (“ASU”) No. 2016-02, Leases, that requires lessees to recognize a
right-of-use asset and lease liability for all leases with a lease term greater than 12 months, along with additional disclosures (Note 16).
At lease inception, 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.
Fortis applied the transition provisions of the new standard as of the adoption date and did not retrospectively adjust prior periods in accordance
with the modified retrospective approach. Fortis elected a package of implementation options, referred to as practical expedients, that allowed it
to not reassess: (i) whether existing contracts, including land easements, are or contain a lease; (ii) the classification of existing leases; or (iii) the initial
direct costs for existing leases. Fortis also utilized the hindsight practical expedient to determine the lease term. Upon adoption, Fortis did not
identify or record an adjustment to the opening balance of retained earnings, and there was no impact on net earnings or cash flows.
Hedging
Effective January 1, 2019, the Corporation adopted ASU No. 2017-12, Targeted Improvements to Accounting for Hedging Activities, which better aligns risk
management activities and financial reporting for hedging relationships through changes to designation, measurement, presentation and disclosure
guidance. Adoption did not have a material impact on the consolidated financial statements and related disclosures.
Fair Value Measurement Disclosures
Effective January 1, 2019, the Corporation adopted ASU No. 2018-13, Changes to the Disclosure Requirements for Fair Value Measurement, which
improves the effectiveness of financial statement note disclosures by clarifying what is required and important to users of the financial statements.
The adoption of this ASU removed the following disclosures for all periods presented: (i) the amount of, and reasons for, transfers between
level 1 and level 2 of the fair value hierarchy; (ii) the policy for the timing of transfers between levels; and (iii) the valuation processes for level 3
fair value measurements.
79
FORTIS INC. 2019 ANNUAL REPORTNotes to Consolidated Financial Statements 3.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (cont’d)
New Accounting Policies (cont’d)
Pensions and Other Post-Retirement Plan Disclosures
Effective December 31, 2019, the Corporation early adopted, on a retrospective basis, ASU No. 2018-14, Changes to the Disclosure Requirements for
Defined Benefit Plans, which modifies the disclosure requirements for employers with defined pension or other post-retirement plans and clarifies
disclosure requirements. In particular, it removed the following disclosures: (i) the amounts in accumulated other comprehensive income expected
to be recognized as components of net period benefit costs over the next fiscal period; and (ii) the effects of a one-percentage-point change
on the assumed health care costs and the change in rates on service cost, interest cost and the benefit obligation for post-retirement health care
benefits (Note 26).
Use of Accounting Estimates
The preparation of these consolidated financial statements in accordance with US 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.
4. FUTURE ACCOUNTING PRONOUNCEMENTS
Income Taxes
ASU No. 2019-12, Simplifying the Accounting for Income Taxes, issued in December 2019, is effective for Fortis January 1, 2021, with early adoption
permitted. Principally, it improves consistent application of, and clarifies, existing income tax guidance. Fortis is assessing the impact that adoption
will have on its consolidated financial statements.
5. SEGMENTED INFORMATION
General
Fortis segments its business based on regulatory status, service territory, and the information used by its President and CEO in deciding how to
allocate resources. Segment performance is evaluated primarily 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 2019 or 2018.
Inter-company balances, transactions and profit are eliminated on consolidation, except for certain inter-company transactions between non-regulated
and regulated entities in accordance with accounting standards for rate-regulated entities, which are summarized below.
(in millions)
Sale of capacity from Waneta Expansion to FortisBC Electric (1)
Lease of gas storage capacity and gas sales from Aitken Creek to FortisBC Energy
(1) Reflects amounts to the April 16, 2019 disposition of the Waneta Expansion (Note 23)
$
2019
17
23
$
2018
47
25
As at December 31, 2019, accounts receivable included approximately $8 million due from Belize Electricity (December 31, 2018 – $16 million).
The Corporation periodically provides short-term financing to subsidiaries to support capital expenditures, acquisitions and seasonal working capital
requirements. As at December 31, 2019, there were inter-segment loans outstanding of $279 million (December 31, 2018 – $nil), payable on demand
with a weighted average interest rate of 2.48%. Total interest charged in 2019 was $2 million.
80
For the years ended December 31, 2019 and 2018FORTIS INC. 2019 ANNUAL REPORTNotes to Consolidated Financial Statements
Year Ended
December 31, 2019
(in millions)
Revenue
Energy supply costs
Operating expenses
Depreciation and
amortization
Gain on disposition
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
Goodwill
Total assets
Capital expenditures
Year Ended
December 31, 2018
(in millions)
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
Goodwill
Total assets
Capital expenditures
REGULATED
NON-REGULATED
UNS Central FortisBC
Fortis FortisBC
ITC Energy Hudson Energy Alberta Electric
Other
Electric
Infra-
Sub
total structure
Energy Corporate
and
Inter-
segment
Other eliminations
Total
$
–
–
56
$
(3) $ 8,783
2,520
–
2,452
(3)
$ 1,761 $ 2,212 $ 917 $ 1,331 $ 598 $ 418 $ 1,467 $ 8,704
2,517
2,363
438
333
254
451
–
145
121
107
890
188
814
650
–
489
270
–
1,002
37
290
174
575
104
–
297
–
451
28
130
57
292
–
–
79
–
133
17
46
19
85
–
–
235
–
325
16
136
39
166
1
–
214
–
239
2
104
6
131
–
–
62
–
128
4
72
6
54
–
–
171
–
218
2
77
20
123
17
–
1,328
–
2,496
106
855
321
1,426
122
–
$ 471 $ 292 $
85 $ 165 $ 131 $
54 $ 106 $ 1,304
$ 7,970 $ 1,794 $ 586 $ 913 $ 228 $ 235 $ 251 $ 11,977
52,379
3,667
4,185
295
10,205
915
7,305
463
4,831
423
19,799
1,148
3,726
317
2,328
106
$
82
3
36
20
–
23
2
–
(1)
26
8
–
2
577
519
30
180
(31)
400
–
67
$
$
18
$ 333
27
711
28
$
–
641
25
$ 1,504 $ 2,202 $ 924 $ 1,187 $ 579 $ 408 $ 1,412 $ 8,216
2,493
2,229
868
609
–
167
315
410
135
105
–
448
322
308
853
182
$
$ 184
2
40
234
822
40
285
139
438
77
–
272
453
10
104
66
293
–
–
71
128
7
41
20
74
–
–
219
338
7
134
55
156
1
–
192
220
1
100
1
120
–
–
61
107
3
40
14
56
–
–
160
217
1
76
22
120
15
–
1,209
2,285
69
780
317
1,257
93
–
32
110
1
6
6
99
27
–
–
–
28
2
(30)
(10)
188
(158)
(70)
–
66
$ 361 $ 293 $
74 $ 155 $ 120 $
56 $ 105 $ 1,164
$
72
$ (136)
$ 8,369 $ 1,884 $ 615 $ 913 $ 227 $ 235 $ 260 $ 12,503
51,519
3,167
4,119
300
4,691
433
6,815
486
19,798
998
10,182
599
3,670
245
2,244
106
$
27
1,478
44
$
–
127
7
$
$
$
–
–
–
–
–
–
–
–
–
1,350
577
3,038
138
1,035
289
1,852
130
67
– $ 1,655
– $ 12,004
53,404
3,720
(327)
–
(10) $ 8,390
2,495
2,287
–
(10)
–
–
–
–
–
–
–
–
1,243
2,365
60
974
165
1,286
120
66
$
$
– $ 1,100
– $ 12,530
53,051
3,218
(73)
–
81
FORTIS INC. 2019 ANNUAL REPORTNotes to Consolidated Financial Statements
6. REVENUE
(in 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
$
$
2019
1,697
1,966
894
1,289
576
362
671
209
206
270
85
8,225
374
8,599
116
68
$
8,783
$
2018
1,539
1,993
963
1,136
554
354
651
200
197
253
78
7,918
408
8,326
16
48
8,390
(1) Includes $273 million and $234 million from regulated operations for 2019 and 2018, respectively
(2)
Includes a $91 million adjustment associated with the November 2019 FERC Order (Notes 2 and 9)
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.
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; (iii) the sale of energy from non-regulated generation operations, including the Waneta Expansion up to its
disposition on April 16, 2019 (Note 23); and (iv) 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 Corporation’s
significant alternative revenue programs 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 9). 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.
82
For the years ended December 31, 2019 and 2018FORTIS INC. 2019 ANNUAL REPORTNotes to Consolidated Financial Statements
At FortisBC Energy and FortisBC Electric, the earnings sharing mechanism allows for a 50/50 sharing of variances from operating and maintenance
expenses and capital expenditures approved as part of the annual revenue requirement. This mechanism was in place until the expiry of the current
PBR plan in 2019. Additionally, variances in the forecast versus actual customer-use rates are captured throughout the year in a revenue stabilization
adjustment mechanism and a flow-through deferral account, both of which are either refunded to, or recovered from, customers in rates within
two years.
Other Revenue
Other revenue primarily includes gains or losses on energy contract derivatives and lease revenue.
7. ACCOUNTS RECEIVABLE AND OTHER CURRENT ASSETS
(in millions)
Trade accounts receivable
Unbilled accounts receivable
Allowance for doubtful accounts
Total accounts receivable
Income tax receivable
Other (1)
$
2019
504
601
(35)
1,070
35
192
$
1,297
2018
538
575
(33)
1,080
91
186
1,357
$
$
(1) Consists mainly of customer billings for non-core services, gas mitigation costs and collateral deposits for gas purchases at FortisBC Energy, and the fair value of derivative
instruments (Note 28)
8. INVENTORIES
(in millions)
Materials and supplies
Gas and fuel in storage
Coal inventory
2019
294
69
31
394
$
$
2018
280
87
31
398
$
$
83
FORTIS INC. 2019 ANNUAL REPORTNotes to Consolidated Financial Statements
9. REGULATORY ASSETS AND LIABILITIES
(in millions)
Regulatory assets
Deferred income taxes (Notes 3 and 25)
Employee future benefits (Notes 3 and 26)
Deferred energy management costs (i)
Rate stabilization and related accounts (ii)
Derivatives (Notes 3 and 28)
Deferred lease costs (iii)
Generation early retirement costs (iv)
Manufactured gas plant site remediation deferral (Note 17)
Other regulatory assets (v)
Total regulatory assets
Less: Current portion
Long-term regulatory assets
Regulatory liabilities
Deferred income taxes (Notes 3 and 25)
Asset removal cost provision (Note 3)
Rate stabilization and related accounts (ii)
Energy efficiency liability (vi)
Renewable energy surcharge (vii)
ROE complaints liability (Note 2)
Electric and gas moderator account (viii)
Employee future benefits (Notes 3 and 26)
Other regulatory liabilities (v)
Total regulatory liabilities
Less: Current portion
Long-term regulatory liabilities
$
2019
1,556
530
279
208
119
116
88
81
406
3,383
(425)
$
2,958
$
1,440
1,187
166
101
94
91
45
45
189
3,358
(572)
$
$
$
2018
1,532
485
230
90
57
110
98
73
400
3,075
(324)
2,751
1,574
1,169
220
106
85
206
60
37
169
3,626
(656)
$
2,786
$
2,970
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 1 to 10 years.
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 resulting from 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 6).
(i)
(ii)
84
For the years ended December 31, 2019 and 2018FORTIS INC. 2019 ANNUAL REPORTNotes to Consolidated Financial Statements
(iii)
(iv)
(v)
(vi)
(vii)
Deferred Lease Costs
Deferred lease costs at FortisBC Electric primarily relate to the Brilliant Power Purchase Agreement (“BPPA”) (Note 16). 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.
Generation Early Retirement Costs
UNS Energy holds an undivided interest in the jointly owned Navajo Generating Station (“Navajo”), located on a site leased from the Navajo
Nation with an initial lease term through December 2019. In June 2017 the Navajo Nation approved a land-lease extension that allowed TEP
and the co-owners of Navajo to continue operations through December 2019 and begin decommissioning activities thereafter. TEP and the
co-owners retired Navajo in November 2019, with related decommissioning activities continuing through 2054, and the capital and operating
costs are being recovered through 2030.
UNS Energy owns the Sundt Generating Facility (“Sundt”) and was required to retire Sundt Units 1 and 2 in November 2019. Capital and
operating costs related to Sundt Units 1 and 2 are being recovered through 2028 and 2030, respectively.
Due to the early retirement of Navajo and Sundt, TEP requested recovery of final retirement costs over a 10-year period in the 2019 general
rate application.
Other Regulatory Assets and Liabilities
These balances are comprised of regulatory assets and liabilities individually less than $40 million.
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.
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.
The ACC measures RES compliance through Renewable Energy Credits (“REC”). 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 10)
with a corresponding regulatory liability to reflect the obligation to use the RECs for future RES compliance. When RECs are reported to the
ACC for compliance with RES requirements, energy supply costs and revenue are recognized in an equal amount.
(viii)
Electric and Gas Moderator Account
Under Central Hudson’s 2018 three-year rate order certain regulatory assets and liabilities were approved by the PSC for offset and an electric
and gas moderator account was established, which will be used for future customer rate moderation.
Regulatory assets not earning a return: (i) totalled $1,510 million and $1,490 million as at December 31, 2019 and 2018, 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.
85
FORTIS INC. 2019 ANNUAL REPORTNotes to Consolidated Financial Statements 10. OTHER ASSETS
(in millions)
Supplemental Executive Retirement Plan
Renewable Energy Credits (Note 9 (vii))
Equity investment – Belize Electricity
Employee future benefits (Note 26)
Operating leases (Note 16)
Other investments
Deferred compensation plan
Equity Investment – Wataynikaneyap Partnership
Other (1)
(1) Includes the fair value of derivatives (Note 28)
2019
145
99
71
63
46
43
30
12
111
620
$
$
2018
143
88
76
27
–
34
26
43
115
552
$
$
ITC, UNS Energy and Central Hudson provide additional post-employment benefits through Supplemental Executive Retirement Plans (“SERPs”) and
deferred compensation plans for Directors and Officers. The assets held to support these plans are reported separately from the related liabilities
(Note 17). Most plan assets are held in trust and funded mainly through trust-owned life insurance policies and mutual funds. Assets in mutual
and money market funds are recorded at fair value on a recurring basis (Note 28). Included in SERP assets are available-for-sale securities at ITC of
$70 million (2018 – $72 million), for which gains and losses are recognized in earnings.
11. PROPERTY, PLANT AND EQUIPMENT
(in millions)
2019
Distribution
Electric (1)
Gas
Transmission
Electric
Gas
Generation
Other
Assets under construction
Land
2018
Distribution
Electric (1)
Gas
Transmission
Electric
Gas
Generation
Other
Assets under construction
Land
Cost
Accumulated
Depreciation
Net Book
Value
$ 11,396
5,277
$
(3,125)
(1,330)
$
8,271
3,947
15,207
2,267
6,380
4,042
1,329
318
(3,293)
(681)
(2,472)
(1,327)
–
–
11,914
1,586
3,908
2,715
1,329
318
$ 46,216
$ (12,228)
$ 33,988
$
11,000
4,767
$
(3,093)
(1,244)
$
7,907
3,523
14,665
2,214
6,164
3,877
1,478
310
(3,212)
(639)
(2,279)
(1,251)
–
–
11,453
1,575
3,885
2,626
1,478
310
$
44,475
$
(11,718)
$
32,757
(1) Includes FortisAlberta’s deferred operating overhead costs of $121 million (December 31, 2018 – $103 million), representing costs related to the construction of PPE that are
deferred for collection in future customer rates over the lives of the related PPE. These costs were reclassified to PPE from long-term regulatory assets to provide greater
comparability between subsidiaries.
86
For the years ended December 31, 2019 and 2018FORTIS INC. 2019 ANNUAL REPORTNotes to Consolidated Financial Statements
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 the Aitken Creek natural gas storage facility.
As at December 31, 2019 and 2018, assets under construction were primarily associated with ongoing transmission projects at ITC and the addition
of gas-fired generating capacity at UNS Energy.
The cost of PPE under finance lease as at December 31, 2019 was $514 million (December 31, 2018 – $656 million) and related accumulated
depreciation was $206 million (December 31, 2018 – $203 million) (Note 16).
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, 2019, interests in jointly owned facilities
consisted of the following.
(in millions, except as noted)
San Juan Unit 1
Four Corners Units 4 and 5
Luna Energy Facility
Gila River Common Facilities
Springerville Coal Handling Facilities
Transmission Facilities
Ownership
(%)
50.0
7.0
33.3
50.0
83.0
1.0–80.0
$
Cost
377
234
74
105
270
982
Accumulated
Depreciation
Net Book
Value
$
(251)
(100)
(1)
(35)
(117)
(384)
$
126
134
73
70
153
598
$
2,042
$
(888)
$
1,154
87
FORTIS INC. 2019 ANNUAL REPORTNotes to Consolidated Financial Statements
12. INTANGIBLE ASSETS
(in millions)
2019
Computer software
Land, transmission and water rights
Other
Assets under construction
2018
Computer software
Land, transmission and water rights
Other
Assets under construction
$
Cost
946
890
115
68
$
2,019
$
860
855
120
81
$
1,916
Accumulated
Amortization
$
$
$
$
(576)
(122)
(61)
–
(759)
(533)
(125)
(58)
–
(716)
Net Book
Value
$
370
768
54
68
$
1,260
$
327
730
62
81
$
1,200
Included in the cost of land, transmission and water rights as at December 31, 2019 was $133 million (December 31, 2018 – $131 million) not subject
to amortization. Amortization expense was $125 million for 2019 (2018 – $106 million). Amortization is estimated to average approximately $77 million
for each of the next five years.
13. GOODWILL
(in millions)
Balance, beginning of year
Acquisition of distribution systems by FortisAlberta
Foreign currency translation impacts (1)
Balance, end of year
2019
$ 12,530
1
(527)
$ 12,004
$
2018
11,644
–
886
$
12,530
(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 US dollar
No goodwill impairment was recognized by the Corporation in 2019 or 2018.
14. ACCOUNTS PAYABLE AND OTHER CURRENT LIABILITIES
(in millions)
Trade accounts payable
Employee compensation and benefits payable
Dividends payable
Customer and other deposits
Gas and fuel cost payable
Accrued taxes other than income taxes
Interest payable
Fair value of derivatives (Note 28)
Manufactured gas plant site remediation (Note 17)
Employee future benefits (Note 26)
Other
88
$
2019
754
229
228
226
225
223
212
83
31
24
143
$
2018
679
193
199
267
281
206
230
69
32
25
108
$
2,378
$
2,289
For the years ended December 31, 2019 and 2018FORTIS INC. 2019 ANNUAL REPORTNotes to Consolidated Financial Statements
15. LONG-TERM DEBT
(in millions)
Maturity Date
2019
2018
ITC
Secured US First Mortgage Bonds –
4.46% weighted average fixed rate (2018 – 4.51%)
Secured US Senior Notes –
4.26% weighted average fixed rate (2018 – 4.19%)
Unsecured US Senior Notes –
3.79% weighted average fixed rate (2018 – 3.91%)
Unsecured US Shareholder Note –
6.00% fixed rate (2018 – 6.00%)
Unsecured US Term Loan Credit Agreement –
2.35% weighted average fixed rate
UNS Energy
Unsecured US Tax-Exempt Bonds – 4.64% weighted
average fixed and variable rate (2018 – 4.66%)
Unsecured US Fixed Rate Notes –
4.38% weighted average fixed rate (2018 – 4.38%)
Central Hudson
Unsecured US Promissory Notes – 4.27% weighted
average fixed and variable rate (2018 – 4.43%)
FortisBC Energy
Unsecured Debentures –
4.87% weighted average fixed rate (2018 – 5.03%)
FortisAlberta
Unsecured Debentures –
4.64% weighted average fixed rate (2018 – 4.64%)
FortisBC Electric
Secured Debentures –
8.80% fixed rate (2018 – 8.80%)
Unsecured Debentures –
5.05% weighted average fixed rate (2018 – 5.05%)
Other Electric
Secured First Mortgage Sinking Fund Bonds –
6.14% weighted average fixed rate (2018 – 6.14%)
Secured First Mortgage Bonds –
5.66% weighted average fixed rate (2018 – 5.66%)
Unsecured Senior Notes –
4.45% weighted average fixed rate (2018 – 4.45%)
Unsecured US Senior Loan Notes and Bonds – 4.53% weighted
average fixed and variable rate (2018 – 4.76%)
Corporate
Unsecured US Senior Notes and Promissory Notes –
3.80% weighted average fixed rate (2018 – 3.41%)
Unsecured Debentures –
6.50% fixed rate (2018 – 6.50%)
Unsecured Senior Notes – 2.85% fixed rate (2018 – 2.85%)
Long-term classification of credit facility borrowings
Fair value adjustment – ITC acquisition
Total long-term debt (Note 28)
Less: Deferred financing costs and debt discounts
Less: Current installments of long-term debt
2020–2055
$
2,624
$
2,652
2040–2049
2020–2043
2028
2021
2020–2040
2021–2048
747
3,312
258
260
603
1,851
2020–2059
986
2026–2049
2,795
2024–2052
2,185
2023
2021–2050
2020–2057
2025–2061
2041–2048
2020–2049
25
710
571
220
152
645
2020–2044
2,903
2039
2023
200
500
640
133
22,320
(129)
(690)
648
3,751
271
–
654
1,943
938
2,595
2,185
25
710
578
220
152
584
4,398
200
500
1,066
161
24,231
(146)
(926)
$ 21,501
$
23,159
89
FORTIS INC. 2019 ANNUAL REPORTNotes to Consolidated Financial Statements
15.
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 at the Corporation have covenants that (i) restrict the issuance of additional debt such that the consolidated debt to
consolidated capitalization ratio does not exceed 70% at any time, and (ii) provide that the Corporation shall not declare, pay or make any dividends
or any other restricted payments if, immediately thereafter, its consolidated debt to consolidated capitalization ratio would exceed 65%.
Long-Term Debt Issuances
(in millions, except %)
ITC
Secured notes
Unsecured term loan credit agreement (4)
Secured notes
First mortgage bonds
Central Hudson
Unsecured notes
Unsecured notes
FortisBC Energy
Unsecured debentures
FortisTCI
Unsecured non-revolving term loan
Caribbean Utilities
Unsecured notes
Unsecured notes
Unsecured notes
Month
Issued
January
June
July
August
October
October
August
February
May
August
August
Interest
Rate
(%)
Maturity
Amount
Use of
Proceeds
4.55
(5)
4.65
3.30
3.89
3.99
2.82
(7)
4.14
4.14
3.83
2049
2021
2049
2049
2049
2059
2049
US 50
US 200
US 50
US 75
US 50
US 50
200
2025
US 5
2049
2049
2039
US 40
US 20
US 20
(1) (2) (3)
(6)
(1) (2) (3)
(1) (2) (3)
(2) (3) (6)
(2) (3) (6)
(1)
(2) (3)
(1) (3) (6)
(2) (3) (6)
(2) (3) (6)
(1) Repay credit facility borrowings
(2) Finance capital expenditures
(3) General corporate purposes
(4) Maximum amount of borrowings under this agreement is US$400 million; in January 2020 the remaining US$200 million was drawn to repay outstanding commercial
paper balances
(5) Floating rate of a one-month LIBOR plus a spread of 0.60%
(6) Repay maturing long-term debt
(7) Floating rate of a one-month LIBOR plus a spread of 1.75%
Fortis used the proceeds from the disposition of the Waneta Expansion (Note 23) to repay credit facility borrowings and repurchase, via a tender
offer, US$400 million of its outstanding 3.055% unsecured senior notes due in 2026. A gain on the repayment of debt of $11 million ($7 million after
tax), net of expenses, was recognized in other income, net (Note 24).
Fortis used the proceeds from the issuance of common shares (Note 18) to redeem the US$500 million, 2.10% unsecured notes that were due in 2021,
to repay credit facility borrowings, and for general corporate purposes.
In January 2020 ITC entered into an unsecured term loan credit agreement, due in January 2021, under which the maximum amount of US$75 million
was borrowed. The proceeds were used to repay credit facility borrowings.
90
For the years ended December 31, 2019 and 2018FORTIS INC. 2019 ANNUAL REPORTNotes to Consolidated Financial Statements
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.
(year)
2020
2021
2022
2023
2024
Thereafter
Credit Facilities
Total
(in millions)
$
690
872
1,146
1,553
1,106
16,953
$
22,320
As at December 31, 2019, the Corporation and its subsidiaries had consolidated credit facilities of approximately $5.6 billion, of which approximately
$4.3 billion was unused, including $1.3 billion unused under the Corporation’s committed revolving corporate credit facility.
The following summarizes the credit facilities of the Corporation and its subsidiaries.
(in 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
$
4,209
(512)
(640)
(64)
Corporate
and Other
$
1,381
–
–
(50)
2019
$
5,590
2018
5,165
$
(512)
(640)
(114)
(60)
(1,066)
(119)
$
2,993
$
1,331
$
4,324
$
3,920
(1) The weighted average interest rate was approximately 3.2% (December 31, 2018 – 4.2%).
(2) The weighted average interest rate was approximately 2.4% (December 31, 2018 – 3.3%). The current portion was $252 million (December 31, 2018 – $735 million).
Credit facilities are syndicated primarily with large banks in Canada and the United States, with no one bank holding more than 20% of the total
facilities. Approximately $5.1 billion of the total credit facilities are committed facilities with maturities ranging from 2020–2024.
91
FORTIS INC. 2019 ANNUAL REPORTNotes to Consolidated Financial Statements
15.
LONG-TERM DEBT (cont’d)
Consolidated credit facilities of approximately $5.6 billion as at December 31, 2019 are itemized below.
(in millions)
Unsecured committed revolving credit facilities
Regulated utilities
ITC (1)
UNS Energy
Central Hudson
FortisBC Energy
FortisAlberta
FortisBC Electric
Other Electric
Other Electric (4)
Corporate and Other
Other facilities
UNS Energy – unsecured non-revolving facility
Central Hudson – 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
Amount
Maturity
US 900
US 500
US 250
700
250
150
190
50
1,350
US
US 225
40
US
10
20
60
31
US
October 2022
October 2022
(2)
August 2024
August 2024
April 2024
(3)
January 2020
(5)
December 2020
n/a
n/a
n/a
April 2020
n/a
(1) ITC also has a US$400 million commercial paper program, under which US$200 million was outstanding as at December 31, 2019, which is reported in short-term borrowings.
(2) US$50 million in July 2020 and US$200 million in October 2020
(3) $40 million in June 2021, $50 million in February 2022 and $100 million in August 2024
(4) Subsequent to year end, facility was increased to US$70 million and the maturity date extended to January 2025
(5) $50 million in April 2022 and $1.3 billion in July 2024 with the option to increase by an amount up to $500 million
16. LEASES
The Corporation and its subsidiaries lease office facilities, utility equipment, land, and communication tower space with remaining terms of up to
22 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 lease premises.
The Corporation’s subsidiaries also have finance leases related to generating facilities with remaining terms of up to 36 years.
Leases were presented on the consolidated balance sheet as follows.
(in millions)
Operating leases
Other assets
Accounts payable and other current liabilities
Other liabilities
Finance leases (1) (2) (3)
Regulatory assets
PPE, net
Current installments of finance leases
Finance leases
$
$
2019
46
(8)
(38)
116
308
(24)
(413)
(1) FortisBC Electric has a finance lease for the BPPA (Note 9 (iii)), 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.
(2) TEP is party to two Springerville Common Facilities leases with fixed purchase options and initial terms to January 2021. During 2019 TEP exercised its option to purchase a
32.2% undivided interest in the Springerville Common Facilities by January 2021 for $88 million.
(3) In December 2019 TEP exercised its option to purchase Gila River Unit 2 for $212 million.
92
For the years ended December 31, 2019 and 2018FORTIS INC. 2019 ANNUAL REPORTNotes to Consolidated Financial Statements
The components of lease expense were as follows.
(in millions)
Operating lease cost
Finance lease cost:
Amortization
Interest
Variable lease cost
Total lease cost
Operating lease cost in 2018 was $10 million.
As at December 31, 2019, the present value of minimum lease payments was as follows.
(in millions)
2020
2021
2022
2023
2024
Thereafter
Less: Imputed interest
Total lease obligations
Less: Current installments
Operating
Leases
Finance
Leases
$
$
10
8
7
6
4
22
57
(11)
46
(8)
38
$
$
56
121
33
33
33
1,083
1,359
(922)
437
(24)
413
As at December 31, 2018, the present value of minimum lease payments was as follows.
(year)
2019
2020
2021
2022
2023
Thereafter
Less: Imputed interest and executory costs
Total capital lease and finance obligations
Less: Current installments
$
2019
10
17
48
39
$
114
Total
66
129
40
39
37
1,105
1,416
(933)
483
(32)
451
$
$
Total
(in millions)
$
$
313
77
80
49
47
1,885
2,451
(1,809)
642
(252)
390
93
FORTIS INC. 2019 ANNUAL REPORTNotes to Consolidated Financial Statements
16.
LEASES (cont’d)
Supplemental lease information was as follows.
(in 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
See Note 27 for non-cash transactions that resulted in right-of-use assets obtained in exchange for new lease liabilities.
17. OTHER LIABILITIES
(in millions)
Employee future benefits (Note 26)
AROs (Note 3)
Stock-based compensation plans (Note 22)
Customer and other deposits
Fair value of derivatives (Note 28)
Manufactured gas plant site remediation (i)
Mine reclamation obligations (ii)
Operating leases
Finance obligations (iii)
Deferred compensation plan (Note 10)
Other
$
2019
832
148
83
70
68
48
43
38
38
33
45
$
$
2019
10
27
4.1
4.8
(10)
(47)
(16)
(212)
2018
741
111
56
57
30
32
40
–
–
29
42
$
1,446
$
1,138
Environmental regulations require Central Hudson to investigate sites at which the Company 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, 2019, an obligation of $74 million (US$57 million) was recognized, including a current portion of $26 million (US$20 million)
recognized in accounts payable and other current liabilities (Note 14). 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 9).
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 $74 million (US$57 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.
Between 2000 and 2005 FortisBC Energy entered into arrangements whereby certain natural gas distribution assets were leased to certain
municipalities and then leased back by FortisBC Energy. These assets are integral equipment to real estate assets and the transactions have
been accounted for as finance transactions, with the proceeds thereof recognized as finance obligations. Lease payments, net of the portion
recognized as interest expense, reduce the finance obligations. The finance obligations have implicit interest rates ranging from 6.9% to
7.25% and are being repaid over an initial 35-year period with an early termination option after 17 years. If the Company exercises this option,
it would pay the municipality an early termination payment equal to the carrying value of the obligation at termination. In November 2019
and October 2018, FortisBC Energy exercised early termination payment options in the amount of $12 million and $27 million, respectively,
on two of these arrangements.
(i)
(ii)
(iii)
94
For the years ended December 31, 2019 and 2018FORTIS INC. 2019 ANNUAL REPORTNotes to Consolidated Financial Statements
18. COMMON SHARES
During 2019 the Corporation issued approximately 4.1 million common shares under its at-the-market common equity program at an average price
of $52.16 per share. The gross proceeds of $212 million ($209 million net of commissions) were used primarily to fund capital expenditures.
Also during 2019 the Corporation issued approximately 22.8 million common shares representing gross proceeds of $1,190 million ($1,167 million net
of commissions) at a price of $52.15 per share. The net proceeds were used to redeem US$500 million of its outstanding 2.10% unsecured notes due
on October 4, 2021, to repay credit facility borrowings, and for general corporate purposes.
19. EARNINGS PER COMMON SHARE
Diluted earnings per share (“EPS”) was calculated using the treasury stock method for options.
2019
Net Earnings Weighted
Average
to Common
Shares
Shareholders
(# millions)
($ millions)
EPS
($)
Basic EPS
Potential dilutive effect of stock options
Diluted EPS
$ 1,655
–
$ 1,655
20. PREFERENCE SHARES
Authorized
Net Earnings
to Common
Shareholders
($ millions)
$ 1,100
–
2018
Weighted
Average
Shares
(# millions)
424.7
0.5
EPS
($)
2.59
–
$
436.8
0.7
$ 3.79
–
437.5
$ 3.78
$ 1,100
425.2
$
2.59
An unlimited number of first preference shares and second preference shares, without nominal or par value.
Issued and outstanding
2019
2018
First Preference Shares
Series F
Series G
Series H
Series I
Series J
Series K
Series M
Number
of Shares
(in thousands)
5,000
9,200
7,025
2,975
8,000
10,000
24,000
66,200
Amount
(in millions)
$
122
225
172
73
196
244
591
$
1,623
Number
of Shares
(in thousands)
5,000
9,200
7,025
2,975
8,000
10,000
24,000
66,200
Amount
(in millions)
$
122
225
172
73
196
244
591
$
1,623
95
FORTIS INC. 2019 ANNUAL REPORTNotes to Consolidated Financial Statements
20. PREFERENCE SHARES (cont’d)
Characteristics of the first preference shares are as follows.
First Preference Shares (1) (2)
Perpetual fixed rate
Series F
Series J (3)
Fixed rate reset (4) (5)
Series G
Series H
Series K (6)
Series M (7)
Floating rate reset (5) (8)
Series I (3)
Series L
Series N
Initial
Yield
(%)
Annual
Dividend
($)
Reset
Dividend
Yield
(%)
Earliest
Redemption
Right to
and/or Redemption Convert on
a One-For-
Value
One Basis
($)
Conversion
Option Date
4.90
4.75
5.25
4.25
4.00
4.10
2.10
–
–
1.2250
1.1875
1.0983
0.6250
0.9823
0.9783
–
–
–
–
–
2.13
1.45
2.05
2.48
1.45
2.05
2.48
December 1, 2011
December 1, 2017
September 1, 2013
June 1, 2015
March 1, 2019
December 1, 2019
June 1, 2015
March 1, 2024
December 1, 2024
25.00
25.50
25.00
25.00
25.00
25.00
25.50
–
–
–
–
–
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) First Preference Shares, Series J were redeemable at $26.00 until December 1, 2018, decreasing by $0.25 each year until December 1, 2021 and redeemable at $25.00 per share
thereafter. First Preference Shares, Series I are redeemable at $25.50 per share, up to but excluding June 1, 2020, and at $25.00 per share on June 1, 2020, and on every fifth
anniversary date thereafter.
(4) On the redemption and/or conversion option date, and 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.
(5) 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.
(6) The annual dividend per share for the First Preference Shares, Series K was reset from $1.0000 to $0.9823 for the five-year period from March 1, 2019 up to but excluding
March 1, 2024.
(7) The annual dividend per share for the First Preference Shares, Series M was reset from $1.0250 to $0.9783 for the five-year period from December 1, 2019 up to but excluding
December 1, 2024.
(8) 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.
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.
96
For the years ended December 31, 2019 and 2018FORTIS INC. 2019 ANNUAL REPORTNotes to Consolidated Financial Statements
21. ACCUMULATED OTHER COMPREHENSIVE INCOME
(in millions)
Opening Balance
Net Change
Ending Balance
2019
Unrealized foreign currency translation gains (losses)
Net investments in foreign operations
Hedges of net investments in foreign operations
Income tax recovery (expense)
Other
Cash flow hedges (Note 28)
Unrealized employee future benefits losses (Note 26)
Income tax recovery
$
1,470
(544)
10
936
11
(20)
1
(8)
$
(757)
185
(13)
(585)
6
(18)
5
(7)
$
713
(359)
(3)
351
17
(38)
6
(15)
Accumulated other comprehensive income
$
928
$
(592)
$
336
2018
Unrealized foreign currency translation gains (losses)
Net investments in foreign operations
Hedges of net investments in foreign operations
Income tax (expense) recovery
Other
Cash flow hedges (Note 28)
Unrealized employee future benefits (losses) gains (Note 26)
Income tax recovery (expense)
Accumulated other comprehensive income
$
$
247
(172)
(1)
74
10
(26)
3
(13)
61
$
1,223
(372)
11
862
1
6
(2)
5
$
1,470
(544)
10
936
11
(20)
1
(8)
$
867
$
928
97
FORTIS INC. 2019 ANNUAL REPORTNotes to Consolidated Financial Statements
22. 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 termination, death or retirement of the
optionee, and vest evenly over a four-year period on each anniversary of the grant date.
The following options were granted in 2019 and 2018.
Options granted (# in 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)
2019
February
2018
February
852
47.57
3.70
3.8
15.2
1.8
5.6
722
41.27
3.43
3.7
15.5
2.1
5.6
March
40
42.00
4.08
3.7
15.7
2.0
5.6
(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 2019.
(in thousands, except as indicated)
Options outstanding, January 1, 2019
Granted
Exercised
Vested
Cancelled/Forfeited
Options outstanding, December 31, 2019
Options vested, December 31, 2019 (2)
Total Options
Non-vested Options (1)
Number of
Options
4,015
852
(1,449)
n/a
–
3,418
1,508
Weighted
Average
Exercise
Price
$
$
$
$
$
37.73
47.57
35.36
n/a
n/a
41.18
37.69
Weighted
Average
Grant Date
Fair Value
$
$
$
$
3.10
3.70
n/a
2.92
n/a
3.43
Number of
Options
1,771
852
n/a
(713)
–
1,910
(1) As at December 31, 2019, there was $7 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, 2019, the weighted average remaining term of vested options was six years with an aggregate intrinsic value of $24 million.
The following table summarizes additional stock option information.
(in millions)
Stock option expense recognized
Stock options exercised:
Cash received for exercise price
Intrinsic value realized by employees
Fair value of options that vested
98
$
2019
2
51
22
2
$
2018
2
12
3
2
For the years ended December 31, 2019 and 2018FORTIS INC. 2019 ANNUAL REPORTNotes to Consolidated Financial Statements
Directors’ 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.
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 (in thousands)
Beginning of year
Granted
Notional dividends reinvested
Paid out
End of year
Additional information (in millions)
Compensation expense recognized
Cash payout (1)
Accrued liability as at December 31 (2)
2019
177
29
6
(47)
165
3
2
9
$
2018
185
32
8
(48)
177
2
2
8
$
(1) Reflects a weighted average payout price of $51.76 per DSU (2018 – $43.15)
(2) Recognized at the respective December 31st VWAP (Note 3) and included in long-term other liabilities (Note 17)
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 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. 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 maturity 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 certain 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 (in thousands)
Beginning of year
Granted
Notional dividends reinvested
Paid out
Cancelled/forfeited
End of year
Additional information (in millions)
Compensation expense recognized
Compensation expense unrecognized (1)
Cash payout (2)
Accrued liability as at December 31 (3)
Aggregate intrinsic value as at December 31 (4)
2019
1,763
690
73
(357)
(51)
2,118
74
35
16
106
141
$
2018
1,351
669
66
(281)
(42)
1,763
22
27
14
50
77
$
(1) Relates to unvested PSUs and is expected to be recognized over a weighted average period of two years
(2) Reflects a weighted average payout price of $45.14 per PSU and a payout percentage of 101% (2018 – $46.01 and 109% respectively)
(3) Recognized at the respective December 31st VWAP (Note 3) and included in accounts payable and other current liabilities and in long-term other liabilities (Notes 14 and 17)
(4) Relates to outstanding PSUs and reflects a weighted average contractual life of one year
99
FORTIS INC. 2019 ANNUAL REPORTNotes to Consolidated Financial Statements
22.
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.
The following table summarizes information related to RSUs.
Number of units (in thousands)
Beginning of year
Granted
Notional dividends reinvested
Paid out
Cancelled/forfeited
End of year
Additional information (in millions)
Compensation expense recognized
Compensation expense unrecognized (1)
Cash payout (2)
Accrued liability as at December 31 (3)
Aggregate intrinsic value as at December 31 (4)
2019
717
429
35
(92)
(39)
1,050
24
17
4
39
56
$
2018
483
305
26
(75)
(22)
717
11
15
3
19
34
$
(1) Relates to unvested RSUs and is expected to be recognized over a weighted average period of two years
(2) Reflects a weighted average payout price of $45.83 per RSU (2018 – $45.55)
(3) Recognized at the respective December 31st VWAP (Note 3) and included in accounts payable and other current liabilities and in long-term other liabilities (Notes 14 and 17)
(4) Relates to outstanding RSUs and reflects a weighted average contractual life of one year
23. DISPOSITION
On April 16, 2019, Fortis sold its 51% ownership interest in the 335-megawatt Waneta Expansion for proceeds of $995 million. A gain on disposition of
$577 million ($484 million after tax), net of expenses, was recognized in the Corporate and Other segment, and the related non-controlling interest
has been removed from equity. Refer to Note 15 for use of proceeds.
Up to the date of disposition, the Waneta Expansion contributed $17 million to earnings before income tax expense, excluding the gain on
disposition (December 31, 2018 – $54 million), of which Fortis’ share was 51%.
100
For the years ended December 31, 2019 and 2018FORTIS INC. 2019 ANNUAL REPORTNotes to Consolidated Financial Statements
24. OTHER INCOME, NET
(in millions)
Equity component of AFUDC
Derivative gains (losses)
Interest income
Gain on repayment of debt (Note 15)
Other
25. INCOME TAXES
Deferred Income Tax Assets and Liabilities
The significant components of deferred income tax assets and liabilities consisted of the following.
(in millions)
Gross deferred income tax assets
Regulatory liabilities
Tax loss and credit carryforwards
Employee future benefits
Unrealized foreign exchange losses on long-term debt
Other
Valuation allowance
Net deferred income tax asset
Gross deferred income tax liabilities
PPE
Regulatory assets
Intangible assets
Net deferred income tax liability
$
2019
74
17
16
11
20
$
138
$
2019
588
532
165
40
88
1,413
(22)
$
1,391
$
(3,986)
(269)
(105)
(4,360)
$
(2,969)
$
$
$
$
$
2018
64
(12)
15
–
(7)
60
2018
635
522
153
69
76
1,455
(56)
1,399
(3,780)
(203)
(102)
(4,085)
$
(2,686)
The deferred income tax assets associated with unrealized foreign exchange losses on long-term debt reflect $22 million of unrealized capital losses
as at December 31, 2019 (December 31, 2018 – $56 million). These deferred income tax assets can only be utilized if the Corporation has capital gains
to offset these losses once realized. Management believes that it is “more likely than not” that Fortis will not be able to generate sufficient future
capital gains and, consequently, the Corporation recognized a valuation allowance.
Management believes that, based on its historical pattern of taxable income, Fortis will produce the necessary income in the future to realize all
other deferred income tax assets.
101
FORTIS INC. 2019 ANNUAL REPORTNotes to Consolidated Financial Statements
25.
INCOME TAXES (cont’d)
Unrecognized Tax Benefits
(in millions)
Beginning of year
Additions related to current year
Adjustments related to prior years
End of year
2019
38
5
(7)
36
$
$
2018
28
6
4
38
$
$
Unrecognized tax benefits, if recognized, would reduce income tax expense by $1 million in 2019. Fortis has not recognized interest expense in 2019
and 2018 related to unrecognized tax benefits.
Income Tax Expense
(in 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
2019
2018
$
901
$
376
49
42
91
$
51
(25)
26
$
$
1,240
$
1,075
(7)
205
198
289
$
$
(22)
161
139
165
$
$
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.
The following is a reconciliation of consolidated statutory taxes to consolidated effective taxes.
(in millions, except %)
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
Difference between gain on sale for accounting and amounts calculated for tax purposes
Release of valuation allowance
Remeasurement of deferred tax liabilities
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
2019
2,141
28.5%
610
$
$
(124)
(73)
(33)
–
(16)
(48)
(17)
(10)
2018
1,451
28.5%
414
$
$
(110)
–
(16)
(44)
(14)
(34)
(21)
(10)
$
289
13.5%
$
165
11.4%
102
For the years ended December 31, 2019 and 2018FORTIS INC. 2019 ANNUAL REPORTNotes to Consolidated Financial Statements
Income Tax Carryforwards
(in millions)
Canadian
Capital loss
Non-capital loss
Other tax credits
Unrecognized
Foreign
Federal and state net operating loss
Other tax credits
Expiring Year
n/a
2028–2039
2026–2038
2020–2039
2023–2039
$
2019
19
110
2
131
(14)
117
2,929
74
3,003
Total income tax carryforwards recognized as at December 31
$
3,120
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 and British Columbia). The Corporation’s 2013 to 2019 taxation years are still
open for audit in Canadian jurisdictions and its 2016 to 2019 taxation years are still open for audit in United States jurisdictions.
26. 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, 2016 for FortisBC Electric and FortisBC Energy (plans covering unionized
employees); December 31, 2017 for Newfoundland Power, FortisAlberta, FortisOntario and the Corporation; December 31, 2018 for FortisBC Energy
(plan covering non-unionized employees); and December 31, 2019 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.
103
FORTIS INC. 2019 ANNUAL REPORTNotes to Consolidated Financial Statements
26. EMPLOYEE FUTURE BENEFITS (cont’d)
Allocation of Plan Assets as at December 31
(weighted average %)
Equities
Fixed income
Real estate
Cash and other
Fair Value of Plan Assets as at December 31
(in millions)
2019
Equities
Fixed income
Real estate
Private equities
Cash and other
2018
Equities
Fixed income
Real estate
Private equities
Cash and other
2019 Target
Allocation
46
47
6
1
100
2019
47
46
6
1
100
Level 1 (1)
Level 2 (1)
Level 3 (1)
$
$
$
$
622
171
–
–
8
801
508
144
–
–
8
660
$
1,050
1,445
16
–
10
$
2,521
$
885
1,338
14
–
11
$
2,248
$
$
$
$
–
–
207
22
–
229
–
–
190
25
–
215
(1) Refer to Note 28 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.
(in millions)
Balance, beginning of year
Return on plan assets
Foreign currency translation
Purchases, sales and settlements
Balance, end of year
2019
215
19
(2)
(3)
229
$
$
2018
45
47
7
1
100
Total
1,672
1,616
223
22
18
$
$
3,551
$
$
$
$
1,393
1,482
204
25
19
3,123
2018
190
15
3
7
215
104
For the years ended December 31, 2019 and 2018FORTIS INC. 2019 ANNUAL REPORTNotes to Consolidated Financial Statements
Funded Status
(in millions)
(1)
Change in benefit obligation
Balance, beginning of year
Service costs
Employee contributions
Interest costs
Benefits paid
Actuarial losses (gains)
Past service costs (credits)/plan amendments
Foreign currency translation
Balance, end of year (2) (3)
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 (4)
Funded status
Balance sheet presentation
Long-term assets (Note 10)
Current liabilities (Note 14)
Long-term liabilities (Note 17)
Defined Benefit
Pension Plans
$
2019
3,207
77
16
124
(144)
439
1
(88)
$
3,632
$
$
$
$
2,830
523
(138)
18
53
(78)
3,208
(424)
46
(12)
(458)
$
(424)
2018
3,215
84
16
114
(145)
(217)
(1)
141
3,207
2,841
(93)
(137)
16
79
124
2,830
(377)
26
(12)
(391)
(377)
$
$
$
$
$
$
$
OPEB Plans
2019
2018
$
$
$
$
$
$
655
27
2
25
(27)
46
4
(20)
712
293
62
(27)
2
28
(15)
343
(369)
17
(12)
(374)
$
(369)
$
$
$
$
$
$
$
665
31
2
23
(26)
(69)
(3)
32
655
277
(13)
(26)
2
29
24
293
(362)
1
(13)
(350)
(362)
(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 $3,352 million (2018 – $2,936 million).
(3) The increases in the defined benefit pension and OPEB obligations were driven by the decrease in discount rates due to lower interest rates.
(4) The increases in the defined benefit pension and OPEB plan assets were driven by favourable market returns, largely related to the performance of equity investments during
the year.
For those defined benefit pension plans for which the projected benefit obligation exceeded the fair value of plan assets as at December 31, 2019, the
obligation was $2,971 million compared to plan assets of $2,511 million, respectively (December 31, 2018 – $2,600 million and $2,207 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, 2019, the
obligation was $2,752 million compared to plan assets of $2,478 million, respectively (December 31, 2018 – $2,185 million and $1,940 million, respectively).
For those OPEB plans for which the accumulated benefit obligation exceeded the fair value of plan assets as at December 31, 2019, the obligation was
$537 million compared to plan assets of $151 million, respectively (December 31, 2018 – $486 million and $123 million, respectively).
105
FORTIS INC. 2019 ANNUAL REPORTNotes to Consolidated Financial Statements
26. EMPLOYEE FUTURE BENEFITS (cont’d)
Net Benefit Cost (1)
Defined Benefit
Pension Plans
OPEB Plans
(in millions)
Service costs
Interest costs
Expected return on plan assets
Amortization of actuarial losses (gains)
Amortization of past service credits/plan amendments
Regulatory adjustments
$
2019
77
124
(161)
24
(1)
2
Net benefit cost
$
65
2018
84
114
(162)
48
–
(1)
83
$
$
2019
27
25
(16)
(4)
(7)
3
28
$
$
2018
31
23
(16)
–
(10)
6
34
$
$
(1) The non-service cost components of net periodic benefit cost are included in other income, net on the consolidated statements of earnings.
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.
(in millions)
Unamortized net actuarial losses (gains)
Unamortized past service costs
Income tax recovery
Accumulated other comprehensive
income (loss) (Note 21)
Net actuarial losses (gains)
Past service credits
Other regulatory deferrals
Regulatory assets (Note 9)
Regulatory liabilities (Note 9)
Net regulatory assets (liabilities)
Defined Benefit
Pension Plans
2019
32
1
(8)
25
486
(9)
15
492
492
–
492
$
$
$
$
$
$
2018
19
1
(3)
17
457
(10)
15
462
462
–
462
$
$
$
$
$
$
OPEB Plans
2019
2018
$
$
$
$
$
$
(2)
7
(1)
4
(18)
(8)
19
(7)
38
(45)
(7)
$
$
$
$
$
$
(2)
2
(1)
(1)
(25)
(16)
27
(14)
23
(37)
(14)
106
For the years ended December 31, 2019 and 2018FORTIS INC. 2019 ANNUAL REPORTNotes to Consolidated Financial Statements
The following table summarizes the components of net benefit cost recognized in comprehensive income or as regulatory assets, which would
otherwise have been recognized in comprehensive income.
(in millions)
2019
2018
2019
2018
Defined Benefit
Pension Plans
OPEB Plans
Current year net actuarial losses (gains)
Past service costs (credits)/plan amendments
Amortization of actuarial losses (gains)
Foreign currency translation
Income tax (recovery) expense
Total recognized in comprehensive income
Current year net actuarial losses (gains)
Past service credits/plan amendments
Amortization of actuarial (losses) gains
Amortization of past service (costs) credits
Foreign currency translation
Regulatory adjustments
Total recognized in regulatory assets
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)
$
$
$
$
11
–
1
1
(5)
8
64
–
(23)
(1)
(10)
–
30
$
$
$
$
Defined Benefit
Pension Plans
2019
4.05
3.20
5.78
3.33
–
(3)
–
(1)
1
2
(1)
41
–
(47)
1
21
4
20
2018
3.56
4.07
5.80
3.35
–
$
$
$
$
–
5
–
–
–
5
3
–
4
8
–
(8)
7
OPEB Plans
2019
4.10
3.25
5.50
–
4.62
$
$
$
$
(2)
(1)
–
–
–
(3)
(39)
(3)
–
11
(3)
(1)
(35)
2018
3.57
4.13
5.48
–
4.61
(1) ITC and UNS use the split discount rate methodology for determining current service and interest costs. All other subsidiaries use the single discount rate approach.
(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 2020 weighted average health care cost trend rate is 6.15% and is assumed to decrease over the next 12 years to the weighted average ultimate health care cost
trend rate of 4.62% in 2031 and thereafter.
Expected Benefit Payments
(year)
2020
2021
2022
2023
2024
2025–2029
Defined Benefit
Pension Payments
(in millions)
$
152
156
164
168
175
959
OPEB
Payments
(in millions)
$
25
27
29
30
31
174
During 2020 the Corporation expects to contribute $46 million for defined benefit pension plans and $32 million for OPEB plans.
In 2019 the Corporation expensed $39 million (2018 – $38 million) related to defined contribution pension plans.
107
FORTIS INC. 2019 ANNUAL REPORTNotes to Consolidated Financial Statements
27. SUPPLEMENTARY CASH FLOW INFORMATION
(in 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
Finance leases
Right-of-use assets obtained in exchange for operating lease liabilities
Contributions in aid of construction
Exercise of stock options into common shares
$
$
$
$
2019
1,007
(37)
1
(8)
(13)
(75)
(8)
(65)
(168)
382
299
88
55
15
5
$
$
$
$
2018
969
73
(204)
1
(8)
16
99
(6)
(102)
328
272
223
–
14
1
28. FAIR VALUE OF FINANCIAL INSTRUMENTS AND RISK MANAGEMENT
Derivatives
The Corporation generally limits derivative usage to those qualifying as accounting, economic or cash flow hedges, or those that are otherwise 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 flows.
Cash flows associated with the settlement of all derivatives are included in operating activities on the consolidated statements of cash flows.
108
For the years ended December 31, 2019 and 2018FORTIS INC. 2019 ANNUAL REPORTNotes to Consolidated Financial Statements
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 were 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 were
measured using forward pricing provided by independent third-party information.
FortisBC Energy holds gas supply contracts and commodity swaps 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, 2019, unrealized losses of $119 million
(December 31, 2018 – $57 million) were recognized as regulatory assets and unrealized gains of $2 million (December 31, 2018 – $9 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 were measured using a market approach utilizing independent third-party information,
where possible.
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 were measured using forward pricing from published market sources.
Unrealized gains or losses associated with changes in the fair value of these energy contracts are recognized in revenue. During 2019 unrealized
losses of $16 million (2018 – unrealized losses of $12 million) were recognized in revenue.
Total Return Swaps
The Corporation holds total return swaps to manage the cash flow risk associated with forecasted future cash settlements of certain stock-based
compensation obligations. The swaps have a combined notional amount of $111 million and terms of one to three years expiring in January 2020,
2021 and 2022. Fair value was measured using an income valuation approach based on forward pricing curves. During 2019 unrealized gains of
$11 million (2018 – unrealized gains of less than $1 million) were recognized in other income, net.
Foreign Exchange Contracts
The Corporation holds US dollar foreign exchange contracts to help mitigate exposure to volatility of foreign exchange rates. The contracts expire
in 2020 and have a combined notional amount of $166 million. Fair value was measured using independent third-party information. During 2019
unrealized gains of $11 million (2018 – unrealized losses of $11 million) were recognized in other income, net.
Interest Rate Swaps
During 2019 ITC entered into forward-starting interest rate swaps to manage the interest rate risk associated with the refinancing of long-term debt
due in June 2021. The swaps have a combined notional value of $260 million and five-year terms with a mandatory early termination provision.
The swaps will be terminated no later than the effective date of November 2020. Fair value was measured using a discounted cash flow method
based on LIBOR rates. Unrealized gains and losses associated with 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 2019 and 2018.
Other Investments
ITC, UNS Energy and Central Hudson hold investments in trust associated with supplemental retirement benefit plans for select employees. These
investments consist of mutual funds and money market accounts, which are recorded at fair value based on quoted market prices in active markets.
Gains and losses on these funds are recognized in other income, net and were not material for 2019 and 2018.
109
FORTIS INC. 2019 ANNUAL REPORTNotes to Consolidated Financial Statements 28.
FAIR VALUE OF FINANCIAL INSTRUMENTS AND RISK MANAGEMENT (cont’d)
Recurring Fair Value Measures
The following table presents the fair value of assets and liabilities that were accounted for at fair value on a recurring basis.
(in millions)
Level 1 (1)
Level 2 (1)
Level 3 (1)
Total
As at December 31, 2019
Assets
Energy contracts subject to regulatory deferral (2) (3)
Energy contracts not subject to regulatory deferral (2)
Foreign exchange contracts, interest rate 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)
As at December 31, 2018
Assets
Energy contracts subject to regulatory deferral (2) (3)
Energy contracts not subject to regulatory deferral (2)
Other investments (4)
Liabilities
Energy contracts subject to regulatory deferral (3) (5)
Energy contracts not subject to regulatory deferral (5)
Foreign exchange contracts, interest rate and total
return swaps (5)
$
$
$
$
$
$
$
$
–
–
14
121
135
(1)
–
(1)
–
–
155
155
–
–
(8)
(8)
$
$
$
$
$
$
$
$
22
8
4
–
34
(138)
(12)
(150)
33
13
–
46
(86)
(1)
(1)
(88)
$
$
$
$
$
$
$
$
–
–
–
–
–
–
–
–
8
3
–
11
(3)
–
–
(3)
$
$
$
$
$
$
$
$
22
8
18
121
169
(139)
(12)
(151)
41
16
155
212
(89)
(1)
(9)
(99)
(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
measurement. At December 31, 2019, all level 3 assets and liabilities transferred to level 2 because observable market data became available.
(2) Included in accounts receivable and other current assets or other assets
(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.
(4) Included in other assets
(5) Included in accounts payable and other current liabilities or other liabilities
The Corporation has elected gross presentation for its derivative contracts under master netting agreements and collateral positions, which applies
only to its energy contracts. The following table presents the potential offset of counterparty netting.
Energy Contracts
(in millions)
As at December 31, 2019
Derivative assets
Derivative liabilities
As at December 31, 2018
Derivative assets
Derivative liabilities
110
Gross Amount
Recognized in
Balance Sheet
Counterparty
Netting of
Energy Contracts
Cash Collateral
Received/Posted
Net Amount
$
$
30
(151)
57
(90)
$
$
22
(22)
28
(28)
$
$
10
(2)
16
–
$
$
(2)
(127)
13
(62)
For the years ended December 31, 2019 and 2018FORTIS INC. 2019 ANNUAL REPORTNotes to Consolidated Financial Statements
Volume of Derivative Activity
As at December 31, 2019, 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.
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) GWh means gigawatt hours and PJ means petajoules.
Credit Risk
2019
628
3,198
168
241
1,855
43
2018
774
651
203
266
1,440
37
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 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, bond, 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 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.
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 $161 million as at December 31, 2019 (December 31, 2018 – $75 million).
Foreign Exchange Hedge
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 US dollar. The earnings and cash flows from, and net investments in, these entities are exposed to fluctuations in the
US dollar-to-Canadian dollar exchange rate. The Corporation has limited this exposure through hedging.
As at December 31, 2019, US$2.2 billion (December 31, 2018 – US$3.4 billion) of corporately issued US dollar-denominated long-term debt has been
designated as an effective hedge of foreign net investments, leaving approximately US$9.7 billion (December 31, 2018 – US$8.0 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, 2019, the carrying value of long-term debt, including current portion, was $22.3 billion (December 31, 2018 – $24.2 billion)
compared to an estimated fair value of $25.3 billion (December 31, 2018 – $25.1 billion).
111
FORTIS INC. 2019 ANNUAL REPORTNotes to Consolidated Financial Statements
29. COMMITMENTS AND CONTINGENCIES
As at December 31, 2019, consolidated unconditional minimum purchase obligations were as follows.
Due
(in millions)
Waneta Expansion capacity agreement (1)
Gas and fuel purchase obligations (2)
Power purchase obligations (3)
Renewable PPAs (4)
Build-transfer agreement – Oso Grande (5)
ITC easement agreement (6)
Renewable energy credit purchase agreements (7)
Debt collection agreement (8)
Other (9)
Total
Year 1
Year 2
Year 3
Year 4
Year 5
Thereafter
$ 2,628
2,398
1,743
1,513
438
401
124
116
299
$
51
606
244
104
438
13
26
3
36
$
52
424
183
104
–
13
18
3
26
$
53
349
168
104
–
13
17
3
24
$
54
255
163
103
–
13
10
3
25
$
55
140
119
103
–
13
10
3
29
$ 2,363
624
866
995
–
336
43
101
159
Total
(1)
(2)
$ 9,660
$ 1,521
$
823
$
731
$
626
$
472
$ 5,487
FortisBC Electric entered into an agreement to purchase capacity from Waneta Expansion. In April 2019 the Waneta Expansion ceased to be
a related party, resulting in the disclosure of FortisBC Electric’s agreement to purchase capacity from the Waneta Expansion over the 40-year
agreement that began in April 2015.
FortisBC Energy ($1.5 billion): includes contracts for the purchase of gas, gas transportation and storage services, with expiry dates from 2020 to
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, 2019.
UNS Energy ($775 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, and the purchase of transmission services for purchased power. 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 between 2020 and 2040.
(3)
Maritime Electric ($669 million): includes an agreement entitling Maritime Electric to approximately 4.55% of the output of New Brunswick Power’s
Point Lepreau nuclear generating station and requiring Maritime Electric to pay its share of the station’s capital operating costs for the life of
the unit. Maritime Electric also has two take-or-pay contracts for the purchase of either capacity or energy, expiring in February 2024.
FortisOntario ($653 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 from January 2020 through December 2030.
FortisBC Electric ($344 million): 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.
(4)
(5)
(6)
(7)
(8)
TEP and UNS Electric are party to renewable PPAs, with expiry dates from 2031 through 2043, that require TEP and UNS Electric to purchase
100% of the output of certain renewable energy generating facilities once commercial operation is achieved. Amounts are the estimated
future payments.
In March 2019 UNS Energy entered into a build-transfer agreement to develop a wind-powered electric generation facility, the Oso Grande
Wind Project, with estimated project cost of US$384 million. Construction commenced in the third quarter of 2019 and is expected to be
completed by December 2020. UNS Energy made payments of US$47 million in 2019 and US$226 million in January 2020 under this agreement.
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 licences associated with the land over which its transmission lines cross.
The agreement expires in December 2050, subject to 10 potential 50-year renewals thereafter.
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.
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,
will be collected from customers in future rates.
(9)
Includes land easements, asset retirement obligations and joint-use asset and shared service agreements.
112
For the years ended December 31, 2019 and 2018FORTIS INC. 2019 ANNUAL REPORTNotes to Consolidated Financial Statements
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. In October 2019 the Wataynikaneyap Partnership entered into loan agreements to finance the project during construction
(“construction loan agreements”). In the event a lender under the construction 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.
Central Hudson is a participant in an investment with other utilities to jointly develop, own and operate electric transmission projects in New York
State. In December 2014 an application was filed with FERC for the recovery of the cost of and return on five high-voltage transmission projects
totalling $2.2 billion (US$1.7 billion). Central Hudson’s maximum commitment is $236 million (US$182 million), for which it has issued a parental
guarantee. As at December 31, 2019, there was no obligation under this guarantee.
As at December 31, 2019, FortisBC Holdings Inc. had $78 million (December 31, 2018 – $77 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.
113
FORTIS INC. 2019 ANNUAL REPORTNotes to Consolidated Financial Statements Historical Financial Summary
Statements of Earnings (in $ millions)
Revenue
Energy supply costs and operating expenses
Depreciation and amortization
Gain on disposition
Other income, net
Finance charges
Income tax expense
Earnings from continuing operations
Earnings from discontinued operations, net of tax
Extraordinary gain, net of tax
Net earnings
Net earnings attributable to non-controlling interests
Net earnings attributable to preference equity shareholders
Net earnings attributable to common equity shareholders
Balance Sheets (in $ millions)
Current assets
Property, plant and equipment, non-utility capital assets(2) and intangible assets
Goodwill
Other long-term assets
Total assets
Current liabilities
Long-term debt (excluding current portion)
Other long-term liabilities
Total liabilities
Total equity
Cash Flows (in $ millions)
Operating activities
Investing activities
Financing activities, excluding dividends
Dividends
Financial Statistics
Return on average book common shareholders’ equity (%)
Capitalization Ratios (%) (year end)
Total debt and finance leases (net of cash)
Preference shares
Common shareholders’ equity
Interest Coverage (x)
Debt
All fixed charges
Total capital expenditures (in $ millions)
Common share data
Book value per share (year end) ($)
Average common shares outstanding (in millions)
Basic earnings per common share ($)
Dividends declared per common share ($)
Dividends paid per common share ($)
Dividend payout ratio (%)
Price earnings ratio (x)
Share trading summary (TSX)
High price ($)
Low price ($)
Closing price ($)
Volume (in thousands)
2019 (1)
8,783
4,972
1,350
577
138
1,035
289
1,852
–
–
1,852
130
67
1,655
2,574
35,248
12,004
3,578
53,404
4,176
21,501
7,614
33,291
20,113
2,663
(2,768)
788
(634)
10.40
55.1
4.0
40.9
2.9
2.9
3,818
36.49
436.8
3.79
1.855
1.8275
48.2
14.2
56.94
44.00
53.88
297,490
2018
8,390
4,782
1,243
–
60
974
165
1,286
–
–
1,286
120
66
1,100
3,261
33,957
12,530
3,303
53,051
4,252
23,159
7,184
34,595
18,456
2,604
(3,252)
1,254
(610)
7.78
59.7
3.9
36.4
2.3
2.3
3,218
34.80
424.7
2.59
1.75
1.725
66.6
17.6
47.36
39.38
45.51
269,284
2017
8,301
4,611
1,179
–
116
914
588
1,125
–
–
1,125
97
65
963
2,207
30,749
11,644
3,222
47,822
3,504
20,691
6,878
31,073
16,749
2,756
(3,025)
932
(593)
7.31
59.2
4.4
36.4
2.7
2.7
3,024
31.77
415.5
2.32
1.65
1.625
70.0
19.9
48.73
40.59
46.11
205,261
(1) Results were impacted by non-recurring items, largely associated with the disposition of Waneta Expansion in 2019, the acquisition of ITC in 2016, the sale of non-core assets in
2015, the acquisition of UNS Energy in 2014 and the acquisition of Central Hudson in 2013.
(2) Non-utility capital assets were sold as part of the sale of commercial real estate and hotel assets in 2015.
114
2016 (1)
6,838
4,372
983
–
53
678
145
713
–
–
713
53
75
585
2,166
30,348
12,364
3,026
47,904
3,944
20,817
6,693
31,454
16,450
1,884
(6,891)
5,491
(441)
5.56
60.6
4.4
35.0
2.1
2.1
2,061
32.31
308.9
1.89
1.55
1.525
80.7
21.9
44.87
35.53
41.46
2015 (1)
6,757
4,465
873
–
197
553
223
840
–
–
840
35
77
728
1,857
20,136
4,173
2,638
28,804
2,638
10,784
5,029
18,451
10,353
1,673
(1,368)
(14)
(332)
9.75
54.8
8.3
36.9
2.7
2.7
2,243
28.62
278.6
2.61
1.43
1.40
53.6
14.3
42.23
34.16
37.41
2014 (1)
5,401
3,690
688
–
(25)
547
66
385
5
–
390
11
62
317
1,787
18,304
3,732
2,410
26,233
2,676
9,911
4,534
17,121
9,112
982
(4,199)
3,627
(266)
5.45
56.4
9.1
34.5
1.6
1.6
1,725
24.89
225.6
1.41
1.30
1.28
90.8
27.6
40.83
29.78
38.96
2013 (1)
4,047
2,654
541
–
(31)
389
32
400
–
20
420
10
57
353
1,296
12,612
2,075
1,925
17,908
2,084
6,424
3,024
11,532
6,376
899
(2,164)
1,434
(248)
8.06
56.2
9.0
34.8
1.9
1.9
1,175
22.38
202.5
1.74
1.25
1.24
71.3
17.5
35.14
29.51
30.45
2012
3,654
2,390
470
–
4
366
61
371
–
–
371
9
47
315
1,093
10,574
1,568
1,715
14,950
1,350
5,741
2,449
9,540
5,410
992
(1,096)
396
(225)
8.06
55.3
9.7
35.0
2.0
2.0
1,146
20.84
190.0
1.66
1.21
1.20
72.3
20.6
34.98
31.70
34.22
2011
3,738
2,547
416
–
38
363
84
366
–
–
366
9
46
311
1,132
9,937
1,565
1,580
14,214
1,305
5,685
2,281
9,271
4,943
915
(1,115)
386
(206)
8.79
57.1
8.3
34.6
2.0
2.0
1,171
20.25
181.6
1.71
1.17
1.16
67.8
19.5
35.45
28.24
33.37
2010
3,647
2,448
406
–
13
359
72
375
–
–
375
10
45
320
1,205
9,336
1,561
1,309
13,411
1,491
5,616
1,977
9,084
4,327
742
(980)
451
(189)
10.06
60.4
8.7
30.9
2.0
2.0
1,071
18.65
172.9
1.85
1.41
1.12
60.5
18.4
34.54
21.60
33.98
293,991
172,038
174,566
120,470
115,962
126,341
120,855
FORTIS INC. 2019 ANNUAL REPORT Property, plant and equipment, non-utility capital assets(2) and intangible assets
Statements of Earnings (in $ millions)
Revenue
Energy supply costs and operating expenses
Depreciation and amortization
Gain on disposition
Other income, net
Finance charges
Income tax expense
Earnings from continuing operations
Earnings from discontinued operations, net of tax
Extraordinary gain, net of tax
Net earnings
Net earnings attributable to non-controlling interests
Net earnings attributable to preference equity shareholders
Net earnings attributable to common equity shareholders
Balance Sheets (in $ millions)
Current assets
Long-term debt (excluding current portion)
Goodwill
Other long-term assets
Total assets
Current liabilities
Other long-term liabilities
Total liabilities
Total equity
Cash Flows (in $ millions)
Operating activities
Investing activities
Dividends
Financial Statistics
Financing activities, excluding dividends
Return on average book common shareholders’ equity (%)
Capitalization Ratios (%) (year end)
Total debt and finance leases (net of cash)
Preference shares
Common shareholders’ equity
Interest Coverage (x)
Debt
All fixed charges
Total capital expenditures (in $ millions)
Common share data
Book value per share (year end) ($)
Average common shares outstanding (in millions)
Basic earnings per common share ($)
Dividends declared per common share ($)
Dividends paid per common share ($)
Dividend payout ratio (%)
Price earnings ratio (x)
Share trading summary (TSX)
High price ($)
Low price ($)
Closing price ($)
Volume (in thousands)
2019 (1)
8,783
4,972
1,350
577
138
1,035
289
1,852
–
–
1,852
130
67
1,655
2,574
35,248
12,004
3,578
53,404
4,176
21,501
7,614
33,291
20,113
2,663
(2,768)
788
(634)
10.40
55.1
4.0
40.9
2.9
2.9
3,818
36.49
436.8
3.79
1.855
1.8275
48.2
14.2
56.94
44.00
53.88
297,490
2018
8,390
4,782
1,243
–
60
974
165
1,286
–
–
1,286
120
66
1,100
3,261
33,957
12,530
3,303
53,051
4,252
23,159
7,184
34,595
18,456
2,604
(3,252)
1,254
(610)
7.78
59.7
3.9
36.4
2.3
2.3
3,218
34.80
424.7
2.59
1.75
1.725
66.6
17.6
47.36
39.38
45.51
2017
8,301
4,611
1,179
–
116
914
588
1,125
–
–
1,125
97
65
963
2,207
30,749
11,644
3,222
47,822
3,504
20,691
6,878
31,073
16,749
2,756
(3,025)
932
(593)
7.31
59.2
4.4
36.4
2.7
2.7
3,024
31.77
415.5
2.32
1.65
1.625
70.0
19.9
48.73
40.59
46.11
(1) Results were impacted by non-recurring items, largely associated with the disposition of Waneta Expansion in 2019, the acquisition of ITC in 2016, the sale of non-core assets in
2015, the acquisition of UNS Energy in 2014 and the acquisition of Central Hudson in 2013.
(2) Non-utility capital assets were sold as part of the sale of commercial real estate and hotel assets in 2015.
269,284
205,261
2016 (1)
6,838
4,372
983
–
53
678
145
713
–
–
713
53
75
585
2,166
30,348
12,364
3,026
47,904
3,944
20,817
6,693
31,454
16,450
1,884
(6,891)
5,491
(441)
5.56
60.6
4.4
35.0
2.1
2.1
2,061
32.31
308.9
1.89
1.55
1.525
80.7
21.9
44.87
35.53
41.46
293,991
2015 (1)
6,757
4,465
873
–
197
553
223
840
–
–
840
35
77
728
1,857
20,136
4,173
2,638
28,804
2,638
10,784
5,029
18,451
10,353
1,673
(1,368)
(14)
(332)
9.75
54.8
8.3
36.9
2.7
2.7
2,243
28.62
278.6
2.61
1.43
1.40
53.6
14.3
42.23
34.16
37.41
172,038
2014 (1)
5,401
3,690
688
–
(25)
547
66
385
5
–
390
11
62
317
1,787
18,304
3,732
2,410
26,233
2,676
9,911
4,534
17,121
9,112
982
(4,199)
3,627
(266)
5.45
56.4
9.1
34.5
1.6
1.6
1,725
24.89
225.6
1.41
1.30
1.28
90.8
27.6
40.83
29.78
38.96
174,566
2013 (1)
4,047
2,654
541
–
(31)
389
32
400
–
20
420
10
57
353
1,296
12,612
2,075
1,925
17,908
2,084
6,424
3,024
11,532
6,376
899
(2,164)
1,434
(248)
8.06
56.2
9.0
34.8
1.9
1.9
1,175
22.38
202.5
1.74
1.25
1.24
71.3
17.5
35.14
29.51
30.45
120,470
2012
3,654
2,390
470
–
4
366
61
371
–
–
371
9
47
315
1,093
10,574
1,568
1,715
14,950
1,350
5,741
2,449
9,540
5,410
992
(1,096)
396
(225)
8.06
55.3
9.7
35.0
2.0
2.0
1,146
20.84
190.0
1.66
1.21
1.20
72.3
20.6
2011
3,738
2,547
416
–
38
363
84
366
–
–
366
9
46
311
1,132
9,937
1,565
1,580
14,214
1,305
5,685
2,281
9,271
4,943
915
(1,115)
386
(206)
8.79
57.1
8.3
34.6
2.0
2.0
1,171
20.25
181.6
1.71
1.17
1.16
67.8
19.5
2010
3,647
2,448
406
–
13
359
72
375
–
–
375
10
45
320
1,205
9,336
1,561
1,309
13,411
1,491
5,616
1,977
9,084
4,327
742
(980)
451
(189)
10.06
60.4
8.7
30.9
2.0
2.0
1,071
18.65
172.9
1.85
1.41
1.12
60.5
18.4
34.98
31.70
34.22
115,962
35.45
28.24
33.37
126,341
34.54
21.60
33.98
120,855
115
FORTIS INC. 2019 ANNUAL REPORTHistorical Financial Summary IN V E S TOR INFORM AT ION
Expected Dividend* and Earnings Release Dates
Dividend Record Dates
May 15, 2020
November 18, 2020
August 19, 2020
February 12, 2021
Dividend Payment Dates
June 1, 2020
December 1, 2020
September 1, 2020
March 1, 2021
Earnings Release Dates
May 6, 2020
October 30, 2020
July 30, 2020
February 12, 2021
* The setting of dividend record dates and the declaration and payment
of dividends are subject to the Board of Directors’ approval.
Transfer Agent and Registrar
Computershare Trust Company of Canada (“Computershare”
or “Transfer Agent”) is responsible for the maintenance of
shareholder records and the issuance, transfer and cancellation
of stock certificates. Transfers can be effected at its Montreal
and Toronto offices in Canada and at the co-transfer agent’s
Canton, MA, Jersey City, NJ, and Louisville, KY offices in the
United States. Computershare also distributes dividends and
shareholder communications. Inquiries with respect to these
matters and corrections to shareholder information should be
addressed to the Transfer Agent.
Computershare Trust Company of Canada
8th Floor, 100 University Avenue, Toronto, ON M5J 2Y1
T: 514.982.7555 or 1.866.586.7638
F: 416.263.9394 or 1.888.453.0330
W: www.investorcentre.com/fortisinc
Computershare Trust Company N.A.
Attn: Stock Transfer Department
Overnight Mail Delivery: 462 South 4th Street, Louisville, KY 40202
Regular Mail Delivery: P.O. Box 505005, Louisville, KY 40233-5005
Direct Deposit of Dividends
Shareholders may arrange for automatic electronic deposit
of dividends to their designated Canadian and U.S. financial
institutions by contacting the Transfer Agent.
Duplicate Annual Reports
While every effort is made to avoid duplications, some
shareholders may receive extra reports as a result of multiple
share registrations. Shareholders wishing to consolidate these
accounts should contact the Transfer Agent.
Eligible Dividend Designation
For purposes of the enhanced dividend tax credit rules
contained in the Income Tax Act (Canada) and any
corresponding provincial and territorial tax legislation,
all dividends paid on common and preferred shares after
December 31, 2005 by Fortis to Canadian residents are
designated as “eligible dividends.” Unless stated otherwise,
all dividends paid by Fortis hereafter are designated as
“eligible dividends” for the purposes of such rules.
Annual Meeting
Thursday, May 7, 2020 – 10:30 a.m.
Holiday Inn St. John’s, 180 Portugal Cove Road,
St. John’s, NL, Canada
Dividend Reinvestment Plan
Fortis offers a Dividend Reinvestment Plan (“DRIP”) as a
convenient method for Common Shareholders to increase
their investments in Fortis. Participants have dividends plus any
optional contributions (minimum of $100, maximum of $30,000
annually) automatically deposited in the plan to purchase
additional Common Shares. Shares can be purchased quarterly
on March 1, June 1, September 1 and December 1 at the
average market price then prevailing on the Toronto Stock
Exchange. Inquiries should be directed to the Transfer Agent.
Share Listings
The Common Shares; First Preference Shares, Series F; First
Preference Shares, Series G; First Preference Shares, Series H;
First Preference Shares, Series I; First Preference Shares, Series J;
First Preference Shares, Series K; and First Preference Shares,
Series M of Fortis Inc. are listed on the Toronto Stock Exchange
and trade under the ticker symbols FTS, FTS.PR.F, FTS.PR.G,
FTS.PR.H, FTS.PR.I, FTS.PR.J, FTS.PR.K and FTS.PR.M, respectively.
The Common Shares are also listed on the New York Stock
Exchange and trade under the ticker symbol FTS.
Valuation Day
For capital gains purposes, the valuation day prices are
as follows:
December 22, 1971
February 22, 1994
$1.531
$7.156
Analyst and Investor Inquiries
T: 709.737.2900
F: 709.737.5307
E: investorrelations@fortisinc.com
116
FORTIS INC. 2019 ANNUAL REPORT FORT IS INC. E X ECU T I V E
Barry V. Perry
President and Chief Executive Officer
Jocelyn H. Perry
Executive Vice President, Chief Financial Officer
David G. Hutchens
Chief Operating Officer and Chief Executive Officer of UNS Energy
Nora M. Duke
Executive Vice President, Sustainability and Chief Human Resource Officer
James P. Laurito
Executive Vice President, Business Development and Chief Technology Officer
James R. Reid
Executive Vice President, Chief Legal Officer and Corporate Secretary
Gary J. Smith
Executive Vice President, Eastern Canadian and Caribbean Operations
Stephanie A. Amaimo
Vice President, Investor Relations
Karen J. Gosse
Vice President, Treasury and Planning
Ronald J. Hinsley
Vice President, Chief Information Officer
Karen M. McCarthy
Vice President, Communications and Corporate Affairs
Regan P. O’Dea
Vice President, General Counsel
James D. Roberts
Vice President, Controller
Photography:
David Howells, St. John’s, NL
Front Cover:
Melissa Graham – Environmental Specialist, FortisBC
Design and Production:
m5 Marketing Communications, St. John’s, NL www.m5.ca
Moveable Inc., Toronto, ON www.moveable.com
Printer:
The Lowe-Martin Group, Ottawa, ON
B OA RD OF DIREC T ORS
Douglas J. Haughey Q X H
Chair of the Board, Fortis Inc.
Calgary, Alberta
Tracey C. Ball Q H
Corporate Director
Victoria, British Columbia
Pierre J. Blouin X H
Corporate Director
Mont-Royal, Quebec
Paul J. Bonavia X H
Corporate Director
Dallas, Texas
Lawrence T. Borgard Q X
Corporate Director
Naples, Florida
Maura J. Clark Q H
Corporate Director
New York, New York
Margarita K. Dilley Q X
Corporate Director
Washington, D.C.
Julie A. Dobson Q H
Corporate Director
Potomac, Maryland
Barry V. Perry
President and CEO, Fortis Inc.
St. John’s, Newfoundland and Labrador
Joseph L. Welch
Corporate Director
Longboat Key, Florida
Jo Mark Zurel Q X
Corporate Director
St. John’s, Newfoundland and Labrador
Q Audit Committee X Human Resources Committee
H Governance and Nominating Committee
For Board of Directors’ biographies,
please visit www.fortisinc.com.
Fortis Place | Suite 1100, 5 Springdale Street | PO Box 8837 | St. John’s, NL, Canada A1B 3T2
T: 709.737.2800 | F: 709.737.5307 | www.fortisinc.com | TSX NYSE: FTS
info@fortisinc.com | @Fortis_NA | Fortis Inc.