2 0 1 8 | A N N U A L R E P O R T
Scott Parker
Central Hudson
WE’RE LOOKING AHEAD, AND LOOKING UP
We’ve all heard the adage “the sky’s the limit”. That rings true for us at
Fortis. We’ve been growing for more than 130 years – and we don’t just
mean in size, but in strength. We’ve seized opportunities, learned from
experience, and celebrated every win, together. But we’ve never lost sight
of what matters most – our people, our customers, our shareholders,
our environment. And that focus is what propels us to even greater
heights today. For us, the sky is still the limit.
10 UTILITY
OPERATIONS
in Canada, the U.S. and
the Caribbean
1.3 MILLION
gas utility customers
EMPLOYEES STRONG
8,800
$53
2 MILLION
BILLION
in total assets
electric utility customers
$
19.5
(as of December 31, 2018)
market cap 45
BILLION
of dividend payment increases
CONSECUTIVE YEARS
Based in
ST. JOHN’S
Newfoundland & Labrador
T S X / N Y SE:F T S
Unless otherwise specified, all financial information referenced is in Canadian dollars.
R E P O R T T O S H A R E H O L D E R S
OUR GROW T H S T R AT EGY CRE AT E S L ONG -T E RM S H A RE HOL DE R VA LUE
Your company has grown into one of the top 15
utilities in North America. During the past five years,
we have acquired and successfully integrated three
strong U.S. based utility franchises – Central Hudson
Gas and Electric in New York State, UNS Energy in
Arizona and ITC Holdings based in Michigan. During
this period our utility rate base grew 156%, from
$10.2 billion to $26.1 billion.
With our business now operating as one strong
North American company, in October 2018 we
launched our most ambitious capital investment
plan ever. The $17.3 billion plan for the period 2019
to 2023 represents an increase of $2.8 billion or 20%
from the previous year’s plan. The investments will
help modernize the electricity grid, strengthen natural
gas infrastructure and enable the delivery of cleaner
energy. Once completed, our utility rate base will
have grown from $26.1 billion today to $35.5 billion
by 2023.
Virtually all of our operating assets are regulated.
Our focus on transmission and distribution assets,
with their lighter environmental footprint, coupled
with the geographic and regulatory diversity of our
business make Fortis one of the lowest-risk utility
companies in North America.
Our track record of delivering strong performance
continued in 2018 with net earnings attributable
to common equity shareholders of $1,100 million,
or $2.59 per common share, compared to
$963 million, or $2.32 per common share, for 2017.
We achieved adjusted net earnings of $1,066 million,
or $2.51 per common share, in 2018 compared
to $1,027 million, or $2.47 per common share,
in 2017. Adjusted earnings per share growth in
2018 was tempered by approximately 2% associated
with U.S. tax reform, which came into effect at the
end of 2017. Our 5.9% quarterly dividend increase
on December 1, 2018 to $0.45 per share, from
$0.425 per share, marked 45 consecutive years
of annual common share dividend payment
increases – one of the longest records for a
Canadian public corporation.
Your company’s long history of superior shareholder
returns continued in 2018 with a one-year total
shareholder return of 2.8%, far exceeding the negative
returns generated by the S&P/TSX Composite Index
and the S&P/TSX Capped Utilities Index, respectively.
This outperformance has also occurred over the
five, 10 and 20-year periods, where your company
experienced average annualized returns in the
10% to 12% range.
2
FORTIS INC. 2018 ANNUAL REPORT Total Annualized Shareholder Return
1-Y EAR
5-Y EAR
Fortis
2 . 8 %
Fortis
S&P/TSX
Composite Index
S&P/TSX Capped
Utilities Index
- 8 . 8 %
-7 . 7 %
S&P/TSX
Composite Index
S&P/TSX Capped
Utilities Index
10 -Y EAR
2 0 -Y EAR
Fortis
1 0 . 5 %
Fortis
S&P/TSX
Composite Index
S&P/TSX Capped
Utilities Index
7 . 9 %
7 . 2 %
S&P/TSX
Composite Index
S&P/TSX Capped
Utilities Index
1 2 . 6 %
4 . 1 %
6 . 1 %
1 2 . 4 %
6 . 6 %
7 . 9 %
3
REPORT TO SHAREHOLDERS F OCUS E D ON GROWING YOUR DIVIDE ND S
FORTIS HAS ONE OF THE LONGEST RECORDS
FOR ANNUAL COMMON SHARE DIVIDEND
PAYMENT INCREASES FOR A CANADIAN PUBLIC
CORPORATION.
In 2018, based on forecasted earnings
growth at our utilities, we extended
annual dividend growth guidance of
approximately 6% through 2023.
This guidance is based on continued
good performance at our utilities,
reasonable regulatory outcomes, the
successful execution of our five-year
capital investment plan and growth in
our franchise territories.
45 YEARS O F D IVI D EN D G ROW TH
Actual Dividend Paid
Forecasted Dividend Payments
$
2.5
2.0
1.5
1.0
0.5
73
75
77
79
81
83
85
87
89
91
93
95
97
99
01
03
05
07
09
11
13
15
17
19F
21F
23F
Y E A R
4
FORTIS INC. 2018 ANNUAL REPORT OUR S T RONG GEOGR A P HIC DIV E RSI T Y
British Columbia
Alberta
Minnesota
Iowa
Michigan
Illinois
Kansas
Missouri
Arizona
Oklahoma
Newfoundland
& Labrador
Prince Edward
Island
Ontario
New York
Regulated Electric
Regulated Gas
FERC-Regulated
Electric Transmission
Long-Term Contracted
Hydro Generation
Natural Gas Storage Facility
Turks and
Caicos Islands
Cayman Islands
Belize
5
REPORT TO SHAREHOLDERS F OCUS E D ON E X ECU T ING T HE $ 17. 3 BIL L ION
F IV E-Y E A R CA P I TA L IN V E S T ME N T P L A N
One of our notable accomplishments in 2018
was the completion of our $3.2 billion capital
investment plan at our utilities and the delivery
of a new five-year capital investment plan.
The new plan includes capital investment of
$17.3 billion for the period 2019 to 2023. It marks
an increase of $2.8 billion – 20% more than the
previous year’s plan.
Execution of the five-year plan is expected to
translate into average annual rate base growth
of 7.1% for the next three years and 6.3% over the
five-year planning period. The capital investment
plan is virtually 100% comprised of projects at our
regulated utilities and consists of a diverse mix of
highly executable low-risk projects. Capital projects
that individually total more than $150 million account
for 23% of the total plan, with the remainder, or
77%, comprised of smaller projects.
Ensuring a Strong, Reliable
Electricity Grid at ITC
As the importance of a strong and resilient grid
continues to increase, we expect more investment in
the wires side of our business in the future.
ITC, our largest utility, has more than 25,000 circuit
kilometres of high voltage electric transmission.
The utility has a singular focus on transmission, and
its vast network of infrastructure across seven states
in the U.S. Midwest requires ongoing infrastructure
investments to meet the growing needs of customers
and ensure preventative maintenance of the grid.
ITC’s rate base is expected to grow at an average
annual growth rate of 7% over the next five years, and
the utility’s continued investment in infrastructure is
a key component of our capital investment plan.
6
FORTIS INC. 2018 ANNUAL REPORT
Upgrades on Schedule for Natural
Gas Infrastructure at FortisBC
FortisBC is the largest distributor of natural gas in
British Columbia with more than one million customers.
In 2018 the utility began the construction of
20 kilometres of new gas lines to ensure the reliable
delivery of natural gas to more than 210,000 homes and
businesses in the Metro Vancouver area. The project
costs are approximately $500 million and construction
is on time and scheduled for completion in 2020.
Tucson Electric Power Poised to Exceed
Ambitious Renewable Energy Targets
Tucson Electric Power (“TEP”) has a target to serve
30% of retail load from renewable generation by
2030, doubling the State of Arizona’s goal. By 2030,
TEP plans to have three times as much wind and solar
energy as they have today, enough to power almost
every home in the Tucson area.
The utility made strong progress in 2018 to achieve
this target. The installation of fuel-efficient natural
gas generators has begun and once complete will
compensate for energy fluctuations associated with
the expanded use of renewable energy. The utility
Delivering Reliable, Cleaner Energy to
Remote First Nations Communities
The Wataynikaneyap Power Project, our partnership
with First Nations communities in northwestern
Ontario, made great progress in 2018. This
regulated electric transmission project will connect
17 communities to the Ontario power grid for the
first time. The project will see the construction of
1,800 kilometres of transmission lines that will enable
communities to move away from an unreliable
diesel plant system to a safer, cleaner, reliable electricity
system that will support the growth of communities.
We achieved two major milestones in 2018. The first
was the announcement of a $1.6 billion funding
also received approval to construct new transmission
lines and install equipment to support what will
become TEP’s largest local solar power and energy
storage project.
framework with the Governments of Canada and
Ontario. The second was the connection of the first
community, Pikangikum, to the Ontario power grid via
the Wataynikaneyap Power transmission line.
7
REPORT TO SHAREHOLDERS F OCUS E D ON BE S T P R AC T ICE S IN S A F E T Y,
RE L I A BIL I T Y A ND CY BE RS ECURI T Y
Strong safety and reliability performance are the
hallmarks of long-term success for a utility business.
Both are priorities at Fortis.
With respect to your company’s safety and reliability
performance metrics, we are outperforming in
comparison to industry averages. The all-injury
frequency rate is an indicator of safety performance
and represents the number of injuries for every
200,000 hours worked. In 2018 the Fortis all-injury
frequency rate was 1.47, outperforming the Canadian
industry rate of 1.6 and the U.S. rate of 1.9.
Our utilities champion a strong culture of health and
safety. We pride ourselves on the principles of doing
your best, working hard and working safely. Sadly,
we experienced tragedy in 2018 when an employee
died in an accident while working at a Fortis utility.
Our unrelenting commitment to safety is stronger
now, more than ever. We are constantly sharing the
best health and safety practices from each of our
utilities to make our company safer and better for
our employees and customers.
For electricity reliability, we monitor the average
hours of interruption per customer served. In 2018
the average hours of interruption for Fortis was 2.07,
a strong statistic in comparison to the industry
average of 3.6 hours.
A L L- I N J U RY F R EQ U E N CY R AT E
E L ECT R I C I T Y C U S TO M E R
AV E R AG E O U TAG E D U R AT I O N
1 . 9
1 . 6
H O U R S
4 . 0
3 . 0
2 . 0
1 . 0
0
3 . 6
2 0 1 6
2 0 1 7
2 0 1 8
2 0 1 6
2 0 1 7
2 0 1 8
Fortis
Fortis
U.S. Energy Information Association Average
(for the period 2015-2017)
Canadian Electricity Association Average
(for the period 2015-2017)
Canadian Electricity & U.S. Energy
Information Association Average
(for the period 2015-2017)
2 . 0
1 . 5
1 . 0
0 . 5
0
8
FORTIS INC. 2018 ANNUAL REPORT Juanita Ghaney
Newfoundland Power
Our unwavering commitment to reliability and
customer service was best demonstrated by FortisBC
as they responded to a significant disruption in their
natural gas supply in 2018. Approximately 700,000
customers faced a potential loss of gas supply due to
a pipeline rupture that affected a supplier’s pipeline.
It was critical for customers to decrease their use
of natural gas quickly in order to maintain a limited
supply. FortisBC led efforts and executed a
well-planned strategy to maintain customer gas
supply. By working closely with customers, there was
minimal disruption of service, allowing homes to
stay warm and businesses to keep operating.
Committed to Cybersecurity
With 93% of our assets dedicated to energy delivery,
we remain focused on protecting the grid and
ensuring its security. We approach cyber and physical
security with the same focus as we do safety and
reliability. Guided by a cyber-risk management
framework developed from leading industry
practices, our utilities have formalized cybersecurity
programs that are constantly monitored as part of
our commitment to continuous improvement.
9
REPORT TO SHAREHOLDERS S US TA IN A BIL I T Y IN AC T ION
Our commitment to sustainable practices has
remained front and centre over our 130+ years of
serving communities and in our decisions while
growing Fortis throughout North America.
Fortis released its first Sustainability Report in
2018, covering our ten utility operations.
The report contains more complete information
on our operations, focusing on the environment,
governance, our customers, our people and
community engagement. It followed the publication
of three previous Environmental Reports.
Our focus on delivering energy to customers naturally
limits our impact on the environment compared
with energy generation-intensive businesses. Energy
delivery represents 93% of our total assets. In 2017,
we delivered 19 times more energy to our customers
than we generated.
While we only own a small amount of fossil fuel-based
generation, this does not lessen our commitment to
reducing carbon emissions. The carbon intensity of
energy delivered to customers in 2017 decreased by
more than 60%. This decrease was largely related
to our acquisition of transmission-focused ITC in 2016.
Further, we decreased greenhouse gas emissions
within the Fortis group by 6% in 2017 compared
to 2016.
We continue to build an inclusive and diverse
workforce throughout our utilities. We are proud of
our commitment to gender diversity and continue to
make great progress in this area. Females represent
42% of our Board, 60% of employees at head
office and approximately a third of our executives
throughout the Fortis group of companies.
10
F O R T I S I N C . 2 0 1 8 A N N U A L R E P O R T
FEMALES REPRESENT 42% OF OUR BOARD,
60% OF EMPLOYEES AT HEAD OFFICE AND
APPROXIMATELY A THIRD OF OUR EXECUTIVES
THROUGHOUT THE FORTIS GROUP OF COMPANIES.
R E P O R T T O S H A R E H O L D E R S
11
11
OUR C OMMI T ME N T T O C OMMUNI T Y RUNS DE E P
IN 2018 WE INVESTED
APPROXIMATELY $13 MILLION IN
THE COMMUNITIES WE SERVE.
Tucson Electric Power employee Shirley
Reilly volunteering during the Annual
Thanksgiving on the Mayflower event.
We want the best for our communities. In 2018 Fortis
and our utilities invested approximately $13 million
in the communities we serve.
Powered by US$2.5 million in startup funding from
TEP, the non-profit Regional Partnering Center was
selected as the operator of a sustainable electric
shuttle system for the Sabino Canyon in southern
Arizona. The area draws more than one million
visitors annually and the new system will operate
zero-emission electric shuttles to carry visitors
safely, quietly and efficiently through the canyon.
FortisAlberta demonstrates its commitment to the
local community through its partnership with the
Shock Trauma Air Rescue Service. The service delivers
emergency medical transportation throughout
rural Alberta. FortisAlberta recently became the
organization’s longest-standing corporate partner.
The utility committed $400,000 over the next five
years, bringing the total commitment to more
than $1.7 million.
12
FORTIS INC. 2018 ANNUAL REPORT In 2018 Fortis made a significant $500,000 donation
to the “Set the Stage” capital campaign of Theatre
Newfoundland and Labrador. The funds will support
the construction of a new performing arts centre for
the Gros Morne Theatre Festival in Newfoundland and
Labrador. The festival has entertained audiences since
1995 and the new centre will provide a much-needed
home for years to come.
We focus on the priorities and needs of local
communities and we take pride in supporting
the communities our employees and customers
call home.
FortisAlberta employee Guy Leblanc (right) raised more than
$11,000 for the Shock Trauma Air Rescue Service (“STARS”) after
close friend and co-worker Jeremy Carabeo (left) had a serious
mountain bike accident and needed to be rescued by STARS.
13
REPORT TO SHAREHOLDERS Matt Peters
Maritime Electric
Enhancing Engagement with Our Shareholders
In November the Board of Directors held shareholder
engagement meetings in Toronto and New York.
This was our second year hosting board-shareholder
engagement meetings, and ten of our largest
shareholders attended. The meetings included an
overview of the Corporation’s business strategy as
well as an engaging question and answer session.
14
FORTIS INC. 2018 ANNUAL REPORT Executive Team Changes
David G. Hutchens was appointed Executive Vice
President, Western Utility Operations, of your
company effective January 1, 2018. In this expanded
role, Mr. Hutchens provides oversight to FortisBC
and FortisAlberta while continuing as President
and CEO of UNS Energy.
Jocelyn H. Perry was appointed Executive Vice
President, Chief Financial Officer, effective
June 1, 2018. Ms. Perry was previously President
and CEO of Newfoundland Power and she
brought her strong work ethic and close to 20 years
of experience working with the Fortis group.
James R. Reid was appointed Executive Vice President,
Chief Legal Officer and Corporate Secretary, effective
March 5, 2018. Mr. Reid was previously a partner
with Davies Ward Phillips & Vineberg LLP where he
practiced for 20 years. Prior to joining Fortis, Mr. Reid
had a 15-year relationship with Fortis, advising on
corporate governance, capital markets transactions
and acquisitions.
Ms. Perry’s appointment came after the retirement
of Karl W. Smith, Executive Vice President, Chief
Financial Officer, in May 2018. Karl spent more than
three decades working with Fortis and performed
many executive roles including President and CEO
of FortisAlberta and Newfoundland Power. We are
grateful for Karl’s dedication to Fortis and wish him
all the best in his retirement.
On November 27, 2018, Fortis opened
trading on the Toronto Stock Exchange
(“TSX”) to acknowledge more than
30 years of Fortis shares trading on
the TSX.
The share price on the TSX was
$4.69 on our first day of trading.
In comparison, the Fortis share price
reached $46.24 on November 22, 2018,
representing a total shareholder return
of over 4,000% during that period.
15
REPORT TO SHAREHOLDERS Each Fortis utility operates as a separate
business with its own local management
and Board of Directors.
Karen Gosse
Fortis
16
F O R T I S I N C . 2 0 1 8 A N N U A L R E P O R T
Election of Directors
We welcomed two new members to our Board of
Directors, Mr. Paul Bonavia and Ms. Julie Dobson.
Mr. Bonavia has extensive utility experience including
running our Arizona utilities prior to their acquisition
by Fortis in 2014. Ms. Dobson is a seasoned
senior executive with extensive experience in the
telecommunications and utility industries.
We acknowledge the contribution and dedication of
outgoing Board members, Mr. Harry McWatters and
Mr. Ron Munkley. Mr. McWatters and Mr. Munkley
completed ten and eight years, respectively, on the
Fortis Board in 2018. Both retired from the Board
after reaching the retirement age for directors in
accordance with the terms of our director tenure
policy. We thank them both for their remarkable
contributions, guidance and leadership.
Our Unique Fortis Business Model
When you buy a Fortis share, you invest in a utility
company that has a very unique business model.
It’s a model that we believe is one of the primary
reasons for our decades of success.
Simply put, we keep our utilities local.
This strong principle guides all of our business
decisions and actions.
We operate a highly decentralized business
that focuses on operational excellence, financial
independence, transparent and constructive
regulatory relationships and providing superior,
reliable service to our customers.
Each Fortis utility operates as a separate business with
its own local management and Board of Directors.
In our larger utilities, a majority of those directors are
independent and generally come from the area the
utility serves. This keeps our utilities close to their
customers and regulators.
THE FORTIS MODEL HAS BEEN A KEY
SUCCESS FACTOR THAT HAS ALLOWED
US TO QUICKLY GROW ACROSS CANADA
AND INTO THE UNITED STATES.
The Fortis model has been a key success factor
that has allowed us to quickly grow across Canada
and into the United States. We committed to keep
operations local, and we have.
A Fortis utility also has the benefit of being part
of a larger business. We share best practices, learn
from each other and provide a support network
when needed.
17
REPORT TO SHAREHOLDERS WE REMAIN FOCUSED ON DOING A GREAT
JOB FOR OUR CUSTOMERS, SHAREHOLDERS
AND COMMUNITIES.
18
F O R T I S I N C . 2 0 1 8 A N N U A L R E P O R T
A BRIGH T PAT H A HE A D
We thank our 8,800 employees for making 2018 a successful year. We remain focused on doing a great job for our
customers, shareholders and communities.
In the years ahead, we will continue to leverage our unique business model, focus on executing our capital investment
plans and growing our earnings and dividends. We are more confident than ever in the potential of your company.
On behalf of the Board of Directors,
Douglas J. Haughey
Chair of the Board
Fortis Inc.
Barry V. Perry
President and CEO
Fortis Inc.
19
REPORT TO SHAREHOLDERS
Financial Highlights
N E T E AR N I N G S AT TR I B UTAB L E TO
CO M M O N EQ U IT Y S HAR E H O L D E RS ($M)
1,100
1,066
1,027
963
728
721
589
585
394
317
2 0 1 4
2 0 1 5 (1)
2 0 1 6 (2)
2 0 1 7 (3)
2 0 1 8
(4)
As Reported
Adjusted
CA P ITAL EXP E N D ITU R ES ($B)
3.2
3.0
2.2
2.1
1.7
2 0 1 4
2 0 1 5
2 0 1 6
2 0 1 7
2 0 1 8
AS S E TS ($B)
53.1
47.9
47.8
M I DY E AR R ATE BAS E ($B)
23.5
24.6
26.1
26.2
28.8
15.6
14.0
2 0 1 4
2 0 1 5
2 0 1 6
2 0 1 7
2 0 1 8
2 0 1 4
2 0 1 5
2 0 1 6
2 0 1 7
2 0 1 8
(1)
Results were impacted by a full year’s contribution from UNS Energy, completion of the Waneta Expansion and gains on the sale of non-core assets. Adjusted net earnings exclude the gains on sale
of non-core assets and other non-operating items.
(2) Results were impacted by accretion associated with the acquisition of ITC in October 2016 and Aitken Creek in April 2016, as well as associated acquisition-related costs. Adjusted net earnings exclude
acquisition-related costs and other non-operating items.
(3) Results were impacted by a full year’s contribution from ITC and Aitken Creek. Adjusted net earnings exclude the impact of U.S. tax reform and other non-operating items.
(4) Results were tempered by the ongoing impact of U.S. tax reform and a reduced independence incentive adder at ITC. Adjusted net earnings exclude certain non-operating items.
All financial information is presented in Canadian dollars. Information is for the fiscal years ended December 31.
20
FORTIS INC. 2018 ANNUAL REPORT Highly Regulated, Low-Risk and Diversified Utility Business
REGU LATED
CUS TOMER S
PEAK DEMAND
ELECTRIC
GAS
TOTAL
MIDYEAR
CAP IT AL
2019 F (1 )
ELECTR IC
(#)
–
GAS
(#)
–
ITC (2)
692
23,634
–
–
EMPLOYEES
ELECTRIC
(#)
(MW)
GAS
(TJ)
SALES
VOLU MES EARNINGS
ASSETS
RATE BASE PR OGRA M
(GWh )
(PJ)
($M )
($B)
($B)
( $M )
UNS Energy
522,000
158,000
2,049
3,107
93
17,406
Central Hudson
300,000
80,000
1,014
1,1 14
153
5,1 18
FortisBC (3)
176,000
1,030,000
2,371
663
1,353
3,250
FortisAlberta
564,000
Other Electric (4)
460,000
–
–
1,1 10
2,743
1,440
2,034
–
–
17,154
9,292
–
13
24
212
–
–
361
293
74
211
120
105
19.8
10.2
3.7
9.0
4.7
4.1
8.5
5.3
1.8
5.8
3.6
2.9
865
1,076
280
619
414
418
Total
2,022,000
1,268,000
8,676
33,295
1,599
52,220
249
1,164
51.5
27.9
3,672
(1) Forecast
(2) Data reflects 100% of ITC’s operations except for earnings, which represent the Corporation’s 80.1% ownership interest.
(3) Includes FortisBC Energy and FortisBC Electric.
(4) Data reflects 100% of Caribbean Utilities’ operations except earnings, which represent the Corporation’s 60% ownership interest. Also includes Newfoundland Power, Maritime Electric,
FortisOntario, a 39% equity investment in Wataynikaneyap Power Limited Partnership, Fortis Turks and Caicos, and a 33% equity investment in Belize Electricity.
NON-REGULATED
Energy Infrastructure (2)
Corporate
(1) Forecast
(2) Comprised of investments in British Columbia and Belize.
GENERATING
CAP ACITY
EMPLOYEES
(MW)
386
-
(#)
65
59
ENERGY
SALES
(GWh )
853
-
EARNINGS
($M)
72
(136)
TOTAL
ASSETS
($B)
1.5
0.1
2019 F (1)
CAPI TAL
PROGRA M
($ M)
28
-
TOTAL ASSETS OF $53 BILLION
AS OF DECEMBER 31, 2018
9 7% R EGU L ATED U TIL ITI ES
Electric
81%
Gas
16%
Non-Regulated
Energy Infrastructure
3%
ASSETS
21
REPORT TO SHAREHOLDERS 2222
F O R T I S I N C . 2 0 1 8 A N N U A L R E P O R T
FORTIS INC. 2018 ANNUAL REPORT Putting our customers first. Nurturing our diverse team
of leaders. Protecting the world around us. Focusing on what
really matters, year after year, has enabled Fortis to become
one of the lowest-risk utilities in North America, delivering
superior shareholder returns for 20 years running.
R E P O R T T O S H A R E H O L D E R S
2323
REPORT TO SHAREHOLDERS Management Discussion and Analysis
Contents
Forward-Looking Information ................................................................................ 24
Corporate Overview ..................................................................................................... 26
Corporate Strategy ........................................................................................................ 28
Key Trends, Risks and Opportunities .................................................................. 28
Summary Financial Highlights ............................................................................... 30
Consolidated Results of Operations ................................................................... 31
Segmented Results of Operations ....................................................................... 34
Regulated Utilities .......................................................................................................... 34
ITC ...................................................................................................................................... 34
UNS Energy .................................................................................................................. 35
Central Hudson ......................................................................................................... 35
FortisBC Energy ......................................................................................................... 36
FortisAlberta ................................................................................................................ 36
FortisBC Electric ........................................................................................................ 37
Other Electric .............................................................................................................. 37
Non-Regulated ................................................................................................................. 38
Energy Infrastructure ............................................................................................. 38
Corporate and Other ............................................................................................. 38
Regulatory Highlights .................................................................................................. 39
Consolidated Financial Position ............................................................................ 41
Liquidity and Capital Resources ............................................................................ 42
Summary of Consolidated Cash Flows ...................................................... 42
Contractual Obligations....................................................................................... 43
Capital Structure ....................................................................................................... 44
Credit Ratings ............................................................................................................. 45
Capital Expenditure Program ........................................................................... 45
Additional Investment Opportunities ......................................................... 49
Cash Flow Requirements .................................................................................... 49
Credit Facilities ........................................................................................................... 50
Off-Balance Sheet Arrangements ........................................................................ 50
Business Risk Management...................................................................................... 51
Changes in Accounting Policies ........................................................................... 60
Future Accounting Pronouncements ................................................................ 61
Financial Instruments ................................................................................................... 62
Critical Accounting Estimates ................................................................................. 64
Related-Party and Inter-Company Transactions ......................................... 67
Selected Annual Financial Information ............................................................ 68
Fourth Quarter Results ................................................................................................ 69
Summary of Quarterly Results ............................................................................... 70
Management’s Evaluation of Disclosure Controls
and Procedures and Internal Controls over
Financial Reporting ................................................................................................. 71
Outlook ................................................................................................................................. 72
Outstanding Share Data ............................................................................................ 72
24
Dated February 14, 2019
The following Fortis Inc. (“Fortis” or the “Corporation”) Management
Discussion and Analysis (“MD&A”) has been prepared in accordance
with National Instrument 51-102 – Continuous Disclosure Obligations.
The MD&A should be read in conjunction with the audited
consolidated financial statements and notes thereto for the year
ended December 31, 2018 (“2018 Annual Financial Statements”).
Financial information contained in this MD&A has been prepared
in accordance with accounting principles generally accepted in the
United States of America (“US GAAP”) and is presented in Canadian
dollars unless otherwise specified.
included
information
FORWARD-LOOKING INFORMATION
Fortis includes forward-looking information in the MD&A within the
meaning of applicable Canadian securities laws and forward-looking
statements within the meaning of the U.S. Private Securities Litigation
Reform Act of 1995, collectively referred to as “forward-looking
in the MD&A
information”. Forward-looking
reflects expectations of Fortis management regarding future growth,
results of operations, performance and business prospects and
opportunities. Wherever possible, words such as “anticipates”, “believes”,
“budgets”, “could”, “estimates”, “expects”, “forecasts”, “intends”, “may”,
“might”, “plans”, “projects”, “schedule”, “should”, “target”, “will”, “would”
and the negative of these terms and other similar terminology or
expressions have been used to identify the forward-looking information,
which includes, without limitation: the satisfaction of the conditions
and the expected timing of the closing of the sale of the Corporation’s
interest in the Waneta Expansion hydroelectric project; the Corporation’s
forecast capital expenditures for the period 2019 through 2023 and
potential funding sources for the capital expenditure program; the
Corporation’s forecast rate base for the period 2019 through 2023; the
expectation that capital investment will support growth in earnings
and dividends; the expectation that the Corporation and its subsidiaries
will continue to have reasonable access to long-term capital in 2019;
targeted average annual dividend growth through 2023; timing of
refund payments stemming from the ITC incentive adder complaint
and the expectation that the order will not have a material impact
on the Corporation’s earnings or cash flows; expected timing of
filing of
receipt and outcome of
regulatory decisions; the nature, timing, benefits, funding sources
and expected costs of certain capital projects including, without
limitation, the ITC Multi-Value Regional Transmission Projects and
34.5 to 69 kilovolt Transmission Conversion Project, UNS Energy
Gila River Natural Gas Generating Station Unit 2, Southline
Transmission Project and New Mexico Wind Project, FortisBC Energy
expansion of the Tilbury liquefied natural gas facility, Lower Mainland
Intermediate Pressure System Upgrade, Eagle Mountain Woodfibre
Gas Line Project and Transmission Integrity Management Capabilities
Project, the Wataynikaneyap Transmission Power Project and additional
opportunities beyond the base plan; the expectation that subsidiary
operating expenses and interest costs will be paid out of subsidiary
operating cash flows; the expectation that cash required to complete
subsidiary capital expenditure programs will be sourced from a
combination of borrowings under credit facilities, long-term debt
offerings and equity
injections from Fortis; the expectation that
maintaining the targeted capital structure of the Corporation’s regulated
operating subsidiaries will not have an impact on its ability to pay
regulatory applications and
FORTIS INC. 2018 ANNUAL REPORT
dividends in the foreseeable future; the expectation that cash required from Fortis to support subsidiary capital expenditure programs and
finance acquisitions will be derived from a combination of borrowings under the Corporation’s committed corporate credit facility, proceeds from
the issuance of common shares, preference shares and long-term debt, and proceeds from non-core asset sales; expected consolidated fixed-term
debt maturities and repayments in 2019 and over the next five years; the expectation that the Corporation and its subsidiaries will remain compliant
with debt covenants throughout 2019; and the expectation that the adoption of future accounting pronouncements will not have a material impact
on the Corporation’s consolidated financial statements.
Certain material factors or assumptions have been applied in drawing the conclusions contained in the forward-looking information, including,
without limitation: the receipt of applicable regulatory approvals and requested rate orders, no material adverse regulatory decisions being received
and the expectation of regulatory stability; no material capital project and financing cost overrun related to any of the Corporation’s capital
projects; the realization of additional opportunities; the Board of Directors exercising its discretion to declare dividends, taking into account the
business performance and financial condition of the Corporation; no significant variability in interest rates; no significant operational disruptions or
environmental liability due to a catastrophic event or environmental upset caused by severe weather, other acts of nature or other major events; the
continued ability to maintain the electricity and gas systems to ensure their continued performance; no severe and prolonged downturn in economic
conditions; no significant decline in capital spending; sufficient liquidity and capital resources; the continuation of regulator-approved mechanisms
to flow through the cost of energy supply costs in customer rates; the ability to hedge exposures to fluctuations in foreign exchange rates, natural gas
prices and electricity prices; no significant changes in tax laws; no significant counterparty defaults; the continued competitiveness of natural gas
pricing when compared with electricity and other alternative sources of energy; the continued availability of natural gas, fuel, coal and electricity
supply; continuation and regulatory approval of power supply and capacity purchase contracts; the ability to fund defined benefit pension plans, earn
the assumed long-term rates of return on the related assets and recover net pension costs in customer rates; no significant changes in government
energy plans, environmental laws and regulations that may materially negatively affect the Corporation and its subsidiaries; maintenance of adequate
insurance coverage; the ability to obtain and maintain licences and permits; retention of existing service territories; 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; favourable labour relations; that the Corporation can reasonably
assess the merit of and potential liability attributable to ongoing legal proceedings; and sufficient human resources to deliver service and execute
the capital expenditure program.
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 the results 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 Risk Management” in this MD&A and in continuous disclosure
materials filed from time to time with Canadian securities regulatory authorities and the U.S. Securities and Exchange Commission. Key risk factors
for 2019 include, but are not limited to: uncertainty regarding the outcome of regulatory proceedings at the Corporation’s utilities; the impact of
fluctuations in foreign exchange rates; risk associated with the impacts of less favourable economic conditions on the Corporation’s results of
operations; risk associated with the completion of the Corporation’s 2019 capital expenditure program, including completion of major capital projects
in the timelines anticipated and at the expected amounts; and uncertainty in the timing of and access to capital markets to arrange sufficient and
cost-effective financing to finance, among other things, capital expenditures and the repayment of maturing debt.
All forward-looking information in the MD&A is given as of the date of the MD&A and 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.
25
FORTIS INC. 2018 ANNUAL REPORTManagement Discussion and Analysis CORPORATE OVERVIEW
Fortis is a leader in the North American regulated electric and gas utility industry, with 2018
revenue of $8.4 billion and total assets of $53 billion as at December 31, 2018. The Corporation’s
8,800 employees serve utility customers in five Canadian provinces, nine U.S. states and
three Caribbean countries. In 2018 the Corporation’s electricity systems met a combined peak
demand of 33,295 megawatts (“MW”) and its gas distribution systems met a peak day demand
of 1,599 terajoules.
The Corporation’s main business, utility operations, is highly regulated and its earnings are primarily
determined under cost of service (“COS”) regulation, in combination with performance-based
rate-setting (“PBR”) mechanisms in certain jurisdictions. Generally, under COS regulation the
respective regulatory authority sets customer electricity and/or gas rates to permit a reasonable
opportunity for the recovery, on a timely basis, of 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”). The ability to recover prudently incurred costs 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 the utility achieving forecasts established in the rate-setting
process. If a historical test year is used to set customer rates, there may be regulatory lag between
when costs are incurred and when they are reflected in customer rates. When PBR mechanisms
are utilized in determining annual revenue requirements and resulting customer rates, a formula is generally applied that incorporates
inflation and assumed productivity improvements. The use of PBR mechanisms should allow a utility a reasonable opportunity to recover
prudently incurred costs and earn its allowed ROE or ROA.
Jocelyn Perry, EVP, CFO, Fortis Inc.
Earnings of regulated utilities may be impacted by: (i) changes in the regulator-approved allowed ROE and/or ROA and common equity
component of capital structure; (ii) changes in rate base; (iii) changes in energy sales or gas delivery volumes; (iv) changes in the number and
composition of customers; (v) variances between actual expenses incurred and forecast expenses used to determine revenue requirements
and set customer rates, as applicable; (vi) regulatory lag in the case of a historical test year; and (vii) foreign exchange rates. The Corporation’s
regulated utilities, where applicable, are permitted by their respective regulatory authority 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.
Entities within the reporting segments that follow operate with substantial autonomy.
Regulated Utilities
ITC
Primarily comprised of ITC Holdings Corp., ITC Investment Holdings Inc. 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 approximately 522,000 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 generation capacity of 3,377 MW, including 57 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 approximately 158,000 retail customers in Arizona’s Mohave, Yavapai, Coconino, Navajo
and Santa Cruz counties.
26
FORTIS INC. 2018 ANNUAL REPORTManagement Discussion and Analysis Central Hudson
Primarily comprised of CH Energy Group, Inc. and Central Hudson Gas & Electric Corporation. Central Hudson is a regulated electric and gas
transmission and distribution utility that serves approximately 300,000 electricity customers and 80,000 natural gas customers in portions
of New York State’s Mid-Hudson River Valley and owns gas-fired and hydroelectric generating capacity totalling 64 MW.
FortisBC Energy
Primarily comprised of FortisBC Energy Inc., which is the largest regulated distributor of natural gas in British Columbia, providing transmission
and distribution services to approximately 1,030,000 customers in more than 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 serving
approximately 564,000 customers. It is not involved in the direct sale of electricity.
FortisBC Electric
Primarily comprised of FortisBC Inc., an integrated regulated electric utility operating in the southern interior of British Columbia serving
approximately 176,000 customers directly and indirectly. It owns four hydroelectric generating facilities with a combined capacity of 225 MW.
It also provides operating, maintenance and management services relating to four hydroelectric generating facilities in British Columbia that
are owned by third parties and to the 335-MW Waneta Expansion hydroelectric generating facility (“Waneta Expansion”) in which Fortis
indirectly holds a 51% controlling interest.
Other Electric
Comprised of utilities in eastern Canada and the Caribbean, as follows: Newfoundland Power Inc. (“Newfoundland Power”);
Maritime Electric Company, Limited (“Maritime Electric”); FortisOntario Inc. (“FortisOntario”); a 39% equity investment in Wataynikaneyap
Power Limited Partnership (“Wataynikaneyap Partnership”); an approximate 60% controlling interest in Caribbean Utilities Company, Ltd.
(“Caribbean Utilities”); FortisTCI Limited and Turks and Caicos Utilities Limited (collectively “FortisTCI”); and a 33% equity investment in
Belize Electricity Limited (“BEL”).
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.
Newfoundland Power is an integrated regulated electric utility and the principal distributor of electricity on the island portion of
Newfoundland and Labrador, serving approximately 268,000 customers. Newfoundland Power has a generating capacity of 139 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”), serving approximately 81,000 customers. Maritime Electric also maintains on-Island generating facilities
with a combined capacity of 145 MW. FortisOntario is comprised of three regulated electric utilities that provide service to approximately
66,000 customers in Fort Erie, Cornwall, Gananoque, Port Colborne and the District of Algoma in Ontario. Wataynikaneyap Partnership
is a partnership between 24 First Nations communities and Fortis with a mandate of connecting remote First Nations communities to
the electricity grid in Ontario through the development of new transmission lines (the “Wataynikaneyap Transmission Power Project”).
Caribbean Utilities is an integrated regulated electric utility and the sole electricity provider on Grand Cayman, serving approximately
30,000 customers, with a diesel-powered generating capacity of 161 MW. FortisTCI is comprised of two integrated regulated electric utilities
that provide electricity to approximately 15,000 customers on certain Turks and Caicos Islands and has a diesel-powered generating capacity
of 91 MW. BEL is an integrated electric utility and the principal distributor of electricity in Belize.
Non-Regulated
Energy Infrastructure
Primarily comprised of long-term contracted generation assets in British Columbia and Belize, and the Aitken Creek natural gas storage facility
(“Aitken Creek”). Generation assets in British Columbia include the Corporation’s interest in the Waneta Expansion, whose output is sold to
British Columbia Hydro and Power Authority (“BC Hydro”) and FortisBC Electric under 40-year power purchase agreements (“PPAs”).
Generation assets in Belize are comprised of three hydroelectric generating facilities with a combined capacity of 51 MW, conducted through
the Corporation’s indirectly wholly owned subsidiary Belize Electric Company Limited (“BECOL”). The output is sold to BEL under 50-year 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.
27
FORTIS INC. 2018 ANNUAL REPORTManagement Discussion and Analysis In January 2019 the Corporation entered into a definitive agreement with Columbia Power Corporation (“CPC”) and Columbia Basin Trust
(“CBT”) to sell its 51% interest in the Waneta Expansion for approximately $1 billion. CPC and CBT, both 100% owned by the Government of
British Columbia, are the Corporation’s partners and together currently own 49% of the Waneta Expansion. Fortis expects the transaction
to close in the second quarter of 2019 following the satisfaction of customary closing conditions. FortisBC Electric will continue to operate
the Waneta Expansion facility and purchase its surplus capacity.
Corporate and Other
Captures expense and revenue items not specifically related to any reportable segment and those business operations that are below the
required threshold for reporting as separate segments, including net corporate expenses of Fortis and the non-regulated holding company
FortisBC Holdings Inc. (“FHI”).
CORPORATE STRATEGY
Fortis strives to provide customers with safe, reliable and cost-effective energy service using sustainable practices while delivering long-term
profitable growth. The Corporation is a well-diversified, regulated, primarily transmission and distribution business characterized by low-risk,
stable and predictable earnings and cash flows.
Earnings per common share and total shareholder return are the primary measures of financial performance. Over the 10-year period ended
December 31, 2018, earnings per common share of Fortis grew at a compound annual growth rate of 5.2%. Over the same period, Fortis
delivered an average annualized total return to shareholders of 10.5%, exceeding the S&P/TSX Capped Utilities and S&P/TSX Composite
Indices, which delivered average annualized performance of 7.2% and 7.9%, respectively, over the same period.
The Corporation is committed to achieving long-term sustainable growth in rate base and earnings resulting from investment in existing
utility operations. Management remains focused on executing the consolidated capital expenditure program and pursuing additional
investment opportunities within existing service territories, and the Corporation’s stand-alone operating model positions it well for such
future investment opportunities. The Corporation maintains a small head office and its utilities operate on a substantially autonomous basis.
Each of the utilities has its own management team and most have oversight by a Board of Directors comprised of a majority of independent
directors. Given that regulatory oversight is usually state or provincially based, the Corporation believes this model provides superior
transparency and best serves the interests of customers.
KEY TRENDS, RISKS AND OPPORTUNITIES
Energy Industry Developments
The North American energy industry continues to transform. There is a continued focus on clean energy and energy conservation initiatives,
while balancing technology advancements and changes in customer needs. Notwithstanding the changes occurring in the utility industry,
safety, reliability and serving customers at the lowest reasonable cost remain at the forefront of the utility industry’s focus.
Changing energy policies at the federal, state and provincial levels are creating volatility in certain jurisdictions by introducing uncertainty
around environmental, tax and trade policies. The regulatory and compliance operating environment also continues to evolve and is
becoming increasingly complex. Such changing policies and regulations create additional opportunities to expand investment in new
generation sources, including natural gas, solar and wind generation, as well as infrastructure to interconnect renewable energy sources
to the grid. The Corporation’s regulated 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 opportunities to improve and expand services through strategic
investments. Such investments in information and operational technology, the exponential growth in data and interconnections to the
electricity systems, and the more volatile security atmosphere are driving the need for increased cyber and physical security systems.
Meaningful customer engagement is increasingly important for utilities. Customers want to make informed energy choices and become
active participants in their energy services with the end goal of reducing energy costs. Utilities can increase customer value by providing
accurate, balanced and relevant energy information that enables customer choices and action. This creates an opportunity for utilities to
demonstrate they are trusted energy partners in an evolving energy market.
28
FORTIS INC. 2018 ANNUAL REPORTManagement Discussion and Analysis Utility customer expectations are also changing with competition for consumer attention becoming increasingly intense. Utility customers
expect personalized service, customized service offerings and more real-time, digital communications. The Corporation’s utilities are well
positioned to satisfy changing customer needs by leveraging new technology.
Despite the challenges facing the utility industry, Fortis is well positioned to capitalize on any resulting opportunities. Its decentralized
structure and customer-focused business culture will support the efforts required to meet evolving customer expectations and to work with
policy makers and regulators on solutions that are financially sustainable for its utilities. Fortis is also a strategic partner in the Energy Impact
Partners utility coalition, which is a private firm that invests in emerging technologies, products, services and business models across the full
electricity supply chain. Leveraging these relationships and partnerships, Fortis will remain at the forefront of emerging technologies to meet
the evolving challenges in the ever-changing utility industry.
Regulation
The Corporation’s key business risk is regulation. Fortis is well positioned to maintain constructive regulatory relationships through local
management teams and boards comprised of mostly independent local board members. Commitment by the Corporation’s utilities to
provide safe and reliable service, operational excellence and positive customer service is also important to ensure supportive regulatory
relationships and obtain full cost recovery and competitive returns for the Corporation’s shareholders.
All of the Corporation’s regulated utilities continue to be actively engaged with each of their regulators and are focused on maintaining
constructive regulatory relationships and outcomes. For a further discussion of material regulatory decisions and applications and regulatory
risk, refer to the “Regulatory Highlights” and “Business Risk Management” sections of this MD&A.
Capital Expenditure Program and Rate Base Growth
The Corporation’s $17.3 billion five-year capital expenditure program is expected to increase rate base from $26.1 billion in 2018 to
approximately $32.0 billion in 2021 and $35.5 billion in 2023, translating into three- and five-year compound annual growth rates of 7.1%
and 6.3%, respectively. Fortis expects this capital investment to support growth in earnings and dividends.
For further information on the Corporation’s consolidated capital expenditure program and the rate base of its regulated utilities, refer to the
“Liquidity and Capital Resources – Capital Expenditure Program” section of this MD&A.
Access to Capital and Liquidity
The Corporation’s regulated utilities require ongoing access to long-term capital to fund investments in infrastructure necessary to provide
service to customers. Long-term capital required to carry out the utility capital expenditure programs is mostly obtained at the regulated
utility level, at terms ranging between 5 and 40 years. As at December 31, 2018, approximately 80% of the Corporation’s consolidated
long-term debt, excluding borrowings under long-term committed credit facilities, had maturities beyond five years. Management expects
consolidated fixed-term debt maturities and repayments to average approximately $929 million annually over the next five years.
To help ensure uninterrupted access to capital and sufficient liquidity to fund capital expenditure programs and working capital
requirements, the Corporation and its subsidiaries have approximately $5.2 billion in credit facilities, of which approximately $3.9 billion
was unused as at December 31, 2018. Based on current credit ratings and capital structures, the Corporation and its subsidiaries expect
to continue to have reasonable access to long-term capital in 2019.
In December 2018 Fortis filed a short-form base shelf prospectus and re-established its at-the-market common equity program. For
additional information, refer to the “Cash Flow Requirements” section of this MD&A.
Dividend Increases
Dividends paid per common share increased to $1.725 in 2018. In the fourth quarter of 2018 Fortis increased its quarterly dividend per
common share by 5.9% to $0.45 per quarter, or $1.80 on an annualized basis. This continues the Corporation’s track record of raising its
annualized dividend to common shareholders for 45 consecutive years.
Fortis also extended its dividend guidance, targeting average annual dividend per common share growth of 6% through 2023. This guidance
takes into account many factors, including the expectation of reasonable outcomes for regulatory proceedings at its utilities, the successful
execution of its $17.3 billion five-year capital expenditure program, and management’s continued confidence in the strength of the
Corporation’s diversified portfolio of assets and record of operational excellence.
29
FORTIS INC. 2018 ANNUAL REPORTManagement Discussion and Analysis SUMMARY FINANCIAL HIGHLIGHTS
For the Years Ended December 31
Net Earnings Attributable to Common Equity Shareholders ($ millions)
Basic Earnings per Common Share ($)
Adjusted Basic Earnings per Common Share ($) (1)
Weighted Average Number of Common Shares Outstanding (millions)
Cash Flow from Operating Activities ($ billions)
Dividends Paid per Common Share ($)
Total Assets ($ billions)
Capital Expenditures ($ billions)
Long-Term Debt Offerings ($ billions)
2018
1,100
2.59
2.51
424.7
2.6
1.725
53.1
3.2
1.6
2017
963
2.32
2.47
415.5
2.8
1.625
47.8
3.0
2.5
Variance
137
0.27
0.04
9.2
(0.2)
0.10
5.3
0.2
(0.9)
(1) Adjusted basic earnings per common share is a non-US GAAP measure. For a definition and reconciliation of this non-US GAAP measure, refer to the “Consolidated Results of
Operations” section of this MD&A.
Basic Earnings per
Common Share
($)
2.61
2.59
2.51
2.47
2.33
2.32
2.11
1.89
1.75
1.41
3.00
2.00
1.00
’14
’15
’16
’17
’18
As Reported
Adjusted
Net Earnings Attributable to Common Equity Shareholders
Fortis achieved net earnings attributable to common equity shareholders of $1,100 million
in 2018 compared to $963 million in 2017. The increase was driven by growth at both
the regulated and non-regulated businesses, as well as lower income tax expense. The
lower income tax expense primarily related to a one-time expense in 2017 associated with
U.S. tax reform, along with the positive tax impacts of electing to file a consolidated state
tax return and designating assets as held for sale in 2018. These increases were partially offset
by a number of other distinct items recognized in 2017, including unrealized mark-to-market
derivative gains, an acquisition break fee, and an unrealized foreign exchange gain on an
affiliate loan. Earnings in 2018 were also tempered by the ongoing impact of U.S. tax reform,
effective January 1, 2018, and a lower ROE incentive adder at ITC, effective April 2018.
Basic Earnings per Common Share
Basic earnings per common share were $2.59 in 2018 compared to $2.32 in 2017. The impact
of higher net earnings attributable to common equity shareholders was partially offset
by an increase in the weighted average number of common shares outstanding, primarily
associated with the Corporation’s dividend reinvestment plan.
Cash Flow from
Operating Activities
($ billions)
Adjusted Earnings per Common Share
Adjusted earnings per share were $2.51 in 2018, up $0.04 from 2017. The increase was driven
by rate base growth at the regulated subsidiaries, strong performance at Aitken Creek and
a lower effective income tax rate. The increase was partially offset by the ongoing impact of
U.S. tax reform, an increase in the weighted average number of common shares outstanding,
as discussed above, and the impact of a reduced ROE incentive adder at ITC.
2.8
2.6
1.9
1.7
1.0
Cash Flow from Operating Activities
Cash flow from operating activities was $2.6 billion for 2018, a decrease of $0.2 billion compared
to 2017. The decrease in cash provided by operating activities was primarily due to lower cash
earnings, driven by ITC as a result of U.S. tax reform, and unfavourable changes in long-term
regulatory deferrals.
’14
’15
’16
’17
’18
3.0
2.5
2.0
1.5
1.0
0.5
30
FORTIS INC. 2018 ANNUAL REPORTManagement Discussion and Analysis Dividends
Dividends paid per common share increased to $1.725 in 2018, 5.9% higher than $1.625 in 2017.
During the fourth quarter of 2018 Fortis increased its quarterly dividend per common share by
5.9% to $0.45.
Total Assets
Total assets increased approximately 11% to $53.1 billion at the end of 2018 compared to
$47.8 billion at the end of 2017. The growth was due to continued investment in energy
infrastructure at the regulated utilities as well as favourable foreign exchange on the
translation of US dollar-denominated assets.
Capital Expenditures
Consolidated capital expenditures were $3.2 billion in 2018 compared to $3.0 billion in 2017.
Total spending for 2018 was consistent with the forecast in the prior year’s MD&A. For a
detailed discussion of the Corporation’s consolidated capital expenditure program, refer to
the “Liquidity and Capital Resources – Capital Expenditure Program” section of this MD&A.
Dividends Paid
per Common Share
($)
1.725
1.625
1.525
1.40
1.28
1.75
1.50
1.25
1.00
0.75
0.50
0.25
’14
’15
’16
’17
’18
Long-Term Capital
The Corporation’s regulated utilities raised approximately $1.6 billion in long-term debt in 2018,
largely in support of capital investment and regularly scheduled debt repayments.
Total Assets
($ billions)
(as at December 31)
For further information, refer to the “Liquidity and Capital Resources – Summary of Consolidated
Cash Flows” section of this MD&A.
53.1
47.9
47.8
55.0
50.0
45.0
40.0
35.0
30.0
25.0
20.0
15.0
10.0
5.0
28.8
26.2
’14
’15
’16
’17
’18
CONSOLIDATED RESULTS OF OPERATIONS
Years Ended December 31
($ millions)
Revenue
Energy Supply Costs
Operating Expenses
Depreciation and Amortization
Other Income, Net
Finance Charges
Income Tax Expense
Net Earnings
Net Earnings Attributable to:
Non-Controlling Interests
Preference Equity Shareholders
Common Equity Shareholders
Net Earnings
Basic Earnings per Common Share
2018
8,390
2,495
2,287
1,243
60
974
165
1,286
120
66
1,100
1,286
2.59
2017
8,301
2,361
2,250
1,179
116
914
588
1,125
97
65
963
1,125
2.32
Variance
89
134
37
64
(56)
60
(423)
161
23
1
137
161
0.27
31
FORTIS INC. 2018 ANNUAL REPORTManagement Discussion and Analysis
Revenue
The increase in revenue was primarily due to higher electricity sales, driven by an increase in system capacity at UNS Energy, and the
flow through in customer rates of higher overall commodity costs. The increase was partially offset by: (i) the recovery of lower income
tax expense due to U.S. tax reform, which reduced the U.S. federal corporate income tax rate from 35% to 21% effective January 1, 2018;
(ii) mark-to-market accounting adjustments for natural gas derivatives at Aitken Creek, which resulted in an unrealized net loss of $10 million
in 2018 compared to an unrealized net gain of $26 million in 2017; and (iii) a change in presentation of certain revenues to a net basis upon
implementation of Accounting Standards Codification (“ASC”) 606, Revenue from Contracts with Customers, in 2018.
Energy Supply Costs
The increase in energy supply costs was primarily due to overall higher commodity costs, driven by UNS Energy as a result of an increase in
system capacity. This increase was partially offset by a lower cost of natural gas and lower gas sales volumes at FortisBC Energy.
Operating Expenses
The increase in operating expenses was primarily due to general inflationary and employee-related cost increases and the receipt of a
$28 million break fee ($24 million net of related transaction costs and tax) associated with a terminated acquisition in 2017. The increase
was partially offset by the corresponding change in presentation for revenue, as discussed above.
Depreciation and Amortization
The increase in depreciation and amortization was primarily due to continued investment in energy infrastructure at the Corporation’s
regulated utilities.
Other Income, Net
The decrease in other income, net of expenses, was primarily due to a one-time $21 million unrealized foreign exchange gain on a
US dollar-denominated affiliate loan in 2017 and the favourable settlement of matters at UNS Energy pertaining to transmission refunds
ordered by the Federal Energy Regulatory Commission (“FERC”) in 2017. The decrease also reflects losses in 2018 on foreign exchange
contracts and a lower equity component of allowance for funds used during construction (“AFUDC”) at FortisBC Energy.
Finance Charges
The increase in finance charges was primarily due to overall higher debt levels to support capital expenditure programs.
Income Tax Expense
The decrease in income tax expense was driven by a lower effective income tax rate primarily due to U.S. tax reform. Also contributing to
the decrease was the favourable impact of a one-time $30 million remeasurement of the Corporation’s deferred income tax liabilities in 2018
that resulted from an election to file a consolidated state income tax return, and deferred income tax impacts related to assets held for sale.
Net Earnings Attributable to Common Equity Shareholders and Basic Earnings per Common Share
The increase in net earnings attributable to common equity shareholders was driven by growth at both the regulated and non-regulated
businesses, as well as lower income tax expense. The lower income tax expense primarily related to a one-time expense of $146 million
in 2017 associated with U.S. tax reform, along with higher Corporate income tax recovery in 2018. The increase in income tax recovery was
due to the remeasurement of deferred income tax liabilities as a result of an election to file a consolidated state income tax return and the
deferred income tax impacts associated with assets held for sale.
These increases were partially offset by: (i) lower earnings associated with a $36 million unfavourable change in the mark-to-market of
natural gas derivatives at Aitken Creek; (ii) higher Corporate expenses, primarily due to the receipt of an acquisition break fee, net of related
transaction costs, of $24 million in 2017; (iii) a one-time $21 million unrealized foreign exchange gain on a US dollar-denominated affiliate
loan in 2017; and (iv) FERC-ordered transmission refunds.
Earnings per common share were $0.27 higher year over year. The impact of the above-noted items on net earnings attributable to common
equity shareholders was partially offset by an increase in the weighted average number of common shares outstanding associated with the
Corporation’s dividend reinvestment plan.
32
FORTIS INC. 2018 ANNUAL REPORTManagement Discussion and Analysis Adjusted Net Earnings Attributable to Common Equity Shareholders and Adjusted Basic Earnings per
Common Share
Fortis uses two financial measures, adjusted net earnings attributable to common equity shareholders and adjusted basic earnings per
common share, that do not have a standardized meaning as prescribed under US GAAP and are not considered US GAAP measures. These
adjusting items may not be comparable with similar adjustments presented by other companies. The most directly comparable US GAAP
measures are net earnings attributable to common equity shareholders and basic earnings per common share, respectively.
The Corporation calculates adjusted net earnings attributable to common equity shareholders as net earnings attributable to common
equity shareholders plus or minus items that management excludes in its evaluation of the underlying operating performance of the
business for the periods presented and to assist with the planning and forecasting of future operating results. In the fourth quarter of 2018,
the Corporation decided to exclude the mark-to-market accounting adjustments related to the natural gas derivatives at Aitken Creek from
its non-US GAAP measures as this item is excluded from management’s evaluation of the underlying operating performance of the Energy
Infrastructure segment. Adjusted basic earnings per common share is calculated by dividing adjusted net earnings attributable to common
equity shareholders by the weighted average number of common shares outstanding.
A reconciliation of the non-US GAAP measures is provided below.
Non-US GAAP Reconciliation
Years Ended December 31
($ millions, except for common share data)
Net Earnings Attributable to Common Equity Shareholders
Adjusting Items:
U.S. tax reform (1)
Unrealized loss (gain) on mark-to-market of derivatives (2)
Consolidated state income tax election (3)
Assets held for sale (3)
Acquisition break fee (4)
Unrealized foreign exchange gain (5)
FERC-ordered transmission refunds (6)
Adjusted Net Earnings Attributable to Common Equity Shareholders
Adjusted Basic Earnings per Common Share ($)
Weighted Average Number of Common Shares Outstanding (millions)
2018
1,100
–
10
(30)
(14)
–
–
–
1,066
2.51
424.7
2017
963
146
(26)
–
–
(24)
(21)
(11)
1,027
2.47
415.5
Variance
137
(146)
36
(30)
(14)
24
21
11
39
0.04
9.2
(1) One-time remeasurement of deferred income tax assets and liabilities resulting from U.S. tax reform (ITC – $91 million, UNS Energy – $5 million, Central Hudson – $2 million, and
Corporate and Other – $48 million)
(2) Represents timing differences related to the accounting of natural gas derivatives at Aitken Creek, included in the Energy Infrastructure segment
(3) Remeasurement of deferred income tax liabilities, included in the Corporate and Other segment
(4) Related to a terminated acquisition, included in the Corporate and Other segment
(5) One-time foreign exchange gain on an affiliate loan, included in the Corporate and Other segment
(6) Favourable settlement of matters at UNS Energy related to prior period FERC filings
33
FORTIS INC. 2018 ANNUAL REPORTManagement Discussion and Analysis
SEGMENTED RESULTS OF OPERATIONS
Segmented Net Earnings Attributable to Common Equity Shareholders
Years Ended December 31
($ millions)
Regulated Utilities
ITC
UNS Energy
Central Hudson
FortisBC Energy
FortisAlberta
FortisBC Electric
Other Electric
Non-Regulated
Energy Infrastructure
Corporate and Other
Net Earnings Attributable to Common Equity Shareholders
2018
2017
Variance
361
293
74
155
120
56
105
72
(136)
1,100
272
270
70
154
120
55
98
94
(170)
963
89
23
4
1
–
1
7
(22)
34
137
A discussion of the financial results of the Corporation’s reporting segments follows. A discussion of the significant regulatory decisions and
applications pertaining to the Corporation’s utilities is provided in the “Regulatory Highlights” section of this MD&A.
REGULATED UTILITIES
The Corporation’s primary business is the ownership and operation of regulated utilities. In 2018 earnings from regulated utilities represented
approximately 94% (2017 – 92%) of the Corporation’s earnings from its operating segments, excluding Corporate and Other segment
expenses. Total regulated utility assets represented approximately 97% of the Corporation’s total assets as at December 31, 2018
(December 31, 2017 – 97%).
ITC
Financial Highlights (1)
Years Ended December 31
Average US:CAD Exchange Rate (2)
Revenue ($ millions)
Earnings ($ millions)
2018
1.30
1,504
361
2017
1.30
1,575
272
Variance
–
(71)
89
(1) Revenue represents 100% of ITC, while earnings represent the Corporation’s 80.1% controlling ownership interest in ITC and reflects consolidated purchase price
accounting adjustments.
(2) The reporting currency of ITC is the US dollar.
Revenue
The decrease in revenue was primarily due to the recovery of lower corporate income tax in customer rates associated with U.S. tax reform,
partially offset by the impact of rate base growth and an increase in expenses recovered through customer rates.
Earnings
The increase in earnings was primarily due to a one-time $91 million deferred income tax expense in 2017 associated with U.S. tax reform.
Also contributing to the increase was rate base growth, partially offset by the net unfavourable impact of U.S. tax reform in 2018 that resulted
in holding company interest being deducted at a lower corporate tax rate.
34
FORTIS INC. 2018 ANNUAL REPORTManagement Discussion and Analysis
UNS Energy
Financial Highlights
Years Ended December 31
Average US:CAD Exchange Rate (1)
Electricity Sales (gigawatt hours (“GWh”))
Gas Volumes (petajoules (“PJ”))
Revenue ($ millions)
Earnings ($ millions)
(1) The reporting currency of UNS Energy is the US dollar.
Electricity Sales & Gas Volumes
2018
1.30
17,406
13
2,202
293
2017
1.30
14,971
13
2,080
270
Variance
–
2,435
–
122
23
The increase in electricity sales was primarily a result of an increase in short-term wholesale sales due to an increase in system capacity
related to the lease of Gila River generating station Unit 2. Short-term wholesale revenues are primarily returned to customers through
regulatory deferral mechanisms and, as a result, do not have an impact on earnings.
Gas volumes were comparable with 2017.
Revenue
The increase in revenue was primarily due to higher electricity sales as discussed above, the flow through of higher energy supply costs and
the impact of the rate case settlement effective February 27, 2017, partially offset by the recovery of lower corporate income tax in customer
rates in 2018 associated with U.S. tax reform.
Earnings
The increase in earnings was primarily due to lower income tax expense associated with U.S. tax reform and the impact of the rate case
settlement as discussed above, partially offset by increased depreciation and amortization expense.
Central Hudson
Financial Highlights
Years Ended December 31
Average US:CAD Exchange Rate (1)
Electricity Sales (GWh)
Gas Volumes (PJ)
Revenue ($ millions)
Earnings ($ millions)
(1) The reporting currency of Central Hudson is the US dollar.
Electricity Sales & Gas Volumes
2018
1.30
5,118
24
924
74
2017
1.30
4,891
22
872
70
Variance
–
227
2
52
4
The increase in electricity sales and gas volumes was primarily due to higher average consumption as a result of colder temperatures
increasing heating load during the winter months and warmer temperatures increasing air conditioning load during the summer months.
Changes in electricity sales and gas volumes at Central Hudson are subject to regulatory revenue decoupling mechanisms and, as a result,
do not have a material impact on revenue and earnings.
Revenue
The increase in revenue was primarily due to the recovery of higher commodity costs from customers and increases in customer delivery
rates effective July 1, 2017 and 2018, partially offset by the recovery of lower corporate income tax in customer rates in 2018 associated with
U.S. tax reform.
Earnings
The increase in earnings was primarily due to the rate increases effective July 1, 2017 and 2018 reflecting a return on increased rate base
assets, partially offset by storm restoration costs.
35
FORTIS INC. 2018 ANNUAL REPORTManagement Discussion and Analysis FortisBC Energy
Financial Highlights
Years Ended December 31
Gas Volumes (PJ)
Revenue ($ millions)
Earnings ($ millions)
Gas Volumes
2018
212
1,187
155
2017
221
1,198
154
Variance
(9)
(11)
1
The decrease in gas volumes was primarily due to lower average consumption as a result of warmer temperatures reducing heating load in
the first half of 2018 and focused customer conservation efforts in the fourth quarter relating to reduced gas supply.
Revenue
The decrease in revenue was primarily due to lower commodity cost of natural gas charged to customers, partially offset by rate base growth.
Earnings
Earnings were consistent year over year as the impact of rate base growth was largely offset by the recognition of AFUDC during 2017
associated with the Tilbury liquified natural gas (“LNG”) facility expansion.
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 of natural gas. As a result of the operation of regulatory deferral mechanisms, changes in consumption levels and
the cost of natural gas do not materially affect earnings.
FortisAlberta
Financial Highlights
Years Ended December 31
Energy Deliveries (GWh)
Revenue ($ millions)
Earnings ($ millions)
Energy Deliveries
2018
17,154
579
120
2017
17,018
600
120
Variance
136
(21)
–
The increase in energy deliveries was primarily due to higher average consumption as a result of colder temperatures increasing heating
load in winter months and warmer temperatures increasing air conditioning load in summer months, as well as higher farm and irrigation
consumption due to lower precipitation. Customer additions also contributed to higher energy deliveries.
Revenue
An election to record municipal franchise fee revenue on a net basis upon implementation of ASC 606, Revenue from Contracts with
Customers, effective January 1, 2018, using the modified retrospective approach under which comparative periods are not restated, resulted
in a decrease in revenue of approximately $43 million. This decrease was partially offset by higher distribution rates effective January 1, 2018,
reflecting a return on increased rate base assets and incremental return due to efficiencies achieved in the first PBR term through an
efficiency carryover mechanism, and revenue associated with customer additions.
Earnings
Earnings were consistent as the increase associated with higher revenue, as discussed above, was offset by higher operating expenses related
to vegetation management and costs associated with a voluntary retirement program completed in the fourth quarter of 2018, as well as
increased interest expense associated with the issuance of long-term debt in September 2017.
36
FORTIS INC. 2018 ANNUAL REPORTManagement Discussion and Analysis FortisBC Electric
Financial Highlights
Years Ended December 31
Electricity Sales (GWh)
Revenue ($ millions)
Earnings ($ millions)
Electricity Sales
2018
3,250
408
56
2017
3,305
398
55
Variance
(55)
10
1
The decrease in electricity sales was due to lower average consumption primarily due to warmer winter temperatures reducing heating
load in 2018.
Revenue
The increase in revenue was primarily due to an increase in revenue recognized from third-party contract work and higher surplus power
sales, partially offset by the flow through of lower overall expenses in customer rates and lower electricity sales.
Earnings
Earnings were comparable with 2017, with the slight increase primarily due to rate base growth.
Variances from regulated forecasts used to set rates for electricity revenue and energy supply costs are flowed through to customers in
future rates through approved regulatory deferral mechanisms and, therefore, do not have an impact on earnings.
Other Electric
Financial Highlights
Years Ended December 31
Average US:CAD Exchange Rate (1)
Electricity Sales (GWh)
Revenue ($ millions)
Earnings ($ millions)
2018
1.30
9,292
1,412
105
2017
1.30
9,196
1,363
98
Variance
–
96
49
7
(1) The reporting currency of Caribbean Utilities and FortisTCI is the US dollar. The reporting currency of BEL is the Belizean dollar, which is pegged to the US dollar at BZ$2.00=US$1.00.
Electricity Sales
The increase in electricity sales was due to overall higher average consumption related to heating load in winter months and air conditioning
load in summer months, increased number of customers, and a recovering economy on the Turks and Caicos Islands following the impact
of Hurricane Irma in 2017.
Revenue
The increase in revenue was primarily due to the flow through in customer rates of higher fuel costs in the Caribbean and higher
electricity sales.
Earnings
The increase in earnings was primarily due to the receipt of FortisTCI’s business interruption insurance proceeds in 2018, higher electricity
sales, and business development costs of approximately $2 million incurred in 2017 related to the Wataynikaneyap Transmission Power
Project, partially offset by lower equity income from BEL.
37
FORTIS INC. 2018 ANNUAL REPORTManagement Discussion and Analysis NON-REGULATED
Energy Infrastructure
Financial Highlights
Years Ended December 31
Energy Sales (GWh)
Revenue ($ millions)
Earnings ($ millions)
Energy Sales
2018
853
184
72
2017
889
226
94
Variance
(36)
(42)
(22)
The decrease in energy sales was primarily due to lower rainfall reducing hydroelectric production in Belize.
Revenue and Earnings
The decrease in revenue and earnings was primarily due to the unfavourable impact of the mark-to-market accounting of natural gas
derivatives at Aitken Creek, with unrealized losses of $10 million during 2018 compared to unrealized gains of $26 million during 2017.
Revenue and earnings were also impacted by favourable pricing of natural gas at Aitken Creek during the first half of 2018, partially offset
by lower hydroelectric production in Belize.
Aitken Creek is subject to commodity price risk, as it purchases and holds natural gas in storage to earn a profit margin from its ultimate sale.
Aitken Creek mitigates this risk by using derivatives to substantially lock in the profit margin that will be realized upon the sale of natural gas.
The fair value accounting of these derivatives creates timing differences and the resultant earnings volatility can be significant from period
to period.
Corporate and Other
Financial Highlights
Years Ended December 31
($ millions)
Net Loss
2018
(136)
2017
(170)
Variance
34
The decrease in net loss was primarily driven by higher income tax recovery due to: (i) deferred income tax expense of $48 million in 2017
associated with U.S. tax reform; (ii) a remeasurement of deferred income tax liabilities of $30 million in 2018 associated with an election to file
a consolidated state income tax return; and (iii) the remeasurement of deferred income tax liabilities of $14 million associated with assets held
for sale. The increase in income tax recovery was partially offset by: (i) the 2018 impact of U.S. tax reform, which resulted in holding company
interest being deductible at a lower corporate tax rate; (ii) the receipt of a $24 million break fee associated with a terminated acquisition in
2017; (iii) a $21 million unrealized foreign exchange gain on a US-dollar denominated affiliate loan in 2017; and (iv) losses in 2018 on foreign
exchange contracts, partially offset by lower stock-based compensation year over year.
38
FORTIS INC. 2018 ANNUAL REPORTManagement Discussion and Analysis REGULATORY HIGHLIGHTS
The following summarizes the significant regulatory decisions and applications pertaining to the Corporation’s regulated utilities for 2018.
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 transmission owners operating in the Midcontinent Independent System Operator (“MISO”) region, which includes
ITCTransmission, METC and ITC Midwest (collectively “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 equates to a 0.25% decrease in ROE, down from the approximate 0.50% that ITC was earning in rates previously approved
by FERC. ITC’s MISO Subsidiaries sought rehearing of this order and began reflecting the 0.25% adder in transmission rates in November 2018.
Refunds began in the fourth quarter of 2018 and were completed in the first quarter of 2019. The order 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”).
FERC orders on the complaints will also set the ROE that will be effective prospectively from the order dates.
In September 2016 FERC ordered that the base ROE for the Initial Refund Period be set at 10.32%, down from 12.38%, with a maximum of
11.35%. The resultant rates apply prospectively from September 2016 until an approved ROE is established for the Second Refund Period.
The MISO transmission owners sought rehearing of this order. 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 June 2016 the presiding Administrative Law Judge (“ALJ”) issued an initial decision on the Second Complaint, recommending a base
ROE of 9.70%, with a maximum of 10.68%. The initial decision of the ALJ is a non-binding recommendation to FERC, and FERC has yet
to issue its order on the Second Complaint. In September 2017 certain MISO transmission owners filed a motion for FERC to dismiss
the Second Complaint. Pending an order from FERC, an estimated regulatory liability of $206 million (US$151 million) has been recognized
(December 31, 2017 – $182 million (US$145 million)).
There is uncertainty regarding the final outcome of the Initial and Second Complaints due in part to a November 2018 FERC order proposing
a new methodology for determining a just and reasonable base ROE. Fortis considers the new methodology to be generally constructive
for transmission owners. If finalized, this proposed methodology will be used to address ITC’s outstanding ROE complaints. Briefs are due
to be filed in the first half of 2019 on the proposed adoption of the new methodology.
Central Hudson
General Rate Application
In June 2018 the New York Public Service Commission (“PSC”) issued an order approving a three-year rate plan, or joint proposal, that
had been filed by Central Hudson along with multiple stakeholders and intervenors, pursuant to the July 2017 general rate application.
The order included an allowed ROE of 8.8% and common equity ratios of 48%, 49% and 50% in rate years one, two and three, respectively,
and is effective July 1, 2018 through June 30, 2021. Also included is 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 this are primarily returned to customers.
FortisAlberta
Generic Cost of Capital
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.
In December 2018 the AUC initiated a proceeding to consider establishing a formula-based approach to setting the approved ROE beginning
for the year 2021, and to consider whether any process changes are necessary for determining capital structure in years in which the ROE
formula is in place.
39
FORTIS INC. 2018 ANNUAL REPORTManagement Discussion and Analysis U.S. Tax Reform
In 2018 the Corporation’s U.S. utilities worked with their respective regulators to return to customers the net income tax savings resulting
from U.S. tax reform.
ITC
In April 2018 ITC’s MISO Subsidiaries reposted formula rates charged to customers retroactive to January 1, 2018, as approved by FERC.
As at December 31, 2018, the amounts owing had been returned to customers.
UNS Energy
In April 2018 the Arizona Corporation Commission approved TEP’s application to return ongoing income tax savings through a combination
of customer bill credits and regulatory liabilities. Customer bill credits became effective in May 2018. As at December 31, 2018, the amounts
owing had been substantially returned to customers. In 2019 and beyond, TEP will continue to return savings to customers using the same
approach. Regulatory liabilities will be returned to customers as part of TEP’s next rate case, which is expected to be filed in 2019.
In March 2018 FERC issued an order directing TEP to either: (i) submit proposed revisions to its transmission rates or transmission revenue
requirement to reflect the reduction in the federal corporate income tax rate; or (ii) show why a rate adjustment is not required. In May 2018
TEP proposed an overall customer rate reduction, to be effective March 2018, reflecting the lower federal corporate income tax rate. FERC
approved the proposal, effective March 21, 2018.
Central Hudson
In June 2018, as part of its approval of the joint proposal discussed above, the PSC approved Central Hudson’s recommendation to reflect the
recovery of lower federal corporate income tax in customer rates, effective July 1, 2018. As at December 31, 2018, $14 million (US$10 million)
was deferred for the future benefit of customers related to the income tax savings realized in the first six months of 2018.
Significant Regulatory Proceedings
The following table summarizes significant upcoming regulatory proceedings with the related filings expected in 2019.
Regulated Utility
TEP
FBC Energy and FBC Electric
Application/Proceeding
Targeted Rate Case Filing
Targeted 2020–2024 Multi-Year Rate Plan Filing
40
FORTIS INC. 2018 ANNUAL REPORTManagement Discussion and Analysis CONSOLIDATED FINANCIAL POSITION
Significant Changes in the Consolidated Balance Sheets between December 31, 2018 and December 31, 2017
Balance Sheet Account
Accounts receivable and
other current assets
Assets held for sale
Regulatory assets
(including current and long-term)
Increase
($ millions) (1)
226
766
133
Property, plant and equipment, net
2,986
Intangible assets, net
Goodwill
Accounts payable and
other current liabilities
Regulatory liabilities
(including current and long-term)
Deferred income tax liabilities
Long-term debt (including current
portion and short-term borrowings)
Capital lease and finance obligations
(including current portion)
Shareholders’ equity
119
886
236
180
388
2,540
181
1,530
Non-controlling interests
177
Explanation
The increase was mainly due to higher income tax receivable, higher wholesale sales at UNS Energy
and foreign exchange.
The increase was due to a reclassification, primarily from property, plant and equipment, of the
assets associated with the expected sale of the Corporation’s 51% interest in the Waneta Expansion.
The increase was primarily due to foreign exchange and higher deferred income taxes at
FortisAlberta, partially offset by the regulator-ordered netting of certain regulatory liabilities at
Central Hudson.
The increase was mainly due to capital expenditures, foreign exchange and the recognition of
a capital lease for Gila River generating station Unit 2 at UNS Energy. The increase was partially
offset by depreciation and the reclassification of assets held for sale.
The increase was primarily due to foreign exchange and ITC expenditures related to land rights
and software.
The increase was due to foreign exchange.
The increase was mainly due to higher amounts owing for energy supply costs and foreign
exchange, partially offset by the timing of transmission cost payments at FortisAlberta.
The increase was primarily due to foreign exchange, partially offset by lower rate stabilization
accounts at FortisBC Energy.
The increase was mainly due to timing differences related to capital expenditures at the regulated
utilities, foreign exchange and the utilization of taxable losses.
The increase was due to debt issuances at the regulated utilities, foreign exchange and higher net
borrowings under committed credit facilities, partially offset by scheduled debt repayments.
The increase was mainly due to UNS Energy’s recognition of a capital lease for Gila River generating
station Unit 2.
The increase was due to: (i) accumulated other comprehensive income associated with the
translation of the Corporation’s US dollar-denominated investments in subsidiaries, net of hedging
activities and tax; (ii) net earnings attributable to common shareholders for 2018, less dividends
declared on common shares; and (iii) the issuance of common shares under the Corporation’s
dividend reinvestment plan.
The increase was due to net earnings and comprehensive income attributable to minority interests.
(1) Includes the impact of foreign exchange based upon the closing foreign exchange rate at December 31, 2018 of US$1.00=CAD$1.36 compared to the closing foreign exchange
rate at December 31, 2017 of US$1.00=CAD$1.25.
41
FORTIS INC. 2018 ANNUAL REPORTManagement Discussion and Analysis
LIQUIDITY AND CAPITAL RESOURCES
Summary of Consolidated Cash Flows
The Corporation’s sources and uses of cash are provided below.
Summary of Consolidated Cash Flows
Years Ended December 31
($ 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 Associated with Assets Held for Sale
Cash, End of Year
Operating Activities
2018
327
2,604
(3,252)
644
24
(15)
332
2017
269
2,756
(3,025)
339
(12)
–
327
Variance
58
(152)
(227)
305
36
(15)
5
The decrease in cash provided by operating activities was primarily due to lower cash earnings, driven primarily by ITC as a result of
U.S. tax reform, and unfavourable changes in long-term regulatory deferrals. Long-term regulatory deferrals decreased mainly due to the
deferral of higher gas storage and transportation costs at FortisBC Energy related to a gas pipeline incident in the fourth quarter of 2018,
and the funding of clean energy initiatives and the deferral of major storm costs at Central Hudson.
Investing Activities
The increase in cash used in investing activities was due to higher capital spending.
Financing Activities
The increase in cash provided by financing activities was primarily due to lower net repayments of credit facilities and short-term
borrowings and lower repayments of long-term debt mainly at the Corporation’s regulated utilities. The increase was partially offset
by lower proceeds from the issuance of long-term debt at the Corporation’s regulated utilities, driven by ITC.
In 2017 approximately 12.2 million common shares of Fortis were issued to an institutional investor for proceeds of $500 million. The net
proceeds were used to repay credit facility borrowings related to the financing of the ITC acquisition.
Proceeds from long-term debt, net of issue costs, are summarized below.
Proceeds from Long-Term Debt, Net of Issue Costs
Years Ended December 31
($ millions)
ITC
UNS Energy
Central Hudson
FortisBC Energy
FortisAlberta
FortisBC Electric
Other Electric
Total
2018 (1)
516
390
136
198
149
–
177
1,566
2017
1,863
–
74
173
199
74
155
2,538
Variance
(1,347)
390
62
25
(50)
(74)
22
(972)
(1) Refer to Note 16 of the 2018 Annual Financial Statements for issue date, form of instrument, interest rate, term and use of proceeds.
In January 2019 ITC issued 30-year US$50 million secured notes at 4.55%. ITC will have an additional US$50 million delayed draw of 30-year
secured notes at 4.65% in July 2019. The net proceeds will be used to repay credit facility borrowings, finance capital expenditures and for
general corporate purposes.
Borrowings under credit facilities by the utilities are primarily in support of their respective capital expenditure programs and/or for working
capital requirements. Repayments are primarily financed through the issuance of long-term debt, cash from operations and/or equity
injections from Fortis. From time to time, proceeds from preference share, common share and long-term debt offerings are used to repay
borrowings under the Corporation’s committed credit facility.
42
FORTIS INC. 2018 ANNUAL REPORTManagement Discussion and Analysis
Common share dividends paid in 2018 totalled $459 million, net of $272 million of dividends reinvested, compared to $419 million, net of
$253 million of dividends reinvested, paid in 2017. The increase in dividends paid was due to a higher annual dividend paid per common
share and an increase in the number of common shares outstanding. The dividend paid per common share was $1.725 in 2018 compared
to $1.625 in 2017. The weighted average number of common shares outstanding was 424.7 million for 2018 compared to 415.5 million for 2017.
Contractual Obligations
Contractual obligations with external third parties in each of the next five years and for periods thereafter, as at December 31, 2018, are
as follows.
Contractual Obligations
As at December 31, 2018
($ millions)
Long-term debt
Interest obligations on long-term debt
Capital lease and finance obligations (i)
Power purchase obligations (ii)
Renewable power purchase obligations (iii)
Gas purchase obligations (iv)
Long-term contracts – UNS Energy (v)
ITC easement agreement (vi)
Renewable energy credit purchase agreements (vii)
Debt collection agreement (viii)
Purchase of Springerville common facilities (ix)
Waneta Partnership promissory note
Joint-use asset and shared service agreements
Operating lease obligations
Other (x)
Total
Due
within
1 year
926
994
313
254
110
359
176
14
24
3
–
72
3
8
108
3,364
Total
24,231
16,345
2,451
2,438
1,699
1,348
777
436
146
119
93
72
52
51
530
50,788
Due in
year 2
731
973
77
191
110
290
142
14
26
3
–
–
3
6
84
2,650
Due in
year 3
1,324
950
80
174
109
242
92
14
18
3
93
–
3
5
89
3,196
Due in
year 4
1,125
902
49
170
109
202
60
14
11
3
–
–
3
4
38
2,690
Due in
year 5
1,605
870
47
172
108
144
46
14
11
3
–
–
3
4
36
3,063
Due
after
5 years
18,520
11,656
1,885
1,477
1,153
111
261
366
56
104
–
–
37
24
175
35,825
(i)
Includes principal payments, imputed interest and executory costs.
(ii) The most significant power purchase obligations are described below.
Maritime Electric ($771 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 ($705 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 Energy ($522 million): an agreement with BC Hydro for the supply of electricity to the Tilbury LNG facility expansion.
(iii)
(iv)
(v)
FortisBC Electric ($345 million): includes an agreement with BC Hydro to purchase up to 200 MW of capacity and 1,752 GWh of associated
energy annually for a 20-year term beginning October 1, 2013.
TEP and UNS Electric are party to renewable PPAs, with expiry dates from 2027 through 2043, that require them to purchase 100% of
the output of certain renewable energy generating facilities once commercial operation is achieved. Amounts shown are the estimated
future payments.
Certain of the Corporation’s subsidiaries, mainly FortisBC Energy, enter into contracts for the purchase of gas, gas transportation and
storage services. 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, 2018.
UNS Energy enters into 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 2019 and 2040.
43
FORTIS INC. 2018 ANNUAL REPORTManagement Discussion and Analysis
(vi)
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.
(vii) 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 generators. Payments are primarily made at contractually
agreed-upon intervals based on metered energy production.
(viii) 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.
(ix)
UNS Energy is obligated to purchase an undivided 32.2% interest in the Springerville Common Facilities if the related two leases are not
renewed. The initial lease terms expire in January 2021.
(x)
Includes stock-based compensation plan obligations, land easements, asset retirement obligations, and defined benefit pension plan
funding obligations.
Other Contractual Obligations
The Corporation’s regulated utilities are obligated to provide service to customers within their respective service territories. Their capital
expenditures are largely to ensure continued and enhanced performance, reliability and safety of the electricity and gas systems and to meet
customer growth. Consolidated capital expenditures are forecast to be approximately $3.7 billion for 2019 and approximately $17.3 billion
over the five-year period from 2019 through 2023.
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 $2.3 billion (US$1.7 billion). Central Hudson’s maximum commitment is $248 million (US$182 million), for which
it has issued a parental guarantee. As at December 31, 2018, there was no obligation under this guarantee.
As at December 31, 2018, FHI had $77 million (December 31, 2017 – $80 million) of parental guarantees outstanding to support storage
optimization activities at Aitken Creek.
Capital Structure
The Corporation’s utilities require ongoing access to capital to fund maintenance and expansion of infrastructure. Fortis raises debt at the
utility level to ensure regulatory transparency, tax efficiency and financing flexibility. To help ensure access to capital, the Corporation targets
a consolidated long-term capital structure that will enable it to maintain investment-grade credit ratings. Each of the Corporation’s regulated
utilities maintains its own capital structure in line with the deemed capital structure reflected in its customer rates.
The consolidated capital structure of Fortis is presented below.
Capital Structure
As at December 31
(%)
Debt (1)
Preference shares
Common shareholders’ equity and minority interest
Total
2018
57.0
3.8
39.2
100.0
2017
56.5
4.2
39.3
100.0
(1) Includes long-term debt and capital lease and finance obligations, including current portion, and short-term borrowings, net of cash
The capital structure was impacted by: (i) an increase in long-term debt to fund energy infrastructure investment and foreign exchange
on the translation of US dollar-denominated debt, partially offset by scheduled debt repayments; (ii) an increase in accumulated other
comprehensive income associated with the translation of the Corporation’s US dollar-denominated investments in subsidiaries, net of
hedging activities and tax; (iii) the issuance of common shares under the Corporation’s dividend reinvestment plan; and (iv) net earnings
attributable to common equity shareholders for 2018, less dividends declared on common shares.
44
FORTIS INC. 2018 ANNUAL REPORTManagement Discussion and Analysis
Credit Ratings
As at December 31, 2018, the Corporation’s credit ratings were as follows.
Rating Agency
Standard & Poor’s (“S&P”)
DBRS
Moody’s Investor Service
Credit Rating
A–
BBB+
BBB (high)
BBB (high)
Baa3
Baa3
Type of Rating
Corporate
Unsecured debt
Corporate
Unsecured debt
Issuer
Unsecured debt
Outlook
Negative
Stable
Stable
The above-noted credit ratings reflect the Corporation’s low business-risk profile and diversity of its operations, the stand-alone nature and
financial separation of each of the regulated subsidiaries of Fortis, and the level of debt at the holding company.
In March 2018 S&P affirmed the Corporation’s credit ratings and revised its outlook from stable to negative due to a modest temporary
weakening of financial measures as a result of U.S. tax reform, which reduces cash flow at the Corporation’s U.S. regulated utilities.
Capital Expenditure Program
Capital investment in energy infrastructure is required to ensure continued and enhanced performance, reliability and safety of the electricity
and gas systems, and to meet customer growth.
Consolidated capital expenditures for 2018 were approximately $3.2 billion and a breakdown by segment and asset category is as follows.
Consolidated Capital Expenditures (1)
Year Ended December 31, 2018
($ millions)
Generation
Transmission
Distribution
Other (3)
Total
Regulated Utilities
ITC
–
916
–
82
998
UNS
Energy
182
58
235
124
599
Central
Hudson
1
32
157
55
FortisBC
Energy
–
230
183
73
245
486
Fortis
Alberta
–
–
370
63
433
FortisBC
Electric
26
17
46
17
Total
Other Regulated
Non-
Electric
64
41
160
35
Utilities Regulated (2) Total
303
1,294
1,151
470
273
1,294
1,151
449
30
–
–
21
106
300
3,167
51
3,218
(1) Represents cash payments to construct property, plant and equipment and intangible assets, as reflected on the consolidated statement of cash flows
(2) Includes Energy Infrastructure and Corporate and Other segments
(3) Includes facilities, equipment, vehicles, information technology and other, along with capital expenditures associated with Alberta Electric System Operator (“AESO”)
transmission-related capital expenditures at FortisAlberta
Planned capital expenditures are based on detailed forecasts of energy demand, cost of labour and materials, as well as other factors,
including economic conditions and foreign exchange rates, which could change and cause actual expenditures to differ from those forecast.
Consolidated capital expenditures of $3.2 billion for 2018 were consistent with the forecast, as disclosed in the MD&A for the year ended
December 31, 2017.
45
FORTIS INC. 2018 ANNUAL REPORTManagement Discussion and Analysis
Consolidated capital expenditures for 2019 are expected to be approximately $3.7 billion and a breakdown by segment and asset category is
as follows.
Forecast Consolidated Capital Expenditures (1)
Year Ending December 31, 2019
($ millions)
Generation
Transmission
Distribution
Other (3)
Total
Regulated Utilities
ITC
–
798
–
67
865
UNS
Energy
406
320
245
105
1,076
Central
Hudson
3
36
163
78
FortisBC
Energy
–
267
141
95
280
503
Fortis
Alberta
–
–
311
103
414
FortisBC
Electric
29
25
43
19
Total
Other Regulated
Non-
Electric
53
198
137
30
Utilities Regulated (2) Total
493
1,644
1,040
523
491
1,644
1,040
497
2
–
–
26
116
418
3,672
28
3,700
(1) Represents forecast cash payments to construct property, plant and equipment and intangible assets, as would be reflected on the consolidated statement of cash flows, as
well as Fortis’ assumed share of estimated capital spending for the Wataynikaneyap Transmission Power Project. Forecast capital expenditures for 2019 are based on a forecast
exchange rate of US$1.00=CAD$1.28. Based on the closing foreign exchange rate on December 31, 2018 of US$1.00=CAD$1.36, forecast capital expenditures for 2019 would be
approximately $3.9 billion.
(2) Includes Energy Infrastructure and Corporate and Other segments
(3) Includes facilities, equipment, vehicles, information technology and other, along with forecast capital expenditures associated with AESO transmission-related investment
at FortisAlberta
The percentage breakdown of 2018 actual and 2019 forecast consolidated capital expenditures among growth, sustaining and other is
as follows.
Consolidated Capital Expenditures
Year Ending December 31
(%)
Growth (1)
Sustaining (2)
Other (3)
Total
Actual
2018
34
52
14
100
Forecast
2019
31
56
13
100
(1) Capital expenditures to connect new customers and infrastructure upgrades required to meet customer and associated load growth, including capital expenditures
associated with AESO transmission-related investment at FortisAlberta
Capital expenditures required to ensure continued and enhanced performance, reliability and safety of generation, transmission and distribution assets
(2)
(3) Relates to facilities, equipment, vehicles, information technology systems and other assets
Over the five-year period from 2019 through 2023 (“five-year capital program”), consolidated capital expenditures are expected to be
approximately $17.3 billion, $2.8 billion higher than $14.5 billion previously forecast for the period from 2018 through 2022, as disclosed in
the MD&A for the year ended December 31, 2017. The increase in the five-year capital program is the result of the Corporation’s sustainable
organic growth platform, the inclusion of Fortis’ assumed share of estimated capital investment for the Wataynikaneyap Transmission
Power Project, and increased investment in grid modernization, renewables, and natural gas infrastructure primarily at ITC, UNS Energy and
FortisBC Energy, respectively. The low-risk, highly executable five-year capital program is virtually all occurring at the regulated utilities and
contains only a small number of major projects.
The approximate breakdown of the capital spending expected to be incurred is as follows: 55% in the U.S., including 26% at ITC; 42% in
Canada; and the remaining 3% in the Caribbean. Capital expenditures at the regulated utilities are subject to regulatory approval. Over the
five-year period, on average annually, the approximate breakdown of the total capital spending to be incurred is as follows: 28% to meet
customer growth; 60% for sustaining capital expenditures; and 12% for facilities, equipment, vehicles, information technology and other assets.
The five-year capital program is expected to be primarily funded with cash from operations, debt raised at the utilities and common equity
from the Corporation’s dividend reinvestment plan. The remaining funds are expected to be generated from the sale of the Waneta Expansion
in 2019. The Corporation’s at-the-market common equity program will also be available to provide further financing flexibility, if needed.
46
FORTIS INC. 2018 ANNUAL REPORTManagement Discussion and Analysis
Actual 2018 and forecast 2019 midyear rate base for the Corporation’s regulated utilities is as follows.
Midyear Rate Base (1)
($ billions)
ITC
UNS Energy
Central Hudson
FortisBC Energy
FortisAlberta
FortisBC Electric
Other Electric
Total
Actual
2018
7.8
4.7
1.6
4.4
3.4
1.3
2.9
26.1
Forecast
2019
8.5
5.3
1.8
4.5
3.6
1.3
2.9
27.9
(1)
Actual midyear rate base for 2018 is based on the actual average exchange rate of US$1.00=CAD$1.30 and forecast midyear rate base for 2019 is based on a forecast
exchange rate of US$1.00=CAD$1.28. Based on the closing foreign exchange rate on December 31, 2018 of US$1.00=CAD$1.36, forecast midyear rate base for 2019 would
be approximately $29 billion.
The most significant capital projects included in the five-year capital program are summarized below.
Significant Capital Projects (1)
($ millions)
Company
ITC (2)(3)
UNS Energy (3)
FortisBC Energy
Wataynikaneyap
Nature of Project
Multi-Value Regional Transmission Projects (“MVPs”)
34.5 to 69 kilovolt (“kV”) Transmission
Conversion Project
Gila River Natural Gas Generating Station Unit 2
Southline Transmission Project
New Mexico Wind Project
Lower Mainland Intermediate Pressure
System Upgrade (“LMIPSU”)
Eagle Mountain Woodfibre Gas Line Project (4)
Transmission Integrity Management Capabilities Project
Inland Gas Upgrades Project
Transmission Power Project (5)
Pre-
2018
370
86
–
–
–
43
–
–
–
–
Actual
2018
211
Forecast
2019
88
Forecast
2020–2023
244
139
–
–
–
165
–
–
3
25
87
211
182
55
187
–
–
14
158
261
–
207
222
65
350
568
208
429
Expected
Year of
Completion
2023
Post-2023
2019
2022
2020
2020
2023
Post-2023
Post-2023
2023
(1) Represents property, plant and equipment and intangible asset expenditures, including both the capitalized debt and equity components of AFUDC, where applicable.
Significant capital projects are identified as those with a total project cost of $150 million or greater and exclude ongoing capital maintenance projects.
(2) Capital expenditures prior to 2018 are from the date of acquisition of October 14, 2016.
(3) Forecast capital expenditures are based on a forecast exchange rate of US$1.00=CAD$1.28 for 2019 through 2023.
(4) Net of forecast customer contributions
(5) Fortis’ assumed share of estimated capital spending, including deferred development costs. Under the funding framework, Fortis will be funding its equity component only.
The MVPs at ITC consist of four regional electric transmission projects that have been identified by MISO to address system capacity needs
and reliability in various states. Approximately $580 million (US$447 million) was invested in the MVPs from the date of acquisition of ITC, and
an additional $332 million (US$259 million) is expected to be spent from 2019 through 2023. One of the MVPs was completed in 2018 and the
remaining projects are in various stages of construction with in-service dates expected to range from 2019 through 2023.
The 34.5 to 69kV Transmission Conversion Project at ITC consists of multiple capital initiatives designed to construct and rebuild new 69-kV
lines, with in-service dates ranging from 2019 to post-2023. Approximately $350 million (US$272 million) is expected to be invested in this
project over the five-year period through 2023.
The 550 MW natural gas-fired Gila River Generating Station Unit 2 at UNS Energy will assist with the replacement of retiring coal-fired
generation facilities. The total cost of the project is estimated to be $211 million (US$165 million) and includes an initial power purchase
agreement with a purchase option expected to be exercised in late 2019.
The Southline Transmission Project is a 600 MW transmission line designed to collect and transmit electricity across southern New Mexico
and southern Arizona. UNS Energy expects to purchase a 250 MW ownership in the project. Construction is expected to commence in 2019,
with completion expected in 2022. The capital cost of the project for UNS Energy is estimated at approximately $390 million (US$304 million).
The transmission line will improve reliability in the region and facilitate the connection of renewable energy resources to the grid, including
the New Mexico Wind Project.
47
FORTIS INC. 2018 ANNUAL REPORTManagement Discussion and Analysis
The New Mexico Wind Project is a 750 MW wind power generating plant that will be interconnected to the Southline Transmission line and
complements UNS Energy’s existing renewable solar generation portfolio. UNS Energy will have a 150 MW ownership under a build-transfer
asset contract, with an option to purchase additional ownership in the future. Construction is expected to commence in 2019, with
completion expected in 2020. The capital cost of the project for UNS Energy is estimated at approximately $280 million (US$217 million).
The Lower Mainland System Upgrade project addresses system capacity and pipeline condition issues for the gas supply system in the
Lower Mainland of British Columbia. The project is being completed in two phases: (i) the Coastal Transmission System (“CTS”) phase, which
increases security of supply; and (ii) the LMIPSU phase, which is focused on addressing pipeline condition issues. Construction activities for
the CTS project are complete, and the new pipelines are in service. During the third quarter of 2018, a significant portion of the Vancouver
section of the LMIPSU project was completed and was gasified in December. Construction of the remaining portion of the project has
resumed in the first quarter of 2019. The total capital cost of both phases is estimated to be approximately $640 million, with approximately
$250 million expected to be spent on the LMIPSU phase from 2019 through 2020. The final project costs remain subject to review by the
British Columbia Utilities Commission (“BCUC”) after the project is complete and in service.
The Eagle Mountain Woodfibre Gas Line Project is a pipeline expansion at a proposed LNG site in Squamish, British Columbia. The current
estimate of FortisBC Energy’s investment in the project may be updated for final scoping, detailed construction estimates and scheduling, and
final determination of customer capital contributions. FortisBC Energy received an Order in Council from the Government of British Columbia
effectively exempting this project from further regulatory approval by the BCUC. In the fourth quarter of 2018, FortisBC Energy and
Woodfibre LNG Limited (“Woodfibre”) entered into a pre-execution work agreement, which enables FortisBC Energy to incur project
feasibility and development costs and establishes the funding requirements from Woodfibre during this phase. FortisBC Energy’s anticipated
capital expenditures, net of forecast customer contributions, is approximately $350 million and remains contingent on Woodfibre making a
final investment decision. The project is expected to be in service in 2023.
The multi-year Transmission Integrity Management Capabilities Project is focused on improving gas line safety and the integrity of the
transmission system, including gas line modifications and looping. The capital cost of the project is estimated at $570 million, an increase
of approximately $260 million from the amount disclosed in the 2017 Annual MD&A. In December 2018 a regulatory deferral account was
approved by the BCUC to capture approximately $40 million of development costs to be incurred in 2019 and 2020 to enable the filing of
a Certificate of Public Convenience (“CPCN”).
The multi-year Inland Gas Upgrades Project will involve gas line modifications and replacements enabling in-line inspection capabilities,
a key tool to confirm the integrity of transmission gas lines. In December 2018 the CPCN application was filed with the BCUC and approval is
expected in the second half of 2019. The total cost of the project is estimated to be $360 million, with $225 million expected to be invested
over the five-year period through 2023. Subject to CPCN approval, construction of the project is expected to commence in 2020.
The Wataynikaneyap Transmission Power Project will connect 17 remote First Nations communities in Northwestern Ontario to the main
electricity grid through the construction of 1,800 kilometres of transmission lines. Wataynikaneyap Power is a licensed transmission company,
regulated by the Ontario Energy Board (“OEB”), equally owned by 24 First Nations communities (51%), in partnership with Fortis (39%)
and Algonquin Power & Utilities Corp. (10%). In March 2018 the project reached a significant milestone with the formal announcement of
a funding framework among Wataynikaneyap Power, the Government of Canada and the Government of Ontario. FortisOntario will be
responsible for construction management and operation of the transmission line.
The total estimated capital cost for the Wataynikaneyap Transmission Power Project is approximately $1.6 billion. The initial phase of the
project to connect the Pikangikum First Nation to Ontario’s power grid was fully funded by the Canadian government and was completed
in late 2018. The next two phases are subject to receipt of all necessary regulatory approvals, including the leave-to-construct approval
from the OEB. The leave-to-construct application was filed with the OEB in June 2018 and approval is expected in the first half of 2019.
These phases are targeted to be completed by the end of 2020 and 2023, respectively. In addition to providing participating First Nations
communities ownership in the transmission line, the project provides socio-economic benefits, reduces environmental risk and lessens
greenhouse gas emissions associated with diesel-fired generation currently used in remote locations.
48
FORTIS INC. 2018 ANNUAL REPORTManagement Discussion and Analysis Additional Investment Opportunities
Management is pursuing additional investment opportunities within existing service territories. These additional investment opportunities,
as discussed below, are not included in the Corporation’s five-year capital program.
ITC – Lake Erie Connector
The Lake Erie Connector is a proposed 1,000 MW, bi-directional, high-voltage direct current underwater transmission line that would provide
the first direct link between 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.
In 2017 the project’s major application process in the United States and Canada was completed upon receipt of permits from the U.S. Army
Corps of Engineers. The project continues to advance through regulatory, operational and economic milestones. Ongoing activities include
completing project cost refinements and securing favourable transmission service agreements with prospective counterparties. Pending
achievement of key milestones, completion of the project would take approximately three years from the commencement of construction.
FortisBC Energy – Liquefied Natural Gas
The Corporation continues to pursue additional LNG infrastructure investment 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 hold
discussions with a number of potential export customers.
Other Opportunities
Other capital investment opportunities include, but are not limited to: incremental regulated transmission investment opportunities and
energy storage and contracted transmission 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.
Cash Flow Requirements
At the subsidiary level, it is expected that operating expenses and interest costs will generally be paid out of operating cash flows, with
varying levels of residual cash flows available for capital expenditures and/or dividend payments to Fortis. Borrowings under credit facilities
may be required from time to time to support seasonal working capital requirements. Cash required to complete capital expenditure
programs is also expected to be financed from a combination of borrowings under credit facilities, long-term debt offerings and equity
injections from Fortis.
Cash required from Fortis to support subsidiary capital expenditure programs is expected to be derived from a combination of borrowings
under the Corporation’s committed corporate credit facility, proceeds from the issuance of common shares, preference shares and long-term
debt, and proceeds from non-core asset sales. Depending on the timing of cash payments from the subsidiaries, borrowings under the
Corporation’s committed corporate credit facility may be required from time to time to support the servicing of debt and payment of dividends.
The Corporation’s ability to service its debt obligations and pay dividends on its common and preference shares is dependent on the
financial results, and related cash payments, of the subsidiaries. Certain regulated subsidiaries are subject to restrictions that may limit their
ability to distribute cash to Fortis. These include restrictions by certain regulators limiting the amount of annual dividends and restrictions
by certain lenders limiting the amount of debt to total capitalization at the subsidiaries. In addition, there are practical limitations on
using the net assets of each of the Corporation’s regulated subsidiaries to pay dividends based on management’s intent to maintain the
regulator-approved capital structures for each of its regulated subsidiaries. The Corporation does not expect that maintaining the targeted
capital structures of its regulated subsidiaries will have an impact on its ability to pay dividends in the foreseeable future.
In December 2018 Fortis filed a short-form base shelf prospectus, under which the Corporation may issue common or preference shares,
subscription receipts or debt securities in an aggregate principal amount of up to $2.5 billion during the 25-month life of the base shelf
prospectus. In December 2018 the Corporation re-established its at-the-market common equity program that allows the issuance of up
to $500 million of common shares from treasury to the public at the Corporation’s discretion, effective until January 2021.
As at December 31, 2018, management expects consolidated fixed-term debt maturities and repayments to be $191 million in 2019 and to
average approximately $929 million annually over the next five years. The combination of available credit facilities and manageable annual
debt maturities and repayments provides the Corporation and its subsidiaries with flexibility in the timing of access to capital markets. For
a discussion of capital resources and liquidity risk, refer to the “Business Risk Management” section of this MD&A.
Fortis and its subsidiaries were in compliance with debt covenants as at December 31, 2018 and are expected to remain compliant in 2019.
49
FORTIS INC. 2018 ANNUAL REPORTManagement Discussion and Analysis Credit Facilities
As at December 31, 2018, the Corporation and its subsidiaries had consolidated credit facilities of approximately $5.2 billion, of which
approximately $3.9 billion was unused, including $1.0 billion unused under the Corporation’s committed revolving corporate credit facility.
The following summarizes the credit facilities of the Corporation and its subsidiaries.
Credit Facilities
As at December 31
($ millions)
Total credit facilities
Credit facilities utilized:
Short-term borrowings
Long-term debt (including current portion) (1)
Letters of credit outstanding
Credit facilities unutilized
(1) The current portion was $735 million (December 31, 2017 – $312 million).
Regulated
Utilities
3,780
Corporate
and Other
1,385
(60)
(731)
(65)
2,924
–
(335)
(54)
996
2018
5,165
(60)
(1,066)
(119)
3,920
2017
4,952
(209)
(671)
(129)
3,943
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 $5.0 billion of the total credit facilities are committed facilities with maturities ranging from 2019 through 2023.
Consolidated credit facilities of approximately $5.2 billion as at December 31, 2018 are itemized below.
Credit Facilities
($ millions)
Unsecured committed revolving credit facilities
Regulated utilities
ITC (1)
UNS Energy
Central Hudson
FortisBC Energy
FortisAlberta
FortisBC Electric
Other Electric
Other Electric
Corporate and Other
Other facilities
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
US
40
10
25
60
35
October 2022
October 2022
(2)
August 2023
August 2023
April 2023
(3)
January 2020
(4)
n/a
n/a
n/a
April 2019
n/a
(1) ITC also has a US$400 million commercial paper program, under which no amounts were outstanding as at December 31, 2018.
(2) US$50 million in July 2020 and US$200 million in October 2020
(3) $50 million in February 2019, $40 million in June 2021, and $100 million in August 2023
(4) $1.3 billion in July 2023, with the option to increase by an amount up to $500 million, and $50 million in April 2021
OFF-BALANCE SHEET ARRANGEMENTS
With the exception of letters of credit outstanding of $119 million as at December 31, 2018 (December 31, 2017 – $129 million), the Corporation
had no off-balance sheet arrangements that are reasonably likely to materially affect liquidity or the availability of, or requirements for,
capital resources.
50
FORTIS INC. 2018 ANNUAL REPORTManagement Discussion and Analysis
BUSINESS RISK MANAGEMENT
The following is a summary of the principal risks facing the Corporation. Other risks may arise or risks not currently considered material may
become material in the future.
The Corporation’s utilities are subject to substantial regulation and may be adversely affected by regulatory or
legislative changes.
Regulated utility assets represented approximately 97% of total assets of Fortis as at December 31, 2018 (December 31, 2017 – 97%). The
Corporation operates utilities in different jurisdictions, including five Canadian provinces, nine U.S. states and three Caribbean countries.
The Corporation’s utilities are subject to regulation by various federal, state and provincial regulators that can affect future revenue and
earnings. These regulators administer various acts and regulations covering material aspects of the utilities’ business, including, among others:
electricity and gas tariff rates charged to customers; the allowed ROEs and deemed capital structures; electricity and gas infrastructure
investments; capacity and ancillary services; the transmission and distribution of energy; the terms and conditions of procurement of
electricity for customers; issuances of securities; the provision of services by affiliates and the allocation of those service costs; certain
accounting matters; and certain aspects of the siting and construction of transmission and distribution systems. Any decisions made by
such regulators could have an adverse effect on the results of operations, financial condition and cash flows of the Corporation’s utilities.
In addition, there is no assurance that the utilities will receive regulatory decisions in a timely manner and, therefore, costs may be incurred
prior to having a corresponding approved revenue requirement.
The Corporation’s utilities follow COS regulation in determining annual revenue requirements and resulting customer rates, under which
the ability to recover the actual cost of service and earn the approved ROE and/or ROA may depend on achieving the forecasts established
in the rate-setting process. Failure of a utility to meet such forecasts could adversely affect the Corporation’s results of operations, financial
condition, and cash flows. When PBR mechanisms are utilized, a formula is generally applied that incorporates inflation and assumed
productivity improvements. The use of PBR mechanisms should allow a utility a reasonable opportunity to recover prudent cost of service
and earn its allowed ROE; however, in the event that inflationary increases exceed the inflationary factor set by the regulator or the utility is
unable to achieve productivity improvements, the Corporation’s results of operations, financial condition and cash flows may be adversely
impacted. In the case of FortisAlberta’s current PBR mechanism, there is a risk that capital expenditures may not qualify, or be approved, for
incremental funding where necessary.
The Corporation and its utilities must address the effects of regulation, including compliance costs imposed on operations as a result of
such regulation. The political and economic environment has had, and may continue to have, an adverse effect on regulatory decisions
with negative consequences for the Corporation’s utilities, including the cancellation or delay of planned development activities or other
capital expenditures, and the incurrence of costs that may not be recoverable through rates. In addition, the Corporation is unable to
predict future legislative or regulatory changes, and there can be no assurance that it will be able to respond adequately or in a timely
manner to such changes. Such legislative or regulatory changes may increase costs and competitive pressures on the Corporation and its
utilities. Any of these events could have an adverse effect on the Corporation’s results of operations, financial condition and cash flows.
For additional information on specific regulatory matters pertaining to the Corporation’s utilities, refer to the “Regulatory Highlights” section
of this MD&A.
Certain elements of ITC’s regulated operating subsidiaries’ formula rates can be and have been challenged, which could result
in lowered rates and/or refunds of amounts previously collected and could have an adverse financial effect on ITC.
ITC’s regulated operating subsidiaries provide transmission service under rates regulated by FERC. FERC has approved the cost-based formula
rates used to calculate the annual revenue requirement, but it has not expressly approved the amount of actual capital and operating
expenditures to be used in the formula rates. All aspects of ITC’s rates approved by FERC, including the formula rate templates, the rates of
return on the actual equity portion of capital structure and the approved targeted capital structure, are subject to challenge by interested
parties or by FERC. In addition, interested parties may challenge ITC’s annual implementation and calculation of projected rates and
formula rate true up pursuant to their approved formula rates under their formula rate implementation protocols. End-use customers and
entities supplying electricity to end-use customers may also attempt to influence government and/or regulators to change the rate-setting
methodologies that apply to ITC, particularly if rates for delivered electricity increase substantially. If it is established that rates are unjust and
unreasonable or that the terms of service provision are unduly discriminatory or preferential, then FERC can make appropriate prospective
adjustments. This could result in lowered rates and/or refunds of amounts collected, any of which could have an adverse effect on ITC’s
results of operations, financial condition and cash flows.
For additional information on third-party complaints with FERC regarding the MISO regional base ROE for certain of ITC’s regulated operating
subsidiaries, refer to the “Regulatory Highlights” section of this MD&A.
51
FORTIS INC. 2018 ANNUAL REPORTManagement Discussion and Analysis
Changes in interest rates could have an adverse financial effect on the Corporation.
Generally, allowed ROEs for regulated utilities in North America are exposed to changes in long-term interest rates. The regulatory process
may consider the general level of interest rates as a factor for setting allowed ROEs. A low-interest rate environment could adversely affect
the allowed ROEs, which could have a negative effect on the results of operations, financial condition and cash flows of the Corporation.
Alternatively, if interest rates increase, regulatory lag may cause a delay in any resulting increase in the allowed ROEs to compensate for
higher cost of capital.
The Corporation and its subsidiaries may also be exposed to interest rate risk associated with borrowings under variable-rate credit facilities,
variable-rate long-term debt and refinancing of long-term debt. At the utilities, interest expense is generally recovered in customer rates,
as approved by the regulators. The inability to flow through interest costs to customers could have an adverse effect on the results of
operations, financial condition and cash flows of the utilities. In addition, a change in the level of interest rates could affect the measurement
and disclosure of the fair value of long-term debt.
Failure of facilities to operate as expected, from the occurrence of natural disasters or severe weather that may be caused by
climate change, could have an adverse financial effect on the Corporation and its utilities.
The ongoing operation of the utilities’ facilities involves risks customary to the electric and gas utility industry, including storms and severe
weather conditions, natural disasters, wars, terrorist acts, failure of critical equipment and other catastrophic events occurring both within
and outside the service territories of the utilities. Such occurrences could result in service disruptions and the inability to deliver electricity
or gas to customers in an efficient manner, resulting in lower earnings and/or cash flows if the situation is not resolved in a timely manner or
the financial impacts of restoration are not alleviated through insurance policies or regulated cost recovery.
Despite preparations for severe weather, ice, wind and snowstorms, hurricanes and other natural disasters, weather will always remain a risk
to the physical assets of utilities. Climate change may have the effect of increasing the severity and frequency of weather-related natural
disasters that could affect the Corporation’s operations and system reliability. Although physical utility assets have been constructed and
are operated and maintained to withstand severe weather, there can be no assurance that they will successfully do so in all circumstances.
The operation of the Corporation’s electric and hydroelectric generating stations involves certain risks, including equipment breakdown
or failure, that may result in the uncontrolled release of water, interruption of fuel supply and lower-than-expected levels of efficiency or
operational performance. Unplanned outages, including extensions of planned outages due to equipment failure or other complications,
occur from time to time and are an inherent risk of the generation business. There can be no assurance that the generation facilities of
Fortis will continue to operate in accordance with expectations.
The operation of electricity transmission and distribution assets is also subject to certain risks, including the potential to cause fires, mainly as
a result of equipment failure, falling trees and lightning strikes to lines or equipment. Certain of the Corporation’s utilities operate in remote
and mountainous terrain with a risk of loss or damage from forest fires, floods, washouts, landslides, earthquakes, avalanches and other
acts of nature. In addition, a significant portion of the utilities’ infrastructure is located in remote areas, which may make access to perform
maintenance and repairs difficult if such assets become damaged.
The Corporation’s gas utilities are exposed to various operational risks associated with gas, including fires, explosions, pipeline leaks,
accidental damage to mains and service lines, corrosion in pipes, pipeline or equipment failure, other issues that can lead to outages
and/or leaks, and any other accidents involving gas that could result in significant operational disruptions and/or environmental liability.
The operation and integrity of the gas assets are also at risk from natural disasters such as earthquakes, fires and floods, any of which have
the potential to interrupt service, result in catastrophic loss and/or give rise to significant third-party liabilities.
Risks associated with fire damage vary depending on weather, the extent of forestation, habitation and third-party facilities located on or
near the land on which the utilities’ facilities are situated. The utilities may become liable for fire-suppression costs, regeneration and timber
value costs, and third-party claims if it is found that such facilities were responsible for a fire, and such claims, if successful, could be material.
The Corporation and its subsidiaries have limited insurance that provides coverage for business interruption, liability and property damage.
In the event of a large uninsured loss caused by severe weather conditions, natural disasters or certain other events beyond the control of
the utility, an application would be made to the respective regulatory authority for the recovery of these costs through customer rates to
offset any loss. However, there can be no assurance that the regulatory authorities would approve any such application in whole or in part.
For further details on the Corporation’s insurance coverage, refer to the insurance coverage risk discussion included in this section.
52
FORTIS INC. 2018 ANNUAL REPORTManagement Discussion and Analysis The Corporation’s electricity and gas systems require ongoing maintenance, improvement and replacement. The utilities could experience
service disruptions and increased costs if they are unable to maintain their asset base. The inability to recover, through approved customer
rates, the expenditures the utilities believe are necessary to maintain, improve, replace and remove assets; the failure by the utilities to
properly implement or complete approved capital expenditure programs; or the occurrence of significant unforeseen equipment failures,
despite maintenance programs, could have an adverse effect on the results of operations, financial condition and cash flows of the
Corporation’s utilities.
Generally, the Corporation’s utilities have designed their electricity and gas systems 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, processes and/or procedures to ensure the safety of employees, contractors and the
general public. Failure to do so may disrupt the ability of the utilities to safely generate, transmit and distribute electricity and gas, which
could have an adverse effect on the operations of the utilities, as well as harm the reputations of the Corporation and the respective utility.
Changes in energy laws, regulations or policies could have an adverse financial effect on the Corporation and its utilities.
The political, regulatory and economic environment may have an adverse effect on the regulatory process and limit the ability of the
Corporation’s utilities to increase earnings or achieve authorized rates of return. The disallowance of the recovery of costs incurred, or a
decrease in the ROE/ROA, could have an adverse effect on the Corporation’s results of operations, financial condition and cash flows. Fortis
cannot predict whether the approved rate methodologies for any of its utilities will be changed. In addition, the U.S. Congress periodically
considers enacting energy legislation that could assign new responsibilities to FERC, modify provisions of the U.S. Federal Power Act or the
Natural Gas Act, as amended, or provide FERC or another entity with increased authority to regulate U.S. federal energy matters. The Corporation
cannot predict whether, and to what extent, its utilities may be affected by changes in energy laws, regulations or policies in the future.
Failure by the Corporation’s applicable utilities to comply with required reliability standards could have an adverse financial
effect on the Corporation and its utilities.
As a result of the Energy Policy Act of 2005, owners, operators and users of the bulk electric system in the United States are subject to
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 reliability standards have also been adopted, sometimes with modifications, in certain
Canadian provinces including British Columbia, Alberta and Ontario. The standards prescribe benchmarks and measures that are designed
to ensure that the bulk electric system operates reliably. Increased reliability standard compliance obligations may cause higher operating
costs and/or capital expenditures for the Corporation’s utilities. If any of the Corporation’s utilities were found to be in violation of mandatory
reliability standards, they could also be subject to significant penalties. Both the costs of regulatory compliance and the costs that may
be imposed due to actual or alleged compliance failures could have an adverse effect on the Corporation’s results of operations, financial
condition and cash flows.
Energy sales of the Corporation’s utilities may be negatively impacted by changes in general economic, credit and market conditions.
The Corporation’s utilities are affected by energy demand in the jurisdictions in which they operate, which may change as a result of
fluctuations in general economic conditions, energy prices, employment levels, personal disposable income, and housing starts. Significantly
reduced energy demand in the Corporation’s service territories could reduce capital spending forecasts, and specifically capital spending
related to new customer growth. A reduction in capital spending would, in turn, affect the Corporation’s rate base and earnings growth.
A severe and prolonged downturn in economic conditions could have an adverse effect on the Corporation’s results of operations, financial
condition and cash flows despite regulatory measures that may be available to compensate for reduced demand. In addition, an extended
decline in economic conditions could make it more difficult for customers to pay for the electricity and gas they consume, thereby affecting
the aging and collection of the utilities’ trade receivables.
If the Corporation and/or its subsidiaries fail to arrange sufficient and cost-effective financing to fund, among other things,
capital expenditures and the repayment of maturing debt, the financial condition of the Corporation and its subsidiaries could be
adversely impacted.
The ability to arrange sufficient and cost-effective financing is subject to numerous factors, including the results of operations and financial
condition of the Corporation and its subsidiaries, the regulatory environment in which the Corporation’s utilities operate and the outcome
of regulatory decisions regarding capital structure and allowed ROEs, conditions in the capital and bank credit markets, ratings assigned by
credit rating agencies, and general economic conditions. Funds generated from operations after payment of expected expenses, including
interest payments, may not be sufficient to fund the repayment of all outstanding liabilities when due or anticipated capital expenditures.
There can be no assurance that sufficient capital will continue to be available on acceptable terms to fund capital expenditures and repay
existing debt.
53
FORTIS INC. 2018 ANNUAL REPORTManagement Discussion and Analysis Consolidated fixed-term debt maturities in 2019 are expected to total $191 million. The ability to meet long-term debt repayments when due
will be dependent on the Corporation and its subsidiaries obtaining sufficient and cost-effective financing to replace maturing indebtedness.
Activity in the global capital markets may impact the cost and timing of issuance of long-term debt by the Corporation and its subsidiaries.
Although the Corporation and its subsidiaries have been successful at raising long-term capital at reasonable rates, the cost of raising capital
could increase and there can be no assurance that the Corporation and its subsidiaries will continue to have reasonable access to capital in
the future.
Generally, the Corporation and its subsidiaries rated by credit rating agencies are subject to financial risk associated with changes in the
credit ratings assigned to them. Credit ratings affect the level of credit risk spreads on new long-term debt and credit facilities. A change
in credit ratings could potentially affect access to various sources of capital and increase or decrease finance charges of the Corporation and
its subsidiaries.
In 2018 there were no changes to the debt credit ratings of the Corporation or its subsidiaries, with the exception of S&P’s revised outlook for
the Corporation from stable to negative in March 2018 due to a modest temporary weakening of financial measures resulting from U.S. tax
reform, which reduced cash flow at the Corporation’s U.S. regulated utilities. As a result of the Corporation’s revised outlook, S&P also revised
its outlook for ITC, TEP, FortisAlberta and Caribbean Utilities. Additionally, in July 2018 Moody’s revised its outlook for Central Hudson from
stable to negative due to the impacts of U.S. tax reform and higher capital expenditures. For details on the Corporation’s credit ratings, see
the “Credit Ratings” section of this MD&A.
Additional information on the Corporation’s consolidated credit facilities, contractual obligations, including long-term debt maturities and
repayments, and consolidated cash flow requirements is provided in the “Liquidity and Capital Resources” section of this MD&A.
The Corporation is subject to risks associated with its growth strategy that may have an adverse financial effect, and actual
capital expenditures may be lower than planned.
The Corporation has a history of growth through acquisitions and 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 the Corporation may incur material unexpected costs. The Corporation’s capital expenditure program generally consists of a large
number of individually small projects; however, the Corporation and its utilities are also involved in a number of major capital projects.
Risks related to such major capital projects include delays and cost overruns. Capital expenditures at the utilities are generally approved
by the respective regulator; however, there is no assurance that any cost overruns would be approved for recovery in customer rates.
Failure to realize the expected benefits of an acquisition and/or cost overruns on major capital projects could have an adverse effect on
the Corporation’s results of operations, financial condition and cash flows.
Additionally, the Corporation’s five-year capital program and associated rate base growth are key assumptions in the Corporation’s targeted
dividend growth guidance. Actual capital expenditures may be lower than planned due to factors beyond the Corporation’s control, which
would result in a lower-than-anticipated rate base and have an adverse effect on the Corporation’s results of operations, financial condition
and cash flows. This could limit the Corporation’s ability to meet its targeted dividend growth.
Changes in tax laws could have an adverse financial effect on the Corporation and its subsidiaries.
The Corporation and its subsidiaries are subject to changes in tax legislation and tax rates in Canada, the United States and other international
jurisdictions. A change in tax legislation or tax rates could adversely affect the results of operations, financial condition and cash flows of the
Corporation and its subsidiaries.
The timing or impacts of any future changes in tax laws, including the impacts of any subsequent technical corrections to existing tax laws,
cannot be predicted. Additionally, certain aspects of U.S. tax reform are still subject to interpretation and clarification, including proposed
regulations regarding base erosion and anti-abuse tax, and certain hybrid arrangements. Therefore, there may be further impacts on the
results of operations, financial condition and cash flows of the Corporation and its U.S. utilities beyond those described herein.
Cybersecurity breaches, acts of war or terrorism, grid disturbances or security breaches involving the misappropriation of
sensitive, confidential and proprietary customer, employee, financial or system operating information could significantly
disrupt the business operations of the Corporation and its subsidiaries and have an adverse effect on its reputation.
As operators of critical energy infrastructure, the Corporation’s utilities face a heightened risk of cyber-attacks. Despite risk-based
cybersecurity programs that 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, and other causes that can result in service disruptions,
system failures, and the disclosure, deliberate or inadvertent, of confidential business, customer and employee information. The ability
of the Corporation’s utilities to operate effectively is dependent upon developing and maintaining complex information systems and
infrastructure that support the operation of generation, transmission and distribution facilities; provide customers with billing, consumption
and load settlement information, where applicable; and support the financial and general operating aspects of the business.
54
FORTIS INC. 2018 ANNUAL REPORTManagement Discussion and Analysis In the event the Corporation’s utilities’ information or operations technology systems are breached, service disruptions, property damage,
and corruption or unavailability of critical data or confidential employee or customer information could result. 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 financial impact of a material breach in cybersecurity, acts of war or terrorism could be
material and may not be covered by insurance policies or, in the case of utilities, through regulatory cost recovery.
The Corporation’s utilities are impacted by variability in weather due to seasonality and weather changes that affect water flows,
which could have an adverse financial effect on the Corporation and its utilities.
Fluctuations in the amount of electricity used by customers can vary significantly in response to seasonal changes in weather and
could impact the results of operations, financial condition and cash flows of the electric utilities. 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 electric heating load. Alternatively, severe weather could unexpectedly increase heating and cooling load, negatively impacting
system reliability.
At the Corporation’s gas utilities, weather has a significant impact on gas distribution volumes as a major portion of the gas distributed
is ultimately used for space heating for residential customers. Because of gas consumption patterns, the gas utilities normally generate
quarterly earnings that vary by season and may not be an indicator of annual earnings. The earnings associated with the Corporation’s gas
utilities are highest in the first and fourth quarters.
Regulatory deferral mechanisms are in place at certain of the Corporation’s utilities to minimize the volatility in earnings that would otherwise
be caused by variations in weather conditions. The absence of these regulatory deferral mechanisms could have an adverse effect on the
results of operations, financial condition and cash flows of the Corporation and its utilities.
Earnings from non-regulated generation assets in Belize and British Columbia are sensitive to rainfall levels and the related impact on
water flows. Hydrologic risk associated with hydroelectric generation at the Waneta Expansion and FortisBC Electric is reduced by the
Canal Plant Agreement, under which fixed energy and capacity entitlements will be received based upon long-term average water flows.
Prolonged adverse weather conditions, however, could lead to a significant and sustained loss of precipitation over the headwaters of the
Kootenay River system, which could reduce the entitlement of the Waneta Expansion and FortisBC Electric to capacity and energy under
the Canal Plant Agreement.
The Corporation’s risk management policies cannot fully eliminate the risk associated with commodity price movements, which
may have an adverse financial effect on the Corporation and its utilities.
The Corporation’s utilities have exposure to long-term and short-term commodity price volatility, including changes in the market price of
gas and world oil prices, which affect the cost of fuel, coal and purchased power. The risk of price volatility is substantially mitigated by the
utilities’ ability to flow through to customers the cost of gas, fuel and purchased power through base rates and/or the use of rate-stabilization
and other mechanisms, as approved by the various regulatory authorities. The ability to flow through energy supply cost to customers
alleviates the effect on earnings of commodity price volatility. This risk has also been reduced by entering into various price-risk management
strategies to reduce exposure to changing commodity rates, including the use of derivative contracts that effectively fix the price of gas, fuel
sources and electricity purchases. The inability to utilize such hedging mechanisms in the future could result in increased exposure to market
price volatility.
There can be no assurance that the current regulator-approved mechanisms allowing for the flow through of energy supply cost will continue
to exist in the future. Also, a severe and prolonged increase in such costs could have an adverse effect on the Corporation’s utilities, despite
regulatory measures available to compensate for changes in these costs. The inability of the regulated utilities to flow through the full
amount of energy supply cost could have an adverse effect on the utilities’ results of operations, financial condition and cash flows.
Increased foreign exchange exposure may have an adverse effect on the Corporation’s earnings and the value of its assets.
A significant portion of the Corporation’s assets, earnings and cash flows are denominated in US dollars. The reporting currency of ITC,
UNS Energy, Central Hudson, Caribbean Utilities, FortisTCI and BECOL is the US dollar. The earnings from, and net investments in, foreign
subsidiaries are exposed to fluctuations in the US dollar-to-Canadian dollar exchange rate. Although the Corporation has limited this
exposure through the use of US dollar-denominated borrowings at the corporate level, such actions are not expected to completely mitigate
this exposure. The foreign exchange gain or loss on the translation of US dollar-denominated interest expense partially offsets the foreign
exchange gain or loss on the translation of the Corporation’s foreign subsidiaries’ earnings. As at December 31, 2018, the Corporation’s
corporately issued US$3,441 million (December 31, 2017 – US$3,385 million) long-term debt had been designated as an effective hedge
of a portion of the Corporation’s foreign net investments. As at December 31, 2018, the Corporation had approximately US$7,970 million
(December 31, 2017 – US$7,548 million) in foreign net investments that were unhedged.
55
FORTIS INC. 2018 ANNUAL REPORTManagement Discussion and Analysis Consolidated earnings and cash flows of Fortis are impacted by fluctuations in the US dollar-to-Canadian dollar exchange rate. On an annual
basis, it is estimated that a 5 cent increase or decrease in the US dollar relative to the Canadian dollar exchange rate of US$1.00=CAD$1.36
as at December 31, 2018 would increase or decrease earnings per common share of Fortis by approximately 6 cents, which reflects a
hedging program implemented in 2017.
The Corporation entered into foreign exchange contracts to manage a portion of its exposure to foreign currency risk. There is no guarantee
that such hedging strategies will be effective. In addition, currency hedging entails a risk of liquidity and, to the extent that the US dollar
depreciates against the Canadian dollar, such hedges could result in losses greater than if hedging had not been used. Hedging arrangements
could 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.
The Corporation and certain of its subsidiaries are subject to counterparty default risk and credit risk associated with
amounts owing from customers and counterparties to derivatives. Any non-payment or non-performance by customers of
the Corporation’s subsidiaries or the derivative counterparties could have an adverse financial effect on the Corporation and
these applicable subsidiaries.
ITC derives approximately 70% of its revenue from the transmission of electricity to three primary customers. While such customers have
investment-grade credit ratings, any failure by such customers to make payments for transmission services could have an adverse effect on
ITC’s results of operations, financial condition and cash flows.
FortisAlberta has a concentration of credit risk as a result of its distribution service billings being to a relatively small group of retailers.
FortisAlberta reduces its credit risk exposure by obtaining from the retailers either a cash deposit, bond, letter of credit or an investment-grade
credit rating from a major rating agency, or a financial guarantee from an entity with an investment-grade credit rating.
UNS Energy, Central Hudson, FortisBC Energy, Aitken Creek and the Corporation may be exposed to credit risk in the event of non-performance
by counterparties to derivatives. Netting arrangements are used to reduce credit risk and net settle payment with counterparties where
net settlement provisions exist. Credit risk is limited by primarily dealing with counterparties that have investment-grade credit ratings.
Non-performance by counterparties could have an adverse effect on the results of operations, financial condition and cash flows of the
Corporation and these applicable subsidiaries.
The competitiveness of gas relative to alternative energy sources could have an adverse financial effect on the Corporation.
If the gas sector becomes less competitive due to pricing or other factors, this could have an adverse effect on the Corporation’s utilities that
are involved in gas distribution and sales. In British Columbia gas primarily competes with electricity for space and hot water heating load. In
addition to other price comparisons, upfront capital costs between electric and gas equipment for hot water and space heating applications
continue to present challenges for the competitiveness of gas on a full-cost basis. In addition, if gas becomes less competitive, the ability
to add new customers could be impaired, and existing customers could reduce their consumption of gas or eliminate its use altogether
as furnaces, water heaters and other appliances are replaced. Such conditions may result in higher customer rates and, in an extreme case,
could ultimately lead to an inability of the Corporation’s gas utilities to fully recover COS in rates charged to customers.
Government policy has also impacted the competitiveness of gas in British Columbia. The Government of British Columbia has introduced
changes to energy policy, including greenhouse gas emission reduction targets and a consumption tax on carbon-based fuels. The
Government of British Columbia has yet to introduce a carbon tax on imported electricity generated through the combustion of
carbon-based fuels. The impact of these changes in energy policy may impact the competitiveness of gas relative to non-carbon-based
or other energy sources.
There are other competitive challenges impacting the penetration of gas in new housing supply, such as the green attributes of the energy
source and the type of housing being built. In addition, municipal and other government policy may regulate or restrict the energy source
permitted in new and existing developments.
A disruption in the wholesale energy markets or failure by an energy or fuel supplier could have an adverse financial effect on the
Corporation and its utilities.
A significant portion of the electricity and gas that the Corporation’s utilities sell to full-service customers is purchased through the wholesale
energy markets or pursuant to contracts with energy suppliers. 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 utilities, could adversely affect such utilities’ ability
to meet their customers’ energy needs and the Corporation’s results of operations, financial condition and cash flows.
56
FORTIS INC. 2018 ANNUAL REPORTManagement Discussion and Analysis Pension and post-retirement benefit plans could require significant future contributions to such plans.
Fortis and the majority of its subsidiaries maintain a combination of defined benefit pension and/or other post-employment benefit (“OPEB”)
plans for certain of their employees and retirees. The most significant cost drivers of these benefit plans are investment performance and
interest rates, which are affected by global financial and capital markets. Financial market disruptions and significant declines in the market
values of the investments held to meet the pension and post-retirement obligations, discount rate assumptions, participant demographics
and increasing longevity, and changes in laws and regulations may require the Corporation and its utilities to make significant funding
contributions to the plans. Large funding requirements or significant increases in expenses could adversely impact the results of operations,
financial condition and cash flows of the Corporation’s utilities.
Certain generation assets of the Corporation’s utilities are jointly owned with, or are operated by, third parties. Therefore, the
utilities may not have the ability to affect the management or operations at such facilities, which could have an adverse financial
effect on the Corporation and these utilities.
Certain of the 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 and, therefore, may not be able to ensure the
proper management of the operations and maintenance of the generating facilities. Further, TEP may have no or limited ability to make
determinations on how best to manage the changing economic conditions or environmental requirements that may affect such facilities.
A divergence in the interests of TEP and the co-owners or operators, as applicable, of such generating facilities could negatively impact
TEP’s results of operations, financial condition and cash flows.
Advances in technology could impair or eliminate the competitive advantage of the Corporation’s utilities.
The emergence of initiatives designed to reduce greenhouse gas 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 have a significant impact on retail
sales, which could negatively impact the results of operations, financial condition and cash flows of the Corporation’s utilities. Heightened
awareness of energy costs and environmental concerns have increased demand for products intended to reduce consumers’ use of
electricity. The Corporation’s utilities are promoting demand-side management programs designed to help customers reduce their energy
usage. These technologies include energy derived from renewable energy sources, customer-owned generation, appliances, battery
storage, equipment and control systems. Advances in these or other technologies could have a significant impact on retail sales, which
could have an adverse effect on the results of operations, financial condition and cash flows of the Corporation’s utilities.
Environmental risks, including the effects of contamination of air, soil or water from hazardous substances, natural gas leaks and
hazardous or toxic emissions from the combustion of fuel required in the generation of electricity could cause the Corporation
and its utilities to incur significant financial losses.
The Corporation’s electric and gas utilities are subject to environmental risks, including the responsibility for remediation of contaminated
properties, whether or not such contamination was actually caused by the utility at the time it was the property owner. The risk of
contamination of air, soil and water at the electric utilities primarily relates to: (i) the transportation, handling and storage of large volumes of
fuel; (ii) the use of petroleum-based products, mainly transformer and lubricating oil, in the utilities’ day-to-day operating and maintenance
activities; (iii) hazardous or toxic emissions from the combustion of fuel required in the generation of electricity; and (iv) management and
disposal of coal combustion residuals and other wastes. The risk of contamination of air, soil or water at the gas utilities primarily relates to
gas and propane leaks and other accidents involving these substances.
Liabilities relating to investigation and remediation of contamination, as well as claims for personal injury or property damage, may arise at many
locations, including formerly owned or operated properties and sites where wastes have been treated or disposed of, as well as properties
the utilities currently own or operate. Such liabilities may arise even where the contamination does not result from non-compliance with
applicable environmental laws. Under a number of environmental laws, such liabilities may also be joint and several, meaning that a party
can be held responsible for more than its share of the liability involved, or even the entire liability. Additional risks include accidents resulting
in hazardous release at or from coal mines that supply generating facilities in which the Corporation’s utilities have an ownership interest.
The key environmental hazards related to hydroelectric generation operations include the creation of artificial water flows that may disrupt
natural habitats and any failure of containment of large volumes of water for the purpose of electricity generation. Such inherent environmental
risks could subject the Corporation and its utilities to litigation and administrative proceedings that could result in substantial monetary
judgments for clean-up costs, damages, fines or penalties. To the extent that the occurrence of any of these events is not fully covered by
insurance, they could adversely affect the utilities’ results of operations, financial condition and cash flows.
57
FORTIS INC. 2018 ANNUAL REPORTManagement Discussion and Analysis Furthermore, the Corporation’s electric and gas utilities are subject to United States and Canadian federal, state and provincial environmental
laws and regulations, including those which impose limitations or restrictions on the discharge of pollutants into the air and water, establish
standards for the management, treatment, storage, transportation and disposal of solid and hazardous wastes and hazardous materials, and
impose obligations to investigate and remediate contamination in certain circumstances. The Corporation’s utilities have incurred expenses
in connection with environmental compliance, and they anticipate that they will continue to do so in the future. Increased compliance costs
or additional operating restrictions from revised or additional regulation could have a negative effect on the Corporation’s and its utilities’
results of operations, financial condition and cash flows.
In particular, the management of greenhouse gas emissions is a concern for the Corporation’s regulated utilities in the United States and
Canada, primarily due to new and emerging federal, state and provincial greenhouse gas laws, regulations and guidelines. For example,
in 2015, the federal government in the United States issued the Clean Power Plan, which would regulate greenhouse gas emissions from
existing fossil fuel-fired generating units. In 2017 the Environmental Protection Agency signed a proposal to repeal the Clean Power Plan and
has not determined whether or not a replacement rule will be issued. The utilities continue to develop compliance strategies and assess the
impact that such legislative changes may have on future operations, as well as the costs to comply with these potential new requirements.
However, due to the significant current uncertainties related to federal and state regulation of greenhouse gas emissions in the United States,
the ultimate financial and operational impact of such regulation cannot be determined at this time.
Some of the coal-fired generating facilities from which the utilities obtain power will be closed before the end of their useful lives in response
to economic conditions and/or recent or future changes in environmental regulation, including potential regulation relating to greenhouse
gas emissions. If such early closures occur, the utility may need to seek from its regulator the recovery of any remaining net book value and
could incur additional expenses relating to accelerated depreciation and amortization, decommissioning and cancellation of long-term
coal contracts of such generating facilities. Any unrecovered costs, if substantial, could have an adverse effect on the results of operations,
financial condition and cash flows of the Corporation’s utilities.
The Corporation and its subsidiaries are not able to insure against all potential risks and may become subject to loss of coverage,
higher insurance premiums and failure by insurers to satisfy eligible claims.
The Corporation and its subsidiaries maintain insurance with respect to potential liabilities and the accidental loss of value of certain of their
physical assets, for amounts and with such insurers as is considered appropriate, taking into account all relevant factors, including practices
of owners of similar assets and operations. However, a significant portion of the Corporation’s regulated electric utilities’ transmission and
distribution assets are not covered under insurance, as is customary in North America, as the cost of coverage is not considered economically
viable. Insurance is subject to coverage limits as well as time-sensitive claims discovery and reporting provisions and there can be no assurance
that the types of liabilities that may be incurred by the Corporation and its subsidiaries will be covered by insurance. The Corporation’s
utilities would likely apply to their respective regulatory authority to recover any loss or liability through increased customer rates. However,
there can be no assurance that a regulatory authority would approve any such application in whole or in part. Any major damage to the
physical assets of the Corporation and its subsidiaries could result in repair costs, loss of revenue and customer claims that are substantial
in amount and could have an adverse effect on the Corporation’s results of operations, financial position and cash flows. In addition,
the occurrence of significant uninsured claims, claims in excess of the insurance coverage limits maintained by the Corporation and its
subsidiaries, or material damage that is self-insured, could have an adverse effect on the Corporation’s results of operations, financial
position and cash flows.
It is anticipated that insurance coverage will be maintained. However, there can be no assurance that the Corporation and its subsidiaries will
be able to obtain or maintain adequate insurance in the future at rates considered reasonable, that insurance will continue to be available
on terms as favourable as the existing arrangements or that the insurance companies will meet their obligations to pay claims.
Certain of the Corporation’s regulated utilities and non-regulated energy infrastructure operations may not be able to obtain or
maintain all required approvals.
The acquisition, ownership and operation of electric and gas utilities and assets require numerous licences, permits, agreements, orders,
approvals and certificates from various levels of government, government agencies and/or third parties. For various reasons, including
increased stakeholder participation, the Corporation’s regulated utilities and non-regulated energy infrastructure operations may not be able
to obtain or maintain all required approvals. If there is a delay in obtaining any required approvals, failure to obtain or maintain any required
approvals, failure to comply with any applicable law, regulation or condition of an approval, or material change to any required approval,
the operation of the assets and the sale of electricity and gas could be prevented or become subject to additional costs, any of which could
have an adverse effect on the results of operations, financial condition and cash flows of the Corporation and its utilities.
58
FORTIS INC. 2018 ANNUAL REPORTManagement Discussion and Analysis Increased external stakeholder activism could have an adverse effect on the Corporation’s ability to execute capital
expenditure programs.
External stakeholders are increasingly challenging investor-owned utilities in the areas of climate change, sustainability, diversity, utility
ROEs and executive compensation. In addition, public opposition to larger infrastructure projects is becoming increasingly common, which
can challenge a utility’s ability to execute capital expenditure programs. While the Corporation is actively monitoring such activism and
is committed to developing stronger relationships with its external stakeholders, failure to effectively respond to public opposition may
adversely affect the Corporation’s capital expenditure programs and, therefore, future organic growth, which could adversely affect its
results of operations, financial condition and cash flows.
Certain of the Corporation’s subsidiaries have facilities and provide limited services on lands that are subject to land claims by
various Indigenous Peoples, which may subject the utilities to various legal, administrative and land-use proceedings.
The Corporation’s utilities in British Columbia provide service to customers on Indigenous Peoples’ lands and maintain gas facilities and
electric generation, transmission and distribution facilities on lands that are subject to land claims by various Indigenous Peoples. A treaty
negotiation process involving various Indigenous Peoples and the Governments of British Columbia and Canada is underway, but the basis
upon which settlements might be reached in the Corporation’s service territories is not clear. Furthermore, 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 rights held by third parties. However, there can be no certainty that the settlement process will not have an adverse effect on the
results of operations, financial condition and cash flows of the Corporation’s utilities in British Columbia.
The Corporation has distribution assets on Indigenous Peoples’ lands in Alberta with access permits to these lands held by TransAlta Utilities
Corporation (“TransAlta”). In order for FortisAlberta to acquire these access permits, both the Department of Aboriginal Affairs and Northern
Development Canada and the individual Indigenous Peoples’ band councils must grant approval. FortisAlberta may be unable to acquire the
access permits from TransAlta and may be unable to negotiate land-use agreements with property owners or, if negotiated, such agreements
may be on terms that are less than favourable to FortisAlberta and, therefore, may have an adverse effect on FortisAlberta.
The Corporation’s utilities face the risk of strikes, work stoppages or an inability to negotiate future collective bargaining
agreements on commercially reasonable terms.
Most of the Corporation’s utilities employ members of labour unions or associations that have entered into collective bargaining agreements
with the utilities. The Corporation considers the relationships of its utilities with their labour unions and associations to be satisfactory
but there can be no assurance that current relations will continue in the future or that the terms under the present collective bargaining
agreements will be renewed. The inability to maintain or renew the collective bargaining agreements on acceptable terms could result in
increased labour costs or service interruptions arising from labour disputes that are not provided for in approved rate orders at the regulated
utilities and which could have an adverse effect on the results of operations, financial condition and cash flows of the Corporation’s utilities.
The Corporation’s utilities may suffer the loss of key personnel or the inability to hire and retain qualified employees.
The ability of Fortis to deliver service in a cost-effective manner is dependent on the ability of the Corporation’s utilities to attract, develop
and retain skilled workforces. Like other utilities across Canada, the United States and the Caribbean, the Corporation’s utilities are faced with
demographic challenges relating to trades, technical staff and engineers. The growing size of the Corporation and a competitive job market
present ongoing recruitment challenges. The Corporation’s significant consolidated capital expenditure program will present challenges to
ensuring the Corporation’s utilities have the qualified workforce necessary to complete the capital work initiatives.
ITC enters into various agreements and arrangements with third parties to provide services for construction, maintenance and operation
of certain aspects of its business, which, if terminated, could result in a shortage of a readily available workforce to provide these services.
If any of these agreements or arrangements is terminated for any reason, ITC may face difficulty finding a qualified replacement workforce
to provide such services, which could have an adverse effect on the ability of ITC to carry on its business and on its results of operations.
The Corporation and its subsidiaries are subject to litigation or administrative proceedings.
The Corporation and its subsidiaries have been and continue to be involved in legal proceedings, administrative proceedings, claims and
other litigation that arise in the ordinary course of business. These actions may include environmental claims, employment-related claims,
securities-based litigation and contractual disputes or claims for personal injury or property damage that occurs in connection with services
performed relating to the operation of the utilities, or actions by regulatory or tax authorities. Unfavourable outcomes or developments
relating to these proceedings or future proceedings, such as judgments for monetary damages, injunctions, denial or revocation of permits
or settlement of claims, could have an adverse effect on the results of operations, financial condition and cash flows of the Corporation
and its subsidiaries.
59
FORTIS INC. 2018 ANNUAL REPORTManagement Discussion and Analysis CHANGES IN ACCOUNTING POLICIES
Revenue Recognition
Effective January 1, 2018, Fortis adopted ASC 606, Revenue from Contracts with Customers, which clarifies the principles for recognizing revenue
and requires additional disclosures. Fortis adopted this standard using the modified retrospective approach, under which comparative periods
are not restated and the cumulative impact is recognized at the date of adoption, supplemented by additional disclosures. Upon adoption,
there were no adjustments to the opening balance of retained earnings.
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.
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. Prior to the adoption of ASC 606, Central Hudson recognized sales tax
and FortisAlberta recognized municipal tax on a gross basis in both revenue and expense. The exclusion of these taxes from revenue resulted
in a decrease in revenue of $49 million for 2018 compared to 2017.
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 will be less than one year.
Revenue is disaggregated by geography, regulatory status, and substantially autonomous utility operations, as discussed in Note 5 of the
2018 Annual Financial Statements. This represents the level of disaggregation used by the Corporation’s President and Chief Executive Officer
to allocate resources and evaluate performance.
Financial Instruments
Effective January 1, 2018, the Corporation adopted Accounting Standards Update (“ASU”) No. 2016-01, Recognition and Measurement of
Financial Assets and Financial Liabilities. Principally, it requires: (i) equity investments in unconsolidated entities not accounted for using the
equity method to be measured at fair value through earnings; however, entities may elect to record equity investments without readily
determinable fair values at cost, less impairment, and plus or minus subsequent adjustments for observable price changes; and (ii) financial
assets and liabilities to be presented separately in the financial statement notes, grouped by measurement category and form. Adoption
did not impact the consolidated financial statements.
Pension and Post-Retirement Benefit Costs
Effective January 1, 2018, the Corporation adopted ASU No. 2017-07, Improving the Presentation of Net Periodic Pension Cost and Net Periodic
Post-Retirement Benefit Cost, which requires current service costs to be grouped in the statement of earnings with other employee
compensation costs arising from services rendered. The remaining components of net periodic benefit costs must be presented separately
and outside of operating income. Additionally, only the service cost component can be capitalized. On adoption, the Corporation applied
the presentation guidance retrospectively and the capitalization guidance prospectively. This resulted in a retrospective $11 million
reclassification from Operating Expenses to Other Income, Net in the consolidated financial statements.
60
FORTIS INC. 2018 ANNUAL REPORTManagement Discussion and Analysis FUTURE ACCOUNTING PRONOUNCEMENTS
Leases
ASU No. 2016-02, Leases (“ASC 842”), issued in February 2016, was effective for Fortis January 1, 2019 and is to be applied using a modified
retrospective approach or an optional transition method with implementation options, referred to as practical expedients. Principally,
it requires balance sheet recognition of a right-of-use asset and a lease liability by lessees for those leases that are classified as operating
leases, along with additional disclosures.
Fortis has selected the optional transition method, which allows entities to continue to apply the current lease guidance in the comparative
periods presented in the year of adoption and apply the transition provisions of the new guidance on the effective date of the new guidance.
Fortis elected a package of practical expedients that allowed it to not reassess the lease classification of existing leases or whether existing
contracts, including land easements, are or contain a lease. Finally, Fortis utilized the hindsight practical expedient to determine the lease term.
Upon adoption, Fortis will recognize right-of-use assets and corresponding lease liabilities of approximately $50 million for operating leases
primarily related to office facilities and utility property. Operating leases related to vehicles and office equipment were identified and quantified
as immaterial. Fortis has not identified an adjustment to opening retained earnings, and there will be no impact on earnings or cash flows.
Fortis implemented changes to processes and control activities related to monitoring the adoption of ASC 842 and made changes to
accounting policies associated with accounting for lease assets and liabilities, and related income and expense, as of January 1, 2019.
Financial Instruments
ASU No. 2016-13, Measurement of Credit Losses on Financial Instruments, issued in June 2016, is effective for Fortis January 1, 2020 and is to
be applied on a modified retrospective basis. Principally, it requires entities to use an expected credit loss methodology and to consider a
broader range of reasonable and supportable information to estimate credit losses. The adoption of this ASU will not have a material impact
on the consolidated financial statements and related disclosures.
Hedging
ASU No. 2017-12, Targeted Improvements to Accounting for Hedging Activities, issued in August 2017, was effective for Fortis January 1, 2019.
Principally, it better aligns risk management activities and financial reporting for hedging relationships through changes to designation,
measurement, presentation and disclosure guidance. For cash flow and net investment hedges that existed at the date of adoption, the
amendments were applied as a cumulative-effect adjustment related to eliminating the separate measurement of ineffectiveness to
accumulated other comprehensive income with a corresponding adjustment to opening retained earnings. Amended presentation and
disclosure guidance was applied prospectively. The adoption of this ASU did not have a material impact on the consolidated financial
statements and related disclosures.
Fair Value Measurement Disclosures
ASU No. 2018-13, Changes to the Disclosure Requirements for Fair Value Measurement, issued in August 2018, is effective for Fortis January 1, 2020
and is to be primarily applied on a retrospective basis, with certain disclosures requiring prospective application. Principally, it improves
the effectiveness of financial statement note disclosures by clarifying what is required and important to users of the financial statements.
In addition, the amendment removes (a) the amount of, and reasons for, transfers between level 2 and level 3 of the fair value hierarchy,
(b) the policy for timing of transfers between levels, and (c) the valuation processes for level 3 fair value measurements. Fortis does not
expect the adoption of this ASU to have a material impact on the related disclosures.
Pensions and Other Post-Retirement Plan Disclosures
ASU No. 2018-14, Changes to the Disclosure Requirements for Defined Benefit Plans, issued in August 2018, is effective for Fortis January 1, 2021
and is to be applied on a retrospective basis for all periods presented. Principally, it modifies the disclosure requirements for employers with
defined pension or other post-retirement plans and clarifies disclosure requirements. In addition, the amendments remove (a) the amounts
in accumulated other comprehensive income expected to be recognized as components of net period benefit costs over the next fiscal
period, (b) the amount and timing of plan assets expected to be returned to the employer, and (c) 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. Fortis does not expect the adoption of this ASU to have a material impact on the related disclosure.
61
FORTIS INC. 2018 ANNUAL REPORTManagement Discussion and Analysis FINANCIAL INSTRUMENTS
Excluding long-term debt, the consolidated carrying value of the Corporation’s financial instruments approximates fair value, reflecting their
short-term maturity, normal trade credit terms and/or nature.
As at December 31, 2018, the carrying value of long-term debt, including the current portion, was $24,231 million (December 31, 2017 –
$21,535 million) compared to an estimated fair value of $25,110 million (December 31, 2017 – $23,481 million).
The fair value of long-term debt is calculated using quoted market prices or, when unavailable, by either: (i) discounting the associated future
cash flows at an estimated yield to maturity equivalent to benchmark government bonds or treasury bills with similar terms to maturity,
plus a credit risk premium equal to that of issuers of similar credit quality; or (ii) obtaining from third parties indicative prices for the same
or similarly rated issues of debt with similar maturities. Since the Corporation does not intend to settle the long-term debt prior to maturity,
the excess of the estimated fair value above the carrying value does not represent an actual liability.
The following table presents the fair value of the assets and liabilities that are accounted for at fair value on a recurring basis.
(in millions)
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)
Total assets
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 (6)
Total liabilities
As at December 31, 2017
Assets
Energy contracts subject to regulatory deferral (2) (3)
Energy contracts not subject to regulatory deferral (2)
Foreign exchange contracts (6)
Other investments (4)
Total assets
Liabilities
Energy contracts subject to regulatory deferral (3) (5)
Energy contracts not subject to regulatory deferral (5)
Interest rate and total return swaps (6)
Total liabilities
Level 1(1)
Level 2(1)
Level 3(1)
Total
$
$
$
$
$
$
$
$
–
–
155
155
–
–
(8)
(8)
–
–
3
78
81
(1)
–
–
(1)
$
$
$
$
$
$
$
$
33
13
–
46
(86)
(1)
(1)
(88)
19
26
–
–
45
(103)
–
(1)
(104)
$
$
$
$
$
$
$
$
8
3
–
11
(3)
–
–
(3)
2
4
–
–
6
(2)
(1)
–
(3)
$
$
$
$
$
41
16
155
212
(89)
(1)
(9)
(99)
21
30
3
78
$
132
$
$
(106)
(1)
(1)
(108)
(1) Under the hierarchy, fair value is determined using: (i) level 1 – unadjusted quoted prices in active markets; (ii) level 2 – other pricing inputs directly or indirectly observable in
the marketplace; and (iii) level 3 – unobservable inputs, used when observable inputs are not available. Classifications reflect the lowest level of input that is significant to the
fair value measurement.
(2) Included in 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, with the exception of long-term wholesale trading contracts and certain gas swap contracts.
(4) Included in other assets
(5) Included in accounts payable and other current liabilities or other liabilities
(6) Included in accounts receivable and other current assets, accounts payable and other current liabilities or other liabilities
62
FORTIS INC. 2018 ANNUAL REPORTManagement Discussion and Analysis
Derivatives
The Corporation generally limits the use of derivatives to those that qualify as accounting, economic or cash flow hedges, or those that are
approved for regulatory recovery.
The Corporation records all derivatives at fair value, with certain exceptions, including those derivatives that qualify for the normal purchase
and normal sale exception. Fair values reflect estimates based on current market information about the derivatives as at the balance sheet
dates. The estimates cannot be determined with precision as they involve uncertainties and matters of judgment and, therefore, may not be
relevant in predicting the Corporation’s future consolidated earnings or cash flows.
Energy contracts subject to regulatory deferral
UNS Energy holds electricity power purchase 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 financial 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, 2018, unrealized losses of $57 million
(December 31, 2017 – $87 million) were recognized as regulatory assets and unrealized gains of $9 million (December 31, 2017 – $2 million)
were recognized in regulatory liabilities.
Energy contracts not subject to regulatory deferral
UNS Energy holds wholesale trading contracts that qualify as derivatives to fix power prices and realize potential margin, of which 10% of
any realized gains are shared with customers through rate stabilization accounts. Fair values were measured using a market approach using
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 earnings. During 2018 unrealized
losses of $12 million (2017 – unrealized gains of $36 million) were recognized in revenue.
Foreign exchange contracts
The Corporation holds US dollar foreign exchange contracts to mitigate exposure to volatility of foreign exchange rates. The contracts expire
in 2019 and have a combined notional amount of $161 million. Fair value was measured using independent third-party information.
Unrealized gains and losses associated with changes in fair value are recognized in earnings. During 2018 unrealized losses of $11 million
(2017 – unrealized gains of $3 million) were recognized in other income, net.
Interest rate and total return swaps
UNS Energy holds an interest rate swap to mitigate exposure to volatility in variable interest rates on capital lease obligations. The swap expires
in 2020 and has a notional amount of $16 million. Fair value was measured using an income valuation approach based on six-month LIBOR.
Unrealized gains and losses associated with changes in the fair value of this interest rate swap, which was designated as a cash flow hedge,
are recognized in other comprehensive income and reclassified to earnings through interest expense over the life of the hedged debt.
The loss expected to be reclassified to earnings within the next 12 months is estimated to be approximately $3 million, net of tax.
The Corporation holds three 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 $41 million and terms ranging from one to three
years, expiring in January 2019, 2020 and 2021. Fair value was measured using an income valuation approach based on forward pricing curves.
Unrealized gains and losses associated with changes in the fair value of the total return swaps are recognized in earnings. During 2018
unrealized gains of less than $1 million (2017 – unrealized losses of less than $1 million) were recognized in other income, net.
63
FORTIS INC. 2018 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 and losses on these funds are recognized in earnings. During 2018 unrealized gains of less than $1 million (2017 – unrealized
gains of less than $1 million) were recognized in other income, net.
Volume of Derivative Activity
As at December 31, 2018, 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.
Volume
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)
2018
774
651
203
266
1,440
37
2017
1,291
761
216
219
2,387
36
CRITICAL ACCOUNTING ESTIMATES
The preparation of the Corporation’s consolidated financial statements in accordance with US GAAP requires management to make estimates
and judgments that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date
of the consolidated financial statements, and the reported amounts of revenue and expenses during the reporting periods. Estimates and
judgments are based on historical experience, current conditions and various other assumptions believed to be reasonable under the
circumstances. Due to changes in facts and circumstances, and the inherent uncertainty involved in making estimates, actual results may differ
significantly from current estimates. Estimates and judgments are reviewed periodically and, as adjustments become necessary, they are
recognized in earnings in the period in which they become known. The Corporation’s critical accounting estimates are discussed as follows.
Regulation
Generally, the accounting policies of the Corporation’s regulated utilities are subject to examination and approval by the respective
regulatory authority. Regulatory assets and liabilities arise as a result of the rate-setting process and have been recognized based on previous,
existing or expected regulatory orders or decisions. Certain estimates are necessary since the regulatory environments in which the
Corporation’s regulated utilities operate often require amounts to be recognized at estimated values until these amounts are finalized
pursuant to regulatory decisions or other regulatory proceedings. The final amounts approved by the regulatory authorities for deferral
as regulatory assets and regulatory liabilities and the approved recovery or settlement periods may differ from those originally expected.
Any resulting adjustments to original estimates are recognized in earnings in the period in which they become known. In the event that
a regulatory decision is received after the balance sheet date but before the consolidated financial statements are issued, the facts and
circumstances are reviewed to determine whether or not it is a recognized subsequent event.
As at December 31, 2018, Fortis recognized a total of $3.2 billion in regulatory assets (December 31, 2017 – $3.0 billion) and $3.6 billion
in regulatory liabilities (December 31, 2017 – $3.4 billion). For further discussion of the nature of regulatory decisions, refer to the
“Consolidated Financial Position” section of this MD&A.
Depreciation and Amortization
Depreciation and amortization are estimates based primarily on the useful life of assets. Estimated useful lives are based on current facts
and historical information and take into consideration the anticipated physical life of the assets. As at December 31, 2018, the Corporation’s
consolidated property, plant and equipment and intangible assets were approximately $33.9 billion, or approximately 64% of total consolidated
assets (December 31, 2017 – $30.7 billion, or approximately 64% of total consolidated assets). Depreciation and amortization was $1.2 billion
for 2018 (2017 – $1.2 billion).
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 against which actual asset removal costs are netted when incurred.
The estimate of asset removal costs is based on historical experience and expected cost trends. The balance of this regulatory liability as at
December 31, 2018 was $1.2 billion (December 31, 2017 – $1.1 billion).
Changes in depreciation rates resulting from a change in the estimated service life or removal costs could have a significant impact on the
Corporation’s consolidated depreciation and amortization expense.
64
FORTIS INC. 2018 ANNUAL REPORTManagement Discussion and Analysis
As part of the customer rate-setting process, appropriate depreciation, amortization and removal cost rates are approved by the respective
regulatory authority. The depreciation periods used and the associated rates are reviewed on an ongoing basis to ensure they continue
to be appropriate. From time to time, third-party depreciation studies are performed at the regulated utilities. Based on the results of these
depreciation studies, the impact of any over- or under-depreciation as a result of actual experience differing from that expected and
provided for in previous depreciation rates is generally reflected in future depreciation rates and depreciation expense, when the differences
are refunded or collected in customer rates, as approved by the regulator.
Capitalized Overhead
Most of the Corporation’s utilities capitalize overhead costs that are not directly attributable to specific property, plant and equipment
but relate to the overall capital expenditure program. The methodology for calculating and allocating capitalized general overhead costs
to property, plant and equipment is established by the utilities’ respective regulator. Any change in the methodology of calculating and
allocating general overhead costs could have a material impact on the amount recognized as operating expenses versus property, plant
and equipment.
Assessment for Impairment of 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 that is determined to be the case, 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 primary method for estimating
the fair value of reporting units is the income approach, whereby net cash flow projections for the reporting units are discounted using an
enterprise value method. The income approach uses underlying estimates and assumptions with varying degrees of uncertainty, including
the amount and timing of expected future cash flows, growth rates, and discount rates.
A secondary valuation method, the market approach, as well as a reconciliation of the total estimated fair value of all reporting units to the
Corporation’s market capitalization, is also performed and compared to the results of the income approach.
As at December 31, 2018, consolidated goodwill totalled approximately $12.5 billion (December 31, 2017 – $11.6 billion). The increase in
goodwill was due to the impact of foreign exchange associated with the translation of US dollar-denominated goodwill. No goodwill
impairment was recognized in 2018 or 2017.
Income Tax Expense
Income tax expense is determined based on estimates of the Corporation’s current income tax and estimates of deferred income tax
resulting from temporary differences between the carrying values of assets and liabilities and their tax values. A deferred income tax asset or
liability is determined for each temporary difference based on enacted income tax rates and laws in effect when the temporary differences
are expected to be recovered or settled. Deferred income tax assets are assessed for the likelihood that they will be recovered from future
taxable income. To the extent recovery is not considered more likely than not, a valuation allowance is recognized against earnings in the
period when the allowance is created or revised. Estimates of the provision for current income tax expense, deferred income tax assets and
liabilities, and any related valuation allowance, might vary from actual amounts incurred.
Employee Future Benefits
The following table summarizes the balance sheet impact of the defined benefit pension and OPEB plans as at December 31, 2018 and 2017,
as well as the net benefit cost for the years then ended.
($ millions)
Benefit obligation
Plan assets
Funded status
Net benefit cost
Defined Benefit
Pension Plans
2018
(3,207)
2,830
(377)
83
2017
(3,215)
2,841
(374)
87
OPEB Plans
2018
(655)
293
(362)
34
2017
(665)
277
(388)
32
Fortis and its subsidiaries each maintains one or a combination of defined benefit pension plans and OPEB plans for qualifying members. The
main assumptions determined by management and used in the actuarial determination of the net benefit cost and related benefit obligation
are the discount rate, the expected long-term rate of return on plan assets and, with respect to OPEBs, the health care cost trend rate.
65
FORTIS INC. 2018 ANNUAL REPORTManagement Discussion and Analysis
Discount Rate
The assumed weighted average discount rate used to measure the projected benefit obligations as at December 31, 2018, and to determine
net pension cost for 2019, is 4.07% compared to 3.58% assumed for the prior year. Discount rates reflect market interest rates on high-quality
bonds with cash flows that match the timing and amount of expected pension payments.
Consolidated defined benefit pension costs were comparable with 2017. Higher expected return on plan assets, lower interest and regulatory
adjustments for 2018 compared to 2017 were largely offset by higher service costs and amortization of actuarial losses. Any increases or
decreases in defined benefit net pension cost at the regulated utilities for 2019 are expected to be recovered from or refunded to customers
in rates, subject to regulatory lag and forecast risk at certain of the utilities.
Rate of Return on Plan Assets
The expected weighted average long-term rate of return on the defined benefit pension plan assets, for the purpose of estimating net
pension cost for 2019, is 5.80% compared to 5.97% used for 2018. The defined benefit pension plan assets experienced total negative returns
of approximately $93 million in 2018 compared to expected positive returns of $162 million. The expected long-term rates of return on
pension plan assets are developed by management with assistance from independent actuaries using best estimates of expected returns,
volatilities and correlations for each class of asset. The best estimates are based on historical performance, future expectations and periodic
portfolio rebalancing among the diversified asset classes.
The OPEB plan assets at ITC, UNS Energy and Central Hudson experienced negative returns of $13 million in 2018 compared to expected
positive returns of approximately $16 million.
The following table provides the sensitivities associated with a 100 basis point, or 1%, change in certain assumptions on the 2018 pension
cost and related obligation.
Sensitivity Analysis
Year Ended December 31, 2018
(Decrease) increase
($ millions)
Defined Benefit Pension Plans:
Net pension benefit cost
Projected benefit obligation (1)
OPEB Plans:
Net OPEB 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
(26)
15
(3)
n/a
23
(57)
3
n/a
(39)
(405)
(8)
(88)
57
509
12
111
n/a
n/a
17
85
n/a
n/a
(11)
(67)
(1) At FortisBC Energy and FortisBC Electric, certain defined benefit pension plans have pension indexing provisions that provide for a portion of investment returns to be
allocated in order to provide for indexing of pension benefits. Therefore, a change in the expected long-term rate of return on pension plan assets has an impact on the
projected benefit obligation.
Other assumptions applied in measuring net benefit cost and/or the benefit obligation include the average rate of compensation increase,
average remaining service life of the active employee group, and employee and retiree mortality rates.
At FortisAlberta, as approved by the regulator, the cost of defined benefit pension plans is recovered in customer rates based on the cash
payments made, with any difference between the cash payments made and the cost incurred being deferred as a regulatory asset or
regulatory liability. ITC, Central Hudson, FortisBC Energy, FortisBC Electric and Newfoundland Power have regulator-approved mechanisms
to defer variations in net pension cost from the forecast net pension cost used to set customer rates. There can be no assurance, however,
that the deferral mechanisms will continue in the future as they are dependent on future regulatory decisions and orders.
66
FORTIS INC. 2018 ANNUAL REPORTManagement Discussion and Analysis
Revenue Recognition
Revenue at the Corporation’s regulated utilities is generally recognized on an accrual basis. Electricity and gas consumption is metered upon
delivery to customers and is recognized as revenue using approved rates when consumed. Meters are read periodically and bills are issued
to customers based on these readings. At the end of each reporting period, a certain amount of consumed electricity and gas will not have
been billed. Electricity and gas that is consumed but not yet billed to customers is estimated and accrued as revenue at each period end, as
approved by the regulator.
The unbilled revenue accrual for the period is based on estimated electricity and gas sales to customers for the period since the last meter
reading at the approved rates. The development of sales estimates generally requires analysis of consumption on a historical basis in relation
to key inputs, such as the current price of electricity and gas, population growth, economic activity, weather conditions and system losses.
The estimation process for accrued unbilled electricity and gas consumption will result in adjustments to revenue in the periods they
become known, when actual results differ from estimates. As at December 31, 2018, the amount of accrued unbilled revenue recognized
in accounts receivable was approximately $575 million (December 31, 2017 – $562 million) on consolidated revenue of $8.4 billion for 2018
(2017 – $8.3 billion).
Contingencies
In April 2013 FHI and Fortis were named as defendants in an action in the British Columbia Supreme Court by the Coldwater Indian Band (“Band”)
regarding interests in a pipeline right of way on reserve lands. The pipeline was transferred by FHI (then Terasen Inc.) to Kinder Morgan Inc.
in 2007. The Band seeks cancellation of the right of way and damages for wrongful interference with the Band’s use and enjoyment of reserve
lands. In May 2016 the Federal Court dismissed the Band’s application for judicial review of the ministerial consent. In September 2017 the
Federal Court of Appeal set aside the Minister’s consent and returned the matter to the Minister for redetermination. No amount has been
accrued as the outcome cannot yet be reasonably determined.
The Corporation and its subsidiaries are subject to various other legal proceedings and claims associated with the ordinary course of business
operations. Management believes that the amount of liability, if any, from these actions would not have a material adverse effect on the
Corporation’s consolidated financial position, results of operations or cash flows.
RELATED-PARTY AND INTER-COMPANY TRANSACTIONS
Related-party transactions are in the normal course of operations and are measured at the amount of consideration agreed to by the related
parties. There were no material related-party transactions in 2018 or 2017.
Inter-company balances, transactions and profit are eliminated on consolidation, except for certain inter-company transactions between
non-regulated and regulated entities in accordance with accounting standards for rate-regulated entities. Inter-company transactions are
summarized below.
Inter-Company Transactions
Years Ended December 31
($ millions)
Sale of capacity from Waneta Expansion to FortisBC Electric
Lease of gas storage capacity and gas sales from Aitken Creek to FortisBC Energy
2018
47
25
2017
46
24
As at December 31, 2018, accounts receivable included approximately $16 million due from BEL (December 31, 2017 – $20 million).
The Corporation periodically provides short-term financing to subsidiaries to support capital expenditure programs, acquisitions and
seasonal working capital requirements. There were no material inter-segment loans outstanding as at December 31, 2018 and 2017.
67
FORTIS INC. 2018 ANNUAL REPORTManagement Discussion and Analysis
SELECTED ANNUAL FINANCIAL INFORMATION
The following table sets forth the annual financial information for the years ended December 31, 2018, 2017 and 2016.
Selected Annual Financial Information
Years Ended December 31
($ millions, except per share amounts)
Revenue
Net earnings
Net earnings attributable to common equity shareholders
Basic earnings per common share
Diluted earnings per common share
Adjusted earnings per common share
Total assets
Long-term debt (excluding current portion)
Preference shares
Common shareholders’ equity
Dividends declared per:
Common share
First Preference Share, Series E (1)
First Preference Share, Series F
First Preference Share, Series G (2)
First Preference Share, Series H
First Preference Share, Series I
First Preference Share, Series J
First Preference Share, Series K
First Preference Share, Series M
2018
8,390
1,286
1,100
2.59
2.59
2.51
53,051
23,159
1,623
14,910
1.75
–
1.2250
1.0345
0.6250
0.7116
1.1875
1.0000
1.0250
2017
8,301
1,125
963
2.32
2.31
2.47
47,822
20,691
1,623
13,380
1.65
–
1.2250
0.9708
0.6250
0.5262
1.1875
1.0000
1.0250
2016
6,838
713
585
1.89
1.89
2.33
47,904
20,817
1,623
12,974
1.55
0.6126
1.2250
0.9708
0.6250
0.4874
1.1875
1.0000
1.0250
(1) In September 2016 the Corporation redeemed all of the issued and outstanding First Preference Shares, Series E.
(2) The annual dividend per share for the First Preference Shares, Series G was reset from $0.9708 to $1.0983 for the five-year period from September 1, 2018 up to but excluding
September 1, 2023.
2018/2017
For a discussion of the reasons for the changes in revenue, net earnings attributable to common equity shareholders and basic earnings
per common share, refer to the “Summary Financial Highlights” and “Consolidated Results of Operations” sections of this MD&A.
The growth in total assets was due to continued investment in energy infrastructure, driven by capital spending at the regulated utilities
as well as favourable foreign exchange on the translation of US dollar-denominated assets. The increase in long-term debt was due to debt
issuances at regulated utilities and foreign exchange, partially offset by scheduled debt repayments.
2017/2016
Revenue increased $1,463 million from 2016, driven by the acquisition of ITC in October 2016. Higher revenue at UNS Energy, mainly due to
the impact of the rate case settlement effective February 2017 and the overall favourable impact of FERC-ordered transmission refunds, and
the flow through in customer rates of overall higher energy supply costs were partially offset by unfavourable foreign exchange associated
with the translation of US dollar-denominated revenue.
Net earnings attributable to common equity shareholders increased $378 million from 2016, driven by a full year of earnings contribution
at ITC, which was acquired in October 2016, lower Corporate and Other expenses, strong performance at UNS Energy, and higher earnings
from Aitken Creek.
Basic earnings per common share were $2.32 in 2017 compared to $1.89 in 2016. The impact of higher net earnings attributable to common
equity shareholders was partially offset by an increase in the weighted average number of common shares outstanding associated with
the financing of the acquisition of ITC and the Corporation’s dividend reinvestment plan.
Total assets and long-term debt were comparable to 2016. The impact of unfavourable foreign exchange on the translation of
US dollar-denominated assets was largely offset by continued investment in energy infrastructure, driven by capital spending at
the regulated utilities.
68
FORTIS INC. 2018 ANNUAL REPORTManagement Discussion and Analysis FOURTH QUARTER RESULTS
The following tables set forth financial information for the fourth quarters of 2018 and 2017.
Summary of Electricity and Energy Sales and Gas Volumes
Fourth Quarters Ended December 31
Regulated Utilities
UNS Energy – Electricity Sales (GWh)
UNS Energy – Gas Volumes (PJ)
Central Hudson – Electricity Sales (GWh)
Central Hudson – Gas Volumes (PJ)
FortisBC Energy (PJ)
FortisAlberta (GWh)
FortisBC Electric (GWh)
Other Electric (GWh)
Non-Regulated
Energy Infrastructure (GWh)
Electricity and Energy Sales
2018
4,751
5
1,250
7
63
4,343
839
2,443
85
2017
3,553
4
1,195
6
69
4,328
869
2,376
129
Variance
1,198
1
55
1
(6)
15
(30)
67
(44)
The increase in electricity sales was driven by higher electricity sales at UNS Energy, primarily resulting from an increase in short-term
wholesale sales due to an increase in system capacity related to the lease of the Gila River generating station Unit 2.
Gas Volumes
Gas volumes were comparable with 2017, with a slight decrease that resulted from focused customer conservation efforts at FortisBC Energy
in the fourth quarter of 2018.
Segmented Revenue and Net Earnings Attributable to Common Equity Shareholders
Fourth Quarters Ended December 31
($ millions, except per share amounts)
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
Basic Earnings per Common Share ($)
Weighted Average Number of Common Shares Outstanding (millions)
2,206
Revenue
Revenue
Net Earnings
2018
2017
Variance
2018
2017
Variance
390
541
234
371
140
111
372
50
–
(3)
396
471
211
366
152
107
347
64
–
(3)
2,111
(6)
70
23
5
(12)
4
25
(14)
–
–
95
92
27
24
72
22
13
22
22
(33)
–
261
0.61
427.5
(1)
28
22
66
29
13
25
25
(73)
–
134
0.32
420.1
93
(1)
2
6
(7)
–
(3)
(3)
40
–
127
0.29
7.4
The increase in revenue was primarily due to higher electricity sales, driven by an increase in system capacity at UNS Energy, favourable
foreign exchange, and the flow through in customer rates of higher overall commodity costs. The increase was partially offset by the
recovery of lower federal corporate income tax in customer rates associated with U.S. tax reform.
Earnings
The increase in earnings was primarily due to lower income tax expense, primarily driven by the one-time expense of $146 million in 2017
associated with U.S. tax reform, along with the positive tax impact of the remeasurement of deferred tax liabilities associated with assets held
for sale. The increase was partially offset by a $21 million unrealized foreign exchange gain on a US-dollar denominated affiliate loan in 2017.
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FORTIS INC. 2018 ANNUAL REPORTManagement Discussion and Analysis
Basic Earnings per Common Share
Basic earnings per common share were $0.29 higher compared to the fourth quarter of 2017, due to higher earnings for the reasons noted
above, partially offset by an increase in the weighted average number of common shares outstanding associated with the Corporation’s
dividend reinvestment plan.
Summary of Consolidated Cash Flows
Fourth Quarters Ended December 31
($ millions)
Cash, Beginning of Period
Cash Provided by (Used in):
Operating Activities
Investing Activities
Financing Activities
Effect of Exchange Rate Changes on Cash and Cash Equivalents
Cash Associated with Assets Held for Sale
Cash, End of Period
2018
195
537
(999)
598
16
(15)
332
2017
252
766
(882)
191
–
–
327
Variance
(57)
(229)
(117)
407
16
(15)
5
The decrease in cash provided by operating activities for the quarter was primarily due to an unfavourable change in working capital driven
by FortisAlberta due to the timing of transmission costs payments, lower cash earnings and unfavourable changes in long-term regulatory
deferrals, driven by the deferral of higher gas storage and transportation costs at FortisBC Energy related to a gas pipeline incident in the
fourth quarter of 2018.
The increase in cash used in investing activities for the quarter was due to higher capital spending, mainly at FortisBC Energy.
The increase in cash provided by financing activities for the quarter was primarily due to lower repayments of long-term debt and lower
net repayments of credit facility borrowings and short-term borrowings. The increase was partially offset by a decrease in proceeds from
the issuance of long-term debt, driven by ITC.
SUMMARY OF QUARTERLY RESULTS
Quarterly information has been obtained from the Corporation’s Interim Financial Statements. These financial results are not necessarily
indicative of results for any future period and should not be relied upon to predict future performance.
Summary of Quarterly Results
Quarter Ended
December 31, 2018
September 30, 2018
June 30, 2018
March 31, 2018
December 31, 2017
September 30, 2017
June 30, 2017
March 31, 2017
Net Earnings
Attributable to
Common Equity
Shareholders
($ millions)
261
276
240
323
134
278
257
294
Revenue
($ millions)
2,206
2,040
1,947
2,197
2,111
1,901
2,015
2,274
Earnings per Common Share
Diluted
($)
0.61
0.65
0.57
0.76
0.31
0.66
0.62
0.72
Basic
($)
0.61
0.65
0.57
0.77
0.32
0.66
0.62
0.72
The summary of the past eight quarters reflects the Corporation’s continued organic growth, seasonality associated with its businesses and
the impact of U.S. tax reform, effective December 2017. Interim results will fluctuate due to the seasonal nature of electricity and gas demand,
as well as the timing and recognition of regulatory decisions. Revenue is also affected by the cost of fuel, purchased power and natural gas,
which is flowed through to customers without markup. Given the diversified nature of the Corporation’s subsidiaries, seasonality may vary.
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 United States are generally highest in the second and third quarters due to the use of air conditioning
and other cooling equipment.
December 2018/December 2017
Net earnings attributable to common equity shareholders were $261 million, or $0.61 per common share, for the fourth quarter of 2018
compared to earnings of $134 million, or $0.32 per common share, for the fourth quarter of 2017. A discussion of the variances in financial
results for the fourth quarter is provided in the “Fourth Quarter Results” section of this MD&A.
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FORTIS INC. 2018 ANNUAL REPORTManagement Discussion and Analysis
September 2018/September 2017
Net earnings attributable to common equity shareholders were $276 million, or $0.65 per common share, for the third quarter of 2018
compared to earnings of $278 million, or $0.66 per common share, for the third quarter of 2017. The decrease in earnings was primarily due
to: (i) the receipt of a break fee associated with the termination of the Waneta Dam purchase agreement recognized in the third quarter
of 2017; and (ii) lower earnings from Aitken Creek related to unrealized net losses on the mark-to-market of natural gas derivatives quarter
over quarter. The decrease was partially offset by: (i) rate base growth driven by ITC; (ii) favourable electricity sales at UNS Energy;
(iii) performance at the Canadian and Caribbean utilities, tempered by higher operating and interest expenses at FortisBC Energy; and
(iv) favourable foreign exchange.
June 2018/June 2017
Net earnings attributable to common equity shareholders were $240 million, or $0.57 per common share, for the second quarter of 2018
compared to earnings of $257 million, or $0.62 per common share, for the second quarter of 2017. The decrease in earnings was primarily due
to: (i) lower earnings from Aitken Creek related to unrealized net losses on the mark-to-market of natural gas derivatives quarter over quarter;
(ii) the impact of U.S. tax reform; (iii) unfavourable foreign exchange; and (iv) the favourable settlement of matters at UNS Energy pertaining
to FERC-ordered transmission refunds in 2017. The decrease was partially offset by the settlement of FortisTCI’s business interruption insurance
claim related to the impact of Hurricane Irma, and growth in rate base.
March 2018/March 2017
Net earnings attributable to common equity shareholders were $323 million, or $0.77 per common share, for the first quarter of 2018
compared to earnings of $294 million, or $0.72 per common share, for the first quarter of 2017. The increase in earnings was primarily
due to: (i) the one-time remeasurement of the Corporation’s deferred income tax liabilities as a result of an election to file a consolidated
state income tax return; (ii) the impact of a full quarter of new rates at UNS Energy compared to last year; and (iii) growth in rate base.
The increase was partially offset by: (i) unfavourable foreign exchange; (ii) lower earnings from Aitken Creek related to unrealized net losses
on the mark-to-market of natural gas derivatives quarter over quarter; (iii) timing differences at Newfoundland Power; and (iv) the favourable
settlement of matters at UNS Energy pertaining to FERC-ordered transmission refunds of $7 million in 2017.
MANAGEMENT’S EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES
AND INTERNAL CONTROLS OVER FINANCIAL REPORTING
Disclosure Controls and Procedures
Disclosure controls and procedures are designed to provide reasonable assurance that information required to be disclosed in reports filed
with, or submitted to, securities regulatory authorities is recorded, processed, summarized and reported within the time periods specified
under Canadian and U.S. securities laws. As at December 31, 2018, an evaluation was carried out under the supervision of, and with the
participation of, the Corporation’s management, including the President and Chief Executive Officer (“CEO”) and the Executive Vice President,
Chief Financial Officer (“CFO”), of the effectiveness of the Corporation’s disclosure controls and procedures, as defined in the applicable
Canadian and United States securities laws. Based on that evaluation, the CEO and CFO concluded that such disclosure controls and
procedures are effective as at December 31, 2018.
Internal Control over Financial Reporting
Internal control over financial reporting 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,
internal control over financial reporting 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 the Corporation’s CEO and CFO, assessed the effectiveness of the Corporation’s internal control
over financial reporting as at December 31, 2018, 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
at December 31, 2018, the Corporation’s internal control over financial reporting was effective.
During the year ended December 31, 2018, there have been no changes in the Corporation’s internal control over financial reporting that
have materially affected, or are reasonably likely to materially affect, the Corporation’s internal control over financial reporting.
71
FORTIS INC. 2018 ANNUAL REPORTManagement Discussion and Analysis OUTLOOK
Over the long term, Fortis is well positioned to enhance value for shareholders through the execution of its capital program, the balance
and strength of its diversified portfolio of utility businesses, as well as growth opportunities within its service territories.
The Corporation’s $17.3 billion five-year capital program is expected to increase rate base from $26.1 billion in 2018 to approximately
$32.0 billion in 2021 and $35.5 billion in 2023, translating into three- and five-year compound annual growth rates of 7.1% and 6.3%,
respectively. The five-year capital program addresses system capacity and improves safety and reliability for the benefit of customers
through investments that improve and automate the electricity grid, address natural gas system capacity and gas line network integrity,
increase cyber protection and allow the grid to deliver cleaner energy.
Fortis is focused on securing further growth opportunities at its subsidiaries, which include the ITC Lake Erie Connector Project, gas
infrastructure opportunities at FortisBC Energy and renewable energy investments, including storage, at UNS Energy.
Fortis expects long-term sustainable growth in rate base to support continuing growth in earnings and dividends. Fortis is targeting
average annual dividend growth of 6% through 2023. 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 program, and
management’s continued confidence in the strength of the Corporation’s diversified portfolio of utilities and record of operational excellence.
OUTSTANDING SHARE DATA
As at February 14, 2019, the Corporation had issued and outstanding 428.6 million common shares; 5.0 million First Preference Shares,
Series F; 9.2 million First Preference Shares, Series G; 7.0 million First Preference Shares, Series H; 3.0 million First Preference Shares, Series I;
8.0 million First Preference Shares, Series J; 10.0 million First Preference Shares, Series K; and 24.0 million First Preference Shares, Series M.
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 and whether such dividends have been declared.
The number of common shares of Fortis that would be issued if all outstanding stock options were converted as at February 14, 2019 is
approximately 4.8 million.
Additional information can be accessed at www.fortisinc.com, www.sedar.com or www.sec.gov. The information contained on, or accessible
through, any of these websites is not incorporated by reference into this document.
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FORTIS INC. 2018 ANNUAL REPORTManagement Discussion and Analysis Financials
Table of Contents
Management’s Report on Internal Control
NOTE 12 Property, Plant and Equipment ������������������������������������������������������������101
over Financial Reporting ������������������������������������������������������������������������������������������������� 74
Report of Independent Registered Public Accounting Firm –
Opinion on the Consolidated Financial Statements ������������������������������������� 75
Report of Independent Registered Public Accounting Firm –
Opinion on Internal Control over Financial Reporting �������������������������������� 76
NOTE 13
Intangible Assets ��������������������������������������������������������������������������������������������102
NOTE 14 Goodwill ��������������������������������������������������������������������������������������������������������������103
NOTE 15 Accounts Payable and Other Current Liabilities ������������������������103
NOTE 16 Long-Term Debt ���������������������������������������������������������������������������������������������104
Consolidated Balance Sheets ��������������������������������������������������������������������������������������������� 77
NOTE 17 Capital Lease and Finance Obligations �������������������������������������������107
Consolidated Statements of Earnings ��������������������������������������������������������������������������� 78
NOTE 18 Other Liabilities �����������������������������������������������������������������������������������������������109
Consolidated Statements of Comprehensive Income ��������������������������������������� 78
NOTE 19 Earnings per Common Share �����������������������������������������������������������������109
Consolidated Statements of Cash Flows ��������������������������������������������������������������������� 79
NOTE 20 Preference Shares ������������������������������������������������������������������������������������������110
Consolidated Statements of Changes in Equity ����������������������������������������������������� 80
NOTE 21 Accumulated Other Comprehensive Income �����������������������������111
Notes to Consolidated Financial Statements
NOTE 22 Stock-Based Compensation Plans ������������������������������������������������������111
NOTE 1
Description of Business �������������������������������������������������������������������������������� 81
NOTE 23 Other Income, Net ����������������������������������������������������������������������������������������114
NOTE 2
Regulation ������������������������������������������������������������������������������������������������������������� 83
NOTE 24
Income Taxes ����������������������������������������������������������������������������������������������������115
NOTE 3
Summary of Significant Accounting Policies ���������������������������������� 85
NOTE 25 Employee Future Benefits ������������������������������������������������������������������������117
NOTE 4
Future Accounting Pronouncements �������������������������������������������������� 93
NOTE 26 Terminated Acquisition������������������������������������������������������������������������������121
NOTE 5
Segmented Information������������������������������������������������������������������������������� 94
NOTE 27 Supplementary Cash Flow Information ������������������������������������������122
NOTE 6
Revenue ������������������������������������������������������������������������������������������������������������������ 96
NOTE 28 Fair Value of Financial Instruments
NOTE 7
Accounts Receivable and Other Current Assets ��������������������������� 97
NOTE 8
Inventories ������������������������������������������������������������������������������������������������������������ 97
NOTE 9
Regulatory Assets and Liabilities ������������������������������������������������������������ 98
NOTE 10 Assets Held for Sale ��������������������������������������������������������������������������������������100
NOTE 11 Other Assets ������������������������������������������������������������������������������������������������������100
and Risk Management ��������������������������������������������������������������������������122
NOTE 29 Variable Interest Entity �������������������������������������������������������������������������������127
NOTE 30 Commitments and Contingencies �����������������������������������������������������128
NOTE 31 Comparative Figures �����������������������������������������������������������������������������������129
73
FORTIS INC. 2018 ANNUAL REPORT 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 at December 31, 2018, 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 at December 31, 2018, the Corporation’s ICFR was effective�
The Corporation’s ICFR as at December 31, 2018 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, 2018� Deloitte LLP issued an unqualified opinion for
both audits�
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
February 14, 2019
74
FORTIS INC. 2018 ANNUAL REPORTFinancials 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 at December 31, 2018 and 2017,
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, 2018, 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 at December 31, 2018 and 2017, and the results of its operations and
its cash flows for each of the two years in the period ended December 31, 2018, 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 at December 31, 2018, 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 14, 2019, 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 audits 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�
Deloitte LLP
Chartered Professional Accountants
St� John’s, Canada
February 14, 2019
We have served as the Corporation’s auditor since 2017�
75
FORTIS INC. 2018 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 at December 31, 2018, 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 at
December 31, 2018, 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, 2018, of the Corporation and our report dated February 14, 2019,
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 (i) pertain to the maintenance of records that, in
reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) 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 (iii) 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 14, 2019
76
FORTIS INC. 2018 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 10)
Total current assets
Other assets (Note 11)
Regulatory assets (Note 9)
Property, plant and equipment, net (Note 12)
Intangible assets, net (Note 13)
Goodwill (Note 14)
Total assets
LIABILITIES AND EQUITY
Current liabilities
Short-term borrowings (Note 16)
Accounts payable and other current liabilities (Note 15)
Regulatory liabilities (Note 9)
Current installments of long-term debt (Note 16)
Current installments of capital lease and finance obligations (Note 17)
Liabilities associated with assets held for sale (Note 10)
Total current liabilities
Other liabilities (Note 18)
Regulatory liabilities (Note 9)
Deferred income taxes (Note 24)
Long-term debt (Note 16)
Capital lease and finance obligations (Note 17)
Total liabilities
Commitments and contingencies (Note 30)
Equity
Common shares (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
$
2018
332
1,357
84
398
324
766
3,261
552
2,854
32,654
1,200
12,530
$
2017
327
1,131
79
367
303
–
2,207
480
2,742
29,668
1,081
11,644
$ 53,051
$
47,822
$
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
$
209
2,053
490
705
47
–
3,504
1,210
2,956
2,298
20,691
414
31,073
11,582
1,623
10
61
1,727
15,003
1,746
16,749
$ 53,051
$
47,822
(1) No par value� Unlimited authorized shares; 428�5 million and 421�1 million
issued and outstanding as at December 31, 2018 and 2017, respectively
Approved on Behalf of the Board
See accompanying Notes to Consolidated Financial Statements
Douglas J. Haughey,
Director
Tracey C. Ball,
Director
77
FORTIS INC. 2018 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
Operating income
Other income, net (Note 23)
Finance charges
Earnings before income tax expense
Income tax expense (Note 24)
Net earnings
Net earnings attributable to:
Non-controlling interests
Preference equity shareholders
Common equity shareholders
Earnings per common share (Note 19)
Basic
Diluted
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
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 income (loss)
Unrealized foreign currency translation gains (losses), net of hedging activities
and income tax recovery (expense) of $11 million and $(2) million, respectively
Other, net of income tax expense of $2 million and nil, respectively
Comprehensive income
Comprehensive income (loss) attributable to:
Non-controlling interests
Preference equity shareholders
Common equity shareholders
See accompanying Notes to Consolidated Financial Statements
2018
$
1,286
985
6
991
$
2,277
$
244
66
1,967
$
2,277
2017
8,301
2,361
2,250
1,179
5,790
2,511
116
914
1,713
588
1,125
97
65
963
1,125
2�32
2�31
2017
1,125
(781)
(2)
(783)
342
(2)
65
279
342
$
$
$
$
$
$
$
$
$
$
78
FORTIS INC. 2018 ANNUAL REPORTFinancials
CONSOLIDATED STATEMENTS OF CASH FLOWS
FORTIS INC.
For the years ended December 31 (in millions of Canadian dollars)
2018
2017
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 24)
Equity component, allowance for funds used during construction (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
Other
Cash used in investing activities
Financing activities
Proceeds from long-term debt, net of issuance costs (Note 16)
Repayments of long-term debt and capital lease and finance obligations
Borrowings under committed credit facilities (Note 31)
Repayments under committed credit facilities (Note 31)
Net change in short-term borrowings (Note 31)
Issue of common shares, net of costs, and dividends reinvested
Dividends
Common shares, net of dividends reinvested
Preference shares
Subsidiary dividends paid to non-controlling interests
Other
Cash from financing activities
Effect of exchange rate changes on cash and cash equivalents
Change in cash and cash equivalents
Less: Cash associated with assets held for sale (Note 10)
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
$
1,286
$
1,125
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
$
1,055
97
27
544
(74)
11
68
(97)
2,756
(2,813)
(211)
102
(103)
(3,025)
2,538
(952)
6,461
(7,480)
(192)
561
(419)
(65)
(109)
(4)
339
(12)
58
–
269
327
$
79
FORTIS INC. 2018 ANNUAL REPORTFinancials
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
FORTIS INC.
Accumulated
Other
Preference Additional Comprehensive
Paid-In
Capital
Shares
(Note 20)
Non-
Income (Loss) Retained Controlling
Interests
(Note 21) Earnings
Total
Equity
For the years ended December 31, 2018 and 2017
Common
(in millions of Canadian dollars,
except share numbers)
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
Shares Common
Shares
(millions)
421.1 $ 11,582
–
–
307
–
–
7.4
$ 1,623
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
As at December 31, 2018
428.5 $ 11,889
$ 1,623
As at December 31, 2016
Net earnings
Other comprehensive loss
Common shares issued
Subsidiary dividends paid to
non-controlling interests
Dividends declared on common
shares ($1�65 per share)
Dividends declared on preference shares
Other
401�5 $ 10,762
–
–
820
–
–
19�6
$ 1,623
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
$
$
$
10
–
–
(1)
–
–
–
2
11
12
–
–
(5)
–
–
–
3
$
$
$
61 $ 1,727
1,166
–
–
–
867
–
$ 1,746 $ 16,749
1,286
991
306
120
124
–
–
–
–
–
–
(85)
(85)
(745)
(66)
–
–
–
18
(745)
(66)
20
928 $ 2,082
$ 1,923 $ 18,456
745 $ 1,455
1,028
–
–
–
(684)
–
$ 1,853 $ 16,450
1,125
(783)
815
97
(99)
–
–
–
–
–
–
(109)
(109)
(691)
(65)
–
–
–
4
(691)
(65)
7
As at December 31, 2017
421�1 $ 11,582
$ 1,623
$
10
$
61 $ 1,727
$ 1,746 $ 16,749
See accompanying Notes to Consolidated Financial Statements
80
FORTIS INC. 2018 ANNUAL REPORTFinancials
Notes to Consolidated Financial Statements
For the years ended December 31, 2018 and 2017
1. DESCRIPTION OF BUSINESS
Fortis Inc� (“Fortis” or the “Corporation”) is principally a North American electric and gas utility holding company� Entities within the reporting
segments that follow operate with substantial autonomy�
Regulated Utilities
ITC
Primarily comprised of ITC Holdings Corp�, ITC Investment Holdings Inc� 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 generation capacity of 3,377 megawatts (“MW”), including 57 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
Primarily comprised of CH Energy Group, Inc� and 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 64 MW�
FortisBC Energy
Primarily 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
Primarily 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 four hydroelectric generating facilities in British Columbia that are owned by third parties and to the 335-MW Waneta Expansion hydroelectric
generating facility (“Waneta Expansion”) in which Fortis indirectly holds a 51% controlling interest (Notes 10 and 29)�
81
FORTIS INC. 2018 ANNUAL REPORT 1.
DESCRIPTION OF BUSINESS (cont’d)
Regulated Utilities (cont’d)
Other Electric
in eastern Canada and
Comprised of utilities
(“Newfoundland Power”);
Maritime Electric Company, Limited (“Maritime Electric”); FortisOntario Inc� (“FortisOntario”); a 49% equity investment in Wataynikaneyap Power Limited
Partnership (“Wataynikaneyap Partnership”) (Note 11); 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 (“BEL”) (Note 11)�
follows: Newfoundland Power
the Caribbean, as
Inc�
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�
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 139 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 145 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�
Wataynikaneyap Partnership is a partnership between 24 First Nations communities and Fortis with a mandate of connecting remote First Nations
communities to the electricity grid in Ontario through the development of new transmission lines�
Caribbean Utilities is an integrated regulated electric utility and the sole electricity provider on Grand Cayman with a diesel-powered generating
capacity of 161 MW� FortisTCI 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� BEL is an integrated electric utility and the principal distributor of electricity in Belize�
Non-Regulated
Energy Infrastructure
Primarily comprised of long-term contracted generation assets in British Columbia and Belize, and the Aitken Creek natural gas storage facility
(“Aitken Creek”)� Generation assets in British Columbia include the Corporation’s interest in the Waneta Expansion (Note 10), whose output is sold to
British Columbia Hydro and Power Authority (“BC Hydro”) and FortisBC Electric under 40-year power purchase agreements (“PPAs”)� Generation
assets in Belize are comprised of three hydroelectric generating facilities with a combined capacity of 51 MW, conducted through the Corporation’s
indirectly wholly owned subsidiary Belize Electric Company Limited (“BECOL”)� The output is sold to BEL under 50-year PPAs� Fortis indirectly owns
93�8% of Aitken Creek, with the remainder owned by BP Canada Energy Company� Aitken Creek is the only underground natural gas storage facility in
British Columbia and has a working gas capacity of 77 billion cubic feet�
Corporate and Other
Captures expense and revenue items not specifically related to any reportable segment and those business operations that are below the
required threshold for reporting as separate segments, including net corporate expenses of Fortis and the non-regulated holding company
FortisBC Holdings Inc� (“FHI”)�
82
For the years ended December 31, 2018 and 2017FORTIS INC. 2018 ANNUAL REPORTNotes to Consolidated Financial Statements
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 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”)�
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� Usage of a
historical test year may cause regulatory lag between when costs are incurred and when they are reflected in customer rates�
When PBR mechanisms are utilized in determining customer rates, a formula is generally applied that incorporates inflation and assumed
productivity improvements for a set term� PBR mechanisms should allow a utility a reasonable opportunity to recover prudently incurred costs and
earn its allowed ROE or ROA�
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
rates reflect an allowed ROE ranging from 11�07% to 12�16% on a capital structure of 60% common equity for 2018 (ROE range of 11�32% to 12�16%
and 60% common equity for 2017)�
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 transmission owners operating in the Midcontinent Independent System Operator (“MISO”) region, which includes ITCTransmission,
METC and ITC Midwest (collectively “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 equates to a 0�25%
decrease in ROE, down from the approximate 0�50% that ITC was earning in rates previously approved by FERC� ITC’s MISO Subsidiaries sought
rehearing of this order and began reflecting the 0�25% adder in transmission rates in November 2018� Refunds began in the fourth quarter of 2018
and were completed in the first quarter of 2019� The order 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”)� FERC orders on the complaints will
also set the ROE that will be effective prospectively from the order dates�
In September 2016 FERC ordered that the base ROE for the Initial Refund Period be set at 10�32%, down from 12�38%, with a maximum of 11�35%� The
resultant rates apply prospectively from September 2016 until an approved ROE is established for the Second Refund Period� The MISO transmission
owners sought rehearing of this order� 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 (Note 9)�
In June 2016 the presiding Administrative Law Judge (“ALJ”) issued an initial decision on the Second Complaint, recommending a base ROE of 9�70%,
with a maximum of 10�68%� The initial decision of the ALJ is a non-binding recommendation to FERC, and FERC has yet to issue its order on the
Second Complaint� In September 2017 certain MISO transmission owners filed a motion for FERC to dismiss the Second Complaint� Pending an order
from FERC, an estimated regulatory liability of $206 million (US$151 million) has been recognized (December 31, 2017 – $182 million (US$145 million))
(Note 9)�
There is uncertainty regarding the final outcome of the Initial and Second Complaints due in part to a November 2018 FERC order proposing a new
methodology for determining a just and reasonable base ROE� If finalized, this proposed methodology will be used to address ITC’s outstanding ROE
complaints� Briefs are due to be filed in the first half of 2019 on the proposed adoption of the new methodology�
83
FORTIS INC. 2018 ANNUAL REPORTNotes to Consolidated Financial Statements 2.
REGULATION (cont’d)
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 electric and gas rates�
Effective February 27, 2017, TEP’s rates reflect an allowed ROE of 9�75% on a capital structure of approximately 50% common equity, effective from
July 1, 2013, prior to which its allowed ROE was 10�0% on a capital structure of 43�5% 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%
and a capital structure of 50�8% common equity�
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�
Effective July 1, 2018, 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 in rate years one, two and three, respectively� Prior thereto,
effective from 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 this 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 for 2014 through 2019 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 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 reflect an allowed ROE
of 8�75% and a capital structure of 38�5% common equity�
Effective January 1, 2016, FortisBC Electric’s rates reflect an allowed ROE of 9�15% and a capital structure of 40% common equity�
FortisAlberta
FortisAlberta is regulated by the Alberta Utilities Commission 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 2013–2017
and 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�
84
For the years ended December 31, 2018 and 2017FORTIS INC. 2018 ANNUAL REPORTNotes to Consolidated Financial Statements 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 2016 to 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, 2016 for a three-year period, 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
2018 and 2017, 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 period of 20 years, expiring in April 2028, with a provision for automatic renewal� Its non-exclusive generation licence is for a term of 25 years,
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 2018 was in the range of 7�00% to
9�00% (range of 6�75% to 8�75% for 2017)�
FortisTCI operates under two 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�
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 controlled variable interest entity� 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�
85
FORTIS INC. 2018 ANNUAL REPORTNotes to Consolidated Financial Statements 3.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (cont’d)
Allowance for Doubtful Accounts
Fortis and each subsidiary, other than ITC, maintains 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 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�
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 as it is expected that such amounts will be reflected in future depreciation expense when they are refunded or collected in
customer rates�
Through methodologies established by their respective regulators, most of the Corporation’s regulated utilities capitalize: (i) overhead costs that
are not directly attributable to specific PPE but relate to the overall capital expenditure program; and (ii) an allowance for funds used during
construction (“AFUDC”)�
The debt component of AFUDC totalling $31 million (2017 – $38 million) is reported as a reduction of finance charges and the equity component is
reported as other income (Note 23)� Both components are charged to earnings through depreciation expense over the estimated service lives of the
applicable PPE�
At FortisAlberta the cost of PPE includes required contributions to the Alberta Electric System Operator (“AESO”) toward funding the construction of
transmission facilities�
Excluding UNS Energy, PPE includes inventory held for the development, construction and betterment of other assets� As required by its regulator,
UNS Energy recognizes 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�
86
For the years ended December 31, 2018 and 2017FORTIS INC. 2018 ANNUAL REPORTNotes to Consolidated Financial Statements 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 2018 ranged from 0�9% to 34�6% (2017 – 0�9% to 34�6%)� The weighted average
composite rate of depreciation, before reduction for amortization of contributions in aid of construction, was 2�5% for 2018 (2017 – 2�6%)�
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
Leases
2018
Service Life
Ranges
Weighted Average
Remaining
Service Life
2017
Weighted Average
Remaining
Service Life
Service Life
Ranges
5–80
14–95
20–90
5–85
1–85
3–70
33
35
42
41
24
15
5–80
14–95
20–80
5–80
5–85
3–70
33
34
41
34
28
14
Leases that transfer to the Corporation substantially all of the risks and benefits incidental to ownership of the leased item are capitalized at the
present value of the minimum lease payments� Capital 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�
Operating lease payments are recognized as an expense on a straight-line basis over the lease term�
Intangible Assets
Intangible assets are recorded at cost less accumulated amortization� Their useful lives are assessed to be either indefinite or finite�
Intangible assets with indefinite useful lives are not amortized and are tested for impairment annually, either individually or, where the particular
entity also has goodwill, at the reporting unit level in conjunction with goodwill impairment testing� An annual review is completed to determine
whether the indefinite life assessment continues to be supportable� If not, the resultant changes are made prospectively�
Intangible assets with finite lives are amortized using the straight-line method based on the estimated service lives of the assets� Amortization rates
for regulated intangible assets are approved by the respective regulators and ranged from 1�0% to 50�0% for 2018 (2017 – 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
2018
Weighted Average
Remaining
Service Life
4
57
13
Service Life
Ranges
3–10
36–90
10–100
2017
Weighted Average
Remaining
Service Life
4
57
10
Service Life
Ranges
3–10
36–80
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 as it is expected that such amounts will be reflected in future amortization costs when they
are refunded or collected in customer rates�
87
FORTIS INC. 2018 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 that is determined to be the case, 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 primary method for estimating the fair value
of reporting units is the income approach, whereby net cash flow projections for the reporting units are discounted using an enterprise value
method� The income approach uses underlying estimates and assumptions with varying degrees of uncertainty, including the amount and timing of
expected future cash flows, growth rates, and discount rates�
A secondary valuation method, the market approach, as well as a reconciliation of the total estimated fair value of all reporting units to the
Corporation’s market capitalization, are also performed and compared to the results of the income approach�
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 its subsidiaries each maintains 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 plans 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 plan 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)�
88
For the years ended December 31, 2018 and 2017FORTIS INC. 2018 ANNUAL REPORTNotes to Consolidated Financial Statements 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, 2018 was $45�14 (December 31, 2017 – $46�01)� 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, 2018 was US$1�00=CAD$1�36 (December 31, 2017 – US$1�00=CAD$1�25)�
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�30 for 2018 (2017 – 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 and RSU obligations; (ii) UNS Energy, to meet forecast load and reserve requirements; and (iii) Aitken Creek, to
manage commodity price risk, capture natural gas price spreads, and manage the financial risk of physical transactions� These derivatives are
measured at fair value with changes thereto recognized in earnings�
Derivatives not designated as hedges are also used by UNS Energy, Central Hudson and FortisBC Energy to reduce energy price risk associated with
purchased power and gas requirements� The settled amounts of these derivatives are generally included in regulated rates, as permitted by the
respective regulators� These derivatives are measured at fair value with changes 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�
89
FORTIS INC. 2018 ANNUAL REPORTNotes to Consolidated Financial Statements 3.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (cont’d)
Derivatives and Hedging (cont’d)
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 power purchase agreements,
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�3 billion as at December 31, 2018 (December 31, 2017 – $561 million)� 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�
90
For the years ended December 31, 2018 and 2017FORTIS INC. 2018 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 18) 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� Actual settlement costs are recognized as a reduction in the accrued liability�
Contingencies
Fortis and its subsidiaries are involved in certain legal and environmental matters 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
time periods� Actual outcomes may differ materially from the amounts recognized�
New Accounting Policies
Revenue Recognition
Effective January 1, 2018, Fortis adopted Accounting Standards Codification (“ASC”) 606, Revenue from Contracts with Customers, which clarifies the
principles for recognizing revenue and requires additional disclosures (Note 6)� Fortis adopted this standard using the modified retrospective
approach, under which comparative periods are not restated and the cumulative impact is recognized at the date of adoption, supplemented by
additional disclosures� Upon adoption, there were no adjustments to the opening balance of retained earnings�
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�
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�
91
FORTIS INC. 2018 ANNUAL REPORTNotes to Consolidated Financial Statements 3.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (cont’d)
New Accounting Policies (cont’d)
Revenue Recognition (cont’d)
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� Prior to the adoption of ASC 606, Central Hudson recognized sales tax and
FortisAlberta recognized municipal tax on a gross basis in both revenue and expense� The exclusion of these taxes from revenue resulted in a decrease
in revenue of $49 million for 2018 compared to 2017�
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 will be less than one year�
Revenue is disaggregated by geography, regulatory status, and substantially autonomous utility operations (Note 5)� This represents the level of
disaggregation used by the Corporation’s President and Chief Executive Officer (“CEO”) to allocate resources and evaluate performance�
Financial Instruments
Effective January 1, 2018, the Corporation adopted Accounting Standards Update (“ASU”) No� 2016-01, Recognition and Measurement of Financial Assets
and Financial Liabilities� Principally, it requires: (i) equity investments in unconsolidated entities not accounted for using the equity method to be
measured at fair value through earnings; however, entities may elect to record equity investments without readily determinable fair values at cost, less
impairment, and plus or minus subsequent adjustments for observable price changes; and (ii) financial assets and liabilities to be presented separately in
the financial statement notes, grouped by measurement category and form� Adoption did not impact these consolidated financial statements�
Pension and Post-Retirement Benefit Costs
Effective January 1, 2018, the Corporation adopted ASU No� 2017-07, Improving the Presentation of Net Periodic Pension Cost and Net Periodic
Post-Retirement Benefit Cost, which requires current service costs to be grouped in the statement of earnings with other employee compensation
costs arising from services rendered� The remaining components of net periodic benefit costs must be presented separately and outside of
operating income� Additionally, only the service cost component can be capitalized� On adoption, the Corporation applied the presentation
guidance retrospectively and the capitalization guidance prospectively� This resulted in a retrospective $11 million reclassification from Operating
Expenses to Other Income, Net in the consolidated financial statements�
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�
92
For the years ended December 31, 2018 and 2017FORTIS INC. 2018 ANNUAL REPORTNotes to Consolidated Financial Statements 4. FUTURE ACCOUNTING PRONOUNCEMENTS
Leases
ASU No� 2016-02, Leases (“ASC 842”), issued in February 2016, is effective for Fortis January 1, 2019 and is to be applied using a modified retrospective
approach or an optional transition method with implementation options, referred to as practical expedients� Principally, it requires balance
sheet recognition of a right-of-use asset and a lease liability by lessees for those leases that are classified as operating leases, along with
additional disclosures�
Fortis has selected the optional transition method, which allows entities to continue to apply the current lease guidance in the comparative periods
presented in the year of adoption and apply the transition provisions of the new guidance on the effective date of the new guidance� Fortis elected a
package of practical expedients that allowed it to not reassess the lease classification of existing leases or whether existing contracts, including land
easements, are or contain a lease� Finally, Fortis utilized the hindsight practical expedient to determine the lease term�
Upon adoption, Fortis will recognize right-of-use assets and corresponding lease liabilities of approximately $50 million for operating leases primarily
related to office facilities and utility property� Operating leases related to vehicles and office equipment were identified and quantified as immaterial�
Fortis has not identified an adjustment to opening retained earnings, and there will be no impact on earnings or cash flows�
Fortis implemented changes to processes and control activities related to monitoring the adoption of ASC 842 and made changes to accounting
policies associated with accounting for lease assets and liabilities, and related income and expense, as of January 1, 2019�
Financial Instruments
ASU No� 2016-13, Measurement of Credit Losses on Financial Instruments, issued in June 2016, is effective for Fortis January 1, 2020 and is to be applied
on a modified retrospective basis� Principally, it requires entities to use an expected credit loss methodology and to consider a broader range of
reasonable and supportable information to estimate credit losses� The adoption of this ASU will not have a material impact on the consolidated
financial statements and related disclosures�
Hedging
ASU No� 2017-12, Targeted Improvements to Accounting for Hedging Activities, issued in August 2017, is effective for Fortis January 1, 2019� Principally,
it better aligns risk management activities and financial reporting for hedging relationships through changes to designation, measurement,
presentation and disclosure guidance� For cash flow and net investment hedges that existed at the date of adoption, the amendments were applied
as a cumulative-effect adjustment related to eliminating the separate measurement of ineffectiveness to accumulated other comprehensive income
with a corresponding adjustment to opening retained earnings� Amended presentation and disclosure guidance was applied prospectively� The
adoption of this ASU will not have a material impact on the consolidated financial statements and related disclosures�
Fair Value Measurement Disclosures
ASU No� 2018-13, Changes to the Disclosure Requirements for Fair Value Measurement, issued in August 2018, is effective for Fortis January 1, 2020 and is
to be primarily applied on a retrospective basis, with certain disclosures requiring prospective application� Principally, it improves the effectiveness of
financial statement note disclosures by clarifying what is required and important to users of the financial statements� In addition, the amendment
removes (a) the amount of, and reasons for, transfers between level 2 and level 3 of the fair value hierarchy, (b) the policy for timing of transfers
between levels, and (c) the valuation processes for level 3 fair value measurements� Fortis does not expect the adoption of this ASU to have a
material impact on the related disclosures�
Pensions and Other Post-Retirement Plan Disclosures
ASU No� 2018-14, Changes to the Disclosure Requirements for Defined Benefit Plans, issued in August 2018, is effective for Fortis January 1, 2021 and is to
be applied on a retrospective basis for all periods presented� Principally, it modifies the disclosure requirements for employers with defined pension
or other post-retirement plans and clarifies disclosure requirements� In addition, the amendments remove (a) the amounts in accumulated other
comprehensive income expected to be recognized as components of net period benefit costs over the next fiscal period, (b) the amount and timing
of plan assets expected to be returned to the employer, and (c) 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� Fortis does not expect the
adoption of this ASU to have a material impact on the related disclosure�
93
FORTIS INC. 2018 ANNUAL REPORTNotes to Consolidated Financial Statements 5. SEGMENTED INFORMATION
General
Fortis segments its business based on regulatory status and service territory, as well as the information used by its President and CEO in deciding
how to allocate resources� The performance of each segment is primarily based on net earnings attributable to common equity shareholders�
Effective January 1, 2018, the former Eastern Canadian and Caribbean segments were aggregated as Other Electric as they individually do not meet
the quantitative threshold for separate reporting�
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 2018 or 2017�
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� Inter-company transactions are summarized below�
(in millions)
Sale of capacity from Waneta Expansion to FortisBC Electric
Lease of gas storage capacity and gas sales from Aitken Creek to FortisBC Energy
$
2018
47
25
$
2017
46
24
As at December 31, 2018, accounts receivable included approximately $16 million due from BEL (December 31, 2017 – $20 million)�
The Corporation periodically provides short-term financing to subsidiaries to support capital expenditure programs, acquisitions and seasonal
working capital requirements� There were no material inter-segment loans outstanding as at December 31, 2018 and 2017�
94
For the years ended December 31, 2018 and 2017FORTIS INC. 2018 ANNUAL REPORTNotes to Consolidated Financial Statements
REGULATED
NON-REGULATED
UNS Central FortisBC
Fortis FortisBC
Energy Alberta Electric
ITC
Energy Hudson
Other
Electric
Sub
total
Energy Corporate
and
Inter-
segment
Other eliminations
Infra-
structure
Total
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
Year Ended
December 31, 2017
(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
$ 1,504 $ 2,202 $ 924 $ 1,187
322
308
868
609
–
448
315
410
$ 579 $ 408 $ 1,412 $ 8,216
2,493
2,229
853
182
–
167
135
105
$
$ 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
19,798
998
4,691
433
10,182
599
6,815
486
3,670
245
2,244
106
$ 1,575 $ 2,080 $ 872 $ 1,198 $ 600 $ 398 $ 1,363 $ 8,086
2,360
2,200
711
609
411
300
836
171
–
198
–
433
260
399
142
90
220
922
37
259
371
329
57
–
260
500
19
101
148
270
–
–
65
148
5
41
42
70
–
–
198
289
22
116
40
155
1
–
190
212
2
93
1
120
–
–
62
104
2
37
14
55
–
–
150
206
1
74
22
111
13
–
1,145
2,381
88
721
638
1,110
71
–
$
27
1,478
44
$
–
127
7
$ 226
2
49
$
1
–
12
32
143
1
5
19
120
26
–
2
(13)
28
189
(69)
(105)
–
65
$ 272
$ 270 $
70 $ 154 $ 120 $
55 $
98 $ 1,039
$
94
$ (170)
Goodwill
Total assets
Capital expenditures
$ 7,698
17,581
982
$ 1,733 $ 566 $ 913 $ 227 $ 235 $ 245 $ 11,617
46,248
8,596
3,003
534
3,814
302
6,418
446
4,454
414
3,188
220
2,197
105
$
27
1,605
21
$
–
76
–
$
(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)
–
(12) $ 8,301
2,361
(1)
2,250
(11)
–
–
(1)
(1)
–
–
–
–
1,179
2,511
116
914
588
1,125
97
65
$
$
–
$
963
–
(107)
–
$ 11,644
47,822
3,024
95
FORTIS INC. 2018 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
Other revenue
$
2018
1,539
1,993
963
1,136
554
354
651
200
197
253
78
7,918
408
8,326
16
48
$
2017
1,583
1,875
814
1,244
593
347
666
191
197
222
71
7,803
395
8,198
(46)
149
Total revenue
(1) Includes $234 million and $217 million from regulated operations for 2018 and 2017, respectively
$
8,390
$
8,301
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) the sale of energy from non-regulated generation operations; (ii) management fee revenue at UNS Energy for the
operation of Springerville Units 3 and 4; (iii) revenue from storage optimization activities at Aitken Creek; 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 on the balance sheet�
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 1% 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�
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 requirements� This mechanism is in place until the expiry of the
current PBR plan in 2019� Additionally, variances in the forecast versus actual customer-use rate 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�
96
For the years ended December 31, 2018 and 2017FORTIS INC. 2018 ANNUAL REPORTNotes to Consolidated Financial Statements
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)
$
2018
538
575
(33)
1,080
91
186
$
2017
460
562
(31)
991
8
132
$
1,357
$
1,131
(1) Consists 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
2018
280
87
31
398
$
$
2017
238
97
32
367
$
$
97
FORTIS INC. 2018 ANNUAL REPORTNotes to Consolidated Financial Statements
9. REGULATORY ASSETS AND LIABILITIES
(in millions)
Regulatory assets
Deferred income taxes (Notes 3 and 24)
Employee future benefits (Notes 3 and 25)
Deferred energy management costs (i)
Deferred lease costs (ii)
Deferred operating overhead costs (iii)
Generation early retirement costs (iv)
Rate stabilization and related accounts (v)
Manufactured gas plant site remediation deferral (Note 18)
Derivatives (Notes 3 and 28)
Other regulatory assets (vi)
Total regulatory assets
Less: Current portion
Long-term regulatory assets
Regulatory liabilities
Deferred income taxes (Notes 3 and 24)
Asset removal cost provision (Note 3)
Rate stabilization and related accounts (v)
ROE complaints liability (Note 2)
Energy efficiency liability (vii)
Renewable energy surcharge (viii)
Electric and gas moderator account (ix)
Employee future benefits (Notes 3 and 25)
Other regulatory liabilities (vi)
Total regulatory liabilities
Less: Current portion
Long-term regulatory liabilities
$
2018
1,532
485
230
110
103
98
90
73
57
400
3,178
(324)
$
2,854
$
1,574
1,169
220
206
106
85
60
37
169
3,626
(656)
$
$
$
2017
1,403
510
200
104
91
105
95
75
87
375
3,045
(303)
2,742
1,484
1,095
254
182
82
66
58
47
178
3,446
(490)
$
2,970
$
2,956
(i)
(ii)
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�
Deferred Lease Costs
Deferred lease costs at FortisBC Electric primarily relate to the Brilliant Power Purchase Agreement (“BPPA”) (Note 17)� The depreciation of
the asset under capital lease and interest expense on the capital lease obligation are not being fully recovered in current customer rates
since these rates only reflect the cash payments required under 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�
(iii)
Deferred Operating Overhead Costs
FortisAlberta has deferred certain operating overhead costs for collection in future customer rates over the lives of the related PPE and
intangible assets�
98
For the years ended December 31, 2018 and 2017FORTIS INC. 2018 ANNUAL REPORTNotes to Consolidated Financial Statements
(iv)
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 allows
TEP and the co-owners of Navajo to continue operations through December 2019 and begin decommissioning activities thereafter� Related
retirement costs are being recovered through 2030�
(v)
(vi)
(vii)
(viii)
UNS Energy owns the Sundt Generating Facility (“Sundt”) and plans to early retire Sundt Units 1 and 2 by the end of 2020 as a result of the
approved addition of gas-fired generation capacity at Sundt� Capital and operating costs related to Sundt Units 1 and 2 are being recovered
through 2028 and 2030, respectively�
As a result of these planned early retirements, the associated assets and other related retirement costs were reclassified from PPE to
regulatory assets�
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)�
Other Regulatory Assets and Liabilities
This balance is 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 an 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 11)
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�
(ix)
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 $1,490 million and $1,464 million as at December 31, 2018 and 2017, 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�
99
FORTIS INC. 2018 ANNUAL REPORTNotes to Consolidated Financial Statements 10. ASSETS HELD FOR SALE
In 2018 Fortis solicited offers to sell its 51% ownership interest in the Waneta Expansion� In January 2019 the Corporation entered into a definitive
agreement with Columbia Power Corporation (“CPC”) and Columbia Basin Trust (“CBT”) to sell its interest for approximately $1 billion� CPC and CBT,
both 100% owned by the Government of British Columbia, are the Corporation’s partners and together currently own 49% of the Waneta Expansion�
Fortis expects the transaction to close in the second quarter of 2019 following the satisfaction of customary closing conditions� FortisBC Electric will
continue to operate the Waneta Expansion facility and purchase its surplus capacity� The related assets and liabilities have been classified as held for
sale and are detailed below�
(in millions)
Cash
Accounts receivable and other current assets
PPE
Intangible assets
Total assets held for sale
Accounts payable and other current liabilities
Other liabilities
Total liabilities associated with assets held for sale
2018
15
3
718
30
766
2
67
69
$
$
$
$
The non-controlling interest of $324 million remained classified in equity�
For both 2018 and 2017, the Waneta Expansion contributed $54 million to earnings before income tax expense, of which 51% is attributable to
common equity shareholders�
11. OTHER ASSETS
(in millions)
Supplemental Executive Retirement Plan
Renewable Energy Credits (Note 9 (viii))
Equity investment – BEL
Equity investment – Wataynikaneyap Partnership
Other investments
Defined benefit pension plan (Note 25)
Deferred compensation plan
Other (1)
2018
143
88
76
43
34
26
26
116
552
$
$
2017
130
62
73
22
29
31
24
109
480
$
$
(1) Other assets are generally recorded at cost and recovered or amortized over the estimated period of future benefit, where applicable� Other assets also include the fair value of
derivatives (Note 28)�
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 18)� 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
$72 million (2017 – $66 million), for which gains and losses are recognized in earnings�
100
For the years ended December 31, 2018 and 2017FORTIS INC. 2018 ANNUAL REPORTNotes to Consolidated Financial Statements
12. PROPERTY, PLANT AND EQUIPMENT
(in millions)
2018
Distribution
Electric
Gas
Transmission
Electric
Gas
Generation
Other
Assets under construction
Land
2017
Distribution
Electric
Gas
Transmission
Electric
Gas
Generation
Other
Assets under construction
Land
Cost
Accumulated
Depreciation
Net Book
Value
$ 10,880
4,767
$
(3,076)
(1,244)
$
7,804
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
$ 44,355
$ (11,701)
$ 32,654
$
9,963
4,093
$
(2,864)
(1,157)
$
12,571
1,954
6,079
3,608
1,717
264
(2,838)
(596)
(1,996)
(1,130)
–
–
7,099
2,936
9,733
1,358
4,083
2,478
1,717
264
$
40,249
$
(10,581)
$
29,668
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 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, 2018, assets under construction were primarily associated with ongoing transmission projects at ITC and the addition of gas-fired
generation capacity at UNS Energy�
The cost of PPE under capital lease as at December 31, 2018 was $656 million (December 31, 2017 – $423 million) and related accumulated
depreciation was $203 million (December 31, 2017 – $176 million)�
101
FORTIS INC. 2018 ANNUAL REPORTNotes to Consolidated Financial Statements
12.
PROPERTY, PLANT AND EQUIPMENT (cont’d)
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, 2018, 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
13. INTANGIBLE ASSETS
(in millions)
2018
Computer software
Land, transmission and water rights
Other
Assets under construction
2017
Computer software
Land, transmission and water rights
Other
Assets under construction
Ownership
(%)
50�0
7�0
33�3
25�0
83�0
1�0–80�0
$
Cost
397
239
79
45
284
1,018
Accumulated
Depreciation
Net Book
Value
$
(183)
(104)
(5)
(16)
(117)
(397)
$
214
135
74
29
167
621
$
2,062
$
(822)
$
1,240
$
Cost
860
855
120
81
$
1,916
$
784
743
117
63
$
1,707
Accumulated
Amortization
$
$
$
$
(533)
(125)
(58)
–
(716)
(474)
(103)
(49)
–
(626)
Net Book
Value
$
327
730
62
81
$
1,200
$
310
640
68
63
$
1,081
Included in the cost of land, transmission and water rights as at December 31, 2018 was $131 million (December 31, 2017 – $150 million) not subject to
amortization� Amortization expense was $106 million for 2018 (2017 – $97 million)� Amortization is estimated to average approximately $81 million for
each of the next five years�
102
For the years ended December 31, 2018 and 2017FORTIS INC. 2018 ANNUAL REPORTNotes to Consolidated Financial Statements
14. GOODWILL
(in millions)
Balance, beginning of year
Acquisition of ITC
Foreign currency translation impacts (1)
Balance, end of year
2018
$ 11,644
–
886
$ 12,530
$
2017
12,364
(6)
(714)
$
11,644
(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 2018 or 2017�
15. ACCOUNTS PAYABLE AND OTHER CURRENT LIABILITIES
(in millions)
Trade accounts payable
Gas and fuel cost payable
Customer and other deposits
Interest payable
Accrued taxes other than income taxes
Dividends payable
Employee compensation and benefits payable
Fair value of derivatives (Note 28)
Manufactured gas plant site remediation (Note 18)
Defined benefit pension and OPEB liabilities (Note 25)
Other
$
2018
679
281
267
230
206
199
193
69
32
25
108
$
2017
696
146
204
223
178
185
184
71
35
22
109
$
2,289
$
2,053
103
FORTIS INC. 2018 ANNUAL REPORTNotes to Consolidated Financial Statements
16. LONG-TERM DEBT
(in millions)
Maturity Date
2018
2017
ITC
Secured US First Mortgage Bonds –
4�51% weighted average fixed rate (2017 – 4�67%)
Secured US Senior Notes –
4�19% weighted average fixed rate (2017 – 4�19%)
Unsecured US Senior Notes –
3�91% weighted average fixed rate (2017 – 3�91%)
Unsecured US Shareholder Note –
6�00% fixed rate (2017 – 6�00%)
Unsecured US Term Loan Credit Agreement –
2�03% weighted average variable rate
UNS Energy
Unsecured US Tax-Exempt Bonds – 4�66% weighted
average fixed and variable rate (2017 – 4�04%)
Unsecured US Fixed Rate Notes –
4�38% weighted average fixed rate (2017 – 4�26%)
Central Hudson
Unsecured US Promissory Notes – 4�43% weighted
average fixed and variable rate (2017 – 4�28%)
FortisBC Energy
Unsecured Debentures –
5�03% weighted average fixed rate (2017 – 5�13%)
FortisAlberta
Unsecured Debentures –
4�64% weighted average fixed rate (2017 – 4�70%)
FortisBC Electric
Secured Debentures –
8�80% fixed rate (2017 – 8�80%)
Unsecured Debentures –
5�05% weighted average fixed rate (2017 – 5�05%)
Other Electric
Secured First Mortgage Sinking Fund Bonds –
6�14% weighted average fixed rate (2017 – 6�14%)
Secured First Mortgage Bonds –
5�66% weighted average fixed rate (2017 – 6�19%)
Unsecured Senior Notes –
4�45% weighted average fixed rate (2017 – 6�11%)
Unsecured US Senior Loan Notes and Bonds – 4�76% weighted
average fixed and variable rate (2017 – 4�80%)
Corporate
Unsecured US Senior Notes and Promissory Notes –
3�41% weighted average fixed rate (2017 – 3�41%)
Unsecured Debentures –
6�50% weighted average fixed rate (2017 – 6�50%)
Unsecured Senior Notes – 2�85% fixed rate (2017 – 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
104
2020–2055
$
2,652
$
2,063
2040–2046
2020–2043
2028
n/a
2020–2040
2021–2048
648
3,751
271
–
654
1,943
2019–2057
938
2026–2048
2,595
2024–2052
2,185
2023
2021–2050
2020–2057
2025–2061
2041–2048
2020–2048
2019–2044
2039
2023
25
710
578
220
152
584
4,398
200
500
1,066
161
24,231
(146)
(926)
596
3,451
250
63
773
1,411
770
2,395
2,035
25
710
585
195
104
525
4,046
200
500
671
167
21,535
(139)
(705)
$ 23,159
$
20,691
For the years ended December 31, 2018 and 2017FORTIS INC. 2018 ANNUAL REPORTNotes to Consolidated Financial Statements
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 has covenants restricting the issuance of additional debt such that consolidated debt cannot exceed 70%
of the Corporation’s consolidated capital structure�
One long-term debt obligation at the Corporation has a covenant which provides that Fortis shall not declare or pay any dividends, other than stock
dividends or cumulative preferred dividends on preference shares not issued as stock dividends, make any other distribution on its shares, redeem
any of its shares or prepay subordinated debt if, immediately thereafter, its consolidated funded obligations would exceed 75% of its total
consolidated capitalization�
Long-Term Debt Issuances
(in millions, except %)
ITC
First mortgage bonds
First mortgage bonds
UNS Energy
Unsecured notes
Central Hudson
Unsecured notes
Unsecured notes
Unsecured notes
FortisBC Energy
Unsecured debentures
FortisAlberta
Unsecured debentures
FortisOntario
Unsecured notes
Maritime Electric
First mortgage bonds
FortisTCI
Unsecured notes
Unsecured non-revolving term loan (7)
(1) Repay maturing long-term debt
(2) Repay credit facility borrowings
(3) Finance capital expenditures
(4) General corporate purposes
(5) Floating rate of a one-month LIBOR plus a spread of 1�75%
(6) Repay a hurricane-related emergency standby loan
(7) Maximum amount of borrowings under this agreement is US$10 million�
Month Issued
Interest
Rate
(%)
Maturity
Amount
Use of
Proceeds
March
November
November
June
October
October
December
September
August
December
February
September
4�00
4�32
4�85
4�27
3�99
4�21
3�85
3�73
4�10
4�15
(5)
(5)
2053
2051
US 225
US 175
2048
US 300
2048
2026
2033
2048
2048
2048
2058
2023
2025
US 25
US 40
US 40
200
150
100
40
US 25
US 5
(1) (2) (3) (4)
(2) (3) (4)
(1) (4)
(3) (4)
(1) (3) (4)
(1) (3) (4)
(2) (4)
(2) (4)
(1) (4)
(2) (4)
(6)
(4)
105
FORTIS INC. 2018 ANNUAL REPORTNotes to Consolidated Financial Statements
16.
LONG-TERM DEBT (cont’d)
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)
2019
2020
2021
2022
2023
Thereafter
Credit Facilities
Total
(in millions)
$
926
731
1,324
1,125
1,605
18,520
$
24,231
As at December 31, 2018, the Corporation and its subsidiaries had consolidated credit facilities of approximately $5�2 billion, of which approximately
$3�9 billion was unused, including $1�0 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
$
3,780
(60)
(731)
(65)
Corporate
and Other
$
1,385
–
(335)
(54)
2018
$
5,165
2017
4,952
$
(60)
(1,066)
(119)
(209)
(671)
(129)
$
2,924
$
996
$
3,920
$
3,943
(1) The weighted average interest rate was approximately 4�2% (December 31, 2017 – 1�8%)�
(2) The weighted average interest rate was approximately 3�3% (December 31, 2017 – 2�5%)� The current portion was $735 million (December 31, 2017 – $312 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�0 billion of the total credit facilities are committed facilities with maturities ranging from 2019 through 2023�
106
For the years ended December 31, 2018 and 2017FORTIS INC. 2018 ANNUAL REPORTNotes to Consolidated Financial Statements
Consolidated credit facilities of approximately $5�2 billion as at December 31, 2018 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
Corporate and Other
Other facilities
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
US
40
10
25
60
35
October 2022
October 2022
(2)
August 2023
August 2023
April 2023
(3)
January 2020
(4)
n/a
n/a
n/a
April 2019
n/a
(1) ITC also has a US$400 million commercial paper program, under which no amounts were outstanding as at December 31, 2018�
(2) US$50 million in July 2020 and US$200 million in October 2020
(3) $50 million in February 2019, $40 million in June 2021, and $100 million in August 2023
(4) $1�3 billion in July 2023, with the option to increase by an amount up to $500 million, and $50 million in April 2021
17. CAPITAL LEASE AND FINANCE OBLIGATIONS
Capital Lease Obligations
UNS Energy
Following the acquisition of Gila River generating station Units 1 and 2 by a third party with whom TEP has a power purchase agreement, TEP
anticipates exercising its option to purchase Gila River Unit 2 in December 2019 for approximately $224 million (US$164 million)� Over the 20-month
lease term, TEP will pay a monthly demand charge consisting of a capacity charge and an operating fee�
For 2018 $10 million (2017 – nil) of demand charges were recognized related to the Gila River Unit 2 capital lease obligation�
TEP is party to two Springerville Common Facilities leases with fixed purchase options totalling US$68 million and initial terms to January 2021� TEP
has the option to renew the leases for periods of two or more years or exercise the purchase options� Additionally, TEP has entered into agreements
with third parties that if the Springerville Common Facilities leases are not renewed, TEP will exercise the purchase options thereunder and the third
parties would be obligated to buy a portion of these facilities or continue to make payments to TEP for their use�
The Springerville Common Facilities lease obligations bear interest at a six-month LIBOR plus a spread of 2�00%� TEP holds an interest rate swap
that effectively fixes the LIBOR rate at 5�77% on $16 million (December 31, 2017 – $23 million) of the total lease obligation of $19 million
(December 31, 2017 – $26 million)� The swap is recognized as a cash flow hedge (Note 28)�
For 2018 $3 million (2017 – $4 million) of interest expense and $8 million (2017 – $8 million) of depreciation expense was recognized related to the
Springerville capital lease obligation�
107
FORTIS INC. 2018 ANNUAL REPORTNotes to Consolidated Financial Statements
17.
CAPITAL LEASE AND FINANCE OBLIGATIONS (cont’d)
FortisBC Electric
FortisBC Electric has a capital lease obligation with respect to the operation of the Brilliant hydroelectric plant (“Brilliant Plant”) in British Columbia�
FortisBC Electric operates and maintains the Brilliant Plant under the BPPA, which expires in 2056, in return for a management fee� In exchange for the
specified take-or-pay amounts of power, the BPPA requires semi-annual payments based on a return on capital, comprised of the original plant
capital charge and periodic upgrade capital charges, which are both subject to fixed annual escalators, as well as sustaining capital charges and
operating expenses� The BPPA includes a market-related price adjustment in 2026� Approximately 94% of the output from the Brilliant Plant is
purchased by FortisBC Electric through the BPPA� The capital lease obligation bears interest at a composite rate of 5�00%� Included in energy supply
costs was $28 million (2017 – $27 million) recognized in accordance with the BPPA, as approved by the BCUC�
FortisBC Electric also has a capital lease obligation with respect to the operation of the Brilliant Terminal Station (“BTS”) under an agreement, which
expires in 2056� The agreement provides that FortisBC Electric will pay a charge related to the recovery of the capital cost of the BTS and related
operating costs� The obligation bears interest at a composite rate of 9�00%� Included in operating expenses was $3 million (2017 – $3 million)
recognized in accordance with the BTS agreement, as approved by the BCUC�
Finance Obligations
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�90% to 7�48% 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 October 2018 FortisBC Energy exercised an early termination payment option in the amount
$27 million on one of these arrangements�
Capital Lease and Finance Obligations Repayments
Present values of the minimum lease payments over the next five years and thereafter are as follows�
Total
(in millions)
$
$
$
313
77
80
49
47
1,885
2,451
(1,809)
642
(252)
390
(year)
2019
2020
2021
2022
2023
Thereafter
Less: Imputed interest and executory costs
Total capital lease and finance obligations
Less: Current installments
108
For the years ended December 31, 2018 and 2017FORTIS INC. 2018 ANNUAL REPORTNotes to Consolidated Financial Statements
18. OTHER LIABILITIES
(in millions)
Defined benefit pension plans (Note 25)
OPEBs (Note 25)
Asset retirement obligations (Note 3)
Customer and other deposits
Stock-based compensation plans (Note 22)
Mine reclamation obligations (1)
Manufactured gas plant site remediation (2)
Fair value of derivatives (Note 28)
Deferred compensation plan (Note 11)
Waneta Partnership promissory note (Note 10)
Other (3)
$
2018
391
350
111
57
56
40
32
30
29
–
42
$
2017
393
381
71
67
39
40
34
37
28
63
57
(1) TEP pays ongoing reclamation costs related to three 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 $90 million (US$66 million) upon
expiry of the coal agreements between 2019 and 2031� The present value of the estimated future liability is shown in the table above�
(2) 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, 2018, an obligation of $64 million
(US$47 million) was recognized, including a current portion of $32 million (US$23 million) recognized in accounts payable and other current liabilities (Note 15)� 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)�
(3) Primarily includes long-term accrued liabilities, deferred lease revenue, funds received in advance of expenditures and unrecognized tax benefits�
$
1,138
$
1,210
19. EARNINGS PER COMMON SHARE
Diluted earnings per share (“EPS”) was calculated using the treasury stock method for options�
2018
Net Earnings Weighted
Average
to Common
Shares
Shareholders
(in millions)
(in millions)
Basic EPS
Potential dilutive effect of stock options
Diluted EPS
$ 1,100
–
$ 1,100
424.7
0.5
425.2
$ 2.59
EPS
$ 2.59
Net Earnings
to Common
Shareholders
(in millions)
$
$
963
–
963
2017
Weighted
Average
Shares
(in millions)
415�5
0�7
EPS
$
2�32
416�2
$
2�31
109
FORTIS INC. 2018 ANNUAL REPORTNotes to Consolidated Financial Statements
20. PREFERENCE SHARES
Authorized
An unlimited number of First Preference Shares and Second Preference Shares, without nominal or par value�
Issued and Outstanding
2018
2017
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
Characteristics of the First Preference Shares are as follows�
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
First Preference Shares (1) (2)
Perpetual fixed rate
Series F
Series J (3)
Fixed rate reset (4) (5)
Series G (6)
Series H
Series K
Series M
Floating rate reset (5) (7)
Series I (3)
Series L
Series N
4�90
4�75
5�25
4�25
4�00
4�10
2�10
–
–
1�2250
1�1875
1�0983
0�6250
1�0000
1�0250
–
–
–
–
–
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�75
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 G was reset from $0�9708 to $1�0983 for the five-year period from September 1, 2018 up to but excluding
September 1, 2023�
(7) 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�
110
For the years ended December 31, 2018 and 2017FORTIS INC. 2018 ANNUAL REPORTNotes to Consolidated Financial Statements
21. ACCUMULATED OTHER COMPREHENSIVE INCOME
(in millions)
Opening Balance
Net Change
Ending Balance
2018
Unrealized foreign currency translation gains (losses)
On net investments in foreign operations
On hedges of net investments in foreign operations
Income tax (expense) recovery
Other
Cash flow hedges (Note 28)
Unrealized employee future benefits (losses) gains (Note 25)
Income tax recovery (expense)
Accumulated other comprehensive income
2017
Unrealized foreign currency translation gains (losses)
On net investments in foreign operations
On hedges of net investments in foreign operations
Income tax recovery (expense)
Other
Cash flow hedges (Note 28)
Unrealized employee future benefits losses (Note 25)
Income tax recovery
$
$
$
247
(172)
(1)
74
10
(26)
3
(13)
61
1,227
(472)
1
756
8
(22)
3
(11)
$
1,223
(372)
11
862
1
6
(2)
5
$
1,470
(544)
10
936
11
(20)
1
(8)
$
867
$
928
$
$
(980)
300
(2)
(682)
2
(4)
–
(2)
247
(172)
(1)
74
10
(26)
3
(13)
61
Accumulated other comprehensive income
$
745
$
(684)
$
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 2018 and 2017�
Options granted (#)
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)
2018
February
721,536
41.27
3.43
3.7
15.5
2.1
5.6
March
39,972
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
2017
February
774,924
42�36
3�22
3�8
16�1
1�2
5�6
111
FORTIS INC. 2018 ANNUAL REPORTNotes to Consolidated Financial Statements
22.
STOCK-BASED COMPENSATION PLANS (cont’d)
Stock Options (cont’d)
The following table summarizes information related to stock options for 2018�
Options outstanding, January 1, 2018
Granted
Exercised
Vested
Cancelled/Forfeited
Options outstanding, December 31, 2018
Options vested, December 31, 2018 (2)
Total Options
Non-vested Options (1)
Weighted
Average
Exercise
Price
($)
36.65
41.31
33.49
n/a
40.44
37.73
35.40
Weighted
Average
Grant Date
Fair Value
($)
2.86
3.46
n/a
2.88
3.08
3.10
Number of
Options
1,812,319
761,508
n/a
(711,484)
(91,216)
1,771,127
Number of
Options
3,702,294
761,508
(357,120)
n/a
(91,216)
4,015,466
2,244,339
(1) As at December 31, 2018, there was $5 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, 2018, the weighted average remaining term of vested options was six years with an aggregate intrinsic value of $23 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
Directors’ DSU Plan
$
2018
2
12
3
2
$
2017
3
40
15
2
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
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)
(1) Reflects a weighted-average payout price of $43�15 per DSU (2017 – $45�37)
(2) Recognized at the respective December 31st VWAP (Note 3) and included in long-term other liabilities (Note 18)
112
2018
184,795
32,132
7,518
(47,898)
176,547
$
2
2
8
2017
199,411
31,453
7,294
(53,363)
184,795
$
3
2
9
For the years ended December 31, 2018 and 2017FORTIS INC. 2018 ANNUAL REPORTNotes to Consolidated Financial Statements
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
Beginning of year
Granted
Notional dividends reinvested
Paid out
Cancelled/forfeited
Transferred to RSU Plan
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)
2018
1,350,960
668,995
66,280
(280,993)
(42,471)
–
1,762,771
$
22
27
14
50
77
2017
931,951
711,749
44,893
(239,509)
(16,910)
(81,214)
1,350,960
$
26
17
11
41
58
(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 $46�01 per PSU and a payout percentage of 109% (2017 – $41�46 and 113%, 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 15 and 18)
(4) Relates to outstanding PSUs and reflects a weighted-average contractual life of one year
113
FORTIS INC. 2018 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
Beginning of year
Granted
Notional dividends reinvested
Paid out
Cancelled/forfeited
Transferred from PSU plan
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)
2018
482,763
305,686
26,263
(75,427)
(22,267)
–
717,018
$
11
15
3
19
34
2017
123,612
349,496
15,407
(74,876)
(12,090)
81,214
482,763
$
8
11
3
11
22
(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�55 per RSU (2017 – $43�42)
(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 15 and 18)
(4) Relates to outstanding RSUs and reflects a weighted-average contractual life of one year
23. OTHER INCOME, NET
(in millions)
Equity component of AFUDC
Interest income
Equity (loss) income – BEL
Net periodic pension cost
Net foreign exchange gain (1)
Other
(1) Includes a one-time $21 million unrealized foreign exchange gain on US dollar-denominated affiliate loan in 2017
2018
64
15
(1)
(1)
–
(17)
60
$
$
$
2017
74
14
4
(11)
26
9
$
116
114
For the years ended December 31, 2018 and 2017FORTIS INC. 2018 ANNUAL REPORTNotes to Consolidated Financial Statements
24. INCOME TAXES
Deferred Income Tax Assets and Liabilities
The significant components of deferred income tax assets and liabilities consist 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
$
2018
635
522
153
69
76
1,455
(56)
$
1,399
$
(3,780)
(203)
(102)
(4,085)
$
(2,686)
$
$
$
2017
596
571
143
28
51
1,389
(44)
1,345
(3,353)
(203)
(87)
(3,643)
$
(2,298)
The deferred income tax assets associated with unrealized foreign exchange losses on long-term debt reflect $56 million of unrealized capital losses
as at December 31, 2018 (December 31, 2017 – $44 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�
Unrecognized Tax Benefits
(in millions)
Beginning of year
Additions related to the current year
Adjustments related to prior years and U�S� Tax Reform
End of year
2018
28
6
4
38
$
$
2017
23
13
(8)
28
$
$
Unrecognized tax benefits, if recognized, would reduce income tax expense by $1 million in 2018� Fortis has not recognized interest expense in 2018
and 2017 related to unrecognized tax benefits�
115
FORTIS INC. 2018 ANNUAL REPORTNotes to Consolidated Financial Statements
24.
INCOME TAXES (cont’d)
Income Tax Expense
(in millions)
Canadian
Earnings before income tax expense
Current income tax
Deferred income tax
Foreign
Earnings before income tax expense
Current income tax
Deferred income tax
Income tax expense
2018
2017
$
376
$
461
51
(25)
26
$
$
1,075
(22)
161
139
165
$
$
41
16
57
1,252
3
528
531
588
$
$
$
$
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
Increase (decrease) resulting from:
Enactment of U�S� Tax Reform (1)
Foreign and other statutory rate differentials
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
2018
1,451
28.5%
414
$
$
–
(110)
(44)
(14)
(34)
(21)
(26)
2017
1,713
28�0%
480
$
$
168
31
–
(26)
(26)
(21)
(18)
$
165
11.4%
$
588
34�3%
(1) In 2017 the Tax Cuts and Jobs Act implemented significant changes to U�S� tax legislation, including a reduction in the U�S� federal corporate income tax from 35% to 21%,
effective January 1, 2018� The Corporation’s U�S� utilities and holding companies were required to remeasure their deferred tax assets and liabilities at the new corporate income
tax rate as at the date of enactment� The one-time remeasurement resulted in an unfavourable earnings impact of $168 million recognized in deferred income tax expense
($146 million after non-controlling interest)�
116
For the years ended December 31, 2018 and 2017FORTIS INC. 2018 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
2025–2038
2026–2037
2022–2038
2021–2038
$
2018
59
387
2
448
(15)
433
2,130
115
2,245
Total income tax carryforwards recognized as at December 31
$
2,678
The Corporation and one or more 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 examinations include the United States (Federal, Arizona, Kansas, Iowa, Michigan,
Minnesota and New York) and Canada (Federal and British Columbia)� The Corporation’s 2012 to 2018 taxation years are still open for audit in the
Canadian jurisdictions and its 2014 to 2018 taxation years are still open for audit in the United States jurisdictions�
25. 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, 2015 for FortisBC Energy (plan covering non-unionized employees);
December 31, 2016 for FortisBC Electric and FortisBC Energy (plans covering unionized employees); December 31, 2017 for Newfoundland Power,
FortisAlberta, FortisOntario and the Corporation; and December 31, 2018 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�
Allocation of Plan Assets as at December 31
(weighted-average %)
Equities
Fixed income
Real estate
Cash and other
2018 Target
Allocation
46
47
6
1
100
2018
45
47
7
1
100
2017
47
46
6
1
100
117
FORTIS INC. 2018 ANNUAL REPORTNotes to Consolidated Financial Statements
25.
EMPLOYEE FUTURE BENEFITS (cont’d)
Fair value of plan assets as at December 31
(in millions)
2018
Equities
Fixed income
Real estate
Private equities
Cash and other
2017
Equities
Fixed income
Real estate
Private equities
Cash and other
Level 1 (1)
Level 2 (1)
Level 3 (1)
$
$
$
$
508
144
–
–
8
660
522
133
–
–
8
663
$
885
1,338
14
–
11
$
2,248
$
949
1,289
13
–
14
$
2,265
$
$
$
$
–
–
190
25
–
215
–
–
168
22
–
190
(1) Refer to Note 28 for a description of the fair value hierarchy�
The following table reconciles the changes in the fair value of pension 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
2018
190
15
3
7
215
$
$
$
Total
1,393
1,482
204
25
19
$
3,123
$
$
$
$
1,471
1,422
181
22
22
3,118
2017
113
12
(2)
67
190
118
For the years ended December 31, 2018 and 2017FORTIS INC. 2018 ANNUAL REPORTNotes to Consolidated Financial Statements
Funded Status
(in millions)
Change in benefit obligation (1)
Balance, beginning of year
Service costs
Employee contributions
Interest costs
Benefits paid
Actuarial losses (gains)
Past service credits/plan amendments
Foreign currency translation
Balance, end of year (2)
Change in value of plan assets
Balance, beginning of year
Actual return on plan assets
Benefits paid
Employee contributions
Employer contributions
Foreign currency translation
Balance, end of year
Funded status
Balance sheet presentation
Long-term assets (Note 11)
Current liabilities (Note 15)
Long-term liabilities (Note 18)
Defined Benefit
Pension Plans
$
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)
2017
3,037
76
16
115
(133)
217
–
(113)
3,215
2,646
336
(127)
16
69
(99)
2,841
(374)
31
(12)
(393)
(374)
$
$
$
$
$
$
$
OPEB Plans
2018
2017
$
$
$
$
$
$
665
31
2
23
(26)
(69)
(3)
32
655
277
(13)
(26)
2
29
24
293
(362)
1
(13)
(350)
$
(362)
$
$
$
$
$
$
$
676
27
2
25
(22)
(14)
(3)
(26)
665
252
37
(22)
2
26
(18)
277
(388)
3
(10)
(381)
(388)
(1) Amounts reflect projected benefit obligation for defined benefit pension plans and accumulated benefit obligation for OPEB plans�
(2) The accumulated benefit obligation for defined benefit pension plans, excluding assumptions about future salary levels, was $2,936 million as at December 31, 2018
(December 31, 2017 – $2,940 million)�
Net Benefit Cost
Defined Benefit
Pension Plans
(in millions)
Service costs
Interest costs
Expected return on plan assets
Amortization of actuarial losses
Amortization of past service credits/plan amendments
Regulatory adjustments
$
2018
84
114
(162)
48
–
(1)
Net benefit cost
$
83
2017
76
115
(151)
45
–
2
87
$
$
OPEB Plans
2018
2017
$
$
31
23
(16)
–
(10)
6
34
$
$
27
25
(14)
2
(12)
4
32
119
FORTIS INC. 2018 ANNUAL REPORTNotes to Consolidated Financial Statements
25.
EMPLOYEE FUTURE BENEFITS (cont’d)
Net Benefit Cost (cont’d)
The following table summarizes the accumulated amounts of net benefit cost that have not yet been recognized in earnings or comprehensive
income and shows their classification on the consolidated balance sheets�
(in millions)
Unamortized net actuarial losses (gains)
Unamortized past service costs
Income tax recovery
Accumulated other comprehensive income (Note 21)
Net actuarial losses (gains)
Past service credits
Other regulatory deferrals
Regulatory assets (Note 9)
Regulatory liabilities (Note 9)
Net regulatory assets
Defined Benefit
Pension Plans
OPEB Plans
2018
2017
2018
2017
$
$
$
$
$
$
19
1
(3)
17
457
(10)
15
462
462
–
462
$
$
$
$
$
$
22
1
(5)
18
443
(11)
10
442
442
–
442
$
$
$
$
$
$
(2)
2
(1)
(1)
(25)
(16)
27
(14)
23
(37)
(14)
$
$
$
$
$
$
–
3
(1)
2
17
(23)
27
21
68
(47)
21
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)
2018
2017
2018
2017
Defined Benefit
Pension Plans
OPEB Plans
Current year net actuarial (gains) losses
Past service (credits) costs/plan amendments
Amortization of actuarial losses
Foreign currency translation
Income tax recovery
Total recognized in comprehensive income
Current year net actuarial losses (gains)
Past service credits/plan amendments
Amortization of actuarial losses
Amortization of past service (costs) credits
Foreign currency translation
Regulatory adjustments
Total recognized in regulatory assets
$
$
$
$
(3)
–
(1)
1
2
(1)
41
–
(47)
1
21
4
20
$
$
$
$
5
–
(1)
(1)
–
3
24
–
(44)
–
(17)
(1)
(38)
$
$
$
$
(2)
(1)
–
–
–
(3)
(39)
(3)
–
11
(3)
(1)
(35)
$
$
$
$
(1)
2
–
–
–
1
(35)
(5)
(1)
12
2
(6)
(33)
Net actuarial losses of $1 million are expected to be amortized to net benefit cost from accumulated other comprehensive income in 2019 related to
defined benefit pension plans�
Net actuarial losses of $24 million, past service credits of $1 million and regulatory adjustments of $1 million are expected to be amortized to net
benefit cost from regulatory assets in 2019 related to defined benefit pension plans� Past service credits of $8 million, net actuarial gains of $4 million
and regulatory adjustments of $4 million are expected to be amortized to net benefit cost from regulatory assets in 2019 related to OPEB plans�
120
For the years ended December 31, 2018 and 2017FORTIS INC. 2018 ANNUAL REPORTNotes to Consolidated Financial Statements
Significant Assumptions
Defined Benefit
Pension Plans
OPEB Plans
(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)
2018
3.56
4.07
5.80
3.35
–
2017
3�98
3�58
5�97
3�34
–
2018
3.57
4.13
5.48
–
4.61
2017
3�96
3�59
5�81
–
4�71
(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 with assistance from external actuaries 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 2019 weighted-average health care cost trend rate for OPEB plans is 6�35% and is assumed to decrease over the next 14 years to the weighted-average ultimate
health care cost trend rate of 4�61% in 2032 and thereafter�
The following table summarizes for 2018 the effects of changing the health care cost trend rate by 1%�
(in millions)
Increase (decrease) in accumulated benefit obligation
Increase (decrease) in service and interest costs
Expected Benefit Payments
(year)
2019
2020
2021
2022
2023
2024–2028
1% increase
$
85
11
1% decrease
$
(67)
(8)
Defined Benefit
Pension Payments
(in millions)
$
147
152
157
165
170
946
OPEB
(in millions)
$
26
28
30
32
33
185
During 2019 the Corporation expects to contribute $47 million for defined benefit pension plans and $31 million for OPEB plans�
In 2018 the Corporation expensed $38 million (2017 – $38 million) related to defined contribution pension plans�
26. TERMINATED ACQUISITION
In May 2017 Fortis had entered into an agreement with Teck Resources Limited to acquire a two-thirds ownership interest in the Waneta Dam and
related transmission assets in British Columbia� In August 2017 BC Hydro exercised its right of first offer in this regard� Consequently, the purchase
agreement with Fortis was terminated, resulting in the payment of a $28 million break fee to Fortis, which was recognized in operating expenses�
121
FORTIS INC. 2018 ANNUAL REPORTNotes to Consolidated Financial Statements
27. SUPPLEMENTARY CASH FLOW INFORMATION
(in millions)
Cash paid 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
Gila River generating station Unit 2 capital lease
Contributions in aid of construction
Exercise of stock options into common shares
$
$
$
$
2018
969
73
(204)
1
(8)
16
99
(6)
(102)
328
272
223
14
1
$
$
$
$
2017
927
69
(74)
(3)
(6)
39
119
(172)
(97)
307
253
–
35
5
28. FAIR VALUE OF FINANCIAL INSTRUMENTS AND RISK MANAGEMENT
Derivatives
The Corporation generally limits the use of derivatives to those that qualify as accounting, economic or cash flow hedges, or those that are approved
for regulatory recovery�
The Corporation records all derivatives at fair value, with certain exceptions, including those derivatives that qualify for the normal purchase and
normal sale exception� Fair values reflect estimates based on current market information about the derivatives as at the balance sheet dates� The
estimates cannot be determined with precision as they involve uncertainties and matters of judgment and, therefore, may not be relevant in
predicting the Corporation’s future consolidated earnings or cash flows�
Cash flows associated with the settlement of all derivatives are included in operating activities in the consolidated statements of cash flows�
Energy contracts subject to regulatory deferral
UNS Energy holds electricity power purchase 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 financial 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, 2018, unrealized losses of $57 million
(December 31, 2017 – $87 million) were recognized as regulatory assets and unrealized gains of $9 million (December 31, 2017 – $2 million) were
recognized in regulatory liabilities (Note 9)�
122
For the years ended December 31, 2018 and 2017FORTIS INC. 2018 ANNUAL REPORTNotes to Consolidated Financial Statements
Energy contracts not subject to regulatory deferral
UNS Energy holds wholesale trading contracts that qualify as derivatives to fix power prices and realize potential margin, of which 10% of any realized
gains are shared with customers through rate stabilization accounts� Fair values were measured using a market approach using 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 earnings� During 2018 unrealized
losses of $12 million (2017 – unrealized gains of $36 million) were recognized in revenue�
Foreign exchange contracts
The Corporation holds US dollar foreign exchange contracts to mitigate exposure to volatility of foreign exchange rates� The contracts expire in 2019
and have a combined notional amount of $161 million� Fair value was measured using independent third-party information�
Unrealized gains and losses associated with changes in fair value are recognized in earnings� During 2018 unrealized losses of $11 million
(2017 – unrealized gains of $3 million) were recognized in other income, net�
Interest rate and total return swaps
UNS Energy holds an interest rate swap to mitigate exposure to volatility in variable interest rates on capital lease obligations (Note 17)� The swap
expires in 2020 and has a notional amount of $16 million� Fair value was measured using an income valuation approach based on six-month LIBOR�
Unrealized gains and losses associated with changes in the fair value of this interest rate swap, which was designated as a cash flow hedge, are
recognized in other comprehensive income and reclassified to earnings through interest expense over the life of the hedged debt� The loss
expected to be reclassified to earnings within the next 12 months is estimated to be approximately $3 million, net of tax�
The Corporation holds three 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 $41 million and terms ranging from one to three years,
expiring in January 2019, 2020 and 2021� Fair value was measured using an income valuation approach based on forward pricing curves�
Unrealized gains and losses associated with changes in the fair value of the total return swaps are recognized in earnings� During 2018 unrealized
gains of less than $1 million (2017 – unrealized losses of less than $1 million) were recognized in other income, net�
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 earnings� During 2018 unrealized gains of less than $1 million (2017 – unrealized gains of less than
$1 million) were recognized in other income, net�
123
FORTIS INC. 2018 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 the assets and liabilities that are 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, 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 (6)
As at December 31, 2017
Assets
Energy contracts subject to regulatory deferral (2) (3)
Energy contracts not subject to regulatory deferral (2)
Foreign exchange contracts (6)
Other investments (4)
Liabilities
Energy contracts subject to regulatory deferral (3) (5)
Energy contracts not subject to regulatory deferral (5)
Interest rate and total return swaps (6)
$
$
$
$
$
$
$
$
–
–
155
155
–
–
(8)
(8)
–
–
3
78
81
(1)
–
–
(1)
$
$
$
$
$
$
$
$
33
13
–
46
(86)
(1)
(1)
(88)
19
26
–
–
45
(103)
–
(1)
(104)
$
$
$
$
$
$
$
$
8
3
–
11
(3)
–
–
(3)
2
4
–
–
6
(2)
(1)
–
(3)
$
$
$
$
$
$
$
$
41
16
155
212
(89)
(1)
(9)
(99)
21
30
3
78
132
(106)
(1)
(1)
(108)
(1) Under the hierarchy, fair value is determined using: (i) level 1 – unadjusted quoted prices in active markets; (ii) level 2 – other pricing inputs directly or indirectly observable in
the marketplace; and (iii) level 3 – unobservable inputs, used when observable inputs are not available� Classifications reflect the lowest level of input that is significant to the
fair value measurement�
(2) Included in 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, with the exception of long-term wholesale trading contracts and certain gas swap contracts�
Included in other assets
(4)
(5) Included in accounts payable and other current liabilities or other liabilities
(6) Included in accounts receivable and other current assets, accounts payable and other current liabilities or other liabilities
Changes in economic conditions or model-based valuation techniques may require the transfer of financial instruments from one hierarchical fair
value level to another� There were no transfers between levels during 2018�
For level 3 measurements, changes in the unobservable inputs could have a significant impact on fair value� Excluding long-term wholesale trading
contracts and certain gas swap contracts, the impacts of fair value changes are subject to regulatory recovery�
124
For the years ended December 31, 2018 and 2017FORTIS INC. 2018 ANNUAL REPORTNotes to Consolidated Financial Statements
The following table reconciles changes in the fair value of level 3 net assets and liabilities�
(in millions)
Balance, beginning of year
Realized gains (losses)
Settlements
Transfers of assets out of level 3
Transfers of liabilities out of level 3
Balance, end of year
2018
3
14
(9)
–
–
8
$
$
2017
2
(13)
12
(2)
4
3
$
$
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, 2018
Derivative assets
Derivative liabilities
As at December 31, 2017
Derivative assets
Derivative liabilities
Gross Amount
Recognized on
Balance Sheet
Counterparty
Netting of
Energy Contracts
Cash Collateral
Received/Posted
Net Amount
$
$
57
(90)
51
(107)
$
$
28
(28)
17
(17)
$
$
16
–
7
–
$
$
13
(62)
27
(90)
Volume of Derivative Activity
As at December 31, 2018, 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�
2018
774
651
203
266
1,440
37
2017
1,291
761
216
219
2,387
36
125
FORTIS INC. 2018 ANNUAL REPORTNotes to Consolidated Financial Statements
28.
FAIR VALUE OF FINANCIAL INSTRUMENTS AND RISK MANAGEMENT (cont’d)
Credit Risk
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� Credit risk is limited as such customers
have investment-grade credit ratings� ITC further reduces credit risk 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� The Company reduces its
exposure by obtaining from the retailers either a cash deposit, bond, letter of credit, an investment-grade credit rating from a major rating agency, or
a financial guarantee from an entity with an investment-grade credit rating�
UNS Energy, Central Hudson, FortisBC Energy, Aitken Creek and the Corporation may be exposed to credit risk in the event of non performance by
counterparties to derivatives� Credit risk is limited 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 $75 million as at December 31, 2018 (December 31, 2017 – $57 million)�
Foreign Exchange Hedge
The reporting currency of ITC, UNS Energy, Central Hudson, Caribbean Utilities, FortisTCI and BECOL is the US dollar� The Corporation’s earnings from,
and net investments in, foreign subsidiaries are exposed to fluctuations in the US dollar-to-Canadian dollar exchange rate� The Corporation has
decreased this exposure by designating US dollar-denominated borrowings at the corporate level as a hedge of its net investment in foreign
subsidiaries� The foreign exchange gain or loss on the translation of US dollar-denominated interest expense partially offsets the foreign exchange
gain or loss on the translation of US dollar-denominated subsidiary earnings�
As at December 31, 2018, US$3,441 million (December 31, 2017 – US$3,385 million) of net investment in foreign subsidiaries was hedged by the
Corporation’s corporately issued US dollar-denominated long-term debt and approximately US$7,970 million (December 31, 2017 – US$7,548 million)
was 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 financial instruments approximates fair value, reflecting their
short-term maturity, normal trade credit terms and/or nature�
As at December 31, 2018, the carrying value of long-term debt, including the current portion, was $24,231 million (December 31, 2017 – $21,535 million)
(Note 16) compared to an estimated fair value of $25,110 million (December 31, 2017 – $23,481 million)� Long-term debt is fair valued using
level 2 inputs�
The fair value of long-term debt is calculated using quoted market prices or, when unavailable, by either: (i) discounting the associated future cash
flows at an estimated yield to maturity equivalent to benchmark government bonds or treasury bills with similar terms to maturity, plus a credit risk
premium equal to that of issuers of similar credit quality; or (ii) obtaining from third parties indicative prices for the same or similarly rated issues of
debt with similar maturities� Since the Corporation does not intend to settle the long-term debt prior to maturity, the excess of the estimated fair
value above the carrying value does not represent an actual liability�
126
For the years ended December 31, 2018 and 2017FORTIS INC. 2018 ANNUAL REPORTNotes to Consolidated Financial Statements 29. VARIABLE INTEREST ENTITY
The Waneta Partnership, which owns and operates the Waneta Expansion on the Pend d’Oreille River in British Columbia, is 51% owned by Fortis and
49% by CPC and CBT (Note 10)� The Waneta Expansion is operated and maintained by a wholly owned subsidiary of the Corporation and the output
is sold to BC Hydro and FortisBC Electric under 40-year contracts� Each partner pays its proportionate share of the costs and is entitled to a
proportionate share of the net revenue�
The Corporation’s ownership interest is a variable interest entity� Fortis is the primary beneficiary as it has the power to direct the activities of the
partnership, the obligation to absorb losses and the right to receive benefits that could be significant to the partnership� Consequently, Fortis
consolidates the Waneta Partnership� The Corporation’s consolidated financial statements include the following with respect to the Waneta Partnership�
(in millions)
Assets
Cash and cash equivalents
Accounts receivable and other current assets
PPE
Intangible assets
Liabilities
Accounts payable and other current liabilities
Other liabilities
Net assets before partners’ equity
Revenue
Expenses
Operating expenses
Depreciation and amortization
Finance charges
Net earnings
2018
2017
$
$
$
$
$
$
15
15
674
30
734
(6)
(67)
(73)
661
94
18
18
4
40
54
$
$
$
$
$
$
16
14
688
30
748
(28)
(63)
(91)
657
93
17
18
4
39
54
Cash used in investing activities at the Waneta Partnership for 2018 included capital expenditures of $27 million (2017 – $5 million)� Cash flow related
to financing activities for 2018 included dividends paid by the Waneta Partnership to non-controlling interests of $35 million (2017 – $34 million) and
advances from non-controlling interests of $11 million (2017 – nil)�
127
FORTIS INC. 2018 ANNUAL REPORTNotes to Consolidated Financial Statements
30. COMMITMENTS AND CONTINGENCIES
As at December 31, 2018, consolidated commitments in each of the next five years and for periods thereafter, excluding repayments of long-term
debt and capital lease and finance obligations separately disclosed in Notes 16 and 17, respectively, were as follows�
(in millions)
Interest obligations on long-term debt
Power purchase obligations (i)
Renewable power purchase obligations (ii)
Gas purchase obligations (iii)
Long-term contracts – UNS Energy (iv)
ITC easement agreement (v)
Renewable energy credit purchase agreements (vi)
Debt collection agreement (vii)
Purchase of Springerville Common Facilities (viii)
Joint-use asset and shared service agreements
Operating lease obligations
Other (ix)
Total
$ 16,345
2,438
1,699
1,348
777
436
146
119
93
52
51
530
$
Due
within
1 year
994
254
110
359
176
14
24
3
–
3
8
108
Due in
year 2
Due in
year 3
Due in
year 4
Due in
year 5
$
973
191
110
290
142
14
26
3
–
3
6
84
$
950
174
109
242
92
14
18
3
93
3
5
89
$
902
170
109
202
60
14
11
3
–
3
4
38
$
870
172
108
144
46
14
11
3
–
3
4
36
Due
after
5 years
$ 11,656
1,477
1,153
111
261
366
56
104
–
37
24
175
Total
(i)
(ii)
(iii)
(iv)
(v)
(vi)
$ 24,034
$ 2,053
$ 1,842
$ 1,792
$ 1,516
$ 1,411
$ 15,420
The most significant power purchase obligations are described below�
Maritime Electric ($771 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 ($705 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 Energy ($522 million): an agreement with BC Hydro for the supply of electricity to the Tilbury liquefied natural gas facility expansion�
FortisBC Electric ($345 million): includes an agreement with BC Hydro to purchase up to 200 MW of capacity and 1,752 GWh of associated energy
annually for a 20-year term beginning October 1, 2013�
TEP and UNS Electric are party to renewable PPAs, with expiry dates from 2027 through 2043, that require them to purchase 100% of the output
of certain renewable energy generating facilities once commercial operation is achieved� Amounts shown are the estimated future payments�
Certain of the Corporation’s subsidiaries, mainly FortisBC Energy, enter into contracts for the purchase of gas, gas transportation and storage
services� 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, 2018�
UNS Energy enters into 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 2019 and 2040�
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 generators� Payments are primarily made at contractually
agreed-upon intervals based on metered energy production�
(vii) 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�
(viii) UNS Energy is obligated to purchase an undivided 32�2% interest in the Springerville Common Facilities if the related two leases are not
renewed� The initial lease terms expire in January 2021 (Note 17)�
Includes stock-based compensation plan obligations, land easements, asset retirement obligations, and defined benefit pension plan
funding obligations�
(ix)
128
For the years ended December 31, 2018 and 2017FORTIS INC. 2018 ANNUAL REPORTNotes to Consolidated Financial Statements
Other Commitments
The Corporation’s regulated utilities are obligated to provide service to customers within their respective service territories� Their capital expenditures
are largely to ensure continued and enhanced performance, reliability and safety of the electricity and gas systems and to meet customer growth�
Consolidated capital expenditures are forecast to be approximately $3�7 billion for 2019 and approximately $17�3 billion over the five-year period from
2019 through 2023�
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�3 billion (US$1�7 billion)� Central Hudson’s maximum commitment is $248 million (US$182 million), for which it has issued a parental
guarantee� As at December 31, 2018, there was no obligation under this guarantee�
As at December 31, 2018, FHI had $77 million (December 31, 2017 – $80 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�
31. COMPARATIVE FIGURES
Effective January 1, 2018, the Corporation elected to present, on the statement of cash flows, all borrowings and repayments under committed
credit facilities on a gross basis and continue to present borrowings and repayments under uncommitted or demand credit facilities on a net
basis as Net Change in Short-Term Borrowings� The presentation change resulted in $365 million, which was previously reported within
Net Repayments and Borrowings under Committed Facilities, being reported on a gross basis, with (i) $4,376 million reported as Borrowings
under Committed Credit Facilities, (ii) $5,441 million reported as Repayments under Committed Credit Facilities, and (iii) $700 million reported as
Net Change in Short-Term Borrowings�
Comparative figures were reclassified to conform with the revised segmentation, as described in Note 5, and to reflect the retrospective adoption of
ASU 2017-07, as described in Note 3�
129
FORTIS INC. 2018 ANNUAL REPORTNotes to Consolidated Financial Statements Historical Financial Summary
Statements of Earnings (in $ millions)
Revenue
Energy supply costs and operating expenses
Depreciation and amortization
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(3) and intangible assets
Goodwill
Other long-term assets
Total assets
Current liabilities
Long-term debt (excluding current portion)
Other long-term liabilities
Preference shares (classified as debt)
Total liabilities
Total equity
Cash Flows (in $ millions)
Operating activities
Investing activities
Financing activities, excluding dividends
Dividends, excluding dividends on preference shares classified as debt
Financial Statistics
Return on average book common shareholders’ equity (%)
Capitalization Ratios (%) (year end)
Total debt and capital lease and finance obligations (net of cash)
Preference shares (classified as debt and equity)
Common shareholders’ equity
Interest Coverage (x)
Debt
All fixed charges
Total gross 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)
2018 (1)
8,390
4,782
1,243
60
974
165
1,286
–
–
1,286
120
66
1,100
3,261
33,854
12,530
3,406
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
2017 (1)
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
47.36
39.38
45.51
269,284
48.73
40.59
46.11
205,261
2016 (1)(2)
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
(1) Financial information for the years 2010 through 2018 prepared under U.S. generally accepted accounting principles (“GAAP”); prior to 2010 prepared under Canadian GAAP.
(2) Results were impacted by non-operating items, largely associated with 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.
(3) Non-utility capital assets were sold as part of the sale of commercial real estate and hotel assets in 2015.
130
2015 (1)(2)
6,757
4,465
2014 (1)(2)
5,401
3,690
2013 (1)(2)
4,047
2,654
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
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
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 (1)
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 (1)
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 (1)
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
2009
3,641
2,577
364
10
369
49
292
–
–
292
12
18
262
1,124
8,538
1,560
917
12,139
1,592
5,239
1,325
320
8,476
3,663
681
(1,045)
563
(176)
8.41
60.2
6.9
32.9
1.9
1.8
1,024
18.61
170.2
1.54
0.78
1.04
67.5
18.6
29.24
21.52
28.68
172,038
174,566
120,470
115,962
126,341
120,855
121,162
FORTIS INC. 2018 ANNUAL REPORT Property, plant and equipment, non-utility capital assets(3) and intangible assets
Statements of Earnings (in $ millions)
Revenue
Energy supply costs and operating expenses
Depreciation and amortization
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
Goodwill
Other long-term assets
Total assets
Current liabilities
Long-term debt (excluding current portion)
Other long-term liabilities
Preference shares (classified as debt)
Total liabilities
Total equity
Cash Flows (in $ millions)
Operating activities
Investing activities
Financing activities, excluding dividends
Dividends, excluding dividends on preference shares classified as debt
Financial Statistics
Return on average book common shareholders’ equity (%)
Capitalization Ratios (%) (year end)
Total debt and capital lease and finance obligations (net of cash)
Preference shares (classified as debt and equity)
Common shareholders’ equity
Interest Coverage (x)
Debt
All fixed charges
Total gross 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)
2018 (1)
8,390
4,782
1,243
60
974
165
1,286
–
–
1,286
120
66
1,100
3,261
33,854
12,530
3,406
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 (1)
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
2016 (1)(2)
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
(1) Financial information for the years 2010 through 2018 prepared under U.S. generally accepted accounting principles (“GAAP”); prior to 2010 prepared under Canadian GAAP.
(2) Results were impacted by non-operating items, largely associated with 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.
(3) Non-utility capital assets were sold as part of the sale of commercial real estate and hotel assets in 2015.
269,284
205,261
293,991
2015 (1)(2)
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)(2)
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)(2)
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 (1)
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
115,962
2011 (1)
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
126,341
2010 (1)
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
120,855
2009
3,641
2,577
364
10
369
49
292
–
–
292
12
18
262
1,124
8,538
1,560
917
12,139
1,592
5,239
1,325
320
8,476
3,663
681
(1,045)
563
(176)
8.41
60.2
6.9
32.9
1.9
1.8
1,024
18.61
170.2
1.54
0.78
1.04
67.5
18.6
29.24
21.52
28.68
121,162
131
FORTIS INC. 2018 ANNUAL REPORTHistorical Financial Summary INVESTOR INFORMATIO N
Expected Dividend* and Earnings Release Dates
Dividend Record Dates
May 17, 2019
November 19, 2019
Dividend Payment Dates
June 1, 2019
December 1, 2019
Earnings Release Dates
May 1, 2019
November 1, 2019
August 20, 2019
February 18, 2020
September 1, 2019
March 1, 2020
August 2, 2019
February 14, 2020
* The setting of dividend record dates and the declaration and payment of dividends
are subject to the Board of Directors’ approval.
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 2, 2019 – 10:30 a.m.
Holiday Inn St. John’s, 180 Portugal Cove Road,
St. John’s, NL, Canada
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 Halifax, Montreal and
Toronto offices in Canada and at the co-transfer agent’s Canton, MA,
Jersey City, NJ, and College Station, TX 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.
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. The DRIP currently offers a 2% discount on the
purchase of Common Shares, issued from treasury, with the reinvested
dividends. Inquiries should be directed 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: 250 Royall Street, Canton, MA 02021
Regular Mail Delivery: P.O. Box 43078, Providence, RI 02940-3070
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.
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
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.
Analyst and Investor Inquiries
T: 709.737.2900
F: 709.737.5307
E: investorrelations@fortisinc.com
132
FORTIS INC. 2018 ANNUAL REPORT
FORTI S INC. EXECUTIV E
Barry V. Perry
President and Chief Executive Officer
Jocelyn H. Perry
Executive Vice President, Chief Financial Officer
Phonse J. Delaney
Executive Vice President, Chief Information Officer
Nora M. Duke
Executive Vice President, Sustainability and Chief Human Resource Officer
David G. Hutchens
Executive Vice President, Western Utility Operations
James P. Laurito
Executive Vice President, Business Development
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
Karen M. McCarthy
Vice President, Communications and Corporate Affairs
Regan P. O’Dea
Vice President, General Counsel
James D. Roberts
Vice President, Controller
Photography:
Chris Crockwell, St. John’s, NL
David Howells, St. John’s, NL
Front Cover: left to right, Bern Price – Team Lead, Asset Management,
Liz Palmera – Team Lead, Transmission Engineering, Chad Howell –
Power Line Technician Lead Hand, Alex Hawco – Supervisor, Civil Engineering,
Melissa King – Power Line Technician, Newfoundland Power.
Design and Production:
m5 Marketing Communications, St. John’s, NL www.m5.ca
Moveable Inc., Toronto, ON www.moveable.com
Printer:
Laudable Print Solutions, Ottawa, ON
BO A RD OF D I REC 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
Ile Bizard, 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
Ida J. Goodreau X H
Corporate Director
Vancouver, British Columbia
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.
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