St. John's, NL - February 14, 2025
FORTIS INC. REPORTS FOURTH QUARTER & ANNUAL 2024 RESULTS
This news release constitutes a "Designated News Release" incorporated by reference in the prospectus supplement
dated December 9, 2024 to Fortis' short form base shelf prospectus dated December 9, 2024.
Fortis Inc. ("Fortis" or the "Corporation") (TSX/NYSE: FTS), a well-diversified leader in the North American regulated electric and gas
utility industry, released its 2024 fourth quarter and annual financial results.1
Highlights
• Annual net earnings of $1.6 billion, or $3.24 per common share for 2024
• Annual adjusted net earnings per common share2 of $3.28, up from $3.09 for 2023, representing 6% growth3
• Capital expenditures2 of $5.2 billion, yielding 6% annual rate base growth3
• Tranche 2.1 projects approved by MISO; ITC now estimates US$3.7-$4.2 billion in investments, with majority expected post-2029
• 4.2% increase in fourth quarter common share dividend achieving 51 years of common share dividend increases
"In 2024, Fortis extended its track record of strong EPS and rate base growth," said David Hutchens, President and Chief Executive
Officer, Fortis Inc. "We executed a $5.2 billion capital program, outperformed industry averages for safety and reliability
performance, and continued to be recognized as a leader for our governance practices."
"We remain focused on extending our track record as we execute our $26 billion five-year capital plan in support of our annual
dividend growth guidance of 4-6% through 2029," said Mr. Hutchens. "Fortis' strength comes from the dedication and hard work of
our people, and we appreciate their efforts in making 2024 another successful year."
Net Earnings
The Corporation reported net earnings attributable to common shareholders ("Net Earnings") of $1.6 billion, or $3.24 per common
share for 2024, compared to $1.5 billion, or $3.10 per common share for 2023. Growth in earnings was primarily driven by rate base
growth across our utilities. New customer rates at Tucson Electric Power ("TEP") effective September 1, 2023 and Central Hudson
effective July 1, 2024, and an unfavourable deferred income tax adjustment recognized by ITC in 2023, also contributed to earnings
growth. The increase was partially offset by higher holding company finance costs, unrealized losses on derivative contracts, and a
$10 million gain realized upon the disposition of Aitken Creek in 2023. The recognition of a refund liability at ITC in 2024 associated
with a reduction in the Midcontinent Independent System Operator ("MISO") base rate of return on common equity ("ROE"), largely
reflecting the retroactive impact to prior periods, also unfavourably impacted earnings. An increase in the weighted average
number of common shares outstanding related to the Corporation's dividend reinvestment plan, also impacted earnings per
common share.
For the fourth quarter of 2024, Net Earnings were $396 million, or $0.79 per common share, compared to $381 million or $0.78 per
common share for the same period in 2023. The increase was due to rate base growth as well as new customer rates at Central
Hudson effective July 1, 2024. The implementation of new customer rates at Central Hudson shifted the timing of quarterly rate
recovery in comparison to related costs, resulting in higher revenue and earnings in the fourth quarter of 2024. The increase in
earnings was tempered by the refund liability recognized at ITC, unrealized losses on derivative contracts, and the gain on
disposition of Aitken Creek in 2023, as discussed above. Lower earnings in Arizona, driven by higher operating expenses, also
unfavourably impacted fourth quarter earnings in comparison to the prior year. Net earnings per common share was also impacted
by an increase in the weighted average number of common shares.
__________________________
1 Financial information is presented in Canadian dollars unless otherwise specified.
2 Non-U.S. GAAP Measures - Fortis uses financial measures that do not have a standardized meaning under generally accepted accounting principles in
the United States of America ("U.S. GAAP") and may not be comparable to similar measures presented by other entities. Fortis presents these non-
U.S. GAAP measures because management and external stakeholders use them in evaluating the Corporation's financial performance and prospects.
Refer to the Non-U.S. GAAP Reconciliation provided herein.
3 Growth rates calculated using a constant U.S. dollar-to-Canadian dollar exchange rate.
i
Adjusted Net Earnings2
Adjusted net earnings attributable to common equity shareholders ("Adjusted Net Earnings") of $1.6 billion for 2024, or $3.28 per
common share, were $124 million, or $0.19 per common share higher than 2023. Adjusted Net Earnings reflects the removal of
items that management excludes in its key decision-making processes and evaluation of operating results. For 2024, Net Earnings
was adjusted to remove the $20 million unfavourable prior period impact associated with the reduction in the MISO base ROE.
For 2023, Net Earnings was adjusted to exclude the $4 million net favourable impact associated with the disposition of Aitken
Creek and the revaluation of deferred income tax assets at ITC. The increase in Adjusted Net Earnings in 2024 reflects these items,
as well as the other factors discussed in Net Earnings.4
For the fourth quarter of 2024, Adjusted Net Earnings of $416 million, or $0.83 per common share, were $66 million, or $0.11 per
common share higher than the same period in 2023. Net Earnings for the fourth quarter of 2024 was adjusted to remove the
$20 million prior period impact associated with the MISO base ROE, as discussed above. For the fourth quarter of 2023, Net
Earnings was adjusted to exclude the disposition of Aitken Creek, including timing impacts associated with the March 31, 2023
effective date of disposition. The increase in fourth quarter Adjusted Net Earnings largely reflects these items, as well as the other
factors discussed in Net Earnings.
Capital Expenditures2
Capital expenditures were $5.2 billion for 2024. Growth in capital was due to investments associated with the Eagle Mountain
Pipeline project at FortisBC Energy, transmission reliability projects at ITC, and construction of the Roadrunner Reserve battery
storage projects at TEP. Capital expenditures increased midyear rate base to $39.0 billion, representing 6% growth over 2023.3
In 2024, construction of the Wataynikaneyap Transmission Power project was completed. This project enables the connection of 17
First Nations communities to the Ontario power grid. Previously these communities had inefficient and unreliable access to
electricity based on diesel generation, which compromised their economic and social well-being and limited opportunities for
growth. The transmission line is majority-owned by 24 First Nations, while Fortis has a 39% ownership interest.
The Corporation's 2025-2029 capital plan of $26.0 billion is $1.0 billion higher than the previous five-year plan. The increase is
driven by projects associated with the MISO long-range transmission plan ("LRTP") and resiliency investments at ITC, as well as
distribution investments largely due to customer growth at FortisAlberta.
The five-year capital plan is expected to be funded primarily by cash from operations and regulated utility debt. Common equity
proceeds are expected to be provided by the Corporation's dividend reinvestment plan, assuming current participation levels. The
Corporation's $500 million at-the-market common equity program remains available and provides funding flexibility as required.
Progress continues with respect to the MISO LRTP projects. Total tranche 1 investments expected for ITC remain in the range of
US$1.4-$1.8 billion through 2030, of which US$1.2 billion are included in the 2025-2029 capital plan. In December 2024, MISO
approved the tranche 2.1 projects. ITC now estimates US$3.7-$4.2 billion in capital expenditures for tranche 2.1 projects located in
Michigan and Minnesota where rights of first refusal are in effect and for projects requiring system upgrades in Iowa which are not
subject to a competitive bidding process. A majority of the tranche 2.1 investment is expected beyond 2029.
Regulatory Updates
In October 2024, the Federal Energy Regulatory Commission ("FERC") issued an order setting the base ROE for transmission owners
operating in the MISO region, including ITC. The order revised the base ROE of ITC's MISO utilities from 10.02% to 9.98% and also
directed the payment of certain refunds, with interest, by December 1, 2025. Fortis' 80.1% share of the related after-tax earnings
impact was approximately $22 million, of which $20 million related to periods prior to January 1, 2024.
In December 2024, the Arizona Corporation Commission ("ACC") approved a formula rate plan policy statement which allows
utilities to propose formula rates with an annual true-up mechanism in future rate cases. A formula rate plan is expected to
improve rate stability for customers, while also reducing regulatory lag and the number of existing rate adjusters. In January 2025,
UNS Gas filed supplemental material to its general rate application proposing an annual rate adjustment mechanism as a result of
the ACC's formula rate policy statement. The timing and outcome of this proceeding are unknown.
__________________________
4 The disposition of Aitken Creek was neutral to Adjusted Net Earnings and EPS for the year.
ii
Outlook
Fortis continues to enhance shareholder value through the execution of its capital plan, the balance and strength of its diversified
portfolio of regulated utility businesses, and growth opportunities within and proximate to its service territories. The Corporation's
$26.0 billion five-year capital plan is expected to increase midyear rate base from $39.0 billion in 2024 to $53.0 billion by 2029,
translating into a five-year compound annual growth rate of 6.5%.3
Beyond the five-year capital plan, opportunities to expand and extend growth include: further expansion of the electric
transmission grid in the U.S. to support load growth and facilitate the interconnection of cleaner energy; transmission investments
associated with the MISO LRTP tranches 1, 2.1 and 2.2 as well as regional transmission in New York; grid resiliency and climate
adaptation investments; renewable gas solutions and liquefied natural gas infrastructure in British Columbia; and the acceleration
of load growth and cleaner energy infrastructure investments across our jurisdictions.
Fortis expects its long-term growth in rate base will drive earnings that support dividend growth guidance of 4-6% annually
through 2029, and is premised on the assumptions and material factors listed under "Forward-Looking Information".
Fortis has reduced its corporate-wide direct greenhouse gas ("GHG") emissions by 34% from a 2019 base year, and has targets to
further reduce such GHG emissions by 50% by 2030 and 75% by 2035. The Corporation's additional 2050 net-zero direct GHG
emissions target reinforces Fortis' commitment to further decarbonize over the long-term, while continuing our focus on reliability
and affordability. The Corporation's ability to achieve the GHG targets may be impacted by federal, state and provincial energy
policies, as well as external factors, including significant customer and load growth and the development of clean energy
technology.
Non-U.S. GAAP Reconciliation
Periods ended December 31
Quarter
Annual
($ millions, except earnings per share)
2024
2023
Variance
2024
2023
Variance
Adjusted Net Earnings
Net Earnings
396
381
15
1,606
1,506
100
Adjusting items:
October 2024 MISO base ROE decision5
20
—
20
20
—
20
Disposition of Aitken Creek6
—
(31)
31
—
(15)
15
Unrealized loss on mark-to-market of derivatives7
—
—
—
—
2
(2)
Revaluation of deferred income tax assets8
—
—
—
—
9
(9)
Adjusted Net Earnings
416
350
66
1,626
1,502
124
Adjusted Basic EPS ($)
0.83
0.72
0.11
3.28
3.09
0.19
Capital Expenditures
Additions to property, plant and equipment
1,629
1,189
440
5,012
3,986
1,026
Additions to intangible assets
64
61
3
206
183
23
Adjusting item:
Wataynikaneyap Transmission Power Project9
—
51
(51)
29
160
(131)
Capital Expenditures
1,693
1,301
392
5,247
4,329
918
________________________________
5 Represents the prior period impact of FERC's October 2024 MISO base ROE decision, net of income tax recovery of $7 million.
6 Aitken Creek was sold on November 1, 2023, with a March 31, 2023 effective date. For the year ended December 31, 2023, the adjustment represents:
(i) the $10 million gain on disposition, net of income tax expense of $13 million; and (ii) $5 million of net earnings at Aitken Creek, recognized in
accordance with U.S. GAAP, during the March 31, 2023 to November 1, 2023 stub period, net of income tax expense of $2 million. For the three-month
period ended December 31, 2023, this adjustment represents: (i) the $10 million gain on disposition; and (ii) $21 million of stub period earnings at
Aitken Creek, net of income tax expense of $9 million, including amounts initially included in Adjusted Net Earnings in the second and third quarters of
2023 prior to the close of the transaction.
7 Represents the impact of mark-to-market accounting of natural gas derivatives at Aitken Creek through the March 31, 2023 effective date of disposition,
net of income tax recovery of $1 million.
8 Represents the revaluation of deferred income tax assets resulting from the reduction in the corporate income tax rate in the state of Iowa.
9 Represents Fortis' 39% share of capital spending for the Wataynikaneyap Transmission Power Project. Construction was completed in the second
quarter of 2024.
iii
About Fortis
Fortis is a well-diversified leader in the North American regulated electric and gas utility industry with 2024 revenue of $12 billion
and total assets of $73 billion as at December 31, 2024. The Corporation's 9,800 employees serve utility customers in five Canadian
provinces, ten U.S. states and three Caribbean countries.
Forward-Looking Information
Fortis includes forward-looking information in this media release within the meaning of applicable Canadian securities laws and forward-looking
statements within the meaning of the U.S. Private Securities Litigation Reform Act of 1995 (collectively referred to as "forward-looking information").
Forward-looking information reflects expectations of Fortis management regarding future growth, results of operations, performance 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: forecast capital expenditures for 2025 through 2029; the expected sources of
funding for the capital plan, including the source of common equity proceeds; the nature, timing, benefits and expected costs of certain capital projects,
including ITC's investments associated with tranches 1 and 2.1 of the MISO LRTP; the expected timing, outcome and impact of legal and regulatory
proceedings and decisions; forecast rate base and rate base growth through 2029; the expected nature, timing and benefits of additional opportunities
beyond the capital plan, including further expansion of the electric transmission grid in the U.S. to support load growth and facilitate the interconnection
of cleaner energy, transmission investments associated with the MISO LRTP tranches 1, 2.1 and 2.2 as well as regional transmission in New York, grid
resiliency and climate adaptation investments, renewable gas solutions and liquefied natural gas infrastructure in British Columbia, and the acceleration
of load growth and cleaner energy infrastructure investments; the expectation that long-term growth in rate base will drive earnings that support dividend
growth guidance of 4-6% annually through 2029; the 2050 net-zero direct GHG emissions target; the 2030 and 2035 direct GHG emissions reduction
targets; and the potential impact of federal, state and provincial energy policies and other factors, including significant customer and load growth and the
development of clean energy technology, on the Corporation's ability to achieve its GHG emissions reduction targets.
Forward-looking information involves significant risks, uncertainties and assumptions. Certain material factors or assumptions have been applied in
drawing the conclusions contained in the forward-looking information, including, without limitation: reasonable outcomes for legal and regulatory
proceedings and the expectation of regulatory stability; the successful execution of the capital plan; no material capital project and financing cost overrun;
sufficient human resources to deliver service and execute the capital plan; the realization of additional opportunities beyond the capital plan; no
significant variability in interest rates; no material changes in the assumed U.S. dollar-to-Canadian dollar exchange rate; the continuation of current
participation levels in the Corporation's dividend reinvestment plan; and the Board of Directors of the Corporation exercising its discretion to declare
dividends, taking into account the business performance and financial condition of the Corporation. 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. For
additional information with respect to certain risk factors, reference should be made to the continuous disclosure materials filed from time to time by the
Corporation with Canadian securities regulatory authorities and the Securities and Exchange Commission. All forward-looking information herein is given
as of the date of this media release. 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.
Teleconference to Discuss 2024 Annual Results
A teleconference and webcast will be held on February 14, 2025 at 8:30 a.m. (Eastern). David Hutchens, President and
Chief Executive Officer and Jocelyn Perry, Executive Vice President and Chief Financial Officer, will discuss the Corporation's 2024
annual results.
Shareholders, analysts, members of the media and other interested parties are invited to listen to the teleconference via the live
webcast on the Corporation's website, www.fortisinc.com/investors/events-and-presentations.
Those members of the financial community in Canada and the United States wishing to ask questions during the call are invited to
participate toll free by calling 1.844.763.8274. Individuals in other international locations can participate by calling 1.647.484.8814.
Please dial in 10 minutes prior to the start of the call. No access code is required.
An archived audio webcast of the teleconference will be available on the Corporation's website two hours after the conclusion of
the call until March 14, 2025. Please call 1.855.669.9658 or 1.412.317.0088 and enter access code 9850557#.
iv
Additional Information
This news release should be read in conjunction with the Corporation's Management Discussion and Analysis and Consolidated
Financial Statements. This and additional information can be accessed at www.fortisinc.com, www.sedarplus.ca, or www.sec.gov.
For more information, please contact:
Investor Enquiries:
Media Enquiries:
Ms. Stephanie Amaimo
Ms. Karen McCarthy
Vice President, Investor Relations
Vice President, Communications & Government Relations
Fortis Inc.
Fortis Inc.
248.946.3572
709.737.5323
investorrelations@fortisinc.com
media@fortisinc.com
v
Contents
About Fortis ..............................................................................................
1
Cash Flow Summary .............................................................................
15
Performance at a Glance ...........................................................................
2
Contractual Obligations ........................................................................
17
The Industry ..............................................................................................
5
Capital Structure and Credit Ratings .....................................................
18
Operating Results ......................................................................................
6
Capital Plan ...........................................................................................
19
Business Unit Performance .......................................................................
7
Business Risks ............................................................................................
22
ITC ........................................................................................................
7
Accounting Matters ...................................................................................
30
UNS Energy ...........................................................................................
7
Financial Instruments ................................................................................
33
Central Hudson ....................................................................................
8
Long-Term Debt and Other ..................................................................
33
FortisBC Energy ....................................................................................
8
Derivatives ............................................................................................
33
FortisAlberta .........................................................................................
9
Selected Annual Financial Information ......................................................
36
FortisBC Electric ....................................................................................
9
Fourth Quarter Results ...............................................................................
37
Other Electric ........................................................................................
10
Summary of Quarterly Results ...................................................................
38
Corporate and Other ............................................................................
10
Related-Party and Inter-Company Transactions ........................................
39
Non-U.S. GAAP Financial Measures ...........................................................
10
Management's Evaluation of Controls and Procedures .............................
39
Regulatory Highlights ...............................................................................
11
Outlook .....................................................................................................
40
Financial Position ......................................................................................
13
Forward-Looking Information ...................................................................
40
Liquidity and Capital Resources ................................................................
14
Glossary .....................................................................................................
41
Cash Flow Requirements ......................................................................
14
Annual Consolidated Financial Statements ...............................................
F-1
Dated February 13, 2025
This MD&A has been prepared in accordance with National Instrument 51-102 - Continuous Disclosure Obligations. It should be read in conjunction
with the 2024 Annual Financial Statements and is subject to the cautionary statement and disclaimer provided under "Forward-Looking
Information" on page 40. Further information about Fortis, including its Annual Information Form, can be accessed at www.fortisinc.com,
www.sedarplus.ca, or www.sec.gov.
Financial information herein has been prepared in accordance with U.S. GAAP (except for indicated Non-U.S. GAAP Financial Measures) and,
unless otherwise specified, is presented in Canadian dollars based, as applicable, on the following U.S. dollar-to-Canadian dollar exchange rates:
(i) average of 1.37 and 1.35 for the years ended December 31, 2024 and 2023, respectively; (ii) 1.44 and 1.32 as at December 31, 2024 and 2023,
respectively; (iii) average of 1.40 and 1.36 for the quarters ended December 31, 2024 and 2023, respectively; and (iv) 1.30 for all forecast periods.
Certain terms used in this MD&A are defined in the "Glossary" on page 41.
ABOUT FORTIS
Fortis (TSX/NYSE: FTS) is a well-diversified leader in the North American regulated electric and gas utility industry, with revenue of $12 billion in
2024 and total assets of $73 billion as at December 31, 2024.
Regulated utilities account for virtually all of the Corporation's assets. The Corporation's 9,800 employees serve 3.5 million utility customers in five
Canadian provinces, ten U.S. states and three Caribbean countries. As at December 31, 2024, 66% of the Corporation's assets were located in the
U.S., 31% in Canada and the remaining 3% in the Caribbean. Operations in the U.S. accounted for 57% of the Corporation's 2024 revenue, with the
remaining 38% in Canada, and 5% in the Caribbean.
Fortis is principally an energy delivery company, with 93% of its assets related to transmission and distribution. The business is characterized by
low-risk, stable and predictable earnings and cash flows. Earnings, EPS and TSR are the primary measures of financial performance.
Management Discussion and Analysis
1
FORTIS INC.
DECEMBER 31, 2024
Fortis' regulated utility businesses are: ITC (electric transmission - Michigan, Iowa, Minnesota, Illinois, Missouri, Kansas, Oklahoma and Wisconsin);
UNS Energy (integrated electric and natural gas distribution - Arizona); Central Hudson (electric transmission and distribution, and natural gas
distribution - New York State); FortisBC Energy (natural gas transmission and distribution - British Columbia); FortisAlberta (electric distribution -
Alberta); FortisBC Electric (integrated electric - British Columbia); Newfoundland Power (integrated electric - Newfoundland and Labrador);
Maritime Electric (integrated electric - Prince Edward Island); FortisOntario (integrated electric - Ontario); Caribbean Utilities (integrated electric -
Grand Cayman); and FortisTCI (integrated electric - Turks and Caicos Islands). Fortis also holds equity investments in Wataynikaneyap Power
(electric transmission - Ontario) and Belize Electricity (integrated electric - Belize).
The Corporation's non-regulated business is limited to Fortis Belize (three hydroelectric generation facilities - Belize). The Aitken Creek natural gas
storage facility in British Columbia was sold on November 1, 2023 with a March 31, 2023 effective date.
Fortis has a unique operating model with a small corporate office in St. John's, Newfoundland and Labrador and business units that operate on a
substantially autonomous basis. Each utility has its own management team and board of directors, with most having a majority of independent
board members, which provides effective oversight within the broad parameters of Fortis policies and best practices. Subsidiary autonomy
supports constructive relationships with regulators, policy makers, customers and communities. Fortis believes this model enhances
accountability, opportunity and performance across the Corporation's businesses, and positions Fortis well for future investment opportunities.
Fortis is focused on providing safe, reliable and cost-effective service to customers. Delivering a cleaner energy future is the Corporation's core
purpose. In addition, management is focused on delivering long-term profitable growth for shareholders through the execution of its capital plan
and the pursuit of investment opportunities within and proximate to its service territories.
Additional information about the Corporation's business and reporting units is provided in Note 1 in the 2024 Annual Financial Statements.
PERFORMANCE AT A GLANCE
Key Financial Metrics
($ millions, except as indicated)
2024
2023
Variance
Common Equity Earnings
Actual
1,606
1,506
100
Adjusted (1)
1,626
1,502
124
Basic EPS ($)
Actual
3.24
3.10
0.14
Adjusted (1)
3.28
3.09
0.19
Dividends
Paid per common share ($)
2.39
2.29
0.10
Actual Payout Ratio (%)
73.6
73.7
(0.1)
Adjusted Payout Ratio (%) (1)
72.7
73.9
(1.2)
Weighted average number of common shares outstanding (# millions)
495.0
486.3
8.7
Operating Cash Flow
3,882
3,545
337
Capital Expenditures (1)
5,247
4,329
918
(1) See "Non-U.S. GAAP Financial Measures" on page 10
Earnings and EPS
Common Equity Earnings increased by $100 million in comparison to 2023. The increase was due to: (i) Rate Base growth; (ii) higher earnings in
Arizona, largely reflecting new customer rates at TEP effective September 1, 2023 and higher production tax credits; (iii) new customer rates and a
higher allowed ROE at Central Hudson effective July 1, 2024; and (iv) an unfavourable deferred income tax adjustment recognized by ITC in 2023.
The increase was partially offset by higher holding company finance costs, unrealized losses on derivative contracts, and a $10 million gain
realized upon the disposition of Aitken Creek in 2023. The recognition of a refund liability at ITC in 2024, due to the reduction in the MISO base
ROE as approved by FERC and largely reflecting the retroactive impact to prior periods, also unfavourably impacted earnings.
In addition to the above-noted items impacting earnings, the change in EPS also reflected an increase in the weighted average number of
common shares outstanding, largely associated with the Corporation's DRIP.
Management Discussion and Analysis
2
FORTIS INC.
DECEMBER 31, 2024
Adjusted Common Equity Earnings and Adjusted Basic EPS increased by $124 million and $0.19, respectively. Refer to "Non-U.S. GAAP Financial
Measures" on page 10 for a reconciliation of these measures. The change in Adjusted Basic EPS is illustrated in the following chart.
CHANGE IN ADJUSTED BASIC EPS
$3.09
$0.12
$0.09
$0.07
$0.03
$0.01
$(0.08)
$(0.05)
$3.28
2023
Adjusted
Basic EPS
U.S. Electric
and Gas
(1)
Western
Canadian
Electric and
Gas (2)
ITC
Transmission
(3)
Other
Electric
(4)
Foreign
Exchange
(5)
Corporate
and Other
(6)
Weighted
Average
Shares
(7)
2024
Adjusted
Basic EPS
(1) Includes UNS Energy and Central Hudson. Reflects higher earnings at UNS Energy due to new customer rates at TEP effective September 1, 2023, higher production tax
credits, and favourable margins on wholesale sales, partially offset by higher operating costs. Also reflects higher earnings at Central Hudson due to Rate Base growth as
well as new customer rates and a higher allowed ROE effective July 1, 2024, partially offset by favourable regulatory adjustments recognized in 2023
(2) Includes FortisBC Energy, FortisAlberta and FortisBC Electric. Primarily reflects Rate Base growth, as well as higher earnings at FortisAlberta due to an increase in the
allowed ROE, higher demand charges and customer growth, partially offset by higher operating expenses
(3) Primarily reflects Rate Base growth, partially offset by higher holding company finance costs
(4) Primarily reflects Rate Base growth and higher electricity sales
(5) Reflects average foreign exchange rate of 1.37 in 2024 compared to 1.35 in 2023, partially offset by a foreign exchange loss associated with the revaluation of U.S. dollar
denominated liabilities at a rate of 1.44 at December 31, 2024
(6) Reflects higher holding company finance costs and unrealized losses on derivative contracts, partially offset by higher hydroelectric production in Belize
(7) Weighted average shares of 495.0 million in 2024 compared to 486.3 million in 2023
Dividends
Fortis paid a dividend of $0.615 per common share in the fourth quarter of 2024, up 4.2% from $0.59 paid in each of the previous four quarters.
This marked the Corporation's 51st consecutive year of increases in dividends paid. The Adjusted Payout Ratio was 73% in 2024 and an average of
76% over the five-year period of 2020 through 2024.
Fortis is targeting annual dividend growth of approximately 4-6% through 2029. See "Outlook" on page 40.
51 CONSECUTIVE YEARS OF INCREASES IN DIVIDENDS PAID
Dividend Payments
73
76
79
82
85
88
91
94
97
00
03
06
09
12
15
18
21
24
Growth in dividends and changes in the market price of the Corporation's common shares have yielded the following TSRs.
TSR (1) (%)
1-Year
5-Year
10-Year
20-Year
Fortis
14.1
6.1
8.4
10.3
(1) Annualized TSR per Bloomberg, as at December 31, 2024
Management Discussion and Analysis
3
FORTIS INC.
DECEMBER 31, 2024
Operating Cash Flow
The $337 million increase in Operating Cash Flow was due to: (i) higher cash earnings, reflecting Rate Base growth, as well as new customer rates
and higher sales at TEP; and (ii) the higher collection of flow-through costs at UNS Energy. Deposits received related to the construction of the
Eagle Mountain Pipeline project and the receipt of an income tax refund at FortisBC Energy also favourably impacted Operating Cash Flow. The
increase was partially offset by: (i) the timing of flow-through costs in customer rates as well as other changes in working capital balances at
FortisBC Energy; (ii) the timing of flow-through transmission costs at FortisAlberta; (iii) higher interest payments; and (iv) the disposition of
Aitken Creek in November 2023, which contributed approximately $110 million of operating cash flow in 2023.
Capital Expenditures
Capital Expenditures in 2024 were $5.2 billion, consistent with expectations and $0.9 billion higher than 2023. The increase compared to 2023 was
primarily due to investments associated with the Eagle Mountain Pipeline project at FortisBC Energy, expenditures on various transmission
reliability projects at ITC, and construction of the Roadrunner Reserve battery storage projects at UNS Energy.
Capital Expenditures is a Non-U.S. GAAP financial measure. Refer to "Non-U.S. GAAP Financial Measures" on page 10.
New Five-Year Capital Plan
The Corporation's 2025-2029 capital plan of $26.0 billion is the largest in the Corporation’s history and is $1.0 billion higher than the previous five-
year plan. The increase is driven by projects associated with the MISO LRTP and resiliency investments at ITC, as well as distribution investments
largely due to customer growth at FortisAlberta. For a detailed discussion of the Corporation's capital expenditure program, see "Capital Plan" on
page 19.
Funding of the capital plan is expected to be primarily through Operating Cash Flow and debt issued at the regulated utilities. Common
equity proceeds are expected to be sourced from the Corporation's DRIP assuming current participation levels. The Corporation's $500 million
ATM Program remains available and provides funding flexibility as required.
The five-year capital plan is expected to increase midyear Rate Base from $39.0 billion in 2024 to $53.0 billion by 2029, translating into a five-year
CAGR of 6.5%.
PROJECTED RATE BASE
(1)
($ billions)
39.0
40.7
43.6
46.6
49.9
53.0
Canadian and Caribbean
U.S.
2024
2025P
2026P
2027P
2028P
2029P
(1) Reflects average exchange rate of 1.37 for 2024 and exchange rate of 1.30 for 2025-2029. On average, Fortis estimates that a five-cent increase or decrease in
the U.S. dollar relative to the Canadian dollar would increase or decrease Rate Base by approximately $1.1 billion over the five-year planning period
Beyond the five-year capital plan, opportunities to expand and extend growth include: further expansion of the electric transmission grid in the
U.S. to support load growth and facilitate the interconnection of cleaner energy; transmission investments associated with the MISO LRTP
tranches 1, 2.1 and 2.2 as well as regional transmission in New York; grid resiliency and climate adaptation investments; renewable gas solutions
and LNG infrastructure in British Columbia; and the acceleration of load growth and cleaner energy infrastructure investments across our
jurisdictions.
Management Discussion and Analysis
4
FORTIS INC.
DECEMBER 31, 2024
THE INDUSTRY
The North American utility industry is undergoing significant transformation due to the need for energy security, the impacts of climate change,
the transition to cleaner energy, and projected growth in load driven by data centers, manufacturing and electrification. These factors are creating
significant investment opportunities for the sector.
Policy makers and regulators at the federal, state, and provincial levels are increasingly prioritizing matters of energy security, with many
continuing to support the transition to cleaner energy. The conjunction of policy and forecasted load growth has resulted in opportunities to
invest in renewable and natural gas generation, energy storage systems and transmission infrastructure. Electrification of transportation and
heating continues to grow and represents another opportunity to reduce carbon emissions while increasing the output and efficiency of the grid.
Grid resilience continues to grow in importance with the increasing frequency and intensity of weather events such as extreme heat and cold,
hurricanes, wildfires, floods and storms. With electricity expected to represent a larger portion of society's energy mix, investments in resiliency are
necessary to improve the grid's ability to withstand and recover from climate events.
Diversity of energy supply and enhanced integration of energy systems are vital to deliver the resilience, energy, and capacity needed to support
economic growth and energy demand. Electric transmission is a critical enabler of load growth, interconnecting large-scale generation while
improving system resilience. Natural gas generation provides a reliable source of energy and capacity that will be an essential resource to meet
growing energy needs. Natural gas investments, as well as energy storage solutions, will enable the adoption of additional renewable energy.
Increased adoption of RNG and, in the longer-term, hydrogen will further contribute to carbon emissions reduction. The Corporation's utilities are
well positioned and actively involved in pursuing these opportunities, which will drive significant capital investment, particularly at ITC, UNS
Energy and in Western Canada.
New technology is stimulating change across the Corporation's service territories. Energy delivery systems are becoming more intelligent, with
advanced meters, remote sensing, and grid automation. More capable operational technology provides utilities with detailed usage data,
enhanced inspection capabilities, and predictive maintenance information, contributing to increased efficiency and more reliable energy delivery.
Energy management capabilities are expanding through emerging storage, demand response, and distributed energy management systems.
Fortis' culture of innovation underlies a continuous drive to find better ways to safely, reliably and affordably deliver the energy and services that
customers need. Fortis is a partner in Energy Impact Partners, a strategic private venture fund that invests in emerging technologies, products,
services and business models that are transforming the industry. The Corporation is also involved in the Low Carbon Resources Initiative, a
collaboration between EPRI and GTI Energy, along with other major utilities, to develop and demonstrate the low- and zero-carbon energy
technologies needed to enable pathways to decarbonization. Fortis is also a member of EPRI's Climate READi, an initiative involving major North
American utilities, regulators, policy makers, and other stakeholders focused on developing an industry-wide best practice framework for
managing physical climate risk.
Meaningful customer engagement is important for utilities as customer expectations change. Customers want to make informed energy choices
and become active participants in the delivery of their energy. They also expect personalized service, customized self-service offerings, and more
real-time, digital communication. To respond to these changes, Fortis' utilities are enhancing customer information systems, adopting digital
technologies including AI, and advancing new and modern approaches to customer engagement. At the same time, increased investment in
cybersecurity is an ongoing priority in the context of an ever-changing threat landscape. Upgrades to the physical security environment are also
required to keep pace with evolving challenges. These technological advancements and challenges offer strategic investment opportunities for
Fortis' utilities.
The Corporation's culture and decentralized structure support our utilities' efforts to meet changing customer expectations, and to work
constructively with regulators and all stakeholders on policy, energy and service solutions. Fortis is well positioned to support energy security,
load growth and the clean energy transition across the Corporation's footprint.
Management Discussion and Analysis
5
FORTIS INC.
DECEMBER 31, 2024
OPERATING RESULTS
Variance
($ millions)
2024
2023
FX
Other
Revenue
11,508
11,517
108
(117)
Energy supply costs
3,249
3,771
32
(554)
Operating expenses
3,040
2,889
29
122
Depreciation and amortization
1,927
1,773
16
138
Other income, net
288
291
(10)
7
Finance charges
1,406
1,305
13
88
Income tax expense
346
360
1
(15)
Net earnings
1,828
1,710
7
111
Net earnings attributable to:
Non-controlling interests
148
137
2
9
Preference equity shareholders
74
67
—
7
Common equity shareholders
1,606
1,506
5
95
Net earnings
1,828
1,710
7
111
Revenue
The decrease in revenue, net of foreign exchange, was due to lower flow-through commodity costs in customer rates at FortisBC Energy and
Central Hudson. The decrease was also due to a reduction in the MISO base ROE at ITC, approved by FERC in October 2024, including retroactive
application to prior periods (see "Regulatory Highlights - Significant Regulatory Matters" on page 12), and lower short-term wholesale sales
revenue at UNS Energy. The decrease was partially offset by Rate Base growth and new customer rates at TEP and Central Hudson, effective
September 1, 2023 and July 1, 2024, respectively.
Energy Supply Costs
The decrease in energy supply costs, net of foreign exchange, was due primarily to lower commodity costs, mainly at FortisBC Energy,
Central Hudson, and UNS Energy.
Operating Expenses
The increase in operating expenses, net of foreign exchange, was due primarily to general inflationary and employee-related cost increases.
Depreciation and Amortization
The increase in depreciation and amortization, net of foreign exchange, was due to continued investment in energy infrastructure at the
Corporation's regulated utilities, and new depreciation rates approved for TEP in September 2023 as part of its general rate application.
Other Income, Net
Other Income, net of foreign exchange, was relatively consistent with 2023. An increase in other income associated with higher AFUDC at
UNS Energy and FortisBC Energy was largely offset by the pre-tax gain recognized in 2023 on the sale of Aitken Creek and net unrealized losses on
derivative contracts.
Finance Charges
The increase in finance charges, net of foreign exchange, was due to higher debt levels to support the Corporation's capital plan, as well as higher
interest rates on new debt issuances.
Income Tax Expense
The decrease in income tax expense, net of foreign exchange, was driven by higher production tax credits at UNS Energy, and the unfavourable
$9 million deferred income tax adjustment recognized at ITC in 2023 following a reduction in the corporate income tax rate in the state of Iowa.
The decrease was partially offset by higher earnings before taxes.
Net Earnings
See "Performance at a Glance - Earnings and EPS" on page 2.
Management Discussion and Analysis
6
FORTIS INC.
DECEMBER 31, 2024
BUSINESS UNIT PERFORMANCE
Common Equity Earnings
Variance
($ millions)
2024
2023
FX (1)
Other
Regulated Utilities
ITC
542
508
8
26
UNS Energy
448
400
6
42
Central Hudson
128
105
3
20
FortisBC Energy
293
274
—
19
FortisAlberta
181
162
—
19
FortisBC Electric
72
68
—
4
Other Electric (2)
163
146
—
17
1,827
1,663
17
147
Non-Regulated
Corporate and Other (3)
(221)
(157)
(12)
(52)
Common Equity Earnings
1,606
1,506
5
95
(1) The reporting currency of ITC, UNS Energy, Central Hudson, Caribbean Utilities, FortisTCI and Fortis Belize is the U.S. dollar. The reporting currency of Belize Electricity is the Belizean
dollar, which is pegged to the U.S. dollar at BZ$2.00=US$1.00. Certain corporate and non-regulated holding company transactions, included in the Corporate and Other segment, are
denominated in U.S. dollars
(2) Consists of the utility operations in eastern Canada and the Caribbean: Newfoundland Power; Maritime Electric; FortisOntario; Wataynikaneyap Power; Caribbean Utilities; FortisTCI;
and Belize Electricity
(3) Consists of non-regulated holding company expenses, as well as earnings from long-term contracted generation assets in Belize. Also includes earnings from Aitken Creek up to the
November 1, 2023 date of disposition
ITC
Variance
($ millions)
2024
2023
FX
Other
Revenue (1)
2,229
2,085
33
111
Earnings (1)
542
508
8
26
(1) Revenue represents 100% of ITC. Earnings represent the Corporation's 80.1% controlling ownership interest in ITC and reflect consolidated purchase price accounting
adjustments.
Revenue
The increase in revenue, net of foreign exchange, was due primarily to Rate Base growth and higher flow-through costs in customer rates.
The increase was partially offset by a decrease in the MISO base ROE from 10.02% to 9.98%, as approved by FERC in October 2024, for the 15-
month period from November 2013 through February 2015 and prospectively from September 2016 (See "Regulatory Highlights - Significant
Regulatory Matters" on page 12).
Earnings
The increase in earnings, net of foreign exchange, was due primarily to Rate Base growth as well as an unfavourable $9 million deferred income
tax adjustment recognized in 2023 following a reduction in the corporate income tax rate in the state of Iowa. The increase was partially offset by:
(i) a decrease in the MISO base ROE from 10.02% to 9.98% as discussed above, which resulted in a $22 million reduction in earnings in 2024,
including $20 million associated with the retroactive impact to prior periods; and (ii) higher holding company finance costs.
UNS Energy
Variance
($ millions, except as indicated)
2024
2023
FX
Other
Retail electricity sales (GWh)
10,870
10,786
—
84
Wholesale electricity sales (GWh) (1)
5,810
5,387
—
423
Gas sales (PJ)
17
17
—
—
Revenue
3,007
3,006
45
(44)
Earnings
448
400
6
42
(1) Primarily short-term wholesale sales
Sales
The increase in retail electricity sales was due primarily to warmer weather and customer additions.
Management Discussion and Analysis
7
FORTIS INC.
DECEMBER 31, 2024
The increase in wholesale electricity sales was driven by higher short-term wholesale sales, due to market conditions, partially offset by lower
long-term wholesale sales due to the expiration of certain contracts. Revenue from short-term wholesale sales, which relate to contracts that are
less than one-year in duration, is primarily credited to customers through the PPFAC mechanism and, therefore, does not materially impact
earnings.
Gas sales were consistent with 2023.
Revenue
The decrease in revenue, net of foreign exchange, was due primarily to: (i) lower wholesale sales revenue, largely driven by unfavourable pricing
on short-term wholesale sales; (ii) the recovery of overall lower fuel and non-fuel costs through the normal operation of regulatory mechanisms;
and (iii) lower transmission revenue. The decrease was partially offset by new customer rates at TEP effective September 1, 2023.
Earnings
The increase in earnings, net of foreign exchange, was due primarily to: (i) new customer rates at TEP effective September 1, 2023, following the
conclusion of the general rate application; (ii) higher production tax credits related to the Oso Grande generating facility; and (iii) higher margins
on long-term wholesale sales. The increase was partially offset by: (i) higher depreciation expense, due to new depreciation rates also approved as
part of the rate application; (ii) higher operating expenses, reflecting labour costs as well as an increase in planned generation maintenance in
2024; and (iii) lower transmission revenue.
Central Hudson
Variance
($ millions, except as indicated)
2024
2023
FX
Other
Electricity sales (GWh)
5,060
4,921
—
139
Gas sales (PJ)
25
24
—
1
Revenue
1,372
1,360
22
(10)
Earnings
128
105
3
20
Sales
The increase in electricity sales was due primarily to higher average consumption by residential and commercial customers due to warmer
weather.
Gas sales were relatively consistent with 2023.
Changes in electricity and gas sales at Central Hudson are subject to regulatory revenue decoupling mechanisms and, therefore, do not materially
impact earnings.
Revenue
The decrease in revenue, net of foreign exchange, was due primarily to the flow-through of lower energy supply costs driven by commodity
prices, partially offset by the conclusion of Central Hudson's 2024 general rate application and related rebasing of customer rates effective
July 1, 2024. Favourable regulatory adjustments recognized in 2023 that did not reoccur in 2024 also contributed to the decrease in revenue.
Earnings
The increase in earnings, net of foreign exchange, was due to Rate Base growth, as well as new customer rates reflecting the rebasing of costs and
a higher allowed ROE effective July 1, 2024. The increase was partially offset by favourable regulatory adjustments recognized in 2023 that did not
reoccur in 2024.
FortisBC Energy
($ millions, except as indicated)
2024
2023
Variance
Gas sales (PJ)
220
213
7
Revenue
1,665
1,955
(290)
Earnings
293
274
19
Sales
The increase in gas sales was due primarily to higher average consumption by industrial, residential and commercial customers.
Management Discussion and Analysis
8
FORTIS INC.
DECEMBER 31, 2024
Revenue
The decrease in revenue was due primarily to the recovery of lower flow-through commodity costs and the normal operation of regulatory
mechanisms.
Earnings
The increase in earnings was due primarily to higher net investments in regulated assets.
FortisBC Energy earns approximately the same margin regardless of whether a customer contracts for the purchase and delivery of natural gas or
only for delivery. Due to regulatory deferral mechanisms, changes in consumption levels and commodity costs do not materially impact earnings.
FortisAlberta
($ millions, except as indicated)
2024
2023
Variance
Electricity deliveries (GWh)
17,324
16,976
348
Revenue
817
738
79
Earnings
181
162
19
Deliveries
The increase in electricity deliveries was due primarily to customer additions and higher average consumption by industrial customers.
As approximately 85% of FortisAlberta's revenue is derived from fixed or largely fixed billing determinants, changes in quantities of energy
delivered are not entirely correlated with changes in revenue. Revenue is a function of numerous variables, many of which are independent of
actual energy deliveries. Significant variations in weather conditions, however, can impact revenue and earnings.
Revenue
The increase in revenue was due to: (i) Rate Base growth, including changes associated with the third PBR term beginning January 1, 2024; (ii) an
increase in the allowed ROE from 8.50% to 9.28%, as approved by the AUC, effective January 1, 2024; and (iii) higher industrial and commercial
demand charges, as well as customer additions.
Earnings
The increase in earnings was due to the higher allowed ROE, Rate Base growth, higher demand charges and customer additions, as discussed
above. The increase was partially offset by higher operating expenses, primarily reflecting operational requirements driven by customer growth,
including higher labour costs.
FortisBC Electric
($ millions, except as indicated)
2024
2023
Variance
Electricity sales (GWh)
3,513
3,478
35
Revenue
545
528
17
Earnings
72
68
4
Sales
The increase in electricity sales was due to higher average consumption by industrial customers, partially offset by lower average consumption by
commercial customers.
Revenue
The increase in revenue was due primarily to higher electricity sales and Rate Base growth, as well as higher energy supply costs recovered from
customers. The increase was partially offset by the normal operation of regulatory mechanisms.
Earnings
The increase in earnings was due primarily to Rate Base growth.
Due to regulatory deferral mechanisms, changes in consumption levels do not materially impact earnings.
Management Discussion and Analysis
9
FORTIS INC.
DECEMBER 31, 2024
Other Electric
Variance
($ millions, except as indicated)
2024
2023
FX
Other
Electricity sales (GWh)
9,879
9,753
—
126
Revenue
1,838
1,761
8
69
Earnings
163
146
—
17
Sales
The increase in electricity sales was mainly due to higher average consumption by residential and commercial customers, as well as customer
additions. Higher average consumption was largely due to the conversion of home heating systems from oil to electric in Eastern Canada and
increased tourism-related activities in the Caribbean.
Revenue
The increase in revenue, net of foreign exchange, was due to Rate Base growth, higher electricity sales and the flow-through of higher energy
supply costs.
Earnings
The increase in earnings, net of foreign exchange, was due primarily to Rate Base growth and higher electricity sales.
Corporate and Other
Variance
($ millions)
2024
2023
FX
Other
Electricity sales (GWh) (1)
215
164
—
51
Revenue (2)
35
84
—
(49)
Net loss (3)
(221)
(157)
(12)
(52)
(1) Reflects electricity sales at Fortis Belize
(2) Includes revenue for Fortis Belize as well as revenue for Aitken Creek up to the November 1, 2023 date of disposition
(3) Includes non-regulated holding company expenses, earnings for Fortis Belize, as well as earnings for Aitken Creek up to the November 1, 2023 date of disposition
Sales
The increase in electricity sales reflected higher hydroelectric production in Belize associated with rainfall levels.
Revenue
The decrease in revenue reflected the disposition of Aitken Creek in November 2023, partially offset by higher hydroelectric production in Belize.
Net Loss
The increase in net loss was due to: (i) higher holding company finance costs; (ii) net unrealized losses on derivative contracts, reflecting losses on
foreign exchange contracts partially offset by gains on total return swaps; and (iii) the $10 million gain on disposition of Aitken Creek recognized
in 2023. The increase in net loss was partially offset by higher hydroelectric production in Belize.
The $12 million foreign exchange impact was largely due to the revaluation of U.S. dollar denominated liabilities following the significant
depreciation in the Canadian dollar relative to the U.S. dollar in the fourth quarter of 2024.
NON-U.S. GAAP FINANCIAL MEASURES
Adjusted Common Equity Earnings, Adjusted Basic EPS, Adjusted Payout Ratio and Capital Expenditures are Non-U.S. GAAP Financial Measures
and may not be comparable with similar measures used by other entities. They are presented because management and external stakeholders
use them in evaluating the Corporation's financial performance and prospects.
Net earnings attributable to common equity shareholders (i.e., Common Equity Earnings) and basic EPS are the most directly comparable
U.S. GAAP measures to Adjusted Common Equity Earnings and Adjusted Basic EPS, respectively. The Actual Payout Ratio calculated using
Common Equity Earnings is the most comparable U.S. GAAP measure to the Adjusted Payout Ratio. These adjusted measures reflect the removal
of items that management excludes in its key decision-making processes and evaluation of operating results.
Capital Expenditures include additions to property, plant and equipment and additions to intangible assets, as shown on the consolidated
statements of cash flows. It also included Fortis' 39% share of capital spending for the Wataynikaneyap Transmission Power Project, consistent
with Fortis' evaluation of operating results and its role as project manager during the construction of the project.
Management Discussion and Analysis
10
FORTIS INC.
DECEMBER 31, 2024
Non-U.S. GAAP Reconciliation
($ millions, except as indicated)
2024
2023
Variance
Adjusted Common Equity Earnings, Adjusted Basic EPS
and Adjusted Payout Ratio
Common Equity Earnings
1,606
1,506
100
Adjusting items:
October 2024 MISO base ROE decision (1)
20
—
20
Disposition of Aitken Creek (2)
—
(15)
15
Unrealized loss on mark-to-market of derivatives (3)
—
2
(2)
Revaluation of deferred income tax assets (4)
—
9
(9)
Adjusted Common Equity Earnings
1,626
1,502
124
Adjusted Basic EPS (5) ($)
3.28
3.09
0.19
Adjusted Payout Ratio (6) (%)
72.7
73.9
(1.2)
Capital Expenditures
Additions to property, plant and equipment
5,012
3,986
1,026
Additions to intangible assets
206
183
23
Adjusting item:
Wataynikaneyap Transmission Power Project (7)
29
160
(131)
Capital Expenditures
5,247
4,329
918
(1) Represents the prior period impact of FERC's October 2024 MISO base ROE decision (see "Regulatory Highlights - Significant Regulatory Matters" on page 12), net of income
tax recovery of $7 million, included in the ITC segment
(2) Aitken Creek was sold on November 1, 2023, with a March 31, 2023 effective date. For the year ended December 31, 2023, the adjustment represents: (i) the $10 million
gain on disposition, net of income tax expense of $13 million; and (ii) $5 million of net earnings at Aitken Creek, recognized in accordance with U.S. GAAP, during the
March 31, 2023 to November 1, 2023 stub period, net of income tax expense of $2 million, included in the Corporate and Other segment
(3) Represents the impact of mark-to-market accounting of natural gas derivatives at Aitken Creek through the March 31, 2023 effective date of disposition, net of income tax
recovery $1 million, included in the Corporate and Other segment
(4) Represents the revaluation of deferred income tax assets resulting from the reduction in the corporate income tax rate in the state of Iowa, included in the ITC segment
(5) Calculated using Adjusted Common Equity Earnings divided by weighted average common shares of 495.0 million in 2024 (2023 - 486.3 million)
(6) Calculated using dividends paid per common share of $2.39 in 2024 (2023 - $2.29) divided by Adjusted Basic EPS
(7) Represents Fortis' 39% share of capital spending for the Wataynikaneyap Transmission Power Project, included in the Other Electric segment. Construction was completed
in the second quarter of 2024
REGULATORY HIGHLIGHTS
General
The earnings of the Corporation's regulated utilities are determined under COS regulation, with some using PBR mechanisms.
Under COS regulation, the regulator sets customer rates to permit a reasonable opportunity for the timely recovery of the estimated costs of
providing service, including a fair rate of return on a deemed or targeted capital structure applied to an approved Rate Base. PBR mechanisms
generally apply a formula that incorporates inflation and assumed productivity improvements for a set term.
The ability to recover prudently incurred costs of providing service and earn the regulator-approved ROE or ROA may depend on achieving the
forecasts established in the rate-setting process. There can be varying degrees of regulatory lag between when costs are incurred and when they
are recovered in customer rates. As well, 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.
Transmission operations in the U.S. are regulated federally by FERC. Remaining utility operations in the U.S. and Canada are regulated by state or
provincial regulators. Utility operations in the Caribbean are regulated by regulatory and governmental authorities.
Additional information about regulation and the regulatory matters discussed below is provided in Note 2 in the 2024 Annual Financial
Statements. Also refer to "Business Risks - Utility Regulation" on page 22.
Management Discussion and Analysis
11
FORTIS INC.
DECEMBER 31, 2024
Significant Regulatory Matters
ITC
MISO Base ROE: In 2022, the D.C. Circuit Court issued a decision vacating certain FERC orders that had established the methodology for setting
the base ROE for transmission owners operating in the MISO region, including ITC, and remanded the matter to FERC for further process. This
matter dates back to complaints filed at FERC in 2013 and 2015 challenging the MISO base ROE then in effect.
In October 2024, FERC issued an order that removed the use of the risk premium model from the calculation of the base ROE, while maintaining
other modifications to the methodology. The updated methodology revised the base ROE from 10.02% to 9.98%, with a maximum ROE inclusive
of incentives not to exceed 12.58%. The order also directed the payment of certain refunds, with interest, by December 2025, for the 15-month
period from November 2013 through February 2015, and prospectively from September 2016. A regulatory liability of $39 million (US$27 million)
associated with the refunds has been recognized by ITC as of December 31, 2024. Fortis' 80.1% share of the related after-tax earnings impact was
approximately $22 million, of which $20 million related to periods prior to January 1, 2024.
Certain MISO transmission owners, including ITC, filed a request for rehearing with FERC in November 2024, and filed an appeal of the order with
the D.C. Circuit Court in January 2025. The requests for rehearing and appeal primarily focus on the refund period and the related interest. The
timing and outcome of these filings are unknown.
Transmission Incentives: In 2021, FERC issued a supplemental NOPR on transmission incentives modifying the proposal in the initial NOPR
released by FERC in 2020. The supplemental NOPR proposes to eliminate the 50-basis point RTO ROE incentive adder for RTO members that have
been members for longer than three years. Although the timing and outcome of this proceeding remain unknown, every 10-basis point change
in ROE at ITC impacts Fortis' annual EPS by approximately $0.01.
Transmission ROFR: In December 2023, the Iowa District Court ruled that the manner in which Iowa's ROFR statute was passed was
unconstitutional. The statute granted incumbent electric transmission owners, including ITC, a ROFR to construct, own and maintain certain
electric transmission assets in the state. The District Court did not make any determination on the merits of the ROFR itself, but did issue a
permanent injunction preventing ITC and others from taking further action to construct the MISO LRTP tranche 1 Iowa projects in reliance on the
ROFR.
MISO's decision with respect to the assignment of the tranche 1 LRTP projects was finalized on July 25, 2022. MISO is the only entity charged with
determining what projects are to be competitively bid pursuant to its tariff. In May 2024, MISO commenced a variance analysis process as a result
of the inability to construct a portion of the tranche 1 LRTP projects in Iowa due to the injunction imposed by the District Court. In August 2024,
MISO concluded the variance analysis, which reaffirmed the original allocation of projects to ITC and other incumbent transmission owners.
Approximately US$800 million of capital expenditures associated with the first tranche of MISO's LRTP in Iowa is reflected in Fortis' 2025-2029
capital plan. While the results of MISO's variance analysis process allow ITC to move forward with the development of its portion of tranche 1 LRTP
projects in Iowa, various legal proceedings with respect to this matter are ongoing for which the timing and outcome are unknown.
UNS Energy
Generic Regulatory Lag Docket: In December 2024, the ACC approved a formula rate plan policy statement which allows utilities to propose
formula rates in future rate cases. A formula rate plan, if approved by the ACC, would adjust rates annually based on a predetermined formula. A
formula rate plan is expected to improve rate stability for customers, while also reducing regulatory lag and the number of existing rate adjusters.
UNS Gas General Rate Application: In November 2024, UNS Gas filed a general rate application with the ACC requesting an increase in gas
delivery rates effective February 1, 2026. The application includes a request to set its ROE at 10.25% and a 56% common equity component of
capital structure. In January 2025, UNS Gas filed supplemental material proposing an annual rate adjustment mechanism as a result of the ACC's
formula rate policy statement discussed above. The timing and outcome of this proceeding are unknown.
Central Hudson
2025 General Rate Application: In August 2024, Central Hudson filed a general rate application with the PSC requesting an increase in electric
and gas delivery rates effective July 1, 2025. The application includes a request to set Central Hudson's allowed ROE at 10% and a 48% common
equity component of capital structure. The timing and outcome of this proceeding are unknown.
Show Cause Order: In October 2024, the PSC issued a Show Cause Order which directed Central Hudson to explain why the PSC should not
initiate an enforcement proceeding in connection with a gas-related explosion that occurred in November 2023. Central Hudson filed its
response in November 2024. The timing and outcome of the Show Cause Order are unknown.
Management Discussion and Analysis
12
FORTIS INC.
DECEMBER 31, 2024
FortisBC Energy and FortisBC Electric
2025-2027 Rate Framework: In April 2024, FortisBC filed an application with the BCUC requesting approval of a rate framework for the period
2025 through 2027. The rate framework builds upon the current multi-year rate plan and includes, amongst other items, updates to depreciation
and capitalized overhead rates, a revised level of operation and maintenance expense per customer indexed for inflation less a fixed productivity
adjustment factor, a similar approach to growth capital, a forecast approach to sustaining and other capital, continued collection of an innovation
fund recognizing the need to accelerate investment in clean energy innovation, and the continued sharing with customers of variances from the
allowed ROE. The rate framework also proposes the continuation of deferral mechanisms currently in place. A decision from the BCUC is expected
in mid-2025.
FortisAlberta
GCOC Decision: In October 2023, the AUC issued a decision on the 2024 GCOC proceeding. In November 2023, FortisAlberta sought permission to
appeal the GCOC decision to the Court of Appeal on the basis that the AUC erred in its decision to not adjust FortisAlberta's ROE and common
equity component of capital structure to address incremental business risk associated with competition from REAs located in FortisAlberta's
service area, as well as heightened regulatory risk due to the non-recovery of costs attributable to REAs. In April 2024, the Court of Appeal granted
FortisAlberta permission to appeal, and a decision is expected in the first quarter of 2025.
Third PBR Term Decision: In October 2023, the AUC issued a decision establishing the parameters for the third PBR term for the period of 2024
through 2028. In November 2023, FortisAlberta sought permission to appeal the decision to the Court of Appeal on the basis that the AUC erred
in its decision to determine capital funding using 2018-2022 historical capital investments without consideration for funding of new capital
programs included in the company's 2023 cost of service revenue requirement as approved by the AUC. FortisAlberta's application for permission
to appeal the decision was heard by the Court of Appeal in December 2024 and a decision is expected in the first quarter of 2025.
FINANCIAL POSITION
Cash and cash equivalents
44
(449) Reflects the timing of a debt issuance at ITC in 2023, with
proceeds reinvested in operating and capital requirements in
2024.
Other assets
87
268 Due primarily to an increase in employee future benefit assets,
driven by higher discount rates as well as investment returns on
DBP and OPEB plans.
Regulatory assets (current and long-term)
126
121 Due to changes associated with various regulatory mechanisms,
including an increase in deferred income taxes and deferred
energy management costs.
Property, plant and equipment, net
2,423
3,648 Reflects capital investments, partially offset by depreciation.
Accounts payable & other current liabilities
119
262 Due to an increase in trade accounts payable related to the
Corporation's capital program, and an increase in customer
deposits for the Eagle Mountain Pipeline project.
Regulatory liabilities (current and long-term)
214
119 Due to changes associated with various regulatory mechanisms
including employee future benefit and future cost of removal
deferrals, partially offset by the normal operation of rate
stabilization accounts.
Deferred income taxes
238
383 Primarily due to higher temporary differences associated with
ongoing capital investments.
Long-term debt (including current portion)
1,655
2,028 Reflects debt issuances, partially offset by debt repayments, as well
as higher borrowings under committed credit facilities, in support
of the Corporation's capital plan.
Shareholders' equity
1,405
898 Due primarily to: (i) Common Equity Earnings for 2024, less
dividends declared on common shares; and (ii) the issuance of
common shares, largely under the DRIP.
Significant Changes between December 31, 2024 and 2023
Balance Sheet Account
Variance
($ millions)
FX
Other Explanation
Management Discussion and Analysis
13
FORTIS INC.
DECEMBER 31, 2024
LIQUIDITY AND CAPITAL RESOURCES
Cash Flow Requirements
At the subsidiary level, it is expected that operating expenses and interest costs will be paid from Operating Cash Flow, with varying levels of
residual cash flow available for capital expenditures and/or dividend payments to Fortis. Remaining capital expenditures are expected to be
financed primarily from borrowings under credit facilities, long-term debt offerings and equity injections from Fortis. Borrowings under credit
facilities may be required periodically to support seasonal working capital requirements.
Cash required of Fortis to support subsidiary growth is generally derived from borrowings under the Corporation's credit facilities, the operation
of the DRIP, as well as issuances of long-term debt, preference equity, and common shares including those issued through the ATM Program. The
subsidiaries pay dividends to Fortis and receive equity injections from Fortis when required. Both Fortis and its subsidiaries initially borrow
through their credit facilities and periodically replace these borrowings with long-term financing. Financing needs also arise to refinance maturing
debt.
Credit facilities are syndicated primarily with large banks in Canada and the U.S., with no one bank holding more than approximately 20% of the
Corporation's total revolving credit facilities. Approximately $5.8 billion of the total credit facilities are committed with maturities ranging from
2025 through 2029. Available credit facilities are summarized in the following table.
Credit Facilities
As at December 31
Regulated
Corporate
($ millions)
Utilities
and Other
2024
2023
Total credit facilities (1)
4,396
1,946
6,342
6,176
Credit facilities utilized:
Short-term borrowings
(98)
—
(98)
(119)
Long-term debt (including current portion)
(1,335)
(881)
(2,216)
(1,572)
Letters of credit outstanding
(81)
(21)
(102)
(101)
Credit facilities unutilized
2,882
1,044
3,926
4,384
(1) Additional information about the Corporation's credit facilities is provided in Note 14 in the 2024 Annual Financial Statements
In April 2024, FortisBC Energy increased its operating credit facility from $700 million to $900 million and extended the maturity to July 2028. In
May 2024, FortisBC Electric increased its operating credit facility from $150 million to $200 million and extended the maturity to April 2028.
In May 2024, the Corporation extended the maturity on its unsecured US$500 million non-revolving term credit facility to May 2025. Half of the
term credit facility was repaid in the third quarter of 2024 and the remaining US$250 million has been fully utilized as at December 31, 2024. The
facility is repayable at any time without penalty. In June 2024, the Corporation amended its $1.3 billion revolving term committed credit facility to
extend the maturity to July 2029.
In August 2024, Newfoundland Power increased its operating credit facility from $100 million to $130 million and extended the maturity to
August 2029.
The Corporation's ability to service debt and pay dividends is dependent on the financial results of, and the related cash payments from, its
subsidiaries. Certain regulated subsidiaries are subject to restrictions that limit their ability to distribute cash to Fortis, including restrictions by
certain regulators limiting annual dividends and restrictions by certain lenders limiting debt to total capitalization. There are also practical
limitations on using the net assets of the regulated subsidiaries to pay dividends, based on management's intent to maintain the subsidiaries'
regulator-approved capital structures. Fortis does not expect that maintaining such capital structures will impact its ability to pay dividends in the
foreseeable future.
As at December 31, 2024, consolidated fixed-term debt maturities/repayments are expected to average $1,484 million annually over the next five
years and approximately 76% of the Corporation's consolidated long-term debt, excluding credit facility borrowings, had maturities beyond five
years.
In December 2024, Fortis filed a short-form base shelf prospectus with a 25-month life under which it may issue common or preference shares,
subscription receipts, or debt securities in an aggregate principal amount of up to $2.0 billion. Fortis also reestablished the ATM Program pursuant
to the short-form base shelf prospectus, which allows the Corporation to issue up to $500 million of common shares from treasury to the public
from time to time, at the Corporation's discretion, effective until January 10, 2027. As at December 31, 2024, $500 million remained available
under the ATM Program and $1.5 billion remained available under the short-form base shelf prospectus.
Management Discussion and Analysis
14
FORTIS INC.
DECEMBER 31, 2024
Fortis is well positioned with strong liquidity. This combination of available credit facilities and manageable annual debt maturities/repayments
provides flexibility in the timing of access to capital markets. Given current credit ratings and capital structures, the Corporation and its
subsidiaries currently expect to continue to have reasonable access to long-term capital in 2025.
Fortis and its subsidiaries were in compliance with debt covenants as at December 31, 2024 and are expected to remain compliant in 2025.
Cash Flow Summary
Summary of Cash Flows
Years ended December 31
($ millions)
2024
2023
Variance
Cash and cash equivalents, beginning of year
625
209
416
Cash from (used in):
Operating activities
3,882
3,545
337
Investing activities
(5,395)
(3,742)
(1,653)
Financing activities
1,064
613
451
Effect of exchange rate changes on cash and cash equivalents
44
—
44
Cash and cash equivalents, end of year
220
625
(405)
Operating Activities
See "Performance at a Glance - Operating Cash Flow" on page 4.
Investing Activities
The increase in cash used in investing activities primarily reflects higher capital expenditures in 2024, as well as the proceeds received in 2023
related to the disposition of Aitken Creek. See "Capital Plan" on page 19. Lower customer contributions in aid of construction also contributed to
the year over year variance.
Financing Activities
Cash flows related to financing activities will fluctuate largely as a result of changes in the subsidiaries' capital expenditures and the amount of
Operating Cash Flow available to fund those capital expenditures, which together impact the amount of funding required from debt and
common equity issuances. See "Cash Flow Requirements" on page 14. The year over year increase in cash from financing activities also reflects the
repayment of credit facility borrowings in 2023 with the proceeds received from the sale of Aitken Creek.
Management Discussion and Analysis
15
FORTIS INC.
DECEMBER 31, 2024
Debt Financing
Month
Issued
Interest Rate
(%)
Maturity
Amount
($ millions)
Use of
Proceeds
Significant Long-Term Debt Issuances
Year ended December 31, 2024
ITC
Secured senior notes
January
5.98
2034
US
85
(1) (2) (3)
First mortgage bonds
January
5.11
2029
US
75
(1) (2) (3)
First mortgage bonds
January
5.38
2034
US
75
(1) (2) (3)
Unsecured senior notes
May
5.65
2034
US
400
(3) (4)
First mortgage bonds
December
4.88
2035
US
125
(1) (2) (3)
First mortgage bonds
December
5.25
2043
US
125
(1) (2) (3)
UNS Energy
Unsecured senior notes
May
5.60
2036
US
30
(1) (3)
Unsecured senior notes
August
5.20
2034
US
400
(3) (4)
Central Hudson
Senior notes
April
5.59
2031
US
25
(1) (3)
Senior notes
April
5.69
2034
US
35
(1) (3)
Senior notes
October
4.88
2029
US
25
(3) (4)
Senior notes
October
5.30
2034
US
44
(3) (4)
Senior notes
October
5.40
2036
US
35
(3) (4)
FortisBC Electric
Unsecured debentures
August
4.92
2054
100
(1)
FortisAlberta
Unsecured debentures
May
4.90
2054
300
(1) (2) (3) (4)
Caribbean Utilities
Unsecured senior notes
May
6.17
2039
US
40
(1) (2) (3)
Unsecured senior notes
May
6.37
2049
US
40
(1) (2) (3)
FortisOntario
Unsecured senior notes
August
5.05
2054
55
(1)
Fortis
Unsecured senior notes
September
4.17
2031
500
(1) (3) (4)
(1) Repay short-term and/or credit facility borrowings
(2) Fund capital expenditures
(3) General corporate purposes
(4) Repay maturing long-term debt
Common Equity Financing
Common Equity Issuances and Dividends Paid
Years ended December 31
($ millions, except as indicated)
2024
2023
Variance
Common shares issued:
Cash (1)
46
43
3
Non-cash (2)
435
409
26
Total common shares issued
481
452
29
Number of common shares issued (# millions)
8.7
8.4
0.3
Common share dividends paid:
Cash
(744)
(701)
(43)
Non-cash (3)
(434)
(408)
(26)
Total common share dividends paid
(1,178)
(1,109)
(69)
Dividends paid per common share ($)
2.39
2.29
0.10
(1) Includes common shares issued under stock option and employee share purchase plans
(2) Common shares issued under the DRIP and stock option plan
(3) Common share dividends reinvested under the DRIP
Management Discussion and Analysis
16
FORTIS INC.
DECEMBER 31, 2024
On December 4, 2024 and February 13, 2025, Fortis declared a dividend of $0.615 per common share payable on March 1, 2025 and June 1, 2025,
respectively. The payment of dividends is at the discretion of the Board and depends on the Corporation's financial condition and other factors.
On March 1, 2024, the annual fixed dividend per share for the First Preference Shares, Series K was reset from $0.9823 to $1.3673 for the five-year
period up to but excluding March 1, 2029.
On December 1, 2024, the annual fixed dividend per share for the First Preference Shares, Series M was reset from $0.9783 to $1.3733 for the five-
year period up to but excluding December 1, 2029.
Contractual Obligations
Contractual Obligations
As at December 31, 2024
($ millions)
Total
Year 1
Year 2
Year 3
Year 4
Year 5
Thereafter
Long-term debt:
Principal (1)
33,405
1,990
2,585
2,541
1,499
1,024
23,766
Interest
19,630
1,371
1,343
1,252
1,162
1,116
13,386
Finance leases (2)
1,139
37
37
37
37
37
954
Other obligations (3)
464
127
110
100
22
21
84
Other commitments: (4)
Gas and fuel purchase obligations
6,299
763
571
520
465
393
3,587
Renewable power purchase agreements
2,628
139
166
182
182
173
1,786
Waneta Expansion capacity agreement
2,362
56
58
59
60
61
2,068
Power purchase obligations
1,335
302
217
131
124
122
439
ITC easement agreement
370
14
14
14
14
14
300
TEP EPC agreements
308
307
1
—
—
—
—
Debt collection agreement
99
3
3
3
3
3
84
Renewable energy credit purchase agreements
58
18
7
6
6
6
15
Other
140
32
11
11
12
10
64
68,237
5,159
5,123
4,856
3,586
2,980
46,533
(1) Amounts not reduced by unamortized deferred financing and discount costs of $191 million. Additional information is provided in Note 14 of the 2024 Annual Financial
Statements
(2) Additional information is provided in Note 15 of the 2024 Annual Financial Statements
(3) Primarily includes commitments with respect to long-term compensation and employee future benefit arrangements
(4) Represents unrecorded commitments. Additional information is provided in Note 27 of the 2024 Annual Financial Statements
Other Contractual Obligations
The Corporation's regulated utilities are obligated to provide service to customers within their respective service territories. Capital Expenditures
are forecast to be approximately $5.2 billion for 2025 and approximately $26.0 billion for the five-year 2025-2029 capital plan. See "Capital Plan" on
page 19.
Under a funding framework with the Governments of Ontario and Canada, Fortis will contribute a minimum of approximately $165 million of
equity capital to Wataynikaneyap Power, based on Fortis' proportionate 39% ownership interest and the final regulatory-approved capital cost of
the related project. Wataynikaneyap Power has construction financing loan agreements in place and it is expected that long-term operating
financing will replace the construction financing. In the event a lender under the loan agreements realizes security on the loans, Fortis may be
required to accelerate its equity capital contributions, which may be in excess of the amount otherwise required of Fortis under the funding
framework, to a maximum total funding of $235 million. Equity of $137 million has been contributed as of December 31, 2024.
UNS Energy has joint generation performance guarantees with participants at Four Corners and Luna, with agreements expiring in 2041 and 2046
respectively, and at San Juan and Navajo through decommissioning. The participants have guaranteed that in the event of payment default, each
non-defaulting participant will bear its proportionate share of expenses otherwise payable by the defaulting participant. In exchange, the non-
defaulting participants are entitled to receive their proportionate share of the generation capacity of the defaulting participant. In the case of San
Juan and Navajo, participants would seek financial recovery from the defaulting party. There is no maximum amount under these guarantees,
except for a maximum of $360 million for Four Corners. As at December 31, 2024, there was no obligation under these guarantees.
Off-Balance Sheet Arrangements
With the exception of letters of credit outstanding of $102 million as at December 31, 2024 and the unrecorded commitments in the table above,
the Corporation had no off-balance sheet arrangements.
Management Discussion and Analysis
17
FORTIS INC.
DECEMBER 31, 2024
Capital Structure and Credit Ratings
Fortis requires ongoing access to capital and, therefore, targets a consolidated long-term capital structure that will enable it to maintain
investment-grade credit ratings. The regulated utilities maintain their own capital structures in line with those reflected in customer rates.
Consolidated Capital Structure
2024
2023
As at December 31
($ millions)
(%)
($ millions)
(%)
Debt (1)
33,435
56.4
29,364
55.7
Preference shares
1,623
2.7
1,623
3.1
Common shareholders' equity and non-controlling interests (2)
24,230
40.9
21,709
41.2
59,288
100.0
52,696
100.0
(1) Includes long-term debt and finance leases, including current portion, and short-term borrowings, net of cash
(2) Includes shareholders' equity, excluding preference shares, and non-controlling interests. Non-controlling interests represented 3.4% as at December 31, 2024
(December 31, 2023 - 3.5%)
Outstanding Share Data
As at February 13, 2025, the Corporation had issued and outstanding 499.3 million common shares and the following First Preference Shares:
5.0 million Series F; 9.2 million Series G; 7.7 million Series H; 2.3 million Series I; 8.0 million Series J; 10.0 million Series K; and 24.0 million Series M.
The common shares of the Corporation have voting rights. The Corporation's first preference shares do not have voting rights unless and until
Fortis fails to pay eight quarterly dividends, whether or not consecutive or declared.
If all outstanding stock options were converted as at February 13, 2025, an additional 1.5 million common shares would be issued and
outstanding.
Credit Ratings
The Corporation's credit ratings shown below reflect its low business risk profile, diversity of operations, the stand-alone nature and financial
separation of each regulated subsidiary, and the level of holding company debt.
As at December 31, 2024
Rating
Type
Outlook
S&P
A-
Issuer
Negative
BBB+
Unsecured debt
Morningstar DBRS
A (low)
Issuer
Stable
A (low)
Unsecured debt
Stable
Moody's
Baa3
Issuer
Stable
Baa3
Unsecured debt
Management Discussion and Analysis
18
FORTIS INC.
DECEMBER 31, 2024
Capital Plan
Capital investment in energy infrastructure is required to ensure the continued and enhanced performance, reliability and safety of the electricity
and gas systems, to meet customer growth, and to deliver cleaner energy.
Capital Expenditures in 2024 were $5.2 billion, consistent with expectations and $0.9 billion higher than 2023. The increase compared to 2023 was
primarily due to investments associated with the Eagle Mountain Pipeline project at FortisBC Energy, expenditures on various transmission
reliability projects at ITC, and construction of the Roadrunner Reserve battery storage projects at UNS Energy.
2024 Capital Expenditures (1)(2)
Regulated Utilities
Total
Regulated
Utilities
Non-
Regulated
Corporate
and Other
Total
($ millions, except as indicated)
ITC
UNS
Energy
Central
Hudson
FortisBC
Energy
Fortis
Alberta
FortisBC
Electric
Other
Electric
Total
1,456
1,151
431
1,035
554
132
483
5,242
5
5,247
Forecast 2025 Capital Expenditures (2)
Regulated Utilities
Total
Regulated
Utilities
Non-
Regulated
Corporate
and Other
Total (3)
($ millions, except as indicated)
ITC
UNS
Energy
Central
Hudson
FortisBC
Energy
Fortis
Alberta
FortisBC
Electric
Other
Electric
Total
1,403
1,276
462
687
624
179
540
5,171
7
5,178
2025-2029 Capital Plan (2)
($ billions)
2025
2026
2027
2028
2029
Total (3)
Five-year capital plan
5.2
5.2
5.6
5.4
4.6
26.0
(1) See "Non-U.S. GAAP Financial Measures" on page 10. Reflects a U.S. dollar-to-Canadian dollar exchange rate of 1.37 for 2024
(2) Excludes the non-cash equity component of AFUDC
(3) Reflects an assumed U.S. dollar-to-Canadian dollar exchange rate of 1.30. On average, Fortis estimates that a five-cent increase or decrease in the U.S. dollar relative to the
Canadian dollar would increase or decrease Capital Expenditures by approximately $600 million over the five-year planning period
The Corporation's 2025-2029 capital plan of $26.0 billion is $1.0 billion higher than the previous five-year plan. The increase is driven by projects
associated with the MISO LRTP and resiliency investments at ITC, as well as distribution investments largely due to customer growth at
FortisAlberta.
The five-year capital plan is low risk and highly executable, with nearly all investments being regulated and only 23% relating to Major Capital
Projects. Geographically, 58% of planned expenditures are expected in the U.S., including 29% at ITC, with 38% in Canada and the remaining 4%
in the Caribbean.
The five-year capital plan is expected to be funded primarily by cash from operations and regulated utility debt. Common equity proceeds are
expected to be provided by the Corporation's DRIP, assuming current participation levels. The Corporation's $500 million ATM Program remains
available and provides funding flexibility as required.
Planned capital expenditures are based on detailed forecasts of energy demand as well as labour and material costs, including inflation, supply
chain availability, general economic conditions, foreign exchange rates and other factors. These factors, including potential new or revised tariffs,
could change and cause actual expenditures to differ from forecast. Fortis remains focused on maintaining customer affordability by controlling
costs, investing in cleaner energy resulting in fuel savings for customers, utilizing available tax credits, and implementing innovative practices,
among other initiatives.
Management Discussion and Analysis
19
FORTIS INC.
DECEMBER 31, 2024
Midyear Rate Base (1)
($ billions)
2024(2)
2025(2)
2029(2)
ITC
12.5
12.8
16.5
UNS Energy
7.6
7.7
10.7
Central Hudson
3.2
3.4
4.3
FortisBC Energy
5.8
6.3
8.7
FortisAlberta
4.4
4.7
5.7
FortisBC Electric
1.7
1.8
2.1
Other Electric
3.8
4.0
5.0
Total
39.0
40.7
53.0
(1) Simple average of Rate Base at beginning and end of the year
(2) Reflects a U.S. dollar-to-Canadian dollar average exchange rate of 1.37 for 2024. 2025 and 2029 reflect an assumed U.S. dollar-to-Canadian dollar exchange rate of 1.30
consistent with the Corporation's 2025-2029 capital plan. On average, Fortis estimates that a five-cent increase or decrease in the U.S. dollar relative to the Canadian dollar
would increase or decrease Rate Base by approximately $1.1 billion over the five-year planning period
Total midyear Rate Base is forecast to grow to $53.0 billion by 2029 underpinned by the five-year capital plan, translating to a CAGR of 6.5%.
Major Capital Projects
Plan
Expected
($ millions)
Pre-2024
Actual 2024
2025-2029
Completion
ITC
MISO LRTP
25
64
1,704
Post-2029
UNS Energy
IRP Related Generation
—
1
1,620
Various
Roadrunner Reserve Battery Storage Project 1
137
286
51
2025
Roadrunner Reserve Battery Storage Project 2
1
115
325
2026
Vail-to-Tortolita Transmission Project
152
47
253
2027
FortisBC Energy
Eagle Mountain Pipeline Project (1)
50
386
314
2027
Tilbury LNG Storage Expansion
29
6
585
2029
AMI Project
7
30
733
2028
Tilbury 1B Project
44
5
339
2029
Total
940
5,924
(1) Net of customer contributions
MISO LRTP
Reflects investments associated with two tranches of the MISO LRTP. In 2022, the MISO board approved the first tranche of projects representing
18 transmission projects across the MISO Midwest subregion with total associated costs estimated at US$10 billion. Six of these projects run
through ITC's MISO operating companies' service territories. ITC estimates transmission investments of US$1.4 billion to US$1.8 billion through
2030 associated with six of the 18 projects, with investments of approximately $1.6 billion (US$1.2 billion) included in the Corporation's 2025-2029
capital plan.
Investments of approximately $0.2 billion (US$0.1 billion) have been included in the Corporation's 2025-2029 capital plan associated with tranche
2.1. Significant additional investment opportunities remain for tranche 2.1 (see "Additional Investment Opportunities" on page 21).
IRP Related Generation
Includes capital expenditures supporting the energy transition as outlined in the 2023 IRPs for TEP and UNS Electric including
renewable generation, energy storage systems and natural gas generation. Investments support approximately 950 MW of generation, subject to
all-source requests for proposals.
Roadrunner Reserve Battery Storage Projects
Consists of two, 200 MW, battery energy storage systems which will facilitate the integration of renewable energy into the electric grid. Each
system is capable of storing 800 MW hours of energy, enough to serve approximately 42,000 homes for four hours when deployed at full capacity.
TEP will own and operate the systems.
Construction of Roadrunner Reserve 1 has commenced and is scheduled for completion in 2025. In October 2024, TEP filed an application with
the ACC requesting approval to defer certain costs associated with owning and operating Roadrunner Reserve 1 for future recovery. TEP cannot
predict the timing or outcome of this application.
In August 2024, TEP entered into an EPC agreement to develop Roadrunner Reserve 2, which is scheduled for completion in 2026.
Management Discussion and Analysis
20
FORTIS INC.
DECEMBER 31, 2024
Vail-to-Tortolita Transmission Project
Includes investment in one circuit of a new double circuit 230 kilovolt transmission line to tie infrastructure into the TEP system, improving service
and reliability to customers. Construction commenced in late 2023, and is scheduled for completion in 2027.
Eagle Mountain Pipeline Project
The project consists of a 50-km pipeline expansion to a small-scale LNG facility owned by Woodfibre LNG near Squamish, British Columbia.
FortisBC Energy commenced construction of the project in 2023 which is scheduled for completion in 2027.
Tilbury LNG Storage Expansion Project
This project replaces the original LNG storage tank at the Tilbury site and increases the available regasification capacity to provide backup gas
supply for lower mainland customers. The regulatory process was adjourned in 2023 in order for FortisBC Energy to prepare further information in
support of the CPCN application. In October 2024, FortisBC Energy filed the additional information requested. A decision from the BCUC is
expected in late 2025.
AMI Project
The project includes replacement of residential, commercial and industrial meters with advanced gas meters to support the safety, resiliency, and
efficient operation of FortisBC Energy's gas distribution system. The project will enable remote meter reading and remote shutoff of gas. The
CPCN application was approved by the BCUC in 2023, and installation of the advanced meters is expected to commence in 2025 and be
substantially complete in 2028.
Tilbury 1B Project
Construction of additional liquefaction and dispensing, including on-shore piping, in support of marine bunkering and to further optimize the
Tilbury Phase 1A Expansion Project. This FortisBC Energy project received an Order in Council from the Government of British Columbia in 2017.
An initial project scope has been filed with regulators to support the federal impact assessment and provincial environmental assessment
required to further expand the Tilbury site.
Additional Investment Opportunities
Fortis is pursuing additional investment opportunities within existing service territories that are not yet included in the five-year capital plan.
ITC
The MISO LRTP is expected to consist of several tranches. The opportunity associated with the first tranche of projects is outlined above. In
December 2024, the MISO board of directors approved a portfolio of tranche 2.1 LRTP projects with estimated transmission costs of approximately
US$22 billion. ITC now estimates a range of US$3.7 billion to US$4.2 billion in capital expenditures for the MISO tranche 2.1 projects located in
Michigan and Minnesota where ROFRs are in effect and for projects requiring system upgrades in Iowa which are not subject to a competitive
bidding process. A majority of the tranche 2.1 investment is expected beyond 2029.
In October 2024, ITC in collaboration with another Midwest U.S. energy company, received MISO approval for the Big Cedar Load Expansion
Project in Iowa. The project will consist of two phases and includes transmission upgrades to serve up to 1,600 MW of new data center
load at the Big Cedar Industrial Center. The first phase of the project requires transmission upgrades to support 800 MW of new load with a
targeted in-service date of 2027, and phase two requires an additional 800 MW with an expected in-service date of 2028. The project requires
franchise approvals from the Iowa Utilities Commission prior to construction. The project has a potential investment of up to US$400 million.
UNS Energy
TEP is experiencing significant interest from potential new large retail customers in the manufacturing, data center, and mining sectors with
energy demands that could create substantial new energy needs. TEP continues to work with the potential companies to assess capital
requirements and associated timelines.
FortisBC Energy - LNG
During 2024, provincial and federal environmental assessment certificates were issued for the Tilbury Marine Jetty project. The construction of the
jetty supports further expansion of FortisBC's Tilbury LNG facility, which is uniquely positioned to meet customer demand for LNG. The site is
scalable, can accommodate additional storage and liquefaction equipment and is close to international shipping lanes. Once constructed, the
jetty would utilize FortisBC Energy's assets at the Tilbury site, including the Tilbury Phase 1B Project yet to be constructed, to service marine
bunkering.
Other Opportunities
Includes incremental transmission investment and grid modernization projects at ITC; projects related to the 2023 IRPs as well as transmission
investments at UNS Energy; regional transmission in New York; further renewable gas and LNG infrastructure opportunities in British Columbia;
grid resiliency and climate adaptation investments; and the acceleration of load growth and cleaner energy infrastructure investments across our
jurisdictions.
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GHG Emissions Reduction Targets
Fortis is primarily an energy delivery company with 93% of its assets related to transmission and distribution. This limits the impact of
the Corporation’s utilities on the environment when compared to more generation-intensive businesses. Fortis has a relatively small amount of
fossil-fuel generation in its portfolio and plans to transition to more renewable sources of energy for its customers.
Fortis continues to lower its already low emissions profile, and has set a 2050 net-zero direct GHG emissions target. This goal is in addition to the
Corporation's interim targets to reduce direct GHG emissions 50% by 2030 and 75% by 2035 from a 2019 base year. Fortis expects to achieve its
targets primarily through TEP's plan to exit from coal, as well as clean energy initiatives across the Corporation's other utilities. The Corporation's
ability to achieve the GHG targets may be impacted by federal, state and provincial energy policies, as well as external factors, including
significant customer and load growth and the development of clean energy technology. Reliability and affordability will remain key priorities as
Fortis works to meet its emissions reduction targets.
Through 2024, Fortis has made significant progress on its emissions reduction targets with the Corporation's Scope 1 emissions 34% lower
compared to 2019 levels. The retirement of certain coal generating stations, the commencement of seasonal operations at other generating
stations, and the introduction of renewable wind and solar energy in Arizona, have supported our carbon emissions reduction to date.
Climate-Related Disclosure Standards
In December 2024, the CSSB issued CSDS S1, General Requirements for Disclosure of Sustainability-Related Financial Information, and CSDS S2,
Climate-Related Disclosures, which require an entity to disclose information about its sustainability-related and climate-related risks and
opportunities, including the disclosure of material Scope 1, 2 and 3 GHG emissions. The CSSB standards are voluntary and must be adopted by
the CSA to become mandatory for Canadian reporting issuers, including Fortis. The CSA continues to work towards a revised climate-related
disclosure rule that will consider the CSSB standards and may include modifications considered appropriate for Canadian capital markets. The
content and timing of the CSA's revised climate-related disclosure rule are unknown. Fortis will continue to monitor updates from the CSA to
assess any potential impact on the Corporation's disclosures.
In March 2024, the SEC released Rule No. 33-11275, The Enhancement and Standardization of Climate-Related Disclosures for Investors, which outlines
climate-related disclosure requirements. The rule requires disclosure of the financial effects of severe weather events and other natural conditions,
as well as other climate-related financial information, in the notes to the financial statements. In addition, the rule requires disclosure of risk
management, governance and oversight activities, the impact of material climate-related risks on a company's strategy, business model and
outlook, and details of material climate-related targets or goals. Disclosure of material Scope 1 and 2 GHG emissions is also required for certain
filers. The SEC subsequently voluntarily stayed the rule pending completion of judicial review by the Court of Appeals for the Eighth Circuit. While
the rule does not apply to Fortis as a foreign private issuer filing in the U.S. using Form 40-F, management is reviewing the standard to assess the
potential impact on the Corporation's disclosures.
BUSINESS RISKS
Fortis has an ERM program that identifies and evaluates the severity and probability of risks to its business. The Fortis Board, through its audit
committee, oversees Fortis' ERM program ensuring that management has an effective risk management system to support strategic planning.
The ERM program at the subsidiary level is overseen by each subsidiary's board of directors and any material risks identified form part of Fortis'
ERM program. Materiality thresholds are reviewed annually. Systems of internal controls are used by management to monitor and manage
identified risks. A summary of the Corporation's significant business risks follows.
Utility Regulation
Regulated utility assets represented virtually all of the Corporation's total assets as at December 31, 2024. Regulatory jurisdictions include five
Canadian provinces, ten U.S. states and three Caribbean countries, as well FERC regulation for transmission assets in the U.S.
Regulators administer legislation covering material aspects of the utilities' business including: customer rates, allowed ROEs and deemed capital
structures; capital expenditures; the terms and conditions for the provision of energy and capacity, ancillary services and affiliate services;
securities issuances; and certain accounting matters. Regulatory or legislative changes and decisions, and delays in the recovery of costs in rates
due to regulatory lag, could have a Material Adverse Effect. The risk of regulatory lag may be significant for UNS Energy given the past practice of
its regulator to use historical test years in setting customer rates.
The ability to recover the actual cost of service and earn the approved ROE or ROA typically depends upon achieving the forecasts established in
the rate-setting process. For those utilities subject to PBR mechanisms, rates reflect assumed inflation rates and productivity improvement factors,
and variances therefrom could adversely affect rates of return. Failure to recover costs and/or earn a return could have a Material Adverse Effect.
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For transmission operations, the underlying elements of FERC-established formula rates can be challenged by third parties which could result in
rate reductions and customer refunds. These underlying elements include the ROE, ROE adders and deemed capital structure, as well as operating
and capital expenditures.
In addition, the U.S. Congress periodically considers enacting energy legislation that could assign new responsibilities to FERC, modify provisions
of the U.S. Federal Power Act or the Natural Gas Act, or provide FERC or another entity with increased authority to regulate U.S. federal energy
matters.
While Fortis is well-positioned to maintain constructive regulatory relationships through local management teams and subsidiary boards of
directors comprised mostly of independent local members, it cannot predict future legislative or regulatory changes, whether caused by
economic, political or other factors. The Corporation and its utilities may experience challenges and compliance costs in responding to such
regulatory changes in an effective and timely manner. Any such regulatory changes or operational impacts could have a Material Adverse Effect.
Physical Risks
The provision of electric and gas service is subject to physical risks, including impacts from severe weather and natural disasters, wars, terrorism,
vandalism, critical equipment failure and other catastrophic events, including wildfires, within and outside the Corporation's service territories.
Electric utilities face risk of loss or damage from wildfires, floods, hurricanes, storm surges, washouts, landslides, earthquakes, avalanches, snow or
ice storms, and other acts of nature. Further, certain utilities operate in remote or mountainous terrain that can be difficult to access for timely
repairs and maintenance.
Gas utilities are exposed to operational risks associated with natural gas, including fires, explosions, pipeline corrosion and leaks, accidental
damage to mains and service lines, equipment failure, damage and destruction from earthquakes, fires, floods and other natural disasters.
Accidents or natural disasters affecting any of the Corporation's electricity or gas utilities can lead to service disruption, spills and commensurate
environmental or other liability.
In addition, the operation of electric and gas systems has the potential to cause fires, including wildfires as a result of equipment failure, falling
trees, lightning strikes to lines or equipment, or otherwise. The risks associated with fire damage vary depending on weather, forestation, the
proximity of habitation and third-party facilities to utility facilities, and other factors. Failure to adequately address the risk of fire and wildfires
could result in civil actions and government enforcement proceedings and utilities may become liable for fire-suppression costs, regeneration
and timber value costs, and third-party losses if their facilities are determined to have been responsible for, or contributed to, a fire or wildfire.
Generating equipment and facilities are subject to physical risks, including equipment breakdown or damage from fire, floods or other natural
disasters, that may result in the uncontrolled release of water, interruption of fuel supply, lower-than-expected operational efficiency or
performance, and service disruption.
Electricity and gas systems require ongoing maintenance, improvement and replacement. The utilities are responsible for operating and
maintaining their assets in a safe manner, including the development and application of appropriate standards, system processes and/or
procedures to ensure the safety of employees, contractors and the general public.
If service disruption, or damage arising from, or caused by, the failure to properly implement or complete approved maintenance and capital
expenditures, severe weather or other physical risks, is not mitigated through insurance policies or the recovery of such costs in customer rates,
such service disruption or damage could result in loss.
Any of the foregoing potential impacts of physical risk could have a Material Adverse Effect.
The foregoing physical risks can be exacerbated by the "Climate Change" risks discussed below.
Climate Change
Climate-Related Physical Risk
Climate change may negatively impact the ability to provide reliable and safe electric and gas service. A changing climate that leads to higher
temperatures and more frequent and severe weather events may impact or disrupt the reliability of electric or gas systems. The physical risks
associated with a changing climate requires the Corporation’s utilities to adapt and respond to continue delivering reliable service to customers.
Severe weather and events related to severe weather impact the Corporation's service territories, primarily in the form of thunderstorms, flooding,
drought, extreme heat, wildfires, hurricanes, storm surges, atmospheric rivers and snow, or ice storms. Increased frequency of such events could
increase the cost of providing service through increased repairs and use of contingency plans. Extreme weather conditions and changes in air
temperature require system backup and can result in system stress, including service disruptions, and decreased efficiency of operating facilities
over time. Changes in precipitation that impact soil moisture and water levels, or result in droughts, could increase the risk of wildfire caused by
the Corporation's electricity assets or may cause water shortages that could adversely affect operations.
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Longer-term climate change impacts, such as sustained higher temperatures, higher sea levels, larger storm surges and floods, could result in
service disruption, shortened asset life, increased repair and replacement costs, and costs associated with strengthened design standards and
systems. The impacts of climate change can intensify the "Physical Risks" (see "Physical Risks" on page 23).
The physical risks posed by the impacts of climate change and resultant damage to assets, service disruption repair and replacement costs, and
liability for third party damages could have a Material Adverse Effect if not resolved in a timely and effective manner and/or mitigated through
insurance policies or regulatory cost recovery. An increase in business risk associated with climate change can also impact credit ratings, which
could affect credit risk spreads on new long-term debt and credit facilities, as well as their availability (see "Access to Capital" on page 28).
Climate-Related Transition Risk
A transition towards decarbonization and further renewable energy use elevates risks associated with policy, legal, technological and market
changes which may have capital and financial implications for the Corporation and its utilities.
The transition to cleaner energy will require the Corporation's utilities to effectively manage, among other things, evolving regulatory and
legislative requirements, new resiliency standards, the integration of new technologies and impacts on customer demand and rates. Failure to
appropriately respond to climate change and decarbonize may disrupt the ability of the utilities to provide safe and cost-effective service, which
could cause reputational harm and other impacts.
Fortis expects changes to government policy and regulation to continue in the coming years (see "Environmental Regulation" on page 25).
Further, the emergence of initiatives designed to reduce GHG emissions, increase renewable energy use, and control or limit the effects of climate
change has increased the incentive for the development of new technologies that produce renewable energy, enable more efficient storage of
energy and reduce energy consumption. As new technologies become widely available, infrastructure design risks and time delays may emerge.
Utility energy delivery systems will require technological changes and updates in order to effectively deliver increasing amounts of renewable
energy to customers (see "Technology Developments and AI" on page 25).
The availability of regulatory mechanisms or the ability of the Corporation's utilities to pass related costs on to customers remains uncertain.
Regulatory lag in relation to the adoption of climate change initiatives and/or the availability of regulatory recovery mechanisms in certain
jurisdictions could contribute to financial harm to Fortis and its utilities (see "Utility Regulation" on page 22).
Technological advancements will be required in order for the Corporation to achieve its net-zero target while preserving system reliability and
customer affordability. In addition to the development and implementation of relevant energy technologies, the Corporation's ability to achieve
its GHG targets depends upon many factors, including the impact of federal, provincial and state energy policies, significant load and customer
growth, the size of the Corporation's service territory, or the adoption of alternative energy products by the public, any of which could cause
actual results and the ability to achieve such targets to materially differ from expectations. The ultimate impact of achieving or failing to achieve
such targets could cause reputational damage which could result in a Material Adverse Effect.
Cybersecurity and Information and Operations Technology
As operators of critical energy infrastructure, the Corporation's utilities are at risk of cybercrime, including cyberattacks, data breaches, cyber
extortion, and similar compromises. As with other businesses, our information systems and the information systems of our third-party vendors are
targeted by malware, phishing efforts, and other cyberattacks. Certain of the information systems of the Corporation's utilities have been
subjected to direct and/or third-party cybersecurity breaches, including unauthorized access, none of which have been material. We expect to be
targeted by similar attacks in the future. The ability of the Corporation's utilities to operate effectively is dependent upon using and maintaining
complex information systems and infrastructure that: (i) support the operation of generation, transmission and distribution facilities, including
electric and gas facilities; (ii) provide customers with billing, consumption and load settlement information, where applicable; and (iii) support
financial and general operations.
Information and operations technology systems, including those of the Corporation's third-party service providers, may be vulnerable to
unauthorized access or disruption due to cyber and other attacks, including hacking, malware, acts of war or terrorism, and acts of vandalism,
among others. Further, geopolitical conflicts and the advancement of AI and generative AI may further increase the scale, sophistication or
frequency of cyberattacks from malicious actors, some of which actions may even be initiated by or connected with nation-state actors.
Any such event could result in the disruption of energy service and other business operations, including safety disruptions, disruption of internal
control processes, property damage, reputational damage, corruption or unavailability of critical data, loss of assets, and the theft, loss,
misappropriation and/or disclosure of sensitive, confidential and proprietary business information, intellectual property, or personal information of
customers and/or employees. The Corporation's exposure to these risks increases as the Corporation continues to partner with third-party
providers (see "Reliance on Supply Chain and Third Parties" on page 28).
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A material cybersecurity breach of the Corporation's information security systems or those of a third-party service provider, or any delay or failure
in assessing the materiality of such breach and related reporting/disclosure, could expose the Corporation to significant remediation costs and/or
adversely affect the operations and financial performance of the Corporation, its reputation and standing with customers, regulators and financial
markets, and expose it to claims for third-party damages or regulatory penalties. The resultant financial impacts may not be fully covered by
insurance policies or, in the case of utilities, through regulatory cost recovery, and could have a Material Adverse Effect.
Growth
Fortis has a history of both growth through acquisitions and organic growth from capital investment in existing service territories. The
Corporation's dividend growth guidance is significantly dependent upon achieving the Rate Base growth expected from the execution of the
five-year capital plan as described under "Capital Plan" on page 19. Projects, particularly Major Capital Projects, are subject to risks of delay and
cost overruns during construction caused by commodity price fluctuations, supply and labour costs, potential new or revised tariffs, supply chain
constraints, supplier non-performance, weather, geologic conditions or other factors beyond the Corporation's control. There is no assurance that
regulators will approve: (i) all of the planned projects or their amounts or timing; (ii) permits in a timely manner, or with reasonable terms and
conditions; or (iii) the recovery of cost overruns in customer rates, which may have a Material Adverse Effect.
Health and Safety
The operations of the Corporation's utilities inherently involve risk to the health and safety of both employees and the public. Personal injury or
loss of life could result from failure to implement or observe appropriate health and safety procedures and gives rise to operational, reputational
or financial impacts, any of which could have a Material Adverse Effect. In addition, failure to comply with health and safety regulations could
result in fines, penalties, reputational damage, litigation, increased capital and operating costs or adverse regulatory outcomes.
Political Environment
The political environment, at the local, national or global level, may impact energy laws, governmental energy policies or regulatory decisions. For
example, political pressure or intervention to address energy prices and customer affordability concerns may impact regulatory decisions, as well
as the period over which the Corporation’s utilities recover allowed costs.
The business is further exposed to risks associated with international relations and geopolitical events. Political, economic or social instability or
events, trade disputes, new or revised tariffs, changes in laws or the imposition of onerous regulations applicable to existing operations, currency
restrictions, and the impacts of changes in political leadership could lead to an increase in commodity prices, impact the availability and cost of
energy or generally affect global economic conditions, any of which could have a Material Adverse Effect (see "Environmental Regulation" below
and "General Economic Conditions" on page 27).
Technology Developments and AI
New technology developments in distributed generation, particularly solar, and energy efficiency products and services, as well as the
implementation of renewable energy and energy efficiency standards, will continue to impact retail sales. Heightened awareness of energy costs
and environmental concerns have increased demand for products that reduce energy consumption. The Corporation's utilities are also
promoting demand-side management programs. New technologies available to customers include energy derived from renewable sources,
customer-owned generation, energy-efficient appliances, battery storage and control systems. Advances in these or other technologies could
have a significant impact on retail sales with a potential Material Adverse Effect. Additionally, advances in AI or generative AI could cause
disruption to our business and, if we are unable to acquire, develop, implement or adopt new technology, we may suffer a competitive
disadvantage, which could also have an adverse effect on our results of operations, financial condition and/or liquidity.
Further, the implementation of new information technology systems and emerging technologies, such as cloud computing, AI and generative AI
into the business, including those impacting utility operations, customer billing systems and cybersecurity threat monitoring, carries risk that any
such technology or system will not operate as expected. Failure to maintain, upgrade, replace or properly implement such new technology or
systems could result in increased risk of a cybersecurity incident and have an adverse effect on operational efficiency, revenue or reputation (see
"Cybersecurity and Information and Operations Technology" on page 24).
Environmental Regulation
The Corporation's businesses are subject to environmental laws and regulations, including those which concern emissions into the air, discharges
into water or soil, use of water, hazardous waste disposal and containment, and the investigation and remediation of contamination, among
others.
The risk of contamination of air, soil and water associated with electricity operations primarily relates to: (i) the transportation, handling, storage
and combustion of fuel; (ii) the use of petroleum-based products, mainly transformer and lubricating oil; (iii) the management and disposal of coal
combustion residuals and other wastes; and (iv) accidents resulting in hazardous release at or from coal mines that supply generating facilities.
Contamination risks at gas operations primarily relate to leaks and other accidents involving gas systems. The key environmental risks for
hydroelectric generation operations include dam failures and the creation of artificial water flows that may disrupt natural habitats.
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FORTIS INC.
DECEMBER 31, 2024
Failure to comply with environmental laws and regulations, or to obtain or comply with any necessary environmental permits pursuant to such
laws and regulations, could result in injunctions, fines or other penalties. Further, liabilities relating to contamination investigation and
remediation, and related claims for personal injury or property damage, may arise at many locations, including formerly and currently owned/
operated properties and waste treatment or disposal sites, regardless of whether such contamination was caused by the business at the time it
owned the property, whether it resulted from non-compliance with applicable environmental laws and regulations, or whether it resulted from
any act or omission of the business. These liabilities could result in substantial monetary judgments for clean-up costs, damages, fines and/or
penalties. To the extent not fully covered by insurance or through regulatory mechanisms, these foregoing costs could have a Material Adverse
Effect.
Environmental laws and regulations continue to develop and may result in significant additional expense. In particular, the management of GHG
emissions and related decarbonization requirements is a concern due to new and emerging federal, state and provincial GHG laws, regulations
and guidelines. Regulation and the pace of regulatory change to address reliability, resiliency, resource planning and safety is expected to
increase. Future legislation could impact generation assets, operations, energy supply, operational costs, reporting obligations and other material
aspects of the Corporation's business. Increased compliance costs or additional operating restrictions from revised or additional regulation could
have a Material Adverse Effect (see "Climate Change" at page 23).
Natural Gas Competitiveness
Approximately 18% of the Corporation's revenue is derived from the delivery of natural gas. In British Columbia, which accounts for 79% of the
Corporation's natural gas revenue, natural gas primarily competes with electricity for space and hot water heating load. Upfront capital costs for
gas service continue to present competitive challenges for natural gas compared to electricity service. If gas becomes less competitive due to
price or other factors, such as government policy or public perception of natural gas or its carbon intensity relative to other energy sources, the
ability to add new customers could be impaired. Existing customers could also reduce their consumption or switch to electricity, placing further
pressure on rates and, in the extreme, could ultimately lead to an inability to recover the utility's cost of service through customer rates.
Government policy could further impact the competitiveness of natural gas in British Columbia. As governments develop policies to address
climate change, any resultant changes to energy policy may impact the competitiveness of natural gas relative to other energy sources.
Additionally, there are other competitive challenges that are impacting the penetration of natural gas into new housing stock such as the carbon
intensity of the energy source and the type of housing stock being built. As part of their own climate change policy plans, local governments may
use various tools at their disposal such as franchise agreements, permits, building codes and zoning bylaws to impose limitations on energy
sources permitted in new and existing developments. Municipalities can also provide incentives, such as higher density allowance, to builders to
adopt carbon free energy options for their developments. These actions and policies may hinder the Corporation's ability to attract new natural
gas customers or retain existing customers.
A decrease in the competitiveness of natural gas due to pricing, government policy or other factors could have a Material Adverse Effect.
Weather Variability and Seasonality
Electricity consumption varies significantly in response to seasonal weather changes which have been and will continue to be impacted by
climate change (see "Climate Change" on page 23). Cool summers may reduce the use of air conditioning and other cooling equipment, while
warmer and less severe winters may reduce heating load. Alternatively, severe weather could unexpectedly increase heating and cooling loads,
negatively impacting system reliability. Hydroelectric generation is sensitive to rainfall levels and unexpected variations in seasonal rainfall levels
can negatively impact operations.
Weather and seasonality have a significant impact on gas distribution volumes as a major portion of natural gas is used for space heating by
residential customers. The earnings of the Corporation's gas utilities are typically highest in the first and fourth quarters. Regulatory deferral and
revenue decoupling mechanisms are in place at certain of the Corporation's utilities to minimize the volatility in earnings that would otherwise be
caused by variations in weather conditions. The absence or the discontinuance of key regulatory mechanisms could result in significant and
prolonged weather variations from seasonal norms having a Material Adverse Effect.
Required Approvals
The acquisition, ownership and operation of electric and gas businesses require numerous licences, permits, agreements, orders, certificates,
consultations, and other approvals from various levels of government, regulators, government agencies and/or other third parties. There is no
assurance that: (i) such approvals will be obtained, continuously maintained or renewed without delay; and (ii) the terms and conditions thereof
will be fully complied with at all times and will not change in a material adverse manner. Significant failures in these regards could prevent the
operation of the businesses and have a Material Adverse Effect.
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Reliability Standards
The Energy Policy Act of 2005 provides for a regulatory framework which requires owners, operators and users of the bulk electric system in the
U.S. to meet mandatory reliability standards developed by the North American Electric Reliability Corporation and its regional entities, which are
approved and enforced by FERC. Many of these, or similar, standards have been adopted in certain Canadian provinces including British Columbia
and Alberta. The failure to develop, implement and maintain appropriate operating practices/systems and capital plans to address reliability
obligations could lead to compliance violations and a Material Adverse Effect, including as a result of the exclusion of related costs from customer
rates and other potentially significant penalties.
Indigenous Peoples' Land Claims
In British Columbia, the Corporation's utilities provide service to customers on Indigenous Peoples' lands and maintain facilities on lands that are
subject to Indigenous Peoples' land claims. Various treaty negotiation processes involving Indigenous Peoples and the Governments of British
Columbia and Canada are underway, but the basis for potential settlements is unclear and not all Indigenous Peoples are participating in such
processes. To date, the policy of the Government of British Columbia has been to structure settlements without prejudicing existing third-party
rights; however, there is no assurance that the settlement processes will not have a Material Adverse Effect.
FortisAlberta has distribution assets on Indigenous Peoples' lands in Alberta with access permits held by a third party. Some of these permits
require approvals from First Nations and Crown-Indigenous Relations and Northern Affairs Canada. FortisAlberta may be unable to obtain such
approvals or negotiate land-use agreements with reasonable terms. Significant failures in these regards could have a Material Adverse Effect.
Certain jointly owned facilities and portions of TEP's transmission lines are located on tribal lands pursuant to leases, land easements and other
rights-of-way that are effective for specified time periods. The inability to receive future approvals for continued access to the facilities and land
could have a Material Adverse Effect.
Joint-Ownership Interests and Third-Party Operators
Certain generating facilities from which TEP receives power are jointly owned with, or are operated by, third parties. TEP may not have sole
discretion or any ability to affect the management or operations of such facilities, including how to best address changing economic conditions
or environmental requirements. A divergence in the interests of TEP and those of the joint owners or operators could have a Material Adverse
Effect.
General Economic Conditions
Fluctuations in general economic conditions, inflation, energy prices, employment levels, personal disposable incomes, housing starts, industrial
activity and other factors, including potential new or revised tariffs, may lower energy demand and sales and reduce capital spending, particularly
to the extent that related customer and Rate Base growth are impacted. A severe and prolonged economic downturn could also impair
customers' ability to pay their bills in a timely manner. Each of these factors could lead to the impairment of goodwill or other long-term assets,
and could have a Material Adverse Effect. Further, the impact of macroeconomic factors, including, but not limited to, international relations and
geopolitical events, could cause weaker economic conditions or increase the volatility of the equity capital markets, which could impact the
business and financial condition of the Corporation or adversely impact the Corporation's share price.
Commodity Price Volatility
Purchased power and gas, and generation fuel costs are subject to commodity price volatility, which is managed through regulator-approved:
(i) mechanisms that permit the flow through in customer rates of commodity price changes and/or that provide for rate-stabilization and other
deferral accounts; and (ii) price-risk management strategies such as the use of derivative contracts that effectively fix costs (see "Financial
Instruments - Derivatives" on page 33).
There is no assurance that current regulator-approved mechanisms or strategies will continue to exist in the future. Additionally, despite these
mechanisms and strategies, severe and prolonged commodity price increases could result in rates that customers are unable to pay and/or could
affect consumption and sales growth, which could have a Material Adverse Effect.
Purchased Power Supply
A significant portion of electricity and gas sold by the Corporation's utilities is purchased through the wholesale energy markets or pursuant to
contracts with energy suppliers and is not being produced by the Corporation's utilities. A disruption in the wholesale energy markets, or a failure
on the part of energy or fuel suppliers or operators of energy delivery systems that connect to the Corporation's utilities, could result in a loss and/
or increase in the cost of purchased power and gas, which could have a Material Adverse Effect. The cost and availability of purchased power and
gas may be adversely impacted by factors discussed under "Climate Change" on page 23, "Environmental Regulation" on page 25 and
"Commodity Price Volatility" above.
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Counterparty Credit Risk
ITC has a concentration of credit risk as approximately 70% of its revenue is derived from three customers. These customers have investment-
grade credit ratings and credit risk is further managed by MISO by requiring a letter of credit or cash deposit equal to the credit exposure, which is
determined by a credit-scoring model and other factors.
FortisAlberta has a concentration of credit risk as its distribution service billings are to a relatively small group of retailers. Credit risk is managed by
obtaining from the retailers either a cash deposit, letter of credit, an investment-grade credit rating, or a financial guarantee from an entity with an
investment-grade credit rating.
Central Hudson has seen an increase in accounts receivable since the suspension of collection efforts initially required in response to the
COVID-19 pandemic. Central Hudson continues to contact customers regarding past-due balances and collection efforts continue to expand.
Under its regulatory framework, Central Hudson can defer uncollectible write-offs above the amounts collected in customer rates for future
recovery.
UNS Energy, Central Hudson, FortisBC Energy, and Fortis may be exposed to credit risk from non-performance by counterparties to derivative
contracts. Credit risk is managed by net settling payments, when possible, and dealing only with counterparties that have investment-grade
credit ratings. At UNS Energy, Central Hudson and FortisBC Energy, certain contractual arrangements require counterparties to post collateral.
There is no assurance that credit risk management strategies will continue to be effective. Significant counterparty defaults could have a Material
Adverse Effect.
Reliance on Supply Chain and Third Parties
Domestic and global supply chain disruptions, as a result of either physical or cyberattacks or geopolitical issues, may delay the delivery or result
in shortages of certain materials, equipment and other resources that are critical to the operation of the Corporation's utilities, or impact the
services and performance of the operation of the Corporation's utilities. Failure to eliminate or manage constraints in, or performance of, the
supply chain may impact the availability of items or service that are necessary to support operations as well as materials that are required for
continued infrastructure growth and could have a Material Adverse Effect. Further, cybersecurity incidents in the Corporation's supply chain or
cyberattacks originating from the Corporation's supply chain may further result in disruption of energy service and other business operations
which could have a Material Adverse Effect.
Interest Rates
Generally, the market price of the Corporation's common shares is inversely correlated to interest rate changes. Additionally, allowed ROEs are
exposed to changes in long-term interest rates, such that a decreasing interest rate environment can result in lower allowed ROEs over time.
While a rising interest rate environment could result in higher allowed ROEs, such ROE changes tend to lag as a result of regulatory timelines.
Borrowings under variable-rate credit facilities and long-term debt, as well as new debt issuances, are also exposed to interest rate changes.
Although interest costs at the regulated utilities are generally recovered through customer rates, the discontinuance of regulatory mechanisms
that permit the flow-through of actual interest costs, the impact of regulatory lag at UNS Energy, and higher finance costs on holding company
debt could have a Material Adverse Effect.
Foreign Exchange Exposure
As at December 31, 2024, 69% of the Corporation's assets were located outside Canada and 62% of 2024 revenue was derived from foreign
operations. The reporting currency of ITC, UNS Energy, Central Hudson, Caribbean Utilities, FortisTCI, Fortis Belize and Belize Electricity is, or is
pegged to, the U.S. dollar. The earnings and cash flow from, and net investments in, these entities are exposed to fluctuations in the U.S. dollar-to-
Canadian dollar exchange rate. The Corporation’s $26.0 billion five-year capital plan for 2025 through 2029 also includes exposure to foreign
exchange.
Fortis has reduced its U.S. dollar currency exposure through hedging. The Corporation has issued and designated U.S. dollar-denominated long-
term debt as an effective hedge of foreign net investments. Fortis has also entered into foreign exchange contracts and cross-currency swaps to
manage a portion of its exposure to foreign currency risk.
Given only partial hedging, earnings and cash flow continue to be impacted by exchange rate fluctuations. In addition, there is no assurance that
existing hedging strategies will continue to be effective, and therefore a significant, prolonged decrease in the U.S dollar-to-Canadian dollar
exchange rate could have a Material Adverse Effect.
Access to Capital
The Corporation and certain of its subsidiaries have incurred material amounts of indebtedness. Ongoing access to cost-effective capital is
required to fund, among other things, capital expenditures and the repayment of maturing debt.
Operating Cash Flow may not be sufficient to fund the repayment of all outstanding liabilities when due or fund anticipated capital expenditures.
Management Discussion and Analysis
28
FORTIS INC.
DECEMBER 31, 2024
The ability to meet long-term debt repayments is dependent upon obtaining sufficient and cost-effective financing to replace maturing
indebtedness. The ability to arrange financing is subject to numerous factors, including the results of operations and financial condition of Fortis
and its subsidiaries, the regulatory environments including decisions regarding capital structure and allowed ROEs, capital market conditions,
general economic conditions, credit ratings, and the environmental, social and governance profile of Fortis and its subsidiaries. Changes in credit
ratings could affect credit risk spreads on new long-term debt and credit facilities, as well as their availability.
Fortis is a holding company and, as such, has no revenue-generating operations of its own. The Corporation’s subsidiaries are separate legal
entities and have no independent obligation to pay dividends to Fortis. Prior to paying dividends to the Corporation, the subsidiaries have
financial obligations that must be satisfied, including, among others, their operating expenses and obligations to creditors. Furthermore, the
Corporation’s utilities are required by regulation to maintain a minimum equity-to-total capital ratio that may restrict their ability to pay dividends
to the Corporation or may require the Corporation to contribute capital to such subsidiaries. The future enactment of laws or regulations may
prohibit or further restrict the ability of the Corporation's subsidiaries to pay dividends or to repay intercorporate indebtedness. In addition, in the
event of a subsidiary’s liquidation or reorganization, the Corporation’s right to participate in a distribution of assets is subject to the prior claims of
the subsidiary’s creditors. As a result, the Corporation’s ability to generate cash flow to service its debt obligations and pay dividends is reliant on
the ability of its subsidiaries to generate sustained earnings and cash flows and to pay dividends and repay loans.
There is no assurance that sufficient capital will continue to be available on acceptable terms. For further information see "Liquidity and Capital
Resources" on page 14.
Taxation
Earnings at Fortis and its subsidiaries could be impacted by changes in income tax rates and other tax legislation in Canada, the U.S. and other
international jurisdictions. The nature, timing or impact of changes in tax laws cannot be predicted and could have a Material Adverse Effect.
Although income taxes at the regulated utilities are generally recovered in customer rates, tax-related regulatory lag can result in recovery delays
or non-recovery for certain periods. At the non-regulated level, changes in income tax rates and other tax legislation could materially affect the
after-tax cost of existing and future debt which is not recoverable in customer rates.
Insurance
Insurance is maintained with reputable industry insurers for property damage, potential liabilities and business interruption for coverage
considered appropriate and in accordance with industry practice.
A significant portion of transmission and distribution assets is uninsured, as is customary in North America, as the cost to insure such assets is
prohibitive. Insurance is subject to coverage limits and deductibles, as well as time-sensitive claims discovery and reporting provisions. There is no
assurance that: (i) the amounts and types of losses from actual damage, liabilities or business interruption will be fully covered by insurance;
(ii) regulatory relief would be obtained for coverage shortfalls; (iii) adequate insurance at reasonable rates will continue to be available; or
(iv) insurers will fulfill their obligations. Significant actual shortfalls in insurance coverage or claims payment could have a Material Adverse Effect.
The availability and cost of certain types of insurance may be adversely impacted by the risks described under "Climate Change" on page 23.
Pandemics and Public Health Crises
The Corporation could be negatively impacted by widespread outbreaks of communicable diseases or other public health crises that cause
economic and/or other disruptions. Outbreaks of communicable diseases, as well as efforts to reduce the health impacts and control disease
spread, can lead to restrictions on business operations, including business closures and the potential impacts of reduced labour availability and
productivity, supply chain disruptions, project construction delays, disruptions to capital markets, governmental and regulatory action, and a
prolonged reduction in economic activity. An extended economic slowdown could reduce energy sales and adversely impact the ability of
customers, contractors and suppliers to fulfill their obligations and could disrupt operations and capital expenditure programs or cause
impairment of goodwill (see "General Economic Conditions" on page 27).
The Corporation's utilities provide essential services and must be operational and maintained throughout any pandemic or other public health
crisis, though such events can challenge operations and increase operating costs. The duration and severity of a pandemic or other public health
crisis could have a Material Adverse Effect.
Talent Management
The delivery of safe, reliable and cost-effective service depends on the attraction, development and retention of a skilled workforce as well as
filling strategic positions. Like its peers, Fortis faces demographic challenges and competitive markets relating to trades, technical and professional
staff, particularly considering its significant capital plan. ITC relies heavily on agreements with third parties to provide services for the construction,
maintenance and operation of certain aspects of its business. Significant failures in attracting or retaining a skilled workforce or filling strategic
positions within the Corporation or its utilities could have a Material Adverse Effect.
Management Discussion and Analysis
29
FORTIS INC.
DECEMBER 31, 2024
Labour Relations
Most of the Corporation's utilities employ members of labour unions or associations under collective bargaining agreements. Fortis considers its
labour relationships to be satisfactory, but there is no assurance that this will continue or that existing collective bargaining agreements will be
renewed on reasonable terms without work disruption or other job action. Significant failures in these regards could cause service interruptions
and/or labour cost increases for which regulators may not allow full recovery in customer rates, and could have a Material Adverse Effect.
Post-Retirement Obligations
Fortis and most of its subsidiaries maintain a combination of DBP and/or OPEB plans for certain employees and retirees. The most significant cost
drivers for these plans are investment performance and interest rates, which are affected by global financial markets. Regulatory deferral
mechanisms are in place at many of the Corporation’s utilities that permit the flow through in customer rates of certain impacts associated with
market fluctuations. Severe and prolonged market disruptions, significant declines in the market values of investments held to meet plan
obligations, discount rate changes, participant demographics, changes in laws and regulations, as well as changes in existing regulatory
treatment of post-retirement benefit costs, may increase plan expenses or require additional plan funding and could have a Material Adverse
Effect.
Reputation, Relationships and Stakeholder Activism
There can be no assurance that internal processes, controls or audits, including those related to the preparation and presentation of financial
statements, will ensure compliance with the Corporation's internal policies, including its Code of Conduct, or anti-bribery and anti-corruption
laws. Employees, affiliates, independent contractors or agents may violate such policies and laws, which may potentially lead to reputational
damage, in addition to potential fines, penalties or litigation, any of which could have a Material Adverse Effect.
The Corporation's operations and growth prospects require strong relationships with key stakeholders, including regulators, governments and
agencies, Indigenous communities, landowners, and environmental organizations. Inadequately managing expectations and issues important to
stakeholders, including those arising during construction of Major Capital Projects, could affect the Corporation's reputation as well as have a
significant impact on its operations and infrastructure development. See "Required Approvals" and "Indigenous Peoples' Land Claims" on page 27.
External stakeholders have been challenging companies regarding climate change, sustainability, diversity, returns (including ROEs and ROAs),
executive compensation, and other matters. Public opposition to larger infrastructure projects is becoming increasingly common, which can
challenge capital plans and resultant organic growth. While the Corporation actively monitors such activism and is committed to developing
stronger relationships with its external stakeholders, failure to effectively manage or respond to stakeholder activism could have a Material
Adverse Effect.
Legal, Administrative and Other Proceedings
Legal, administrative and other proceedings arise in the ordinary course of business and may include environmental claims, employment-related
claims, securities-based litigation, contractual disputes, personal injury or property damage claims, actions by regulatory or tax authorities, and
other matters. Unfavourable outcomes such as judgments or settlements for monetary or other damages, injunctions, denial or revocation of
permits, reputational harm, and other results could have a Material Adverse Effect.
ACCOUNTING MATTERS
New Accounting Policies
Segment Reporting: The Corporation adopted ASU No. 2023-07, Improvements to Reportable Segment Disclosures, for the year ended
December 31, 2024 and will adopt it for interim periods beginning in 2025. This update requires disclosure of incremental segment information,
including significant segment expenses and other items that are included in segment profit or loss. This adoption of this standard did not
materially impact Fortis' disclosures.
Future Accounting Pronouncements
Income Taxes: ASU No. 2023-09, Improvements to Income Tax Disclosures, is effective for Fortis on January 1, 2025 on a prospective basis, with
retrospective application and early adoption permitted. The ASU requires additional disclosure of income tax information by jurisdiction to reflect
an entity's exposure to potential changes in tax legislation, and associated risks and opportunities. Fortis does not expect the ASU to materially
impact its disclosures.
Expense Disaggregation: ASU No. 2024-03, Disaggregation of Income Statement Expenses, is effective for Fortis on January 1, 2027 for annual
periods and on January 1, 2028 for interim periods, on a prospective basis, with retrospective application and early adoption permitted. The ASU
requires detailed disclosure of certain expense categories included on the consolidated statements of earnings, including energy supply costs,
operating expenses, and depreciation and amortization expense. Fortis is assessing the impact on its disclosures.
Management Discussion and Analysis
30
FORTIS INC.
DECEMBER 31, 2024
Critical Accounting Estimates
General
The preparation of the 2024 Annual Financial Statements required management to make estimates and judgments that affect the reported
amounts of, and disclosures related to, assets, liabilities, revenues, expenses, gains, losses and contingencies. Management evaluates these
estimates on an ongoing basis based upon historical experience, current conditions, and assumptions believed to be reasonable at the time they
are made, with any adjustments recognized in the period they become known. Actual results may differ significantly from these estimates.
Regulatory Assets and Liabilities
As at December 31, 2024, Fortis recognized regulatory assets of $4.6 billion (2023 - $4.4 billion) and regulatory liabilities of $4.3 billion (2023 -
$4.0 billion).
Regulatory assets represent future revenues and/or receivables associated with certain costs incurred that will be, or are expected to be,
recovered from customers in future periods through the rate-setting process. Regulatory liabilities represent: (i) future reductions or limitations of
increases in revenue associated with amounts that will be, or are expected to be, refunded to customers through the rate-setting process; or
(ii) obligations to provide future service that customers have paid for in advance.
The recognition of regulatory assets and liabilities and the period(s) of settlement are often estimates based on past, existing or expected
regulatory orders in relation to the nature of the underlying amounts, and are subject to regulatory approval. There is no assurance that actual
settlement amounts and the related settlement periods will not be materially different from those estimated. Differences arising from the
regulator's orders would be recognized in accordance with those orders, whereby any amounts disallowed would be immediately recognized in
earnings with the remainder recognized in earnings in accordance with their inclusion in customer rates.
Employee Future Benefits
Key Estimates and Assumptions
DBP Plans
OPEB Plans
Years ended December 31
($ millions, except as indicated)
2024
2023
2024
2023
Funded status: (1)
Benefit obligation (2)
(3,440)
(3,347)
(603)
(596)
Plan assets
3,613
3,313
506
430
173
(34)
(97)
(166)
Net benefit cost (2)
11
21
12
15
Key assumptions: (weighted average %)
Discount rate as at December 31 (3)
5.25
4.84
5.43
4.94
Expected long-term rate of return on plan assets (4)
6.51
6.58
6.05
5.92
Rate of compensation increase
3.52
3.37
—
—
Health care cost trend increase rate (5)
—
—
4.53
4.52
(1) Periodic actuarial valuations determine funding contributions for the DBP plans and U.S. OPEB plans, while Canadian OPEB plans are unfunded
(2) Actuarially determined using the projected benefits method prorated on service and management's best estimate of expected plan investment performance, salary
escalation, average remaining service life of employees, mortality rates and, for OPEB plans, expected health care costs
(3) Reflects market interest rates on high-quality bonds with cash flows that match the timing and amount of expected pension payments. The discount rate used during the
year for DBP plans is 4.84% (2023 - 5.36%) and 4.96% (2023 - 5.39%) for OPEB plans
(4) Developed using best estimates of expected returns, volatilities and correlations for each class of asset. Estimates are based on historical performance, future expectations
and periodic portfolio rebalancing among the diversified asset classes
(5) Actuarially determined, the projected 2025 rate is 6.51% and is assumed to decrease over the next 10 years to the ultimate rate of 4.53% in 2034 and thereafter
Sensitivity Analysis
Rate of Return
Discount Rate
Health Care Costs
Trend Rate
Year ended December 31, 2024
1% change
1% change
1% change
($ millions)
Increase
Decrease
Increase
Decrease
Increase
Decrease
DBP plans:
Net benefit cost
(33)
29
(24)
41
n/a
n/a
Projected benefit obligation
(2)
(66)
(378)
453
n/a
n/a
OPEB plans:
Net benefit cost
(4)
4
(9)
11
14
(11)
Accumulated benefit obligation
—
—
(68)
84
62
(52)
Management Discussion and Analysis
31
FORTIS INC.
DECEMBER 31, 2024
At the regulated utilities, changes in net benefit cost are generally expected to be reflected in customer rates, subject to regulatory lag and
forecast risk at certain utilities.
ITC, Central Hudson, FortisBC Energy, FortisBC Electric and Newfoundland Power have regulator-approved mechanisms to defer variations
between actual net pension cost and that forecast and reflected in customer rates. There is no assurance that these deferral mechanisms will
continue in the future.
Depreciation and Amortization
As at December 31, 2024, Fortis recognized property, plant and equipment and intangible assets of $51.1 billion (2023 - $44.9 billion) representing
70% of total assets (2023 - 68%). Depreciation and amortization of these assets totalled $1.8 billion for 2024 (2023 - $1.7 billion).
Depreciation and amortization reflect the estimated useful lives of the underlying assets, which considers historical experience, manufacturers'
ratings and specifications, the past and expected future pattern and nature of usage, and other factors.
At the regulated utilities, depreciation rates require regulatory approval and include a provision for estimated future removal costs, not identified
as a legal obligation. Estimates primarily reflect historical experience and expected cost trends. The provision is recognized as a long-term
regulatory liability against which actual removal costs are netted when incurred. As at December 31, 2024, this regulatory liability was $1.7 billion
(2023 - $1.5 billion).
Depreciation rates at the regulated utilities are typically determined through periodic depreciation studies performed by external experts. Where
actual experience differs from previous estimates, resultant differences are generally reflected in future depreciation rates and thereby recovered
or refunded through customer rates in the manner prescribed by the regulator.
Goodwill Impairment
As at December 31, 2024, Fortis recognized goodwill of $13.1 billion (2023 - $12.2 billion), representing 18% of total assets (2023 - 18%). The
increase in goodwill was due to a higher U.S. dollar-to-Canadian dollar exchange rate at December 31, 2024 in comparison to December 31, 2023,
and the associated impact on the translation of U.S. dollar-denominated goodwill.
Goodwill at each of the Corporation's reporting units is tested for impairment annually and whenever an event or change in circumstances
indicates that fair value may be below carrying value. If so determined, goodwill is written down to estimated fair value and an impairment loss is
recognized.
The Corporation performs a qualitative assessment on each reporting unit and if it is determined that it is not likely that fair value is less than
carrying value, then a quantitative estimate of fair value is not required. When a quantitative assessment is performed, the primary method for
estimating fair value of the reporting units is the income approach, whereby net cash flow projections are discounted. Underlying estimates and
assumptions, with varying degrees of uncertainty, include the amount and timing of expected future cash flows, growth rates, and discount rates.
A secondary valuation, the market approach along with a reconciliation of the total estimated fair value of all the reporting units to the
Corporation's market capitalization, is also performed and evaluated.
The recognition of impairment losses could have a Material Adverse Effect. Such losses are not recoverable in regulated utility rates. To the extent
impairment losses signal lower expected future cash flows to support interest payments on unregulated holding company debt and dividends on
common shares, they could adversely affect the future cost of such capital, expressed as higher interest rates on such debt, which is not
recoverable in regulated utility rates, and lower common share market prices.
Income Tax
As at December 31, 2024, deferred income tax liabilities, income tax receivable, deferred income taxes included in regulatory assets, income tax
payable, and deferred income taxes included in regulatory liabilities totalled $5.0 billion, $nil, $2.2 billion, $33 million and $1.3 billion, respectively
(2023 - $4.4 billion, $78 million, $2.1 billion, $nil, and $1.3 billion, respectively). Income tax expense was $346 million in 2024 (2023 - $360 million).
Current income taxes reflect the estimated taxes payable/receivable in the current year based on enacted tax rates and laws, and the estimated
proportion of taxable earnings/loss attributable to various jurisdictions.
Deferred income tax assets and liabilities reflect temporary differences between the tax and accounting basis of assets and liabilities. A deferred
income tax asset or liability is determined for each temporary difference based on enacted income tax rates and laws in effect when the
temporary differences are expected to be recovered or settled. A valuation allowance is recognized in earnings to the extent that future tax
recovery is not assessed as "more likely than not".
Management Discussion and Analysis
32
FORTIS INC.
DECEMBER 31, 2024
At the regulated utilities, differences between the income tax expense or recovery recognized under U.S. GAAP and reflected in customer rates,
which is expected to be recovered from, or refunded to, customers in future rates, are recognized as regulatory assets or liabilities. These are
subsequently amortized to earnings in accordance with their inclusion in customer rates pursuant to the regulator's orders. Otherwise, changes in
expectations and resultant estimates arising from changes in tax rates, tax laws, jurisdictional earnings allocations and other factors are recognized
in earnings upon occurrence.
The Corporation and certain of its subsidiaries are subject to taxation in Canada, the United States and other foreign jurisdictions. The material
jurisdictions in which the Corporation is subject to potential income tax compliance examinations include the United States (Federal, Arizona,
Kansas, Iowa, Michigan, Minnesota and New York) and Canada (Federal, British Columbia and Alberta). The Corporation's 2020 to 2024 taxation
years are still open for audit in Canadian jurisdictions, and its 2020 to 2024 taxation years are still open for audit in U.S. jurisdictions. The impact of
such income tax compliance examinations could be material to the Corporation (see "Business Risks - Taxation" on page 29).
In June 2024, the Government of Canada enacted legislation with respect to interest deductibility limitations and global minimum tax, both of
which were applicable to Fortis as of January 1, 2024. There was no material impact to Fortis in 2024 and the Corporation does not expect a
material impact on its financial results, Operating Cash Flow or credit metrics over the five-year planning period.
Derivatives
The fair values of derivatives are based on estimates that cannot be determined with precision as they involve uncertainties and matters of
judgment and, therefore, may not be relevant in predicting future earnings or cash flows.
Contingencies
The Corporation and its subsidiaries are subject to various legal proceedings and claims arising in the ordinary course of business, including those
generally described under "Business Risks - Legal, Administrative and Other Proceedings" on page 30, for which no amounts have been accrued
because the outcomes currently cannot be reasonably determined. Further information is provided in Note 27 in the 2024 Annual Financial
Statements.
FINANCIAL INSTRUMENTS
Long-Term Debt and Other
As at December 31, 2024, the carrying value of long-term debt, including the current portion, was $33.4 billion (2023 - $29.7 billion) compared to
an estimated fair value of $31.3 billion (2023 - $27.9 billion).
The consolidated carrying value of the remaining financial instruments, other than derivatives, approximates fair value, reflecting their short-term
maturity, normal trade credit terms and/or nature.
Derivatives
The Corporation generally limits the use of derivatives to those that qualify as accounting, economic or cash flow hedges, or those that are
approved for regulatory recovery. Derivatives are recorded at fair value, with certain exceptions, including those derivatives that qualify for the
normal purchase and normal sale exception.
Energy contracts subject to regulatory deferral
UNS Energy holds electricity power purchase contracts, customer supply contracts and gas swap contracts to reduce its exposure to energy price
risk. Fair values are measured primarily under the market approach using independent third-party information, where possible. When published
prices are not available, adjustments are applied based on historical price curve relationships, transmission costs and line losses.
Central Hudson holds swap contracts for electricity and natural gas to minimize price volatility by fixing the effective purchase price. Fair values
are measured using forward pricing provided by independent third-party information.
FortisBC Energy holds gas supply contracts to fix the effective purchase price of natural gas. Fair values reflect the present value of future cash
flows based on published market prices and forward natural gas curves.
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, 2024, unrealized losses of $175 million
(2023 - $197 million) were recognized as regulatory assets and unrealized gains of $41 million (2023 - $37 million) were recognized as regulatory
liabilities.
Management Discussion and Analysis
33
FORTIS INC.
DECEMBER 31, 2024
Energy contracts not subject to regulatory deferral
UNS Energy holds wholesale trading contracts to fix power prices and realize potential margin, of which 10% of any realized gains is shared with
customers through rate stabilization accounts. Fair values are measured using a market approach incorporating, where possible, independent
third-party information.
Aitken Creek, which was sold on November 1, 2023, held gas swap contracts to manage exposure to changes in natural gas prices, capture
natural gas price spreads, and manage the financial risk posed by physical transactions. Fair values were measured using forward pricing from
published market sources.
Gains or losses associated with changes in the fair value of these energy contracts are recognized in revenue. In 2024, gains of $48 million (2023 -
losses of $28 million) were recognized in revenue.
Total return swaps
The Corporation holds total return swaps to manage the cash flow risk associated with forecast future cash and/or share settlements of certain
stock-based compensation obligations. The swaps have a combined notional amount of $134 million and terms up to three years expiring at
varying dates through January 2027. Fair value is measured using an income valuation approach based on forward pricing curves. Unrealized
gains and losses associated with changes in fair value are recognized in other income, net. In 2024, unrealized gains of $12 million (2023 - $nil)
were recognized in other income, net.
Foreign exchange contracts
The Corporation holds U.S. dollar-denominated foreign exchange contracts to help mitigate exposure to foreign exchange rate volatility. The
contracts expire at varying dates through September 2026 and have a combined notional amount of $608 million. Fair value was measured using
independent third-party information. Unrealized gains and losses associated with changes in fair value are recognized in other income, net. In
2024, unrealized losses of $17 million (2023 - unrealized gains of $10 million) were recognized in other income, net.
Interest rate contracts
During 2024, ITC entered into and settled interest rate locks with a combined notional value of US$300 million. These contracts were used to
manage interest rate risk associated with the issuance of US$400 million unsecured senior notes in May 2024. Realized losses of US$3 million were
recognized in other comprehensive income, which will be reclassified to earnings as a component of interest expense over five years.
ITC also entered into five-year interest rate swap contracts in 2024 with a combined notional value of US$135 million. The swaps will be used to
manage interest rate risk associated with forecasted debt issuances. Fair value was measured using a discounted cash flow method based on SOFR.
Unrealized gains and losses associated with the changes in fair value are recognized in other comprehensive income, and will be reclassified to
earnings as a component of interest expense over the life of the debt. Unrealized gains of US$4 million were recorded in 2024.
In 2025, ITC entered into five-year interest rate swap contracts with a notional value of US$95 million to manage interest rate risk associated with
forecasted debt issuances, increasing the total notional amount of interest rate swaps outstanding to US$230 million.
During 2024, the Corporation entered into and settled interest rate locks with a combined notional value of $250 million. These contract were
used to manage interest rate risk associated with the issuance of $500 million unsecured senior notes in September 2024. Realized losses of
$2 million were recognized in other comprehensive income, which will be reclassified to earnings as a component of interest expense over
seven years.
Cross-Currency interest rate swaps
The Corporation holds cross-currency interest rate swaps, maturing in 2029, to effectively convert its $500 million, 4.43% unsecured senior notes
to US$391 million, 4.34% debt. The Corporation has designated this notional U.S. debt as an effective hedge of its foreign net investments and
unrealized gains and losses associated with exchange rate fluctuations on the notional U.S. debt are recognized in other comprehensive income,
consistent with the translation adjustment related to the foreign net investments. Other changes in the fair value of the swaps are also recognized
in other comprehensive income but are excluded from the assessment of hedge effectiveness. Fair value is measured using a discounted cash
flow method based on SOFR. In 2024, unrealized losses of $29 million (2023 - unrealized gains of $15 million) were recorded in other
comprehensive income.
Management Discussion and Analysis
34
FORTIS INC.
DECEMBER 31, 2024
Derivative Fair Values
The following table presents derivative assets and liabilities that are accounted for at fair value on a recurring basis.
($ millions)
Level 1 (1)
Level 2 (1)
Level 3 (1)
Total
As at December 31, 2024
Assets (2)
Energy contracts subject to regulatory deferral
—
63
—
63
Energy contracts not subject to regulatory deferral
—
7
—
7
Total return swaps and interest rate contracts
—
16
—
16
Other investments
150
—
—
150
150
86
—
236
Liabilities (3)
Energy contracts subject to regulatory deferral
—
(197)
—
(197)
Energy contracts not subject to regulatory deferral
—
(2)
—
(2)
Foreign exchange contracts and cross-currency interest rate swaps
—
(45)
—
(45)
—
(244)
—
(244)
As at December 31, 2023
Assets (2)
Energy contracts subject to regulatory deferral
—
49
—
49
Energy contracts not subject to regulatory deferral
—
6
—
6
Foreign exchange contracts
—
5
—
5
Other investments
145
—
—
145
145
60
—
205
Liabilities (3)
Energy contracts subject to regulatory deferral
—
(209)
—
(209)
Energy contracts not subject to regulatory deferral
—
(3)
—
(3)
Total return and cross-currency interest rate swaps
—
(6)
—
(6)
—
(218)
—
(218)
(1) Under the hierarchy, fair value is determined using: (i) Level 1 - unadjusted quoted prices in active markets; (ii) Level 2 - other pricing inputs directly or indirectly observable
in the marketplace; and (iii) Level 3 - unobservable inputs, used when observable inputs are not available. Classifications reflect the lowest level of input that is significant to
the fair value measurement.
(2) Included in cash and cash equivalents, accounts receivable and other current assets, or other assets
(3) Included in accounts payable and other current liabilities or other liabilities
Derivative Volumes
As at December 31
2024
2023
Energy contracts subject to regulatory deferral (1)
Electricity swap contracts (GWh)
774
628
Electricity power purchase contracts (GWh)
430
588
Gas swap contracts (PJ)
236
228
Gas supply contracts (PJ)
105
134
Energy contracts not subject to regulatory deferral (1)
Wholesale trading contracts (GWh)
1,499
1,310
Gas swap contracts (PJ)
3
3
(1) Energy contracts settle on various dates through 2029
Management Discussion and Analysis
35
FORTIS INC.
DECEMBER 31, 2024
SELECTED ANNUAL FINANCIAL INFORMATION
Years ended December 31
($ millions, except as indicated)
2024
2023
2022
Revenue
11,508
11,517
11,043
Net earnings
1,828
1,710
1,514
Common Equity Earnings
1,606
1,506
1,330
EPS: ($)
Basic
3.24
3.10
2.78
Diluted
3.24
3.10
2.78
Total assets
73,486
65,920
64,252
Long-term debt (excluding current portion)
31,224
27,235
25,931
Dividends declared: ($)
Per common share
2.41
2.31
2.20
Per first preference share:
Series F
1.2250
1.2250
1.2250
Series G (1)
1.5308
1.3145
1.0983
Series H
0.4588
0.4588
0.4588
Series I (2)
1.4902
1.5619
0.9157
Series J
1.1875
1.1875
1.1875
Series K (3)
1.3673
0.9823
0.9823
Series M (4)
1.0770
0.9783
0.9783
(1)
The annual dividend per share was reset to $1.5308 for the five-year period from September 1, 2023 up to but excluding September 1, 2028
(2)
Floating quarterly dividend rate is reset every quarter based on the then current three-month Government of Canada Treasury Bill rate plus the applicable reset dividend
yield
(3)
The annual dividend per share was reset from $0.9823 to $1.3673 for the five-year period from March 1, 2024 up to but excluding March 1, 2029
(4)
The annual dividend per share was reset from $0.9783 to $1.3733 for the five-year period from December 1, 2024 up to but excluding December 1, 2029
2024/2023
For a discussion of the changes in revenue, Common Equity Earnings, EPS, total assets and long-term debt see "Performance at a Glance" on
page 2, "Operating Results" on page 6, and "Financial Position" on page 13.
2023/2022
The increase in revenue was due primarily to: (i) a higher U.S. dollar-to-Canadian dollar exchange rate; (ii) Rate Base growth; (iii) higher retail
revenue at UNS Energy driven by new customer rates effective September 1, 2023, customer additions, and warmer weather; and
(iv) the recognition of a regulatory deferral at FortisBC associated with the new cost of capital parameters approved by the BCUC effective
January 1, 2023. The increase was partially offset by the flow-through of lower commodity costs in customer rates.
Common Equity Earnings increased by $176 million in comparison to 2022. The increase was primarily driven by Rate Base growth across our
utilities and the new cost of capital parameters approved for FortisBC effective January 1, 2023. Higher earnings in Arizona also contributed to
earnings growth, reflecting higher retail electricity sales, new customer rates at TEP effective September 1, 2023, and lower depreciation expense
associated with retirement of the San Juan generating station in 2022. An increase in the market value of certain investments that support
retirement benefits, and the higher U.S. dollar-to-Canadian dollar exchange rate, also favourably impacted earnings year over year. The increase
was partially offset by higher corporate finance costs and lower earnings from Aitken Creek.
In addition to the above-noted items impacting earnings, the change in EPS also reflected an increase in the weighted average number of
common shares outstanding, largely associated with the Corporation's DRIP.
The increase in total assets was primarily due to capital expenditures in 2023 and an increase in regulatory assets, largely due to an increase in
deferred income taxes and unrealized losses on energy derivatives. The increase was partially offset by the translation of U.S. dollar-denominated
assets at a lower U.S. dollar-to-Canadian dollar exchange rate.
Management Discussion and Analysis
36
FORTIS INC.
DECEMBER 31, 2024
FOURTH QUARTER RESULTS
Sales
(GWh, except as indicated)
2024
2023
Variance
Regulated Utilities
UNS Energy
Retail Electricity
2,348
2,302
46
Wholesale Electricity
1,295
1,349
(54)
Gas (PJ)
5
5
—
Central Hudson
Electricity
1,187
1,196
(9)
Gas (PJ)
6
6
—
FortisBC Energy (PJ)
67
66
1
FortisAlberta
4,428
4,273
155
FortisBC Electric
916
901
15
Other Electric
2,533
2,525
8
Non-Regulated
Corporate and Other
80
58
22
Electricity sales for the fourth quarter were largely consistent with the comparable period in 2023 for most of Fortis' utilities. The increase in retail
sales at UNS Energy was due primarily to customer additions, while the decrease in wholesale sales was related to lower long-term wholesale
sales due to the expiration of certain contracts. As well, the increase in sales at FortisAlberta was due to customer additions and higher average
consumption from industrial and residential customers.
Gas sales for the fourth quarter were consistent with the comparable period in 2023.
Revenue and Common Equity Earnings
Revenue
Earnings
($ millions, except as indicated)
2024
2023
Variance
2024
2023
Variance
Regulated Utilities
ITC
567
527
40
127
136
(9)
UNS Energy
659
706
(47)
52
62
(10)
Central Hudson
356
311
45
66
36
30
FortisBC Energy
522
544
(22)
120
105
15
FortisAlberta
207
188
19
42
36
6
FortisBC Electric
149
145
4
18
15
3
Other Electric
479
457
22
52
35
17
Non-regulated
Corporate and Other
10
7
3
(81)
(44)
(37)
Total
2,949
2,885
64
396
381
15
Weighted average number of common shares outstanding (# millions)
498.2
489.4
8.8
Basic EPS ($)
0.79
0.78
0.01
The increase in revenue was due primarily to Rate Base growth, a higher U.S. dollar-to-Canadian dollar exchange rate, and new customer rates at
Central Hudson effective July 1, 2024. The implementation of Central Hudson's new customer rates has shifted the timing of quarterly rate
recovery in comparison to related costs, resulting in higher revenue and earnings in the fourth quarter of 2024. The increase was partially offset
by: (i) lower flow-through costs at UNS Energy and FortisBC Energy; and (ii) the recognition of a refund liability at ITC in 2024, largely reflecting the
prior period impact of the reduction in the MISO base ROE approved by FERC (see "Regulatory Highlights - Significant Regulatory Matters" on
page 12).
The increase in Common Equity Earnings was driven by Rate Base growth as well as higher earnings at Central Hudson due to new customer rates
and a higher allowed ROE effective July 1, 2024. The increase was partially offset by the refund liability recognized at ITC, discussed above, and
lower earnings in Arizona, largely reflecting higher operating expenses. Unrealized losses on derivative contracts and the $10 million gain on
disposition of Aitken Creek recognized in 2023 also unfavourably impacted fourth quarter earnings in comparison to the prior year.
The favourable earnings impact resulting from the translation of U.S. dollar denominated earnings at the higher average U.S. dollar-to-Canadian
dollar exchange rate was largely offset by foreign exchange losses associated with the revaluation of U.S. dollar denominated liabilities at a rate of
US$1.00=CA$1.44 at December 31, 2024.
Management Discussion and Analysis
37
FORTIS INC.
DECEMBER 31, 2024
The increase in basic EPS reflects higher Common Equity Earnings, as discussed above, partially offset by an increase in the weighted average
number of common shares outstanding, largely associated with the Corporation's DRIP.
Cash Flows
($ millions)
2024
2023
Variance
Cash and cash equivalents, beginning of period
896
765
131
Cash from (used in):
Operating activities
962
746
216
Investing activities
(1,796)
(748)
(1,048)
Financing activities
125
(134)
259
Effect of exchange rate changes on cash and cash equivalents
33
(13)
46
Change in cash associated with assets held for sale
—
9
(9)
Cash and cash equivalents, end of period
220
625
(405)
Operating Activities
The increase in Operating Cash Flow was largely driven by FortisBC Energy reflecting higher deposits received, net of expenditures incurred,
associated with the Eagle Mountain Pipeline project, as well as other changes in working capital balances. The increase was partially offset by the
timing of flow-through transmission amounts at FortisAlberta as well as higher interest payments.
Investing Activities
The increase in cash used in investing activities primarily reflects higher capital expenditures in 2024, as well as the proceeds received in 2023
related to the disposition of Aitken Creek. Lower customer contributions in aid of construction also contributed to the variance.
Financing Activities
The increase in cash from financing activities reflects changes in the subsidiaries' capital expenditures and the amount of Operating Cash Flow
available to fund those capital expenditures, as well as the repayment of credit facility borrowings in the fourth quarter of 2023 associated with
the proceeds received from the sale of Aitken Creek. See "Cash Flow Summary" on page 15.
SUMMARY OF QUARTERLY RESULTS
Common Equity
Revenue
Earnings
Basic EPS
Diluted EPS
Quarter ended
($ millions)
($ millions)
($)
($)
December 31, 2024
2,949
396
0.79
0.79
September 30, 2024
2,771
420
0.85
0.85
June 30, 2024
2,670
331
0.67
0.67
March 31, 2024
3,118
459
0.93
0.93
December 31, 2023
2,885
381
0.78
0.78
September 30, 2023
2,719
394
0.81
0.81
June 30, 2023
2,594
294
0.61
0.61
March 31, 2023
3,319
437
0.90
0.90
Generally, within each calendar year, quarterly results fluctuate in accordance with seasonality. Given the diversified nature of the Corporation's
subsidiaries, seasonality varies. Earnings of the gas utilities tend to be highest in the first and fourth quarters due to space-heating requirements.
Earnings of the electric distribution utilities in the U.S. tend to be highest in the second and third quarters due to the use of air conditioning and
other cooling equipment.
Generally, from one calendar year to the next, quarterly results reflect: (i) continued organic growth driven by the Corporation's capital plan;
(ii) any significant temperature fluctuations from seasonal norms; (iii) the impact of market conditions, particularly with respect to long-term
wholesale sales at UNS Energy; (iv) the timing and significance of any regulatory decisions; (v) changes in the U.S. dollar-to-Canadian dollar
exchange rate; (vi) for revenue, the flow through in customer rates of commodity costs; and (vii) for EPS, increases in the weighted average
number of common shares outstanding.
December 2024/December 2023
See "Fourth Quarter Results" on page 37.
Management Discussion and Analysis
38
FORTIS INC.
DECEMBER 31, 2024
September 2024/September 2023
Common Equity Earnings increased by $26 million and basic EPS increased by $0.04 in comparison to the third quarter of 2023. The increase was
driven by: (i) Rate Base growth; and (ii) strong earnings in Arizona, reflecting new customer rates at TEP effective September 1, 2023, an increase in
the market value of investments that support retirement benefits and higher production tax credits. Unrealized gains on derivative contracts
recognized in the third quarter of 2024, and an unfavourable deferred income tax adjustment recognized by ITC in the third quarter of 2023, also
contributed to the growth in earnings. The increase was partially offset by the timing of recognition of new cost of capital parameters approved
for FortisBC in 2023, which included $26 million associated with the retroactive impact to January 1, 2023, as well as higher holding company
finance costs. The change in basic EPS also reflected an increase in the weighted average number of common shares outstanding, largely
associated with the Corporation's DRIP.
June 2024/June 2023
Common Equity Earnings increased by $37 million and basic EPS increased by $0.06 in comparison to the second quarter of 2023. The increase
was driven by strong earnings in Arizona, reflecting new customer rates at TEP effective September 1, 2023 and higher retail electricity sales
associated with warmer weather. Rate Base growth across our utilities and the timing of recognition of new cost of capital parameters approved
for FortisBC in 2023 also contributed to earnings growth. The increase was partially offset by lower earnings for Central Hudson and the
Other Electric segment, largely reflecting higher operating costs. The change in basic EPS also reflected an increase in the weighted average
number of common shares outstanding, largely associated with the Corporation's DRIP.
March 2024/March 2023
Common Equity Earnings increased by $22 million and basic EPS increased by $0.03 in comparison to the first quarter of 2023. The increase was
due to the timing of recognition of new cost of capital parameters approved for FortisBC in 2023 and Rate Base growth across our utilities. The
increase was partially offset by higher holding company costs, including finance charges and unrealized losses on derivative contracts, and the
November 1, 2023 disposition of Aitken Creek. In addition, the change in EPS reflected an increase in the weighted average number of common
shares outstanding, largely associated with the Corporation's DRIP.
RELATED-PARTY AND INTER-COMPANY TRANSACTIONS
Related-party transactions are in the normal course of operations and are measured at the amount of consideration agreed to by the related
parties. There were no material related-party transactions in 2024 or 2023.
As of December 31, 2024, accounts receivable included $18 million due from Belize Electricity (December 31, 2023 - $8 million).
Fortis periodically provides short-term financing to subsidiaries to support capital expenditures and seasonal working capital requirements, the
impacts of which are eliminated on consolidation. As at December 31, 2024 and 2023, there were no inter-segment loans outstanding. Interest
charged on inter-segment loans was not material in 2024 and 2023.
MANAGEMENT'S EVALUATION OF CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
DCP are designed to provide reasonable assurance that information required to be disclosed in reports filed with, or submitted to, securities
regulatory authorities is recorded, processed, summarized and reported within the time periods specified under Canadian and U.S. securities laws.
As of December 31, 2024, an evaluation was carried out under the supervision of, and with the participation of, the Corporation's management,
including the CEO and CFO, of the effectiveness of the Corporation's DCP, as defined in the applicable Canadian and U.S. securities laws. Based on
that evaluation, the CEO and CFO concluded that such DCP are effective as of December 31, 2024.
Internal Control over Financial Reporting
ICFR is designed by, or under the supervision of, the Corporation's CEO and CFO and effected by the Corporation's Board, management and other
personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external
purposes in accordance with U.S. GAAP. Because of its inherent limitations, ICFR may not prevent or detect misstatements. Also, projections of any
evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or
that the degree of compliance with the policies or procedures may deteriorate.
The Corporation's management, including the Corporation's CEO and CFO, assessed the effectiveness of the Corporation's ICFR as of
December 31, 2024, based on the criteria set forth in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring
Organizations of the Treadway Commission. Based on this assessment, management concluded that, as of December 31, 2024, the Corporation's
ICFR was effective.
During the year ended December 31, 2024, there have been no changes in the Corporation's ICFR that have materially affected, or are reasonably
likely to materially affect, the Corporation's ICFR.
Management Discussion and Analysis
39
FORTIS INC.
DECEMBER 31, 2024
OUTLOOK
Fortis continues to enhance shareholder value through the execution of its capital plan, the balance and strength of its diversified portfolio of
regulated utility businesses, and growth opportunities within and proximate to its service territories. The Corporation's $26.0 billion five-year
capital plan is expected to increase midyear Rate Base from $39.0 billion in 2024 to $53.0 billion by 2029, translating into a five-year CAGR of 6.5%.
Beyond the five-year capital plan, opportunities to expand and extend growth include: further expansion of the electric transmission grid in the
U.S. to support load growth and facilitate the interconnection of cleaner energy; transmission investments associated with the MISO LRTP
tranches 1, 2.1, and 2.2 as well as regional transmission in New York; grid resiliency and climate adaptation investments; renewable gas solutions
and LNG infrastructure in British Columbia; and the acceleration of load growth and cleaner energy infrastructure investments across our
jurisdictions.
Fortis expects its long-term growth in Rate Base will drive earnings that support dividend growth guidance of 4-6% annually through 2029, and is
premised on the assumptions and material factors listed under "Forward-Looking Information".
Fortis has reduced its corporate-wide direct GHG emissions by 34% from a 2019 base year, and has targets to further reduce such GHG emissions
by 50% by 2030 and 75% by 2035. The Corporation's additional 2050 net-zero direct GHG emissions target reinforces Fortis' commitment to
further decarbonize over the long-term, while continuing our focus on reliability and affordability. The Corporation's ability to achieve the GHG
targets may be impacted by federal, state and provincial energy policies, as well as external factors, including significant customer and load
growth and the development of clean energy technology.
FORWARD-LOOKING INFORMATION
Fortis includes forward-looking information in the MD&A within the meaning of applicable Canadian securities laws and forward-looking statements within the meaning of the U.S.
Private Securities Litigation Reform Act of 1995, (collectively referred to as "forward-looking information"). Forward-looking information reflects expectations of Fortis management
regarding future growth, results of operations, performance, business prospects and opportunities. Wherever possible, words such as anticipates, believes, budgets, could, estimates,
expects, forecasts, intends, may, might, plans, projects, schedule, should, target, will, would, and the negative of these terms, and other similar terminology or expressions, have been used
to identify the forward-looking information, which includes, without limitation: the expectation that Fortis is well-positioned for future investment opportunities; annual dividend growth
guidance through 2029; forecast Capital Expenditures for 2025 through 2029; the expected sources of funding for the capital plan, including the source of common equity proceeds;
forecast midyear Rate Base for 2029 and projected Rate Base growth from 2024 through to 2029; the expected nature, timing and benefits of additional opportunities beyond the capital
plan, including further expansion of the electric transmission grid in the U.S. to support load growth and facilitate the interconnection of cleaner energy, transmission investments
associated with the MISO LRTP tranches 1, 2.1 and 2.2 as well as regional transmission in New York, grid resiliency and climate adaptation investments, renewable gas solutions and LNG
infrastructure in British Columbia, and the acceleration of load growth and cleaner energy infrastructure investments; expected implications of utility industry trends on the utility sector
and on the Corporation's capital investments; the expected timing, outcome and impact of legal and regulatory proceedings and decisions; the expected or potential funding sources for
operating expenses, interest costs and capital expenditures; the expectation that maintaining the targeted capital structure of the regulated operating subsidiaries will not have an
impact on the Corporation's ability to pay dividends in the foreseeable future; the expected consolidated fixed-term debt maturities and repayments over the next five years; the
expectation that the Corporation and its subsidiaries will continue to have reasonable access to long-term capital and will remain compliant with debt covenants in 2025; the expected
uses of proceeds from debt financings; the performance of contractual obligations to provide equity capital to Wataynikaneyap Power; the potential impact of new or revised tariffs on
forecast and actual capital expenditures; forecast midyear Rate Base for 2025 and 2029 by segment; the nature, timing, benefits and expected costs of certain capital projects, including
ITC's transmission projects associated with the MISO LRTP, IRP Related Generation, the Roadrunner Reserve Battery Storage Projects 1 and 2, the Vail-to-Tortolita Transmission Project, the
Eagle Mountain Pipeline Project, the Tilbury LNG Storage Expansion, the AMI Project, and the Tilbury 1B Project, and additional investment opportunities; the 2050 net-zero direct GHG
emissions target; the 2030 and 2035 direct GHG emissions reduction targets; how the Corporation's GHG emissions targets are expected to be achieved, including TEP's plan to exit coal;
the potential impact of federal, state and provincial energy policies and other factors, including significant customer and load growth and the development of clean energy technology,
on the Corporation's ability to achieve its GHG emissions reduction targets; the expected impacts of future accounting pronouncements on the Corporation's disclosures; the potential
impact of the recognition of goodwill impairment losses; the potential and expected impacts of income tax compliance examinations and legislation with respect to interest deductibility
limitations and global minimum tax; and the expectation that long-term growth in Rate Base will drive earnings that support dividend growth guidance of 4-6% annually through 2029.
Forward-looking information involves significant risks, uncertainties and assumptions. Certain material factors or assumptions have been applied in drawing the conclusions contained
in the forward-looking information including, without limitation: reasonable legal and regulatory decisions and the expectation of regulatory stability; the successful execution of the
capital plan; no material capital project or financing cost overrun; sufficient human resources to deliver service and execute the capital plan; the realization of additional opportunities
beyond the capital plan; no significant variability in interest rates; no material changes in the assumed U.S. dollar- to- Canadian dollar exchange rate; the continuation of current
participation levels in the Corporation's DRIP; the Board exercising its discretion to declare dividends, taking into account the financial performance and condition of the Corporation; no
significant operational disruptions or environmental liability or upset; the continued ability to maintain the performance of the electricity and gas systems; no severe and prolonged
economic downturn; sufficient liquidity and capital resources; the ability to hedge exposures to fluctuations in foreign exchange rates, natural gas prices and electricity prices; the
continued availability of natural gas, fuel, coal and electricity supply; continuation of power supply and capacity purchase contracts; no significant changes in government energy plans,
environmental laws and regulations that could have a material negative impact; maintenance of adequate insurance coverage; the ability to obtain and maintain licences and permits;
retention of existing service areas; no significant changes in tax laws and the continued tax deferred treatment of earnings from the Corporation's foreign operations; continued
maintenance of information technology infrastructure and no material breach of cybersecurity; continued favourable relations with Indigenous Peoples; and favourable labour relations.
Fortis cautions readers that a number of factors could cause actual results, performance or achievements to differ materially from those discussed or implied in the forward-looking
information. These factors should be considered carefully and undue reliance should not be placed on the forward-looking information. Risk factors which could cause results or events to
differ from current expectations are detailed under the heading "Business Risks" in this MD&A and in other continuous disclosure materials filed from time to time with Canadian securities
regulatory authorities and the Securities and Exchange Commission. Key risk factors for 2025 include, but are not limited to: uncertainty regarding changes in utility regulation, including
the outcome of regulatory proceedings at the Corporation's utilities; the physical risks associated with the provision of electric and gas service, which can be exacerbated by the impacts
of climate change; risks related to environmental laws and regulations; risks associated with capital projects and the impact on the Corporation's continued growth; risks associated with
cybersecurity and information and operations technology; the impact of weather variability and seasonality on heating and cooling loads, gas distribution volumes and hydroelectric
generation; risks associated with commodity price volatility and supply of purchased power; and risks related to general economic conditions, including inflation, interest rate and foreign
exchange risks.
All forward-looking information herein is given as of February 13, 2025. 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.
Management Discussion and Analysis
40
FORTIS INC.
DECEMBER 31, 2024
GLOSSARY
2024 Annual Financial Statements: the Corporation's audited
consolidated financial statements and notes thereto for the year ended
December 31, 2024
Actual Payout Ratio: dividends paid per common share divided by basic
EPS
Adjusted Basic EPS: Adjusted Common Equity Earnings divided by the
basic weighted average number of common shares outstanding
Adjusted Common Equity Earnings: net earnings attributable to
common equity shareholders adjusted as shown under "Non-U.S. GAAP
Financial Measures" on page 10
Adjusted Payout Ratio: dividends paid per common share divided by
Adjusted Basic EPS as shown under "Non-U.S. GAAP Financial Measures" on
page 10
AFUDC: allowance for funds used during construction
AI: artificial intelligence
Aitken Creek: Aitken Creek Gas Storage ULC, a 93.8%-owned subsidiary of
FortisBC Holdings Inc., sold on November 1, 2023
AMI: advanced metering infrastructure
ATM Program: at-the-market equity program
ACC: Arizona Corporation Commission
ASU: accounting standards update
AUC: Alberta Utilities Commission
BCUC: British Columbia Utilities Commission
Belize Electricity: Belize Electricity Limited, in which Fortis indirectly holds
a 33% equity interest
Board: Board of Directors of the Corporation
CAGR(s): compound annual growth rate of a particular item. CAGR = (EV/
BV)(1/n)-1, where: (i) EV is the ending value of the item; (ii) BV is the beginning
value of the item; and (iii) n is the number of periods. Calculated on a
constant U.S. dollar-to-Canadian dollar exchange rate
Capital Expenditures: cash outlay for additions to property, plant and
equipment and intangible assets as shown in the Annual Financial
Statements, as well as Fortis' 39% share of capital spending for the
Wataynikaneyap Transmission Power project. See "Non-U.S. GAAP Financial
Measures" on page 10
Caribbean Utilities: Caribbean Utilities Company, Ltd., an indirect
approximately 60%-owned (as at December 31, 2024) subsidiary of Fortis,
together with its subsidiary
Central Hudson: CH Energy Group, Inc., an indirect wholly-owned
subsidiary of Fortis, together with its subsidiaries, including Central Hudson
Gas & Electric Corporation
CEO: Chief Executive Officer of Fortis
CFO: Chief Financial Officer of Fortis
Common Equity Earnings: net earnings attributable to common equity
shareholders
Corporation: Fortis Inc.
COS: cost of service
Court of Appeal: Court of Appeal of Alberta
CPCN: Certificate of Public Convenience and Necessity
CSA: Canadian Securities Administrators
CSDS: Canadian Sustainability Disclosure Standard
CSSB: Canadian Sustainability Standards Board
DBP: defined benefit pension
D.C. Circuit Court: U.S. Court of Appeals for the District of Columbia Circuit
DCP: disclosure controls and procedures
DRIP: dividend reinvestment plan
EPC: engineering, procurement and construction
EPRI: Electric Power Research Institute
EPS: earnings per common share
ERM: enterprise risk management
FERC: Federal Energy Regulatory Commission
Fortis: Fortis Inc.
FortisAlberta: FortisAlberta Inc., an indirect wholly-owned subsidiary of
Fortis
FortisBC: FortisBC Energy and FortisBC Electric
FortisBC Electric: FortisBC Inc., an indirect wholly-owned subsidiary of
Fortis, together with its subsidiaries
FortisBC Energy: FortisBC Energy Inc., an indirect wholly-owned subsidiary
of Fortis, together with its subsidiaries
FortisOntario: FortisOntario Inc., a direct wholly-owned subsidiary of Fortis,
together with its subsidiaries
FortisTCI: FortisTCI Limited, an indirect wholly-owned subsidiary of Fortis,
together with its subsidiary
Fortis Belize: Fortis Belize Limited, an indirect wholly-owned subsidiary of
Fortis
Four Corners: Four Corners Generating Station, Units 4 and 5
FX: foreign exchange associated with the translation of U.S. dollar-
denominated amounts. Foreign exchange is calculated by applying the
change in the U.S. dollar-to-Canadian dollar FX rates to the prior period
U.S. dollar balance
Management Discussion and Analysis
41
FORTIS INC.
DECEMBER 31, 2024
GCOC: generic cost of capital
GHG: greenhouse gas
GWh: gigawatt hour(s)
ICFR: internal control over financial reporting
IRP: integrated resource plan
ITC: ITC Investment Holdings Inc., an indirect 80.1%-owned subsidiary of
Fortis, together with its subsidiaries, including International Transmission
Company, Michigan Electric Transmission Company, LLC, ITC Midwest LLC,
and ITC Great Plains, LLC
LNG: liquefied natural gas
LRTP: long range transmission plan
Luna: Luna Energy Facility
Major Capital Projects: projects, other than ongoing maintenance
projects, individually costing $200 million or more in the forecast/planning
period
Maritime Electric: Maritime Electric Company, Limited, an indirect wholly-
owned subsidiary of Fortis
Material Adverse Effect: a material adverse effect on the Corporation's
business, results of operations, financial position or liquidity, on a
consolidated basis
MD&A: the Corporation's management discussion and analysis for the year
ended December 31, 2024
MISO: Midcontinent Independent System Operator, Inc.
Moody's: Moody's Investor Services, Inc.
Morningstar DBRS: DBRS Limited
MW: megawatt(s)
Navajo: Navajo Generating Station
Newfoundland Power: Newfoundland Power Inc., a direct wholly-owned
subsidiary of Fortis
Non-U.S. GAAP Financial Measures: financial measures that do not have
a standardized meaning prescribed by U.S. GAAP
NOPR: notice of proposed rulemaking
NYSE: New York Stock Exchange
OPEB: other post-employment benefits
Operating Cash Flow: cash from operating activities
PBR: performance-based rate-setting
PJ: petajoule(s)
PPFAC: purchased power and fuel adjustment clause
PSC: New York State Public Service Commission
Rate Base: the stated value of property on which a regulated utility is
permitted to earn a specified return in accordance with its regulatory
construct
REA: Rural Electrification Association
RNG: renewable natural gas
ROA: rate of return on Rate Base
ROE: rate of return on common equity
ROFR: right of first refusal
RTO: regional transmission organization
S&P: Standard & Poor's Financial Services LLC
San Juan: San Juan Generating Station Unit 1
SEC: U.S. Securities and Exchange Commission
SEDAR+: Canadian System for Electronic Document Analysis and Retrieval
SOFR: secured overnight financing rates
TEP: Tucson Electric Power Company
TSR: total shareholder return, which is a measure of the return to common
equity shareholders in the form of share price appreciation and dividends
(assuming reinvestment) over a specified time period in relation to the share
price at the beginning of the period.
TSX: Toronto Stock Exchange
UNS Electric: UNS Electric, Inc.
UNS Energy: UNS Energy Corporation, an indirect wholly-owned subsidiary
of Fortis, together with its subsidiaries, including TEP, UNS Electric and
UNS Gas
UNS Gas: UNS Gas, Inc.
U.S.: United States of America
U.S. GAAP: accounting principles generally accepted in the U.S.
Waneta Expansion: Waneta Expansion hydroelectric generation facility
Wataynikaneyap Power: Wataynikaneyap Power Limited Partnership, in
which Fortis indirectly holds a 39% equity interest
Management Discussion and Analysis
42
FORTIS INC.
DECEMBER 31, 2024
FORTIS INC.
Audited Consolidated Financial Statements
As at and for the years ended December 31, 2024 and 2023
Consolidated Financial Statements
1
FORTIS INC.
DECEMBER 31, 2024
Table of Contents
Management's Report on Internal Control over Financial Reporting ........
2
NOTE 9
Other Assets ..........................................................................
23
Report of Independent Registered Public Accounting Firm
NOTE 10
Property, Plant and Equipment .............................................
23
("PCAOB ID No. 01208") - Opinion on the Financial Statements ............
3
NOTE 11
Intangible Assets ...................................................................
24
Report of Independent Registered Public Accounting Firm - Opinion on .
NOTE 12
Goodwill ................................................................................
25
Internal Control over Financial Reporting .............................................
5
NOTE 13
Accounts Payable and Other Current Liabilities .....................
25
Consolidated Balance Sheets ....................................................................
6
NOTE 14
Long-Term Debt ....................................................................
26
Consolidated Statements of Earnings .......................................................
7
NOTE 15
Leases ....................................................................................
29
Consolidated Statements of Comprehensive Income ...............................
7
NOTE 16
Other Liabilities ......................................................................
30
Consolidated Statements of Cash Flows ...................................................
8
NOTE 17
Earnings Per Common Share .................................................
31
Consolidated Statements of Changes in Equity ........................................
9
NOTE 18
Preference Shares ..................................................................
31
Notes to Consolidated Financial Statements
NOTE 19
Accumulated Other Comprehensive Income ........................
33
NOTE 1
Description of Business ..........................................................
10
NOTE 20
Stock-Based Compensation Plans .........................................
33
NOTE 2
Regulation .............................................................................
11
NOTE 21
Disposition ............................................................................
35
NOTE 3
Summary of Significant Accounting Policies .........................
13
NOTE 22
Other Income, Net .................................................................
36
NOTE 4
Segmented Information ........................................................
19
NOTE 23
Income Taxes .........................................................................
36
NOTE 5
Revenue ................................................................................
20
NOTE 24
Employee Future Benefits ......................................................
37
NOTE 6
Accounts Receivable and Other Current Assets.....................
21
NOTE 25
Supplementary Cash Flow Information .................................
41
NOTE 7
Inventories .............................................................................
21
NOTE 26
Fair Value of Financial Instruments and Risk Management ....
41
NOTE 8
Regulatory Assets and Liabilities ............................................
21
NOTE 27
Commitments and Contingencies ........................................
45
MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Management of Fortis Inc. and its subsidiaries (the "Corporation") is responsible for establishing and maintaining adequate internal control over financial
reporting ("ICFR"). The Corporation's ICFR is designed by, or under the supervision of, the Corporation's President and Chief Executive Officer ("CEO") and
Executive Vice President, Chief Financial Officer ("CFO") and effected by the Corporation's board of directors, management and other personnel to provide
reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with
accounting principles generally accepted in the United States of America. Because of its inherent limitations, ICFR may not prevent or detect
misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to risk that controls may become inadequate because of
changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
The Corporation's management, including its CEO and CFO, assessed the effectiveness of the Corporation's ICFR as of December 31, 2024, based on the
criteria set forth in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
Based on this assessment, management concluded that, as of December 31, 2024, the Corporation's ICFR was effective.
The Corporation's ICFR as of December 31, 2024 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, 2024. Deloitte LLP issued an unqualified opinion for both audits.
February 13, 2025
/s/ David G. Hutchens
/s/ Jocelyn H. Perry
David G. Hutchens
Jocelyn H. Perry
President and Chief Executive Officer, Fortis Inc.
Executive Vice President, Chief Financial Officer, Fortis Inc.
St. John's, Canada
Consolidated Financial Statements
2
FORTIS INC.
DECEMBER 31, 2024
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and the Board of Directors of Fortis Inc.
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Fortis Inc. and subsidiaries (the "Corporation") as of December 31, 2024 and 2023, 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, 2024, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all
material respects, the financial position of the Corporation as of December 31, 2024 and 2023, and the results of its operations and its cash flows for each
of the two years in the period ended December 31, 2024, in conformity with accounting principles generally accepted in the United States of America.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Corporation's
internal control over financial reporting as of December 31, 2024, 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 13, 2025, expressed an unqualified opinion on
the Corporation's internal control over financial reporting.
Basis for Opinion
These financial statements are the responsibility of the Corporation's management. Our responsibility is to express an opinion on the Corporation's
financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to
the Corporation in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission
and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included
performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures
that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial
statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the
overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current-period audit of the financial statements that were communicated or
required to be communicated to the audit committee and that (1) relate to accounts or disclosures that are material to the financial statements and (2)
involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion
on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the
critical audit matters or on the accounts or disclosures to which they relate.
Assessment for Impairment of Goodwill - Refer to Notes 3 and 12 to the financial statements
Critical Audit Matter Description
The Corporation assesses goodwill for impairment annually as well as whenever any event or other change indicates that the fair value of a reporting unit
may be below its carrying value. Management has determined that there is no impairment based on its current annual assessment.
Management's assessment primarily utilizes the income approach which is based on underlying estimates and assumptions with varying degrees of
uncertainty. Those with the highest degree of subjectivity and impact are the assumed terminal growth rates and discount rates. Auditing these estimates
and assumptions required a high degree of audit judgment and effort, including the involvement of a fair value specialist.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the terminal growth rate and discount rate used by management to estimate the fair value of more recently acquired
reporting units included the following, among others:
•
Evaluating the effectiveness of controls over the estimated fair value of the reporting units, including the review and approval of the terminal growth
rate and discount rate selected by management.
•
Evaluating management's ability to accurately forecast the terminal growth rate by:
•
Assessing the methodology used in management's determination of the terminal growth rate; and
•
Comparing management's assumptions to historical data and available market projection data.
•
With the assistance of a fair value specialist, evaluating the reasonableness of the discount rate by:
•
Testing the source information underlying the determination of the discount rate; and
•
Developing a range of independent estimates and comparing those to the discount rate selected by management.
Consolidated Financial Statements
3
FORTIS INC.
DECEMBER 31, 2024
Impact of Rate Regulation on the financial statements - Refer to Notes 2, 3 and 8 to the financial statements
Critical Audit Matter Description
The Corporation's regulated utilities are subject to rate regulation and annual earnings oversight by various federal, state and provincial regulatory
authorities who have jurisdiction in the United States and Canada. Rates and resultant earnings of the Corporation's regulated utilities are determined
under cost of service regulation, with some using performance-based rate-setting mechanisms. The regulation of rates is premised on the full recovery of
prudently incurred costs and a reasonable rate of return on asset value ("ROA") or common shareholders' equity ("ROE"). Regulatory decisions can have an
impact on the timely recovery of costs and the regulator-approved ROE and/or ROA. Accounting for the economics of rate regulation impacts multiple
financial statement line items and disclosures, such as property, plant, and equipment; regulatory assets and liabilities; operating revenues and expenses;
income taxes; and depreciation expense.
We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions
about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the potential impact of future regulatory
orders on the financial statements. Management judgments include assessing the likelihood of recovery of costs incurred or a refund to customers
through the rate-setting process. While the Corporation's regulated utilities have indicated they expect to recover costs from customers through
regulated rates, there is a risk that the respective regulatory authority will not approve full recovery of the costs incurred and a reasonable ROE and/or ROA.
Auditing these matters required especially subjective judgment and specialized knowledge of accounting for rate regulation due to its inherent
complexities across different jurisdictions.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the likelihood of recovery of costs incurred or a refund to customers through the rate-setting process, included the
following, among others:
•
Evaluating the effectiveness of controls over the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering
costs in future rates or of a future reduction in rates.
•
Assessing relevant regulatory orders, regulatory statutes and interpretations as well as procedural memorandums, utility and intervener filings, and
other publicly available information to evaluate the likelihood of recovery in future rates or of a future reduction in rates and the ability to earn a
reasonable ROA or ROE.
•
For regulatory matters in progress, inspecting the regulated utilities' filings for any evidence that might contradict management's assertions. We
obtained an analysis from management and letters from internal and external legal counsel, as appropriate, regarding cost recoveries or a future
reduction in rates.
•
Evaluating the Corporation's disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
/s/ Deloitte LLP
Chartered Professional Accountants
St. John's, Canada
February 13, 2025
We have served as the Corporation's auditor since 2017.
Consolidated Financial Statements
4
FORTIS INC.
DECEMBER 31, 2024
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and the Board of Directors of Fortis Inc.
Opinion on Internal Control over Financial Reporting
We have audited the internal control over financial reporting of Fortis Inc. and subsidiaries (the "Corporation") as of December 31, 2024, based on criteria
established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In
our opinion, the Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2024, based on
criteria established in Internal Control - Integrated Framework (2013) issued by COSO.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated
financial statements as of and for the year ended December 31, 2024, of the Corporation and our report dated February 13, 2025, expressed an unqualified
opinion on those financial statements.
Basis for Opinion
The Corporation's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness
of internal control over financial reporting, included in the accompanying Management's Report on Internal Control over Financial Reporting. Our
responsibility is to express an opinion on the Corporation's internal control over financial reporting based on our audit. We are a public accounting firm
registered with the PCAOB and are required to be independent with respect to the Corporation in accordance with the U.S. federal securities laws and the
applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included
obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design
and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the
circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control over Financial Reporting
A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal
control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately
and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as
necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures
of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable
assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material
effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of
effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of
compliance with the policies or procedures may deteriorate.
/s/ Deloitte LLP
Chartered Professional Accountants
St. John's, Canada
February 13, 2025
Consolidated Financial Statements
5
FORTIS INC.
DECEMBER 31, 2024
CONSOLIDATED BALANCE SHEETS
FORTIS INC.
As at December 31 (in millions of Canadian dollars)
2024
2023
ASSETS
Current assets
Cash and cash equivalents
$
220
$
625
Accounts receivable and other current assets (Note 6)
1,886
1,818
Prepaid expenses
182
150
Inventories (Note 7)
685
566
Regulatory assets (Note 8)
823
866
Total current assets
3,796
4,025
Other assets (Note 9)
1,653
1,298
Regulatory assets (Note 8)
3,808
3,518
Property, plant and equipment, net (Note 10)
49,456
43,385
Intangible assets, net (Note 11)
1,661
1,510
Goodwill (Note 12)
13,112
12,184
Total assets
$
73,486
$
65,920
LIABILITIES AND EQUITY
Current liabilities
Short-term borrowings (Note 14)
$
98
$
119
Accounts payable and other current liabilities (Note 13)
3,353
2,972
Regulatory liabilities (Note 8)
595
577
Current installments of long-term debt (Note 14)
1,990
2,296
Total current liabilities
6,036
5,964
Regulatory liabilities (Note 8)
3,696
3,381
Deferred income taxes (Note 23)
5,020
4,399
Long-term debt (Note 14)
31,224
27,235
Finance leases (Note 15)
343
339
Other liabilities (Note 16)
1,314
1,270
Total liabilities
47,633
42,588
Commitments and contingencies (Note 27)
Equity
Common shares (1)
15,589
15,108
Preference shares (Note 18)
1,623
1,623
Additional paid-in capital
8
9
Accumulated other comprehensive income (Note 19)
2,067
653
Retained earnings
4,521
4,112
Shareholders' equity
23,808
21,505
Non-controlling interests
2,045
1,827
Total equity
25,853
23,332
Total liabilities and equity
$
73,486
$
65,920
(1) No par value. Unlimited authorized shares. 499.3 million and 490.6 million issued and outstanding
as at December 31, 2024 and 2023, respectively
Approved on Behalf of the Board
/s/ Jo Mark Zurel
/s/ Maura J. Clark
Jo Mark Zurel,
Maura J. Clark,
See accompanying Notes to Consolidated Financial Statements
Director
Director
Consolidated Financial Statements
6
FORTIS INC.
DECEMBER 31, 2024
CONSOLIDATED STATEMENTS OF EARNINGS
FORTIS INC.
For the years ended December 31 (in millions of Canadian dollars, except per share amounts)
2024
2023
Revenue (Note 5)
$
11,508
$
11,517
Expenses
Energy supply costs
3,249
3,771
Operating expenses
3,040
2,889
Depreciation and amortization
1,927
1,773
Total expenses
8,216
8,433
Operating income
3,292
3,084
Other income, net (Note 22)
288
291
Finance charges
1,406
1,305
Earnings before income tax expense
2,174
2,070
Income tax expense (Note 23)
346
360
Net earnings
$
1,828
$
1,710
Net earnings attributable to:
Non-controlling interests
$
148
$
137
Preference equity shareholders (Note 18)
74
67
Common equity shareholders
1,606
1,506
$
1,828
$
1,710
Earnings per common share (Note 17)
Basic
$
3.24
$
3.10
Diluted
$
3.24
$
3.10
See accompanying Notes to Consolidated Financial Statements
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
For the years ended December 31 (in millions of Canadian dollars)
2024
2023
Net earnings
$
1,828
$
1,710
Other comprehensive income (loss)
Unrealized foreign currency translation gains (losses), net of hedging activities and income tax
recovery (expense) of $14 million and $(3) million, respectively
1,561
(402)
Other, net of income tax expense of $3 million and $4 million, respectively
9
6
1,570
(396)
Comprehensive income
$
3,398
$
1,314
Comprehensive income attributable to:
Non-controlling interests
$
304
$
96
Preference equity shareholders
74
67
Common equity shareholders
3,020
1,151
$
3,398
$
1,314
See accompanying Notes to Consolidated Financial Statements
Consolidated Financial Statements
7
FORTIS INC.
DECEMBER 31, 2024
CONSOLIDATED STATEMENTS OF CASH FLOWS
FORTIS INC.
For the years ended December 31 (in millions of Canadian dollars)
2024
2023
Operating activities
Net earnings
$
1,828
$
1,710
Adjustments to reconcile net earnings to net cash provided by operating activities:
Depreciation - property, plant and equipment
1,695
1,542
Amortization - intangible assets
153
150
Amortization - other
79
81
Deferred income tax expense (Note 23)
154
272
Equity component, allowance for funds used during construction (Note 22)
(139)
(101)
Other
43
72
Change in long-term regulatory assets and liabilities
(99)
(100)
Change in working capital (Note 25)
168
(81)
Cash from operating activities
3,882
3,545
Investing activities
Additions to property, plant and equipment
(5,012)
(3,986)
Additions to intangible assets
(206)
(183)
Contributions in aid of construction
106
216
Proceeds on disposition, net (Note 21)
—
454
Contributions to equity-accounted investees
—
(24)
Other
(283)
(219)
Cash used in investing activities
(5,395)
(3,742)
Financing activities
Proceeds from long-term debt, net of issuance costs (Note 14)
3,124
2,810
Repayments of long-term debt and finance leases
(1,718)
(1,210)
Borrowings under committed credit facilities
8,618
7,217
Repayments under committed credit facilities
(8,055)
(7,276)
Net change in short-term borrowings
(25)
(126)
Issue of common shares, net of costs, and dividends reinvested
46
43
Dividends
Common shares, net of dividends reinvested
(744)
(701)
Preference shares
(74)
(67)
Subsidiary dividends paid to non-controlling interests
(110)
(83)
Other
2
6
Cash from financing activities
1,064
613
Effect of exchange rate changes on cash and cash equivalents
44
—
Change in cash and cash equivalents
(405)
416
Cash and cash equivalents, beginning of year
625
209
Cash and cash equivalents, end of year
$
220
$
625
Supplementary Cash Flow Information (Note 25)
See accompanying Notes to Consolidated Financial Statements
Consolidated Financial Statements
8
FORTIS INC.
DECEMBER 31, 2024
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
FORTIS INC.
For the years ended December 31
(in millions of Canadian dollars, except share
numbers)
Common
Shares
(# millions)
Common
Shares
Preference
Shares
(Note 18)
Additional
Paid-In
Capital
Accumulated
Other
Comprehensive
Income (Loss)
(Note 19)
Retained
Earnings
Non-
Controlling
Interests
Total
Equity
As at December 31, 2023
490.6 $ 15,108
$
1,623
$
9
$
653
$
4,112
$
1,827
$ 23,332
Net earnings
—
—
—
—
—
1,680
148
1,828
Other comprehensive income
—
—
—
—
1,414
—
156
1,570
Common shares issued
8.7
481
—
—
—
—
—
481
Advances from non-controlling interests
—
—
—
—
—
—
21
21
Subsidiary dividends paid to non-
controlling interests
—
—
—
—
—
—
(110)
(110)
Dividends declared on common shares
($2.41 per share)
—
—
—
—
—
(1,197)
—
(1,197)
Dividends on preference shares
—
—
—
—
—
(74)
—
(74)
Other
—
—
—
(1)
—
—
3
2
As at December 31, 2024
499.3 $ 15,589
$
1,623
$
8
$
2,067
$
4,521
$
2,045
$ 25,853
As at December 31, 2022
482.2 $
14,656
$
1,623
$
10
$
1,008
$
3,733
$
1,812
$ 22,842
Net earnings
—
—
—
—
—
1,573
137
1,710
Other comprehensive loss
—
—
—
—
(355)
—
(41)
(396)
Common shares issued
8.4
452
—
—
—
—
—
452
Subsidiary dividends paid to non-
controlling interests
—
—
—
—
—
—
(83)
(83)
Dividends declared on common shares
($2.31 per share)
—
—
—
—
—
(1,127)
—
(1,127)
Dividends on preference shares
—
—
—
—
—
(67)
—
(67)
Other
—
—
—
(1)
—
—
2
1
As at December 31, 2023
490.6 $
15,108
$
1,623
$
9
$
653
$
4,112
$
1,827
$ 23,332
See accompanying Notes to Consolidated Financial Statements
Consolidated Financial Statements
9
FORTIS INC.
DECEMBER 31, 2024
1. DESCRIPTION OF BUSINESS
Fortis Inc. ("Fortis" or the "Corporation") is a well-diversified North American regulated electric and gas utility holding company. Entities within the
reporting segments that follow operate with substantial autonomy.
Regulated Utilities
ITC: ITC Investment Holdings Inc., ITC Holdings Corp. and the electric transmission operations of its regulated operating subsidiaries, which include
International Transmission Company ("ITCTransmission"), Michigan Electric Transmission Company, LLC ("METC"), ITC Midwest LLC ("ITC Midwest"), and ITC
Great Plains, LLC. Fortis owns 80.1% of ITC and an affiliate of GIC Private Limited owns a 19.9% minority interest.
ITC owns and operates high-voltage transmission lines in Michigan's lower peninsula and portions of Iowa, Minnesota, Illinois, Missouri, Kansas, Oklahoma
and Wisconsin.
UNS Energy: UNS Energy Corporation, which primarily includes Tucson Electric Power Company ("TEP"), UNS Electric, Inc. ("UNS Electric") and UNS Gas, Inc.
("UNS Gas").
UNS Energy's largest operating subsidiary, TEP, and UNS Electric are vertically integrated regulated electric utilities. They generate, transmit and distribute
electricity to retail customers in southeastern Arizona, including the greater Tucson metropolitan area. TEP also sells wholesale electricity to other entities
in the western United States. Together they own generating capacity of 3,442 megawatts ("MW"), including 68 MW of solar capacity and 250 MW of wind
capacity. Several generating assets in which they have an interest are jointly owned.
UNS Gas is a regulated gas distribution utility serving retail customers in northern and southern Arizona.
Central Hudson: CH Energy Group, Inc., which primarily includes Central Hudson Gas & Electric Corporation. Central Hudson is a regulated electric and gas
transmission and distribution utility that serves portions of New York State's Mid-Hudson River Valley and owns gas-fired and hydroelectric generating
capacity totalling 43 MW.
FortisBC Energy: FortisBC Energy Inc., which is the largest regulated distributor of natural gas in British Columbia, providing transmission and distribution
services. FortisBC Energy sources 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. FortisAlberta
is not involved in the direct sale of electricity.
FortisBC Electric: FortisBC Inc. is an integrated regulated electric utility operating in the southern interior of British Columbia. It owns four hydroelectric
generating facilities with a combined capacity of 225 MW. It also provides operating, maintenance and management services relating to five hydroelectric
generating facilities in British Columbia that are owned by third parties.
Other Electric: Eastern Canadian and Caribbean utilities, as follows: Newfoundland Power Inc. ("Newfoundland Power"); Maritime Electric Company,
Limited ("Maritime Electric"); FortisOntario Inc. ("FortisOntario"); a 39% equity investment in Wataynikaneyap Power Limited Partnership ("Wataynikaneyap
Power"); an approximate 60% controlling interest in Caribbean Utilities Company, Ltd. ("Caribbean Utilities"); FortisTCI Limited and Turks and Caicos Utilities
Limited (collectively, "FortisTCI"); and a 33% equity investment in Belize Electricity Limited ("Belize Electricity").
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 145 MW, of which 98 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 90 MW. FortisOntario consists of three regulated
electric utilities that provide service to customers in Fort Erie, Cornwall, Gananoque, Port Colborne and the District of Algoma in Ontario with a generating
capacity of 3 MW. Wataynikaneyap Power is a transmission company majority-owned by 24 First Nations in which Fortis owns a 39% interest. The 1,800
kilometer Wataynikaneyap Power Transmission Line will connect 17 remote First Nations to the Ontario power grid.
Caribbean Utilities is an integrated regulated electric utility and the sole electricity provider on Grand Cayman with a diesel-powered generating capacity
of 166 MW. FortisTCI consists of two integrated regulated electric utilities that provide electricity to certain Turks and Caicos Islands and has a generating
capacity of 99 MW, including 95 MW of diesel-powered generating capacity and 4 MW of solar capacity. Belize Electricity is an integrated electric utility and
the principal distributor of electricity in Belize.
Non-Regulated
Corporate and Other: Captures expenses and revenues not specifically related to any reportable segment and those business operations that are below
the required threshold for segmented reporting. Consists of non-regulated holding company expenses, as well as non-regulated long-term contracted
generation assets in Belize. The generation assets include three hydroelectric generating facilities with a combined generating capacity of 51 MW, held
through the Corporation's indirectly wholly owned subsidiary Fortis Belize Limited, the output of which is sold to Belize Electricity under 50-year power
purchase agreements ("PPAs"). Also includes results for the Aitken Creek natural gas storage facility ("Aitken Creek") until the November 1, 2023 date of
disposition (Note 21).
Notes to Consolidated Financial Statements
For the years ended December 31, 2024 and 2023
10
FORTIS INC.
DECEMBER 31, 2024
2. REGULATION
General
The earnings of the Corporation's regulated utilities are determined under cost of service ("COS") regulation, with some using performance-based rate
setting ("PBR") mechanisms.
Under COS regulation, the regulator sets customer rates to permit a reasonable opportunity for the timely recovery of the estimated costs of providing
service, including a fair rate of return on a deemed or targeted capital structure applied to an approved regulatory asset value ("rate base"). PBR
mechanisms generally apply a formula that incorporates inflation and assumed productivity improvements for a set term.
The ability to recover prudently incurred costs of providing service and earn the regulator-approved rate of return on common shareholders' equity
("ROE") and/or rate of return on rate base assets ("ROA") may depend on achieving the forecasts established in the rate-setting process. As well, the
Corporation's regulated utilities, where applicable, are permitted by their respective regulators to flow through to customers, without markup, the cost of
natural gas, fuel and/or purchased power through base customer rates and/or the use of rate stabilization and other mechanisms (Note 8). There can be
varying degrees of regulatory lag between when costs are incurred and when they are reflected in customer rates.
Nature of Regulation
Allowed
Common
Equity
(%)
Allowed ROE (1)
(%)
Regulated Utility
Regulatory Authority
2024
2023
Significant Features
ITC
Federal Energy Regulatory
Commission ("FERC")
60.0
10.73
(2)
10.77
(2) Cost-based formula rates, with
annual true-up mechanism (3)
Incentive adders
TEP
Arizona Corporation Commission
("ACC")
54.3
9.55
9.55 (4) COS regulation
Historical test year
FERC
(5)
9.79
9.79
Formula transmission rates
UNS Electric
ACC
53.7
9.75
(6)
9.50
UNS Gas
ACC
50.8
9.75
(7)
9.75
Central Hudson
New York State Public Service
Commission ("PSC")
48.0
9.50
(8)
9.00
COS regulation
Future test year
FortisBC Energy
British Columbia Utilities Commission
("BCUC")
45.0
9.65
9.65
COS regulation with formula
components and incentives
FortisBC Electric
BCUC
41.0
9.65
9.65
Future test year
FortisAlberta
Alberta Utilities Commission ("AUC")
37.0
9.28
8.50
PBR, with formula to calculate
ROE on an annual basis (9)
Newfoundland Power
Newfoundland and Labrador Board of
Commissioners of Public Utilities
45.0
8.50
8.50
COS regulation
Future test year
Maritime Electric
Island Regulatory and Appeals
Commission
40.0
9.35
9.35
COS regulation
Future test year
FortisOntario (10)
Ontario Energy Board
40.0
8.52-9.30
8.52-9.30
COS regulation with incentive
mechanisms
Caribbean Utilities (11)
Utility Regulation and Competition
Office
N/A
8.25-10.25
7.50-9.50
COS regulation
Rate-cap adjustment
mechanism
FortisTCI (12)
Government of the Turks and Caicos
Islands
N/A
15.00-17.50
15.00-17.50
COS regulation
Historical test year
(1) ROA for Caribbean Utilities and FortisTCI
(2) Reflects the allowed common equity and ROE for ITCTransmission, METC, and ITC Midwest. The ROE above is inclusive of the base ROE as well as incentive adders totalling 0.75%. FERC issued an
order in October 2024 retroactively revising the base ROE to certain prior periods including 2023. See "Significant Regulatory Matters" below
(3) Annual true-up collected or refunded in rates within a two-year period
(4) Allowed common equity of 54.3% and ROE of 9.55% effective September 1, 2023
(5) The allowed common equity component for FERC transmission rates is formulaic, and is updated annually based on TEP's actual equity ratio
(6) Allowed common equity of 53.7% and ROE of 9.75% effective February 1, 2024
(7) A general rate application requesting new customer rates is ongoing. See "Significant Regulatory Matters" below
(8) ROE of 9.5% effective July 1, 2024. A general rate application requesting new customer rates effective July 1, 2025 is ongoing. See "Significant Regulatory Matters" below
(9) In 2023, FortisAlberta was subject to a COS revenue requirement. The ROE for 2025 has been set at 8.97%
(10) Two of FortisOntario's utilities follow COS regulation with incentive mechanisms, while the remaining utility is subject to a 35-year franchise agreement expiring in 2033
(11) Operates under licences from the Government of the Cayman Islands. Its exclusive transmission and distribution licence is for an initial 20-year period, expiring in April 2028, with a provision for
automatic renewal. Its non-exclusive generation licence is for a 25-year term, expiring in November 2039
(12) Operates under 25 and 50 year licences from the Government of the Turks and Caicos Islands, which expire in 2036 and 2037, respectively
Notes to Consolidated Financial Statements
For the years ended December 31, 2024 and 2023
11
FORTIS INC.
DECEMBER 31, 2024
2. REGULATION (cont'd)
Significant Regulatory Matters
ITC
MISO Base ROE: In 2022, the U.S. Court of Appeals for the District of Columbia Circuit issued a decision vacating certain FERC orders that had established
the methodology for setting the base ROE for transmission owners operating in the Midcontinent Independent System Operator, Inc. ("MISO") region,
including ITC, and remanded the matter to FERC for further process. This matter dates back to complaints filed at FERC in 2013 and 2015 challenging the
MISO base ROE then in effect.
In October 2024, FERC issued an order that removed the use of the risk premium model from the calculation of the base ROE, while maintaining other
modifications to the methodology. The updated methodology revised the base ROE from 10.02% to 9.98%, with a maximum ROE inclusive of incentives
not to exceed 12.58%. The order also directed the payment of certain refunds, with interest, by December 2025, for the 15-month period from November
2013 through February 2015, and prospectively from September 2016. A regulatory liability of $39 million (US$27 million) associated with the refunds has
been recognized by ITC as of December 31, 2024.
Certain MISO transmission owners, including ITC, filed a request for rehearing with FERC in November 2024, and filed an appeal of the order with the D.C.
Circuit Court in January 2025. The requests for rehearing and appeal primarily focus on the refund period and the related interest. The timing and outcome
of these filings are unknown.
Transmission Incentives: In 2021, FERC issued a supplemental notice of proposed rulemaking ("NOPR") on transmission incentives modifying the proposal
in the initial NOPR released by FERC in 2020. The supplemental NOPR proposes to eliminate the 50-basis point regional transmission organization ("RTO")
ROE incentive adder for RTO members that have been members for longer than three years. The timing and outcome of this proceeding remain unknown.
Transmission Right of First Refusal ("ROFR"): In December 2023, the Iowa District Court ruled that the manner in which Iowa's ROFR statute was passed
was unconstitutional. The statute granted incumbent electric transmission owners, including ITC, a ROFR to construct, own and maintain certain electric
transmission assets in the state. The District Court did not make any determination on the merits of the ROFR itself, but did issue a permanent injunction
preventing ITC and others from taking further action to construct the MISO long-range transmission plan ("LRTP") tranche 1 Iowa projects in reliance on
the ROFR.
In May 2024, MISO commenced a variance analysis process as a result of the inability to construct a portion of the tranche 1 LRTP projects in Iowa due to
the injunction imposed by the District Court. In August 2024, MISO concluded the variance analysis, which reaffirmed the original allocation of projects to
ITC and other incumbent transmission owners. While the results of MISO's variance analysis process allow ITC to move forward with the development of its
portion of tranche 1 LRTP projects in Iowa, various legal proceedings with respect to this matter are ongoing for which the timing and outcome are
unknown.
UNS Energy
Generic Regulatory Lag Docket: In December 2024, the ACC approved a formula rate plan policy statement which allows utilities to propose formula rates
in future rate cases. A formula rate plan, if approved by the ACC, would adjust rates annually based on a predetermined formula. A formula rate plan is
expected to improve rate stability for customers, while also reducing regulatory lag and the number of existing rate adjusters.
UNS Gas General Rate Application: In November 2024, UNS Gas filed a general rate application with the ACC requesting an increase in gas delivery rates
effective February 1, 2026. The application includes a request to set its ROE at 10.25% and a 56% common equity component of capital structure. In
January 2025, UNS Gas filed supplemental material proposing an annual rate adjustment mechanism as a result of the ACC's formula rate policy statement
discussed above. The timing and outcome of this proceeding are unknown.
Central Hudson
2025 General Rate Application: In August 2024, Central Hudson filed a general rate application with the PSC requesting an increase in electric and gas
delivery rates effective July 1, 2025. The application includes a request to set Central Hudson's allowed ROE at 10% and a 48% common equity component
of capital structure. The timing and outcome of this proceeding are unknown.
Show Cause Order: In October 2024, the PSC issued a Show Cause Order which directed Central Hudson to explain why the PSC should not initiate an
enforcement proceeding in connection with a gas-related explosion that occurred in November 2023. Central Hudson filed its response in
November 2024. The timing and outcome of the Show Cause Order are unknown.
FortisBC Energy and FortisBC Electric
2025-2027 Rate Framework: In April 2024, FortisBC filed an application with the BCUC requesting approval of a rate framework for the period 2025
through 2027. The rate framework builds upon the current multi-year rate plan and includes, amongst other items, updates to depreciation and
capitalized overhead rates, a revised level of operation and maintenance expense per customer indexed for inflation less a fixed productivity adjustment
factor, a similar approach to growth capital, a forecast approach to sustaining and other capital, continued collection of an innovation fund recognizing
the need to accelerate investment in clean energy innovation, and the continued sharing with customers of variances from the allowed ROE. The rate
framework also proposes the continuation of deferral mechanisms currently in place. A decision from the BCUC is expected in mid-2025.
Notes to Consolidated Financial Statements
For the years ended December 31, 2024 and 2023
12
FORTIS INC.
DECEMBER 31, 2024
2. REGULATION (cont'd)
FortisAlberta
Generic Cost of Capital ("GCOC") Decision: In October 2023, the AUC issued a decision on the 2024 GCOC proceeding. In November 2023, FortisAlberta
sought permission to appeal the GCOC decision to the Court of Appeal of Alberta ("Court of Appeal") on the basis that the AUC erred in its decision to not
adjust FortisAlberta's ROE and common equity component of capital structure to address incremental business risk associated with competition from
Rural Electrification Associations ("REAs") located in FortisAlberta's service area, as well as heightened regulatory risk due to the non-recovery of costs
attributable to REAs. In April 2024, the Court of Appeal granted FortisAlberta permission to appeal, and a decision is expected in the first quarter of 2025.
Third PBR Term Decision: In October 2023, the AUC issued a decision establishing the parameters for the third PBR setting term for the period of 2024
through 2028. In November 2023, FortisAlberta sought permission to appeal the decision to the Court of Appeal on the basis that the AUC erred in its
decision to determine capital funding using 2018-2022 historical capital investments without consideration for funding of new capital programs included
in the company's 2023 cost of service revenue requirement as approved by the AUC. FortisAlberta's application for permission to appeal the decision was
heard by the Court of Appeal in December 2024 and a decision is expected in the first quarter of 2025.
3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation
These consolidated financial statements have been prepared and presented in accordance with accounting principles generally accepted in the United
States of America ("U.S. GAAP") for rate-regulated entities, and are in Canadian dollars unless otherwise indicated.
These consolidated financial statements include the accounts of the Corporation and its subsidiaries. They reflect the equity method of accounting for
entities in which Fortis has significant influence, but not control, and proportionate consolidation for assets that are jointly owned with non-affiliated
entities.
Cash and Cash Equivalents
Cash and cash equivalents include cash, cash held in margin accounts, and short-term deposits with initial maturities of three months or less from the date
of deposit.
Allowance for Credit Losses
Fortis and its subsidiaries recognize an allowance for credit losses to reduce accounts receivable for amounts estimated to be uncollectible. The allowance
for credit losses is estimated based on historical collection patterns, sales, and current and forecast economic and other conditions. Accounts receivable
are written off in the period in which they are deemed uncollectible.
Inventories
Inventories, consisting of materials and supplies, gas, fuel and coal in storage, are measured at the lower of weighted average cost and net realizable value.
Regulatory Assets and Liabilities
Regulatory assets and liabilities arise as a result of the utility rate-setting process and are subject to regulatory approval. Regulatory assets represent future
revenues and/or receivables associated with certain costs incurred that will be, or are expected to be, recovered from customers in future periods through
the rate-setting process. Regulatory liabilities represent: (i) future reductions or limitations of increases in revenue associated with amounts that will be, or
are expected to be, refunded to customers through the rate-setting process; or (ii) obligations to provide future service that customers have paid for in
advance.
Certain remaining recovery and settlement periods are those expected by management and the actual periods could differ based on regulatory approval.
Investments
Investments are reviewed annually for potential impairment in value. Impairments are recognized when identified.
Notes to Consolidated Financial Statements
For the years ended December 31, 2024 and 2023
13
FORTIS INC.
DECEMBER 31, 2024
3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (cont'd)
Property, Plant and Equipment
Property, plant and equipment ("PPE") are recognized at cost less accumulated depreciation. Contributions in aid of construction by customers and
governments are recognized as a reduction in the cost of, and are amortized in a manner consistent with, the related PPE.
Depreciation rates of the Corporation's regulated utilities include a provision for estimated future removal costs not identified as a legal obligation. The
provision is recognized as a long-term regulatory liability (Note 8) against which actual removal costs are netted when incurred.
The Corporation's regulated utilities derecognize PPE on disposal or when no future economic benefits are expected from their use. Upon derecognition,
any difference between cost and accumulated depreciation, net of salvage proceeds, is charged to accumulated depreciation. No gain or loss is
recognized.
Through methodologies established by their respective regulators, the Corporation's regulated utilities capitalize: (i) overhead costs that are not directly
attributable to specific PPE but relate to the overall capital expenditure plan; and (ii) an allowance for funds used during construction ("AFUDC"). The debt
component of AFUDC for 2024 totalled $74 million (2023 - $56 million) and is reported as a reduction of finance charges and the equity component is
reported as other income (Note 22). Both components are recorded to earnings through depreciation expense over the estimated service lives of the
applicable PPE.
Excluding UNS Energy and Central Hudson, PPE includes inventory held for the development, construction and betterment of other assets. As required by
its regulators, UNS Energy and Central Hudson recognize such items as inventory until used and reclassifies them to PPE once put into service.
Repairs and maintenance costs are charged to earnings in the period incurred. Replacements and betterments that extend the useful lives of PPE are
capitalized.
PPE is depreciated using the straight-line method based on the estimated service lives of the assets. Depreciation rates for regulated PPE are approved by
the respective regulators and ranged from 0.5% to 33.0% for 2024 (2023 - 0.5% to 35.0%). The weighted average composite rate of depreciation, before
reduction for amortization of contributions in aid of construction, was 2.7% for 2024 (2023 – 2.6%).
The service life ranges and weighted average remaining service life of PPE as at December 31 were as follows.
2024
2023
(years)
Service Life
Ranges
Weighted
Average
Remaining
Service Life
Service Life
Ranges
Weighted
Average
Remaining
Service Life
Distribution
Electric
5-80
32
5-80
31
Gas
18-83
37
18-95
38
Transmission
Electric
20-85
42
20-90
41
Gas
10-80
35
10-85
36
Generation
2-95
22
2-95
23
Other
3-80
13
3-80
10
Intangible Assets
Intangible assets are recorded at cost less accumulated amortization. Their useful lives are assessed to be either indefinite or finite.
Intangible assets with indefinite useful lives are not amortized and are tested for impairment annually, either individually or, where the particular entity
also has goodwill, at the reporting unit level in conjunction with goodwill impairment testing. An annual review is completed to determine whether the
indefinite life assessment continues to be supportable. If not, the resultant changes are made prospectively.
Intangible assets with finite lives are amortized using the straight-line method based on the estimated service lives of the assets. Amortization rates for
regulated intangible assets are approved by the respective regulators and ranged from 1.0% to 33.0% for 2024 (2023 – 1.0% to 33.0%).
Notes to Consolidated Financial Statements
For the years ended December 31, 2024 and 2023
14
FORTIS INC.
DECEMBER 31, 2024
3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (cont'd)
The service life ranges and weighted average remaining service life of finite-life intangible assets as at December 31 were as follows.
2024
2023
(years)
Service Life
Ranges
Weighted
Average
Remaining
Service Life
Service Life
Ranges
Weighted
Average
Remaining
Service Life
Computer software
3-18
5
3-18
5
Land, transmission and water rights
30-85
52
30-90
52
Other
10-100
16
10-100
14
The Corporation's regulated utilities derecognize intangible assets on disposal or when no future economic benefits are expected from their use. Upon
derecognition any difference between the cost and accumulated amortization of the asset, net of salvage proceeds, is charged to accumulated
amortization. No gain or loss is recognized.
Impairment of Long-Lived Assets
The Corporation reviews the valuation of PPE, intangible assets with finite lives, and other long-term assets when events or changes in circumstances
indicate that the total undiscounted cash flows expected to be generated by the asset may be below carrying value. If that is determined to be the case,
the asset is written down to estimated fair value and an impairment loss is recognized.
Goodwill
Goodwill represents the excess of the purchase price over the fair value of the identifiable net assets related to business acquisitions.
Goodwill at each of the Corporation's reporting units is tested for impairment annually and whenever an event or change in circumstances indicates that
fair value may be below carrying value. If so determined, goodwill is written down to estimated fair value and an impairment loss is recognized.
The Corporation performs a qualitative assessment on each reporting unit, and if it is determined that it is not likely that fair value is less than carrying
value, then a quantitative estimate of fair value is not required. When a quantitative assessment is performed, the primary method for estimating fair value
of the reporting units is the income approach, whereby net cash flow projections are discounted. Underlying estimates and assumptions, with varying
degrees of uncertainty, include the amount and timing of expected future cash flows, growth rates, and discount rates. A secondary valuation, the market
approach along with a reconciliation of the total estimated fair value of all the reporting units to the Corporation's market capitalization, is also performed
and evaluated.
Deferred Financing Costs
Issue costs, discounts and premiums are recognized against, and amortized over the life of, the related long-term debt.
Employee Future Benefits
Fortis and each subsidiary maintain one or a combination of defined benefit pension ("DBP") 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 DBP 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.
DBP 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 DBP 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.
Notes to Consolidated Financial Statements
For the years ended December 31, 2024 and 2023
15
FORTIS INC.
DECEMBER 31, 2024
3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (cont'd)
For most of the Corporation's regulated utilities, any difference between DBP or OPEB plan costs ordinarily recognized under U.S. GAAP and those
recovered from customers in current rates is subject to deferral account treatment and is expected to be recovered from, or refunded to, customers in
future rates. In addition, any unamortized balances related to net actuarial gains and losses, past service costs and transitional obligations associated with
DBP or OPEB plans, as applicable, which would otherwise be recognized in accumulated other comprehensive income, are subject to deferral account
treatment (Note 8).
Leases
A right-of-use asset and lease liability is recognized for leases with a lease term greater than 12 months. The right-of-use asset and liability are both
measured at the present value of future lease payments, excluding variable payments that are based on usage or performance. Future lease payments
include both lease components (e.g., rent, real estate taxes and insurance costs) and non-lease components (e.g., common area maintenance costs),
which Fortis accounts for as a single lease component. The present value is calculated using the rate implicit in the lease or a lease-specific secured
interest rate based on the remaining lease term. Renewal options are included in the lease term when it is reasonably certain that the option will be
exercised.
Finance leases are depreciated over the lease term, except where: (i) ownership of the asset is transferred at the end of the lease term, in which case
depreciation is over the estimated service life of the underlying asset; and (ii) the regulator has approved a different recovery methodology for rate-setting
purposes, in which case the timing of the expense recognition will conform to the regulator's requirements.
Revenue Recognition
Most revenue is derived from energy sales and the provision of transmission services to customers based on regulator-approved tariff rates. Most contracts
have a single performance obligation, being the delivery of energy or the provision of transmission services. No component of the transaction price is
allocated to unsatisfied performance obligations. Energy sales are generally measured in kilowatt hours, gigajoules or transmission load delivered. The
billing of energy sales is based on customer meter readings, which occur systematically throughout each month. The billing of transmission services at ITC
is based on peak monthly load.
FortisAlberta is a distribution company and is required by its regulator to arrange and pay for transmission services with the Alberta Electric System
Operator ("AESO"). This includes the collection of transmission revenue from its customers, which occurs through the transmission component of its
regulator-approved rates. FortisAlberta reports transmission revenue and expenses on a net basis.
Electricity, gas and transmission service revenue includes an estimate for unbilled energy consumed or service provided since the last meter reading that
has not been billed at the end of the reporting period. Sales estimates generally reflect an analysis of historical consumption in relation to key inputs, such
as current energy prices, population growth, economic activity, weather conditions and system losses. Unbilled revenue accruals are adjusted in the
periods actual consumption becomes known.
Generation revenue from non-regulated operations is recognized on delivery at contracted fixed or market rates.
Variable consideration is estimated at the most likely amount and reassessed at each reporting date until the amount is known. Variable consideration,
including amounts subject to a future regulatory decision, is recognized as a refund liability until entitlement is probable.
Revenue excludes sales and municipal taxes collected from customers.
The Corporation has elected not to assess or account for any significant financing components associated with revenue billed in accordance with equal
payment plans as the period between the transfer of energy to customers and the customers' payment is less than one year.
Stock-Based Compensation
Fortis recognizes liabilities associated with directors' deferred share units ("DSUs"), performance share units ("PSUs") and restricted share
units ("RSUs"). DSUs represent cash-settled awards whereas PSUs and RSUs represent cash or share-settled awards. 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 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 PSUs and RSUs is over the lesser of three years or the
period to retirement eligibility and for DSUs is at the time of grant. Forfeitures are accounted for as they occur.
Notes to Consolidated Financial Statements
For the years ended December 31, 2024 and 2023
16
FORTIS INC.
DECEMBER 31, 2024
3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (cont'd)
Foreign Currency Translation
Assets and liabilities of the Corporation's foreign operations, all of which have a U.S. dollar functional currency, are translated at the exchange rate in effect
at the balance sheet date and the resultant unrealized translation gains and losses are recognized in accumulated other comprehensive income.
The exchange rate as at December 31, 2024 was US$1.00=CA$1.44 (2023 – US$1.00=CA$1.32).
Revenue and expenses of the Corporation's foreign operations are translated at the average exchange rate for the reporting period, which was
US$1.00=CA$1.37 for 2024 (2023 - US$1.00=CA$1.35).
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 U.S. dollar cash inflows and forecast future
cash settlements of DSU, PSU and RSU obligations; and (ii) UNS Energy, to meet forecast load and reserve requirements. Aitken Creek, to its date of
disposition, utilized derivatives to manage commodity price risk, capture natural gas price spreads, and manage the financial risk of physical transactions
(Note 21). Derivatives are measured at fair value with changes thereto recognized in earnings.
Derivatives not designated as hedges are also used by UNS Energy, Central Hudson and FortisBC Energy to reduce energy price risk associated with
purchased power and gas requirements. The settled amounts of these derivatives are generally included in regulated rates, as permitted by the respective
regulators. These derivatives are measured at fair value with changes recognized as regulatory assets or liabilities for recovery from, or refund to, customers
in future rates (Note 8).
Derivatives that meet the normal purchase or normal sale scope exception are not measured at fair value and settled amounts are recognized in earnings
as energy supply costs.
Derivatives Designated as Hedges
Fortis, ITC and Central Hudson use cash flow hedges, from time to time, to manage interest rate risk. Unrealized gains and losses are initially recognized in
accumulated other comprehensive income and reclassified to earnings when the underlying hedged transaction affects earnings.
The Corporation's earnings from, and net investments in, foreign subsidiaries and certain equity-accounted investments are exposed to fluctuations in the
U.S. dollar-to-Canadian dollar exchange rate. The Corporation has hedged a portion of this exposure through U.S. dollar-denominated debt at the
corporate level. Exchange rate fluctuations associated with the translation of this debt and the foreign net investments are recognized in accumulated
other comprehensive income.
Presentation of Derivatives
The fair value of derivatives is recognized as current or long-term assets and liabilities depending on the timing of settlements and resulting cash flows.
Derivatives under master netting agreements and collateral positions are presented on a gross basis. Cash flows associated with the settlement of all
derivatives are presented in operating activities in the consolidated statements of cash flows.
Income Taxes
The Corporation and its taxable subsidiaries follow the asset and liability method of accounting for income taxes. Current income tax expense or recovery
is recognized for the estimated income taxes payable or receivable in the current year.
Deferred income tax assets and liabilities are recognized for temporary differences between the tax and accounting basis of assets and liabilities, as well as
for the benefit of losses available to be carried forward to future years for tax purposes that are "more likely than not" to be realized. They are measured
using enacted income tax rates and laws in effect when the temporary differences are expected to be recovered or settled. The effect of a change in
income tax rates on deferred income tax assets and liabilities is recognized in earnings in the period when the change occurs. Valuation allowances are
recognized when it is "more likely than not" that all of, or a portion of, a deferred income tax asset will not be realized.
Customer rates at ITC, UNS Energy, Central Hudson and Maritime Electric reflect current and deferred income tax. Customer rates at FortisAlberta reflect
current income tax. Customer rates at FortisBC Energy, FortisBC Electric, Newfoundland Power and FortisOntario reflect current income tax and, for certain
regulatory balances, deferred income tax. Caribbean Utilities, FortisTCI and Fortis Belize are not subject to income tax.
Differences between the income tax expense or recovery recognized under U.S. GAAP and reflected in current customer rates, which is expected to be
recovered from, or refunded to, customers in future rates, are recognized as regulatory assets or liabilities (Note 8).
Notes to Consolidated Financial Statements
For the years ended December 31, 2024 and 2023
17
FORTIS INC.
DECEMBER 31, 2024
3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (cont'd)
Income Taxes (cont'd)
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 $8.1 billion as at December 31, 2024 (2023 - $6.3 billion). If such earnings are repatriated, the
Corporation may be subject to income taxes and foreign withholding taxes. The determination of the amount of unrecognized deferred income tax
liabilities on such amounts is impractical.
Tax benefits associated with actual or expected income tax positions are recognized when the "more likely than not" recognition threshold is met. The tax
benefits are measured at the largest amount of benefit that is greater than 50% likely to be realized upon settlement.
Income tax interest and penalties are recognized as income tax expense when incurred.
Asset Retirement Obligations
The Corporation's subsidiaries have asset retirement obligations ("AROs") associated with certain generation, transmission, distribution and
interconnection assets, including land and environmental remediation and/or asset removal. These assets and related licences, permits, rights-of-way and
agreements are reasonably expected to effectively exist and operate in perpetuity due to their nature. Consequently, where the final date and cost of
remediation and/or removal of the noted assets cannot be reasonably determined, AROs have not been recognized.
Otherwise, AROs are recognized at fair value in the period incurred as an increase in PPE and long-term other liabilities (Note 16) if a reasonable estimate of
fair value can be determined. Fair value is estimated as the present value of expected future cash outlays, discounted at a credit-adjusted risk-free interest
rate. The increase in the liability due to the passage of time is recognized through accretion and the capitalized cost is depreciated over the useful life of
the asset. Accretion and depreciation expense are deferred as a regulatory asset or liability based on regulatory recovery of these costs. Actual settlement
costs are recognized as a reduction in the accrued liability.
Contingencies
Fortis and its subsidiaries are subject to various legal proceedings and claims that arise in the normal course of business. Management makes judgments
regarding the future outcome of contingent events and recognizes a loss based on its best estimate when it is determined that such loss, or range of loss,
is probable and can be reasonably estimated. Legal fees are expensed as incurred. When a loss is recoverable in future rates, a regulatory asset is also
recognized.
Management regularly reviews current information to determine whether recognized provisions should be adjusted and new provisions are required.
However, estimating probable losses requires considerable judgment about potential actions by third parties and matters are often resolved over long
periods of time. Actual outcomes may differ materially from the amounts recognized.
Use of Accounting Estimates
The preparation of these consolidated financial statements in accordance with U.S. GAAP requires management to make estimates and judgments,
including those arising from matters dependent upon the finalization of regulatory proceedings, that affect the reported amounts of assets, liabilities,
revenues, expenses, gains and losses. Management evaluates these estimates on an ongoing basis based upon historical experience, current conditions,
and assumptions believed to be reasonable at the time they are made, with any adjustments being recognized in the period they become known. Actual
results may differ significantly from these estimates.
New Accounting Policies
Segment Reporting: The Corporation adopted ASU No. 2023-07, Improvements to Reportable Segment Disclosures, for the year ended December 31, 2024
and will adopt it for interim periods beginning in 2025. This update requires disclosure of incremental segment information, including significant segment
expenses and other items that are included in segment profit or loss. This adoption of this standard did not materially impact Fortis' disclosures.
Future Accounting Pronouncements
The Corporation considers the applicability and impact of all Accounting Standards Updates ("ASUs") issued by the Financial Accounting Standards Board.
Any ASUs not included in these consolidated financial statements were assessed and determined to be either not applicable to the Corporation or are not
expected to have a material impact on the consolidated financial statements.
Income Taxes: ASU No. 2023-09, Improvements to Income Tax Disclosures, is effective for Fortis on January 1, 2025 on a prospective basis, with retrospective
application and early adoption permitted. The ASU requires additional disclosure of income tax information by jurisdiction to reflect an entity's exposure
to potential changes in tax legislation, and associated risks and opportunities. Fortis does not expect the ASU to materially impact its disclosures.
Expense Disaggregation: ASU No. 2024-03, Disaggregation of Income Statement Expenses, is effective for Fortis on January 1, 2027 for annual periods and on
January 1, 2028 for interim periods, on a prospective basis, with retrospective application and early adoption permitted. The ASU requires detailed
disclosure of certain expense categories included on the consolidated statements of earnings, including energy supply costs, operating expenses, and
depreciation and amortization expense. Fortis is assessing the impact on its disclosures.
Notes to Consolidated Financial Statements
For the years ended December 31, 2024 and 2023
18
FORTIS INC.
DECEMBER 31, 2024
4. SEGMENTED INFORMATION
Fortis' CEO is considered the chief operating decision maker ("CODM") for purposes of reviewing segment performance. Fortis segments its business
based on regulatory jurisdiction and service territory, as well as the information used by the CODM in deciding how to allocate resources. Segment
performance is evaluated principally on net earnings attributable to common equity shareholders, and this measure is used consistently in the evaluation
of actual segment performance as well as in the Corporation’s business plan and forecasting processes.
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 2024 or 2023.
As of December 31, 2024, accounts receivable included $18 million due from Belize Electricity (December 31, 2023 - $8 million).
Fortis periodically provides short-term financing to subsidiaries to support capital expenditures and seasonal working capital requirements, the impacts of
which are eliminated on consolidation. As at December 31, 2024 and 2023, there were no inter-segment loans outstanding. Interest charged on inter-
segment loans was not material in 2024 and 2023.
Regulated
Non-Regulated
Inter-
UNS
Central FortisBC
Fortis FortisBC
Other
Sub-
Corporate
segment
($ millions)
ITC
Energy
Hudson
Energy
Alberta
Electric
Electric
total
and Other eliminations
Total
Year ended December 31, 2024
Revenue
2,229
3,007
1,372
1,665
817
545
1,838 11,473
35
— 11,508
Energy supply costs
—
1,183
393
423
—
155
1,095 3,249
—
— 3,249
Operating expenses
530
798
659
418
195
141
250 2,991
49
— 3,040
Depreciation and amortization
448
404
134
337
291
88
218 1,920
7
— 1,927
Operating income
1,251
622
186
487
331
161
275 3,313
(21)
— 3,292
Other income, net
96
51
58
45
11
6
29
296
(8)
—
288
Finance charges
483
155
79
155
135
81
93 1,181
225
— 1,406
Income tax expense
200
70
37
83
26
14
23
453
(107)
—
346
Net earnings
664
448
128
294
181
72
188 1,975
(147)
— 1,828
Non-controlling interests
122
—
—
1
—
—
25
148
—
—
148
Preference share dividends
—
—
—
—
—
—
—
—
74
—
74
Net earnings attributable to
common equity shareholders
542
448
128
293
181
72
163 1,827
(221)
— 1,606
Additions to property, plant and
equipment and intangible assets
1,456
1,151
431
1,035
554
132
454 5,213
5
— 5,218
As at December 31, 2024
Goodwill
8,828
1,987
649
913
231
235
269 13,112
—
— 13,112
Total assets
27,202 14,690
6,278 10,156
6,181
2,807
5,810 73,124
374
(12) 73,486
Year ended December 31, 2023
Revenue
2,085
3,006
1,360
1,955
738
528
1,761 11,433
84
— 11,517
Energy supply costs
—
1,290
499
760
—
153
1,069
3,771
—
— 3,771
Operating expenses
494
776
601
408
180
127
231
2,817
72
— 2,889
Depreciation and amortization
416
361
113
309
265
96
204
1,764
9
— 1,773
Operating income
1,175
579
147
478
293
152
257
3,081
3
— 3,084
Other income, net
82
49
54
34
6
4
23
252
39
—
291
Finance charges
427
145
67
163
125
79
86
1,092
213
— 1,305
Income tax expense
208
83
29
74
12
9
26
441
(81)
—
360
Net earnings
622
400
105
275
162
68
168
1,800
(90)
— 1,710
Non-controlling interests
114
—
—
1
—
—
22
137
—
—
137
Preference share dividends
—
—
—
—
—
—
—
—
67
—
67
Net earnings attributable to
common equity shareholders
508
400
105
274
162
68
146
1,663
(157)
— 1,506
Additions to property, plant and
equipment and intangible assets
1,103
916
341
593
608
126
466
4,153
16
— 4,169
As at December 31, 2023
Goodwill
8,127
1,830
597
913
228
235
254 12,184
—
— 12,184
Total assets
24,269 12,784
5,371
9,225
5,962
2,715
5,227 65,553
401
(34) 65,920
Notes to Consolidated Financial Statements
For the years ended December 31, 2024 and 2023
19
FORTIS INC.
DECEMBER 31, 2024
5. REVENUE
The following table presents the disaggregation of the Corporation's revenue on the consolidated statements of earnings by geography and substantially
autonomous utility operations.
($ millions)
2024
2023
Electric and gas revenue
United States
ITC
2,205
2,098
UNS Energy
2,731
2,707
Central Hudson
1,366
1,329
Canada
FortisBC Energy
1,538
1,766
FortisAlberta
770
699
FortisBC Electric
481
460
Newfoundland Power
770
759
Maritime Electric
277
258
FortisOntario
235
217
Caribbean
Caribbean Utilities
402
388
FortisTCI
118
108
Total electric and gas revenue
10,893
10,789
Other services revenue
350
374
Revenue from contracts with customers
11,243
11,163
Alternative revenue
169
150
Other revenue
96
204
Total revenue
11,508
11,517
Revenue from Contracts with Customers
Electric and gas revenue includes revenue from the sale and/or delivery of electricity and gas, transmission revenue, and wholesale electric revenue, all
based on regulator-approved tariff rates including the flow through of commodity costs.
Other services revenue includes management fees at UNS Energy for the operation of Springerville Units 3 and 4 and revenue from other services that
reflect the ordinary business activities of Fortis' utilities. Other services revenue for 2023 also includes revenue from storage optimization activities at Aitken
Creek through the date of disposition (Note 21).
Alternative Revenue
Alternative revenue programs allow utilities to adjust future rates in response to past activities or completed events if certain criteria are met. Alternative
revenue is recognized on an accrual basis with a corresponding regulatory asset or liability until the revenue is settled. Upon settlement, revenue is not
recognized as revenue from contracts with customers but rather as settlement of the regulatory asset or liability. The significant alternative revenue
programs of Fortis' utilities are summarized as follows.
ITC's formula rates include an annual true-up mechanism that compares actual revenue requirements to billed revenue, and any under- or over-
collections are accrued as a regulatory asset or liability and reflected in future rates within a two year period (Note 8). The formula rates do not require
annual regulatory approvals, although inputs remain subject to legal challenge.
UNS Energy's lost fixed-cost recovery mechanism ("LFCR") surcharge recovers lost fixed costs, as measured by a reduction in non-fuel revenue, associated
with energy efficiency savings and distributed generation. To recover the LFCR regulatory asset, UNS Energy is required to file an annual LFCR adjustment
request with the ACC for the LFCR revenue recognized in the prior year. The recovery is subject to a year-over-year cap of 2% of total retail revenue.
FortisBC Energy and FortisBC Electric have an earnings sharing mechanism that provides for a 50/50 sharing of variances from the allowed ROE.
Additionally, variances between forecast and actual customer-use rates and industrial and other customer revenue are captured in a revenue stabilization
account and a flow-through deferral account, respectively, to be refunded to, or received from, customers in rates within two years.
Other Revenue
Other revenue primarily includes gains or losses on energy contract derivatives, as well as regulatory deferrals at FortisBC Energy and FortisBC Electric
including cost recovery variances from forecast.
Notes to Consolidated Financial Statements
For the years ended December 31, 2024 and 2023
20
FORTIS INC.
DECEMBER 31, 2024
6. ACCOUNTS RECEIVABLE AND OTHER CURRENT ASSETS
($ millions)
2024
2023
Trade accounts receivable
1,009
890
Unbilled accounts receivable
738
727
Allowance for credit losses
(78)
(68)
1,669
1,549
Income tax receivable
—
78
Other (1)
217
191
1,886
1,818
(1) Consists mainly of customer billings for non-core services, gas mitigation costs and collateral deposits for gas purchases, and the fair value of derivative instruments (Note 26)
Allowance for Credit Losses
The allowance for credit losses changed as follows.
($ millions)
2024
2023
Balance, beginning of year
(68)
(58)
Credit loss expensed
(30)
(33)
Credit loss deferral
(31)
(13)
Write-offs, net of recoveries
55
35
Foreign exchange
(4)
1
Balance, end of year
(78)
(68)
See Note 26 for disclosure on the Corporation's credit risk.
7. INVENTORIES
($ millions)
2024
2023
Materials and supplies
548
431
Gas and fuel in storage
65
96
Coal inventory
72
39
685
566
8. REGULATORY ASSETS AND LIABILITIES
($ millions)
2024
2023
Regulatory assets
Deferred income taxes (Note 3)
2,248
2,058
Deferred energy management costs (1)
591
521
Rate stabilization and related accounts (2)
453
521
Employee future benefits (Notes 3 and 24)
235
254
Derivatives (Notes 3 and 26)
175
197
Deferred lease costs (3)
142
137
Deferred restoration costs (4)
133
115
Manufactured gas plant site remediation deferral (Note 16)
82
81
Generation early retirement costs (5)
66
64
Renewable natural gas account (6)
58
47
Other regulatory assets (7)
448
389
Total regulatory assets
4,631
4,384
Less: Current portion
(823)
(866)
Long-term regulatory assets
3,808
3,518
Notes to Consolidated Financial Statements
For the years ended December 31, 2024 and 2023
21
FORTIS INC.
DECEMBER 31, 2024
8. REGULATORY ASSETS AND LIABILITIES (cont'd)
($ millions)
2024
2023
Regulatory liabilities
Future cost of removal (Note 3)
1,728
1,547
Deferred income taxes (Note 3)
1,329
1,280
Employee future benefits (Notes 3 and 24)
459
294
Rate stabilization and related accounts (2)
208
292
Renewable energy surcharge (8)
155
129
Energy efficiency liability (9)
88
78
Electric and gas moderator account (10)
61
50
AESO charges deferral (11)
58
121
Other regulatory liabilities (7)
205
167
Total regulatory liabilities
4,291
3,958
Less: Current portion
(595)
(577)
Long-term regulatory liabilities
3,696
3,381
(1) Deferred Energy Management Costs: Certain regulated subsidiaries provide energy management services to facilitate customer energy efficiency
programs where the related expenditures have been deferred as a regulatory asset and are being amortized, and recovered from customers through
rates, on a straight-line basis over periods ranging from one to 10 years.
(2) Rate Stabilization and Related Accounts: Rate stabilization accounts mitigate the earnings volatility otherwise caused by variability in the cost of fuel,
purchased power and natural gas above or below a forecast or predetermined level, and by weather-driven volume variability. At certain utilities,
revenue decoupling mechanisms minimize the earnings impact of reduced energy consumption as energy efficiency programs are implemented.
Resultant deferrals are recovered from, or refunded to, customers in future rates as approved by the respective regulators.
Related accounts include the annual true-up mechanism at ITC (Note 5).
(3) Deferred Lease Costs: Deferred lease costs at FortisBC Electric primarily relate to the Brilliant Power Purchase Agreement ("BPPA") (Note 15). The
depreciation of the asset under finance lease and interest expense on the finance lease obligation are not being fully recovered in current customer
rates since these rates only reflect the cash payments required under the BPPA. The annual differences are being deferred as a regulatory asset, which is
expected to be recovered from customers in future rates over the term of the lease, which expires in 2056.
(4) Deferred Restoration Costs: Incremental costs incurred at Central Hudson and Maritime Electric associated with restoration activities due to significant
weather events. Incremental costs incurred in excess of that collected in customer rates at Central Hudson are recovered through rate stabilization
accounts. The form and recovery period for Maritime Electric will be determined by the regulator.
(5) Generation Early Retirement Costs: Includes costs at TEP associated with the retirement of the Navajo Generating Station ("Navajo"), Sundt Generating
Facility Units 1 and 2, and the San Juan Generating Station ("San Juan"), as approved for recovery by its regulator.
(6) Renewable Natural Gas Account: Reflects the variance between costs incurred to procure consumable biomethane gas and the related revenue
recovered in customer rates. The difference is generally refunded or recovered from customers within one year.
(7) Other Regulatory Assets and Liabilities: Comprised of regulatory assets and liabilities individually less than $50 million.
(8) Renewable Energy Surcharge: Under the ACC's Renewable Energy Standard ("RES"), UNS Energy is required to increase its use of renewable energy each
year until it represents at least 15% of its total annual retail energy requirements by 2025. The cost of carrying out the plan is recovered from
retail customers through a RES surcharge. Any RES surcharge collections above or below the costs incurred to implement the plans are deferred as a
regulatory liability or asset.
The ACC measures RES compliance through Renewable Energy Credits ("RECs"). Each REC represents one kilowatt hour generated from renewable
resources. When UNS Energy purchases renewable energy, the premium paid above the market cost of conventional power equals the REC recoverable
through the RES surcharge. When RECs are purchased, UNS Energy records their cost as long-term other assets (Note 9) with a corresponding
regulatory liability to reflect the obligation to use the RECs for future RES compliance. When RECs are utilized for RES compliance, energy supply costs
and revenue are recognized in an equal amount.
(9) 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.
(10)Electric and Gas Moderator Account: As part of Central Hudson's general rate applications, certain regulatory assets and liabilities were offset and
included in the electric and gas moderator account, which will be used for future customer rate moderation.
(11)AESO Charges Deferral: Relates to differences in revenue collected and amounts incurred for transmission-related items at FortisAlberta that are
expected to be collected or refunded in customer rates.
Notes to Consolidated Financial Statements
For the years ended December 31, 2024 and 2023
22
FORTIS INC.
DECEMBER 31, 2024
8. REGULATORY ASSETS AND LIABILITIES (cont'd)
Regulatory assets not earning a return: (i) totalled $1,908 million and $1,995 million as at December 31, 2024 and 2023, respectively; (ii) are primarily related
to deferred income taxes and employee future benefits; and (iii) generally do not represent a past cash outlay as they are offset by related liabilities that,
likewise, do not incur a carrying cost for rate-making purposes. Recovery periods vary or are yet to be determined by the respective regulators.
9. OTHER ASSETS
($ millions)
2024
2023
Employee future benefits (Note 24)
551
355
Equity investments (1)
259
237
Other investments
225
180
RECs (Note 8)
176
155
Supplemental Executive Retirement Plan ("SERP")
127
117
Operating leases (Note 15)
64
51
Derivatives
48
43
Deferred compensation plan
29
22
Other
174
138
1,653
1,298
(1) Includes investments in Belize Electricity and Wataynikaneyap Power
ITC, UNS Energy and Central Hudson provide additional post-employment benefits through SERPs and deferred compensation plans for directors and
officers. The assets held to support these plans are reported separately from the related liabilities (Note 16). Most plan assets are held in trust and funded
mainly through life insurance policies and mutual funds. Assets in mutual and money market funds are recorded at fair value on a recurring basis
(Note 26).
10. PROPERTY, PLANT AND EQUIPMENT
($ millions)
Cost
Accumulated
Depreciation
Net Book
Value
2024
Distribution
Electric
15,771
(4,078)
11,693
Gas
7,148
(1,866)
5,282
Transmission
Electric
23,084
(4,865)
18,219
Gas
2,937
(894)
2,043
Generation
8,056
(3,110)
4,946
Other
5,014
(1,809)
3,205
Assets under construction
3,578
—
3,578
Land
490
—
490
66,078
(16,622)
49,456
2023
Distribution
Electric
14,352
(3,708)
10,644
Gas
6,682
(1,736)
4,946
Transmission
Electric
19,886
(4,267)
15,619
Gas
2,751
(843)
1,908
Generation
7,192
(2,739)
4,453
Other
4,444
(1,645)
2,799
Assets under construction
2,581
—
2,581
Land
435
—
435
58,323
(14,938)
43,385
Notes to Consolidated Financial Statements
For the years ended December 31, 2024 and 2023
23
FORTIS INC.
DECEMBER 31, 2024
10. PROPERTY, PLANT AND EQUIPMENT (cont'd)
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")). 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). These assets include transmission stations, telemetry, transmission pipe and other related equipment.
Generation assets are those used to generate electricity. These assets include hydroelectric and thermal generation stations, gas and combustion turbines,
coal-fired generating stations, dams, reservoirs, photovoltaic systems, wind resources and other related equipment.
Other assets include buildings, equipment, vehicles, inventory, and information technology assets.
As at December 31, 2024, assets under construction largely reflect ongoing transmission projects at ITC and UNS Energy, as well as the Roadrunner Reserve
battery storage projects at UNS Energy and the Eagle Mountain Pipeline project at FortisBC Energy.
The cost of PPE under finance lease as at December 31, 2024 was $324 million (2023 - $318 million) and related accumulated depreciation was
$119 million (2023 - $113 million) (Note 15).
Jointly Owned Facilities
UNS Energy and ITC hold undivided interests in jointly owned generating facilities and transmission systems, are entitled to their pro rata share of the PPE,
and are proportionately liable for the associated operating costs and liabilities. As at December 31, 2024, interests in jointly owned facilities consisted of
the following.
Ownership
Accumulated
Net Book
($ millions, except as indicated)
(%)
Cost
Depreciation
Value
Transmission Facilities
Various
1,704
(489)
1,215
Springerville Common Facilities
86.0
580
(344)
236
Springerville Coal Handling Facilities
83.0
299
(154)
145
Four Corners Units 4 and 5 ("Four Corners")
7.0
311
(155)
156
Gila River Common Facilities
50.0
131
(52)
79
Luna Energy Facility ("Luna")
33.3
101
3
104
3,126
(1,191)
1,935
11. INTANGIBLE ASSETS
Accumulated
Net Book
($ millions)
Cost
Amortization
Value
2024
Computer software
1,035
(493)
542
Land, transmission and water rights
1,188
(210)
978
Other
143
(95)
48
Assets under construction
93
—
93
2,459
(798)
1,661
2023
Computer software
1,040
(528)
512
Land, transmission and water rights
1,071
(182)
889
Other
132
(81)
51
Assets under construction
58
—
58
2,301
(791)
1,510
Included in the cost of land, transmission and water rights as at December 31, 2024 was $123 million (2023 - $113 million) not subject to amortization.
Amortization expense was $153 million for 2024 (2023 - $150 million). Amortization is estimated to average approximately $97 million for each of the next
five years.
Notes to Consolidated Financial Statements
For the years ended December 31, 2024 and 2023
24
FORTIS INC.
DECEMBER 31, 2024
12. GOODWILL
($ millions)
2024
2023
Balance, beginning of year
12,184
12,464
Disposition of Aitken Creek (Note 21)
—
(27)
Foreign currency translation impacts (1)
928
(253)
Balance, end of year
13,112
12,184
(1) Relates to the translation of goodwill associated with the acquisitions of ITC, UNS Energy, Central Hudson, Caribbean Utilities and FortisTCI, whose functional currency is the U.S. dollar
No goodwill impairment was recognized by the Corporation in 2024 or 2023.
13. ACCOUNTS PAYABLE AND OTHER CURRENT LIABILITIES
($ millions)
2024
2023
Trade accounts payable
1,121
990
Customer and other deposits
360
263
Dividends payable
314
295
Interest payable
305
274
Accrued taxes other than income taxes
304
268
Employee compensation and benefits payable
303
275
Gas and fuel cost payable
221
232
Derivatives (Note 26)
169
170
Income tax payable
33
—
Employee future benefits (Note 24)
29
28
Other
194
177
3,353
2,972
Notes to Consolidated Financial Statements
For the years ended December 31, 2024 and 2023
25
FORTIS INC.
DECEMBER 31, 2024
14. LONG-TERM DEBT
($ millions)
Maturity Date
2024
2023
ITC
Secured U.S. First Mortgage Bonds -
4.34% weighted average fixed rate (2023 - 4.22%)
2027-2055
3,944
3,268
Secured U.S. Senior Notes -
4.16% weighted average fixed rate (2023 - 4.00%)
2028-2055
1,511
1,278
Unsecured U.S. Senior Notes -
4.37% weighted average fixed rate (2023 - 4.16%)
2026-2043
5,610
5,165
Unsecured U.S. Shareholder Note -
6.00% fixed rate (2023 - 6.00%)
2028
286
263
UNS Energy
Unsecured U.S. Fixed Rate Notes -
4.09% weighted average fixed rate (2023 - 3.80%)
2026-2053
4,172
3,668
Central Hudson
Unsecured U.S. Promissory Notes - 4.38% weighted
average fixed and variable rate (2023 - 4.27%)
2025-2060
1,974
1,687
FortisBC Energy
Unsecured Debentures -
4.61% weighted average fixed rate (2023 - 4.61%)
2026-2052
3,295
3,295
FortisAlberta
Unsecured Debentures -
4.63% weighted average fixed rate (2023 - 4.52%)
2034-2054
2,835
2,685
FortisBC Electric
Unsecured Debentures -
4.72% weighted average fixed rate (2023 - 4.70%)
2035-2054
960
860
Other Electric
Secured First Mortgage Sinking Fund Bonds -
5.24% weighted average fixed rate (2023 - 5.24%)
2026-2060
739
748
Secured First Mortgage Bonds -
5.29% weighted average fixed rate (2023 - 5.29%)
2025-2061
320
320
Unsecured Senior Notes -
4.61% weighted average fixed rate (2023 - 4.45%)
2041-2054
207
152
Unsecured U.S. Senior Loan Notes and Bonds -
5.03% weighted average fixed and variable rate (2023 - 4.89%)
2025-2052
876
702
Corporate and Other
Unsecured U.S. Senior Notes and Promissory Notes -
3.79% weighted average fixed rate (2023 - 3.82%)
2026-2044
2,172
2,251
Unsecured Debentures -
6.51% fixed rate (2023 - 6.51%)
2039
200
200
Unsecured Senior Notes -
4.11% weighted average fixed rate (2023 - 4.10%)
2028-2033
2,000
1,500
Long-term classification of credit facility borrowings
2,216
1,572
Fair value adjustment - ITC acquisition
88
89
Total long-term debt (Note 26)
33,405
29,703
Less: Deferred financing costs and debt discounts
(191)
(172)
Less: Current installments of long-term debt
(1,990)
(2,296)
31,224
27,235
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.
Notes to Consolidated Financial Statements
For the years ended December 31, 2024 and 2023
26
FORTIS INC.
DECEMBER 31, 2024
14. LONG-TERM DEBT (cont'd)
The Corporation's unsecured debentures and senior notes are redeemable at the option of Fortis at the greater of par or a specified price together with
accrued and unpaid interest.
Certain long-term debt agreements have covenants that provide that the Corporation shall not declare, pay or make any restricted payments, including
special or extraordinary dividends, if immediately thereafter its consolidated debt to consolidated capitalization ratio would exceed 65%.
Significant Long-Term Debt Issuances in 2024
Month
Issued
Interest
Rate
(%)
Maturity
Amount
($ millions)
Use of
Proceeds
ITC
Secured senior notes
January
5.98
2034
US
85
(1) (2) (3)
First mortgage bonds
January
5.11
2029
US
75
(1) (2) (3)
First mortgage bonds
January
5.38
2034
US
75
(1) (2) (3)
Unsecured senior notes
May
5.65
2034
US
400
(3) (4)
First mortgage bonds
December
4.88
2035
US
125
(1) (2) (3)
First mortgage bonds
December
5.25
2043
US
125
(1) (2) (3)
UNS Energy
Unsecured senior notes
May
5.60
2036
US
30
(1) (3)
Unsecured senior notes
August
5.20
2034
US
400
(3) (4)
Central Hudson
Senior notes
April
5.59
2031
US
25
(1) (3)
Senior notes
April
5.69
2034
US
35
(1) (3)
Senior notes
October
4.88
2029
US
25
(3) (4)
Senior notes
October
5.30
2034
US
44
(3) (4)
Senior notes
October
5.40
2036
US
35
(3) (4)
FortisBC Electric
Unsecured debentures
August
4.92
2054
100
(1)
FortisAlberta
Unsecured debentures
May
4.90
2054
300
(1) (2) (3) (4)
Caribbean Utilities
Unsecured senior notes
May
6.17
2039
US
40
(1) (2) (3)
Unsecured senior notes
May
6.37
2049
US
40
(1) (2) (3)
FortisOntario
Unsecured senior notes
August
5.05
2054
55
(1)
Fortis
Unsecured senior notes
September
4.17
2031
500
(1) (3) (4)
(1) Repay short-term and/or credit facility borrowings
(2) Fund capital expenditures
(3) General corporate purposes
(4) Repay maturing long-term debt
Notes to Consolidated Financial Statements
For the years ended December 31, 2024 and 2023
27
FORTIS INC.
DECEMBER 31, 2024
14. 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.
($ millions)
Total
2025
1,990
2026
2,585
2027
2,541
2028
1,499
2029
1,024
Thereafter
23,766
33,405
In December 2024, Fortis filed a short-form base shelf prospectus with a 25-month life under which it may issue common or preference shares,
subscription receipts, or debt securities in an aggregate principal amount of up to $2.0 billion. Fortis also reestablished the at-the-market equity program
("ATM Program") pursuant to the short-form base shelf prospectus, which allows the Corporation to issue up to $500 million of common shares from
treasury to the public from time to time, at the Corporation's discretion, effective until January 10, 2027. As at December 31, 2024, $500 million remained
available under the ATM Program and $1.5 billion remained available under the short-form base shelf prospectus.
Credit Facilities
($ millions)
Regulated
Utilities
Corporate
and Other
2024
2023
Total credit facilities
4,396
1,946
6,342
6,176
Credit facilities utilized:
Short-term borrowings (1)
(98)
—
(98)
(119)
Long-term debt (including current portion) (2)
(1,335)
(881)
(2,216)
(1,572)
Letters of credit outstanding
(81)
(21)
(102)
(101)
Credit facilities unutilized
2,882
1,044
3,926
4,384
(1) The weighted average interest rate was approximately 6.1% (2023 - 6.9%).
(2) The weighted average interest rate was approximately 4.6% (2023 - 6.2%). The current portion was $1,860 million (2023 - $1,160 million).
Credit facilities are syndicated primarily with large banks in Canada and the U.S., with no one bank holding more than approximately 20% of the
Corporation's total revolving credit facilities. Approximately $5.8 billion of the total credit facilities are committed with maturities ranging from 2025
through 2029.
In April 2024, FortisBC Energy increased its operating credit facility from $700 million to $900 million and extended the maturity to July 2028. In May 2024,
FortisBC Electric increased its operating credit facility from $150 million to $200 million and extended the maturity to April 2028.
In May 2024, the Corporation extended the maturity on its unsecured US$500 million non-revolving term credit facility to May 2025. Half of the term credit
facility was repaid in the third quarter of 2024 and the remaining US$250 million has been fully utilized as at December 31, 2024. The facility is repayable at
any time without penalty. In June 2024, the Corporation amended its $1.3 billion revolving term committed credit facility to extend the maturity to July
2029.
In August 2024, Newfoundland Power increased its operating credit facility from $100 million to $130 million and extended the maturity to August 2029.
Notes to Consolidated Financial Statements
For the years ended December 31, 2024 and 2023
28
FORTIS INC.
DECEMBER 31, 2024
14. LONG-TERM DEBT (cont'd)
Consolidated credit facilities of approximately $6.3 billion as at December 31, 2024 are itemized below.
($ millions)
Amount
Maturity
Unsecured committed revolving credit facilities
Regulated utilities
ITC (1)
US
1,000
2028
UNS Energy
US
375
2027
Central Hudson
US
250
2029
FortisBC Energy
900
2028
FortisAlberta
250
2029
FortisBC Electric
200
2028
Other Electric
285
(2)
Other Electric
US
83
2025
Corporate and Other
1,350
(3)
Other facilities
Regulated utilities
Central Hudson - uncommitted credit facility
US
60
n/a
FortisBC Energy - uncommitted credit facility
55
2025
FortisBC Electric - unsecured demand overdraft facility
10
n/a
Other Electric - unsecured demand facilities
20
n/a
Other Electric - unsecured demand facility and emergency standby loan
US
93
2025
Corporate and Other
Unsecured non-revolving facility
US
250
2025
Unsecured revolving facility
US
150
2025
Unsecured non-revolving facility
21
n/a
(1) ITC also has a US$400 million commercial paper program, under which $nil was outstanding as at December 31, 2024 and 2023
(2) $90 million in 2027, $65 million in 2027, and $130 million in 2029
(3) $50 million in 2026 and $1.3 billion in 2029
15. LEASES
The Corporation and its subsidiaries lease office facilities, utility equipment, land, and communication tower space with remaining terms of up to 23 years,
with optional renewal terms. Certain lease agreements include rental payments adjusted periodically for inflation or require the payment of real estate
taxes, insurance, maintenance, or other operating expenses associated with the leased premises.
The Corporation's subsidiaries also have finance leases related to generating facilities with remaining terms of up to 31 years.
Leases were presented on the consolidated balance sheets as follows.
($ millions)
2024
2023
Operating leases
Other assets
64
51
Accounts payable and other current liabilities
(17)
(12)
Other liabilities
(47)
(39)
Finance leases (1)
Regulatory assets
142
137
PPE, net
205
205
Accounts payable and other current liabilities
(4)
(3)
Finance leases
(343)
(339)
(1) FortisBC Electric has a finance lease for the BPPA (Note 8), which relates to the sale of the output of the Brilliant hydroelectric plant, and for the Brilliant Terminal Station ("BTS"), which relates to the
use of the station. Both agreements expire in 2056. In exchange for the specified take-or-pay amounts of power, the BPPA requires semi-annual payments based on a return on capital, which
includes the original and ongoing capital cost, and related variable power purchase costs. The BTS requires semi-annual payments based on a charge related to the recovery of the capital cost of
the BTS, and related variable operating costs.
Notes to Consolidated Financial Statements
For the years ended December 31, 2024 and 2023
29
FORTIS INC.
DECEMBER 31, 2024
15. LEASES (cont'd)
The components of lease expense were as follows.
($ millions)
2024
2023
Operating lease cost
19
12
Finance lease cost:
Amortization
2
3
Interest
33
33
Variable lease cost
21
23
Total lease cost
75
71
As at December 31, 2024, the present value of minimum lease payments was as follows.
($ millions)
Operating
Leases
Finance
Leases
Total
2025
18
37
55
2026
15
37
52
2027
12
37
49
2028
6
37
43
2029
4
37
41
Thereafter
19
954
973
74
1,139
1,213
Less: Imputed interest
(10)
(792)
(802)
Total lease obligations
64
347
411
Less: Current installments
(17)
(4)
(21)
47
343
390
Supplemental lease information follows.
($ millions, except as indicated)
2024
2023
Weighted average remaining lease term (years)
Operating leases
7
7
Finance leases
31
32
Weighted average discount rate (%)
Operating leases
4.6
4.5
Finance leases
5.0
5.0
16. OTHER LIABILITIES
($ millions)
2024
2023
Employee future benefits (Note 24)
446
527
AROs (Note 3)
249
163
Customer and other deposits
128
168
Stock-based compensation plans (Note 20)
113
82
Manufactured gas plant site remediation (1)
101
94
Derivatives (Note 26)
66
48
Deferred compensation plan (Note 9)
63
54
Operating leases (Note 15)
47
39
Mine reclamation obligations (2)
40
30
Retail energy contract (3)
20
27
Other
41
38
1,314
1,270
Notes to Consolidated Financial Statements
For the years ended December 31, 2024 and 2023
30
FORTIS INC.
DECEMBER 31, 2024
16. OTHER LIABILITIES (Cont'd)
(1) Environmental regulations require Central Hudson to investigate sites at which it or its predecessors once owned and/or operated manufactured gas
plants and, if necessary, remediate those sites. Costs are accrued based on the amounts that can be reasonably estimated. Central Hudson has notified
its insurers that it intends to seek reimbursement where insurance coverage exists. Differences between actual costs and the associated rate allowances
are deferred as a regulatory asset for future recovery (Note 8).
(2) TEP pays ongoing reclamation costs related to two coal mines that supply generating facilities in which it has an ownership interest but does not
operate. Costs are deferred as a regulatory asset and recovered from customers as permitted by the regulator. TEP's share of the reclamation costs is
estimated to be $49 million. The present value of the estimated future liability in included in other liabilities.
(3) FortisAlberta has an agreement with a retail energy provider to act as its default retailer to eligible customers under the regulated retail option. As part
of this agreement FortisAlberta received an upfront payment which is being amortized to revenue over the eight year agreement.
17. EARNINGS PER COMMON SHARE
Diluted earnings per share ("EPS") was calculated using the treasury stock method for stock options.
2024
2023
Net Earnings
Weighted
Net Earnings
Weighted
to Common
Average
to Common
Average
Shareholders
Shares
EPS
Shareholders
Shares
EPS
($ millions)
(# millions)
($)
($ millions)
(# millions)
($)
Basic EPS
1,606
495.0
3.24
1,506
486.3
3.10
Potential dilutive effect of stock options (Note 20)
—
0.2
—
—
0.2
—
Diluted EPS
1,606
495.2
3.24
1,506
486.5
3.10
18. PREFERENCE SHARES
Authorized
An unlimited number of first preference shares and second preference shares, without nominal or par value.
Issued and Outstanding
2024
2023
First Preference Shares
Number
Number
of Shares
Amount
of Shares
Amount
(thousands)
($ millions)
(thousands)
($ millions)
Series F
5,000
122
5,000
122
Series G
9,200
225
9,200
225
Series H
7,665
188
7,665
188
Series I
2,335
57
2,335
57
Series J
8,000
196
8,000
196
Series K
10,000
244
10,000
244
Series M
24,000
591
24,000
591
66,200
1,623
66,200
1,623
Notes to Consolidated Financial Statements
For the years ended December 31, 2024 and 2023
31
FORTIS INC.
DECEMBER 31, 2024
18. PREFERENCE SHARES (Cont'd)
Characteristics of the first preference shares are as follows:
Reset
Right to
Dividend
Annual
Dividend
Redemption
Redemption
Convert on
Rate
Dividend
Yield
and/or Conversion
Value
a One-For-
First Preference Shares (1) (2)
(%)
($)
(%)
Option Date
($)
One Basis
Perpetual fixed rate
Series F
4.90
1.2250
—
Currently Redeemable
25.00
—
Series J
4.75
1.1875
—
Currently Redeemable
25.00
—
Fixed rate reset (3) (4)
Series G
6.12
1.5308
2.13
September 1, 2028
25.00
—
Series H
1.84
0.4588
1.45
June 1, 2025
25.00
Series I
Series K
5.47
1.3673
2.05
March 1, 2029
25.00
Series L
Series M
5.49
1.3733
2.48
December 1, 2029
25.00
Series N
Floating rate reset (4) (5)
Series I
(5)
—
1.45
June 1, 2025
25.00
Series H
Series L
—
—
—
—
—
Series K
Series N
—
—
—
—
—
Series M
(1) Holders are entitled to receive a fixed or floating cumulative quarterly cash dividend as and when declared by the Board of Directors of the Corporation, payable in equal installments on the first
day of each quarter.
(2) On or after the specified redemption dates, the Corporation has the option to redeem for cash the outstanding first preference shares, in whole or in part, at the specified per share redemption
value plus all accrued and unpaid dividends up to but excluding the dates fixed for redemption, and in the case of the first preference shares that reset, on every fifth anniversary date thereafter.
(3) On the redemption and/or conversion option date, and on each five-year anniversary thereafter, the reset annual dividend per share will be determined by multiplying $25.00 per share by the
annual fixed dividend rate, which is the sum of the five-year Government of Canada Bond Yield on the applicable reset date, plus the applicable reset dividend yield.
(4) On each conversion option date, the holders have the option, subject to certain conditions, to convert any or all of their shares into an equal number of Cumulative Redeemable first preference
shares of a specified series.
(5) The floating quarterly dividend rate will be reset every quarter based on the then current three-month Government of Canada Treasury Bill rate plus the applicable reset dividend yield.
On the liquidation, dissolution or winding-up of Fortis, holders of common shares are entitled to participate ratably in any distribution of assets of Fortis,
subject to the rights of holders of first and second preference shares, and any other class of shares of the Corporation entitled to receive the assets of the
Corporation on such a distribution, in priority to or ratably with the holders of the common shares.
Notes to Consolidated Financial Statements
For the years ended December 31, 2024 and 2023
32
FORTIS INC.
DECEMBER 31, 2024
19. ACCUMULATED OTHER COMPREHENSIVE INCOME
($ millions)
Opening
Balance
Net Change
Ending
Balance
2024
Unrealized foreign currency translation gains (losses)
Net investments in foreign operations
1,059
1,653
2,712
Hedges of net investments in foreign operations
(452)
(262)
(714)
Income tax recovery
4
14
18
611
1,405
2,016
Other
Interest rate hedges (Note 26)
62
10
72
Unrealized employee future benefits (losses) gains (Note 24)
(9)
2
(7)
Income tax expense
(11)
(3)
(14)
42
9
51
Accumulated other comprehensive income
653
1,414
2,067
2023
Unrealized foreign currency translation gains (losses)
Net investments in foreign operations
1,495
(436)
1,059
Hedges of net investments in foreign operations
(530)
78
(452)
Income tax recovery (expense)
7
(3)
4
972
(361)
611
Other
Interest rate hedges (Note 26)
49
13
62
Unrealized employee future benefits losses (Note 24)
(6)
(3)
(9)
Income tax expense
(7)
(4)
(11)
36
6
42
Accumulated other comprehensive income
1,008
(355)
653
20. STOCK-BASED COMPENSATION PLANS
Stock Options
Beginning January 1, 2022, the Corporation no longer grants stock options. Existing options to purchase common shares of the Corporation are
exercisable for a period of 10 years from the grant date, expire no later than three years after the death or retirement of the optionee, and vest evenly over
a four year period on each anniversary of the grant date. Compensation expense related to stock options was measured at the grant date using the Black-
Scholes fair value option-pricing model with each grant amortized to compensation expense 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.
As at December 31, 2024, the Corporation had 1.5 million stock options outstanding (2023 - 1.9 million) with a weighted average exercise price of $48.96
(2023 - $48.12). There were 1.4 million options vested as of December 31, 2024 (2023 – 1.6 million) with a weighted average exercise price of $48.87 (2023 -
$47.19).
In 2024, 0.4 million stock options were exercised (2023 - 0.3 million) for cash proceeds of $15 million (2023 - $13 million) and an intrinsic value realized by
option holders of $5 million (2023 - $6 million).
DSUs
Directors of the Corporation who are not officers are eligible for grants of DSUs representing the equity portion of their annual compensation. Directors
can also 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.
Beginning in 2024, in any year in which a director satisfies their share ownership target, the director may elect to receive a portion of their equity
compensation in cash or common shares, with the remaining portion to be granted as DSUs. Common share elections are satisfied quarterly through
purchases on the Toronto Stock Exchange or the New York Stock Exchange.
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.
Notes to Consolidated Financial Statements
For the years ended December 31, 2024 and 2023
33
FORTIS INC.
DECEMBER 31, 2024
20. STOCK-BASED COMPENSATION PLANS (cont'd)
DSUs (cont'd)
The following table summarizes information related to DSUs.
2024
2023
Number of units (thousands)
Beginning of year
241
224
Granted
29
40
Notional dividends reinvested
10
10
Paid out
(39)
(33)
End of year
241
241
The accrued liability has been recognized at the respective December 31st VWAP and included in other liabilities (Note 16). The accrued liability,
compensation expense and cash payout were not material for 2024 or 2023.
PSUs
Senior management of the Corporation and its subsidiaries, and all ITC employees, are eligible for grants of PSUs representing a component of their long-
term compensation.
Each PSU vests over a three year period, has an underlying value equivalent to that of one common share of the Corporation, and is entitled to
commensurate notional common share dividends. PSUs are generally settled in cash with cash payouts calculated at the end of the three year vesting
period as the product of: (i) the number of units vested; (ii) the VWAP of the Corporation's common shares for the five trading days prior to the vesting
date; and (iii) a payout percentage that may range from 0% to 200%. Effective with the 2024 grant, PSUs granted under the Corporation's Omnibus Equity
Plan can be settled in cash or common shares of the Corporation. PSUs settled through common shares will be satisfied by issuing common shares from
treasury.
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; (ii) the Corporation's cumulative EPS, or for subsidiaries the company's
cumulative net income, as compared to the target established at the time of the grant; and (iii) beginning with the 2022 PSU grant, the Corporation's
Scope 1 carbon reduction performance as compared to target established at the time of the grant. In addition, the 2023 PSU grant included a payout
modifier based on the achievement of diversity, equity and inclusion goals.
The following table summarizes information related to PSUs.
2024
2023
Number of units (thousands)
Beginning of year
1,942
1,790
Granted
788
722
Notional dividends reinvested
78
66
Paid out
(609)
(606)
Cancelled/forfeited
(28)
(30)
End of year
2,171
1,942
Additional information ($ millions)
Compensation expense recognized
53
45
Compensation expense unrecognized (1)
34
28
Cash payout
44
46
Accrued liability as at December 31 (2)
105
90
Aggregate intrinsic value as at December 31 (3)
139
118
(1) Relates to unvested PSUs and is expected to be recognized over a weighted average period of two years
(2) Recognized at the respective December 31st VWAP and included in accounts payable and other current liabilities and in other liabilities (Notes 13 and 16)
(3) Relates to outstanding PSUs and reflects a weighted average contractual life of one year
Notes to Consolidated Financial Statements
For the years ended December 31, 2024 and 2023
34
FORTIS INC.
DECEMBER 31, 2024
20. STOCK-BASED COMPENSATION PLANS (cont'd)
RSUs
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, has an underlying value equivalent to that of one common share of the Corporation, is entitled to commensurate
notional common share dividends, and is settled in cash or common shares of the Corporation. Beginning with the 2024 grant, RSUs settled through
common shares will be satisfied by issuing common shares from treasury.
The following table summarizes information related to RSUs.
2024
2023
Number of units (thousands)
Beginning of year
1,079
977
Granted
464
416
Notional dividends reinvested
38
35
Paid out
(357)
(323)
Cancelled/forfeited
(23)
(26)
End of year
1,201
1,079
Additional information ($ millions)
Compensation expense recognized
29
21
Compensation expense unrecognized (1)
21
17
Cash payout
19
17
Accrued liability as at December 31 (2)
54
42
Aggregate intrinsic value as at December 31 (3)
75
59
(1) Relates to unvested RSUs and is expected to be recognized over a weighted average period of two years
(2) Recognized at the respective December 31st VWAP and included in accounts payable and other current liabilities and in long-term other liabilities (Notes 13 and 16)
(3) Relates to outstanding RSUs and reflects a weighted average contractual life of one year
Share-settlements were not material for 2024 and 2023.
21. DISPOSITION
On November 1, 2023, FortisBC Holdings Inc. ("FHI") completed the sale of its Aitken Creek business to a subsidiary of Enbridge Inc. for approximately
$470 million including working capital and closing adjustments, following the satisfaction of all regulatory requirements. The transaction reflected a March
31, 2023 effective date. A gain on disposition of $23 million ($10 million after tax), net of transaction costs, was recognized in the Corporate and Other
segment.
For the seven-month period between the March 31, 2023 effective date and the November 1, 2023 disposition date, Aitken Creek recognized net earnings,
excluding the gain as noted above, of $5 million.
From January 1, 2023 through to the November 1, 2023 disposition date, excluding the gain, Aitken Creek recognized net earnings of $20 million.
Notes to Consolidated Financial Statements
For the years ended December 31, 2024 and 2023
35
FORTIS INC.
DECEMBER 31, 2024
22. OTHER INCOME, NET
($ millions)
2024
2023
Equity component of AFUDC
139
101
Non-service component of net periodic benefit cost
73
62
Interest income (1)
64
76
Equity income
14
14
Gain on disposal of Aitken Creek, pre-tax (Note 21)
—
23
Gain on derivatives, net
—
9
Net foreign exchange (loss) gain
(10)
4
Other
8
2
288
291
(1) Includes interest on short-term deposits, as well as interest on regulatory deferrals, including the PPFAC at TEP and UNS Electric
23. INCOME TAXES
Deferred Income Tax Assets and Liabilities
The significant components of deferred income tax assets and liabilities consisted of the following.
($ millions)
2024
2023
Gross deferred income tax assets
Regulatory liabilities
659
636
Tax loss and credit carryforwards
629
600
Employee future benefits
123
136
Other
216
144
1,627
1,516
Valuation allowance
(50)
(23)
Net deferred income tax asset
1,577
1,493
Gross deferred income tax liabilities
PPE
(5,993)
(5,355)
Regulatory assets
(432)
(372)
Intangible assets
(172)
(165)
(6,597)
(5,892)
Net deferred income tax liability
(5,020)
(4,399)
Income Tax Expense
($ millions)
2024
2023
Canadian
Earnings before income tax expense
518
526
Current income tax
154
71
Deferred income tax
(87)
17
Total Canadian
67
88
Foreign
Earnings before income tax expense
1,656
1,544
Current income tax
38
17
Deferred income tax
241
255
Total Foreign
279
272
Income tax expense
346
360
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.
Notes to Consolidated Financial Statements
For the years ended December 31, 2024 and 2023
36
FORTIS INC.
DECEMBER 31, 2024
23. INCOME TAXES (cont'd)
The following is a reconciliation of consolidated statutory taxes to consolidated effective taxes.
($ millions, except as indicated)
2024
2023
Earnings before income tax expense
2,174
2,070
Combined Canadian federal and provincial statutory income tax rate (%)
30.0
30.0
Expected federal and provincial taxes at statutory rate
652
621
(Decrease)/Increase resulting from:
Foreign and other statutory rate differentials
(169)
(166)
Effects of rate-regulated accounting
(97)
(98)
Tax credits
(36)
(14)
Enactment of new tax laws, change in tax rate
2
12
Other
(6)
5
Income tax expense
346
360
Effective tax rate (%)
15.9
17.4
Income Tax Carryforwards(1)
($ millions)
Expiring Year
2024
Canadian
Non-capital loss
2028-2044
155
Other tax credits and restricted interest and financing expenses(2)
2026-2044
77
232
Foreign
Federal and state net operating loss(3)
2029-2044
315
Other tax credits
2027-2044
82
397
Total income tax carryforwards recognized
629
(1) Income tax carryforwards presented on an after-tax basis
(2) Indefinite carryforward for restricted interest and financing expenses
(3) Indefinite carryforward for Federal net operating losses, and for states that have adopted the Federal provisions, effective for tax years beginning after December 31, 2017
The Corporation and certain of its subsidiaries are subject to taxation in Canada, the United States and other foreign jurisdictions. The material jurisdictions
in which the Corporation is subject to potential income tax compliance examinations include the United States (Federal, Arizona, Kansas, Iowa, Michigan,
Minnesota and New York) and Canada (Federal, British Columbia and Alberta). The Corporation's 2020 to 2024 taxation years are still open for audit in
Canadian jurisdictions, and its 2020 to 2024 taxation years are still open for audit in United States jurisdictions.
24. EMPLOYEE FUTURE BENEFITS
For DBP 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, 2021 for certain FortisBC Energy and FortisBC Electric plans; December 31, 2022 for
the remaining FortisBC Energy and FortisBC Electric plans, Newfoundland Power, FortisAlberta and FortisOntario; December 31, 2023 for the Corporation;
and December 31, 2024 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 DBP 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.
Notes to Consolidated Financial Statements
For the years ended December 31, 2024 and 2023
37
FORTIS INC.
DECEMBER 31, 2024
24. EMPLOYEE FUTURE BENEFITS (cont'd)
Allocation of Plan Assets
2024 Target
Allocation
(weighted average %)
2024
2023
Equities
46
47
46
Fixed income
46
45
45
Real estate
7
7
8
Cash and other
1
1
1
100
100
100
Fair Value of Plan Assets
($ millions)
Level 1 (1)
Level 2 (1)
Level 3 (1)
Total
2024
Equities
773
1,168
—
1,941
Fixed income
268
1,561
—
1,829
Real estate
—
—
300
300
Cash and other
23
26
—
49
1,064
2,755
300
4,119
2023
Equities
666
1,059
—
1,725
Fixed income
232
1,447
—
1,679
Real estate
—
—
291
291
Cash and other
34
14
—
48
932
2,520
291
3,743
(1) See Note 26 for a description of the fair value hierarchy.
The following table reconciles the changes in the fair value of plan assets that have been measured using Level 3 inputs.
($ millions)
2024
2023
Balance, beginning of year
291
282
Return on plan assets
5
(9)
Foreign currency translation
3
(1)
Purchases, sales and settlements
1
19
Balance, end of year
300
291
Notes to Consolidated Financial Statements
For the years ended December 31, 2024 and 2023
38
FORTIS INC.
DECEMBER 31, 2024
24. EMPLOYEE FUTURE BENEFITS (cont'd)
Funded Status
DBP Plans
OPEB Plans
($ millions)
2024
2023
2024
2023
Change in benefit obligation (1)
Balance, beginning of year
3,347
3,063
596
582
Service costs
74
62
25
22
Employee contributions
17
17
4
3
Interest costs
161
159
29
30
Benefits paid
(181)
(169)
(35)
(31)
Actuarial (gains) losses
(115)
255
(49)
(1)
Past service credits/plan amendments
(3)
—
—
—
Foreign currency translation
140
(40)
33
(9)
Balance, end of year (2)
3,440
3,347
603
596
Change in value of plan assets
Balance, beginning of year
3,313
3,079
430
389
Actual return on plan assets
249
373
50
61
Benefits paid
(174)
(162)
(31)
(26)
Employee contributions
17
17
4
3
Employer contributions
57
46
14
13
Foreign currency translation
151
(40)
39
(10)
Balance, end of year
3,613
3,313
506
430
Funded status
173
(34)
(97)
(166)
Balance sheet presentation
Other assets (Note 9)
395
236
156
119
Other current liabilities (Note 13)
(16)
(15)
(13)
(13)
Other liabilities (Note 16)
(206)
(255)
(240)
(272)
173
(34)
(97)
(166)
(1) Amounts reflect projected benefit obligation for DBP plans and accumulated benefit obligation for OPEB plans.
(2) The accumulated benefit obligation, which excludes assumptions about future salary levels, for DBP plans was $3,144 million as at December 31, 2024 (2023 - $2,983 million).
For those DBP plans for which the projected benefit obligation exceeded the fair value of plan assets as at December 31, 2024, the obligation was
$1,668 million compared to plan assets of $1,460 million (2023 - $1,940 million and $1,681 million, respectively).
For those DBP plans for which the accumulated benefit obligation exceeded the fair value of plan assets as at December 31, 2024, the obligation was
$195 million compared to plan assets of $62 million (2023 - $268 million and $130 million, respectively).
For those OPEB plans for which the accumulated benefit obligation exceeded the fair value of plan assets as at December 31, 2024, the obligation was
$296 million compared to plan assets of $44 million (2023 - $320 million and $36 million, respectively).
Net Benefit Cost (1)
DBP Plans
OPEB Plans
($ millions)
2024
2023
2024
2023
Service costs
74
62
25
22
Interest costs
161
159
29
30
Expected return on plan assets
(221)
(202)
(26)
(22)
Amortization of actuarial gains
(1)
(9)
(17)
(19)
Amortization of past service credits/plan amendments
(1)
(1)
(1)
(1)
Regulatory adjustments
(1)
12
2
5
11
21
12
15
(1) The non-service benefit cost components of net periodic benefit cost are included in other income, net in the consolidated statements of earnings.
Notes to Consolidated Financial Statements
For the years ended December 31, 2024 and 2023
39
FORTIS INC.
DECEMBER 31, 2024
24. EMPLOYEE FUTURE BENEFITS (cont'd)
The following table summarizes the accumulated amounts of net benefit cost that have not yet been recognized in earnings or comprehensive income
and shows their classification on the consolidated balance sheets.
DBP Plans
OPEB Plans
($ millions)
2024
2023
2024
2023
Unamortized net actuarial losses (gains)
11
12
(11)
(10)
Unamortized past service costs
1
1
6
6
Income tax (recovery) expense
(3)
(3)
1
1
Accumulated other comprehensive income
9
10
(4)
(3)
Net actuarial losses (gains)
46
189
(283)
(215)
Past service credits
(1)
(2)
(2)
(3)
Other regulatory deferrals
12
(11)
4
2
57
176
(281)
(216)
Regulatory assets (Note 8)
235
254
—
—
Regulatory liabilities (Note 8)
(178)
(78)
(281)
(216)
Net regulatory assets (liabilities)
57
176
(281)
(216)
The following table summarizes the components of net benefit cost recognized in comprehensive income or as regulatory (liabilities) assets.
DBP Plans
OPEB Plans
($ millions)
2024
2023
2024
2023
Current year net actuarial (gains) losses
(1)
4
(1)
1
Past service credits/plan amendments
—
—
—
(1)
Foreign currency translation
—
(1)
—
—
Income tax recovery
—
(1)
—
—
Total recognized in comprehensive income
(1)
2
(1)
—
Current year net actuarial (gains) losses
(142)
78
(72)
(40)
Amortization of actuarial gains
1
9
16
18
Amortization of past service credits
1
2
1
1
Foreign currency translation
(2)
(1)
(12)
2
Regulatory adjustments
23
(5)
2
(5)
Total recognized in regulatory (liabilities) assets
(119)
83
(65)
(24)
Significant Assumptions
DBP Plans
OPEB Plans
(weighted average %)
2024
2023
2024
2023
Discount rate as at December 31 (1)
5.25
4.84
5.43
4.94
Expected long-term rate of return on plan assets (2)
6.51
6.58
6.05
5.92
Rate of compensation increase
3.52
3.37
—
—
Health care cost trend increase as at December 31 (3)
—
—
4.53
4.52
(1) The discount rate used during the year was 4.84% for DBP plans (2023 - 5.36%) and 4.96% for OPEB plans (2023 - 5.39%). ITC and UNS Energy use the split discount rate methodology for
determining current service and interest costs. All other subsidiaries use the single discount rate approach.
(2) Developed by management using best estimates of expected returns, volatilities and correlations for each class of asset. Best estimates are based on historical performance, future expectations
and periodic portfolio rebalancing among the diversified asset classes.
(3) The projected 2025 health care cost trend rate is 6.51% and is assumed to decrease over the next 10 years to the ultimate health care cost trend rate of 4.53% in 2034 and thereafter.
Notes to Consolidated Financial Statements
For the years ended December 31, 2024 and 2023
40
FORTIS INC.
DECEMBER 31, 2024
24. EMPLOYEE FUTURE BENEFITS (cont'd)
Expected Benefit Payments
($ millions)
DBP Plans
OPEB Plans
2025
$
196
$
33
2026
201
34
2027
206
34
2028
210
35
2029
218
36
2030-2034
1,155
203
During 2025, the Corporation expects to contribute $49 million for DBP plans and $12 million for OPEB plans.
In 2024, the Corporation expensed $58 million (2023 - $53 million) related to defined contribution pension plans.
25. SUPPLEMENTARY CASH FLOW INFORMATION
($ millions)
2024
2023
Years ended December 31
Cash paid (received) for
Interest
1,361
1,255
Income taxes
(17)
129
Change in working capital
Accounts receivable and other current assets
(2)
142
Prepaid expenses
(21)
(7)
Inventories
(73)
(1)
Regulatory assets - current portion
93
104
Accounts payable and other current liabilities
115
(390)
Regulatory liabilities - current portion
56
71
168
(81)
Non-cash financing activity
Common share dividends reinvested
434
408
As at December 31
Non-cash investing and financing activities
Accrued capital expenditures
722
516
Contributions in aid of construction
14
15
26. 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.
Derivatives are recorded at fair value, with certain exceptions, including those derivatives that qualify for the normal purchase and normal sale exception.
Fair values reflect estimates based on current market information about the derivatives as at the balance sheet dates. The estimates cannot be determined
with precision as they involve uncertainties and matters of judgment and, therefore, may not be relevant in predicting the Corporation's future
consolidated earnings or cash flow.
Notes to Consolidated Financial Statements
For the years ended December 31, 2024 and 2023
41
FORTIS INC.
DECEMBER 31, 2024
26. FAIR VALUE OF FINANCIAL INSTRUMENTS AND RISK MANAGEMENT (cont'd)
Energy Contracts Subject to Regulatory Deferral
UNS Energy holds electricity power purchase contracts, customer supply contracts and gas swap contracts to reduce its exposure to energy price risk. Fair
values are measured primarily under the market approach using independent third-party information, where possible. When published prices are not
available, adjustments are applied based on historical price curve relationships, transmission costs and line losses.
Central Hudson holds swap contracts for electricity and natural gas to minimize price volatility by fixing the effective purchase price. Fair values are
measured using forward pricing provided by independent third-party information.
FortisBC Energy holds gas supply contracts to fix the effective purchase price of natural gas. Fair values reflect the present value of future cash flows based
on published market prices and forward natural gas curves.
Unrealized gains or losses associated with changes in the fair value of these energy contracts are deferred as a regulatory asset or liability for recovery from,
or refund to, customers in future rates, as permitted by the regulators. As at December 31, 2024, unrealized losses of $175 million (2023 - $197 million)
were recognized as regulatory assets and unrealized gains of $41 million (2023 - $37 million) were recognized as regulatory liabilities.
Energy Contracts Not Subject to Regulatory Deferral
UNS Energy holds wholesale trading contracts to fix power prices and realize potential margin, of which 10% of any realized gains is shared with
customers through rate stabilization accounts. Fair values are measured using a market approach incorporating, where possible, independent third-party
information.
Aitken Creek, which was sold on November 1, 2023 (Note 21), held gas swap contracts to manage exposure to changes in natural gas prices, capture
natural gas price spreads, and manage the financial risk posed by physical transactions. Fair values were measured using forward pricing from published
market sources.
Gains or losses associated with changes in the fair value of these energy contracts are recognized in revenue. In 2024, gains of $48 million (2023 - losses of
$28 million) were recognized in revenue.
Total Return Swaps
The Corporation holds total return swaps to manage the cash flow risk associated with forecast future cash and/or share settlements of certain stock-
based compensation obligations. The swaps have a combined notional amount of $134 million and terms up to three years expiring at varying dates
through January 2027. Fair value is measured using an income valuation approach based on forward pricing curves. Unrealized gains and losses associated
with changes in fair value are recognized in other income, net. In 2024, unrealized gains of $12 million (2023 - $nil) were recognized in other income, net.
Foreign Exchange Contracts
The Corporation holds U.S. dollar-denominated foreign exchange contracts to help mitigate exposure to foreign exchange rate volatility. The contracts
expire at varying dates through September 2026 and have a combined notional amount of $608 million. Fair value was measured using independent
third-party information. Unrealized gains and losses associated with changes in fair value are recognized in other income, net. In 2024, unrealized losses of
$17 million (2023 - unrealized gains of $10 million) were recognized in other income, net.
Interest Rate Contracts
During 2024, ITC entered into and settled interest rate locks with a combined notional value of US$300 million. These contracts were used to manage
interest rate risk associated with the issuance of US$400 million unsecured senior notes in May 2024. Realized losses of US$3 million were recognized in
other comprehensive income, which will be reclassified to earnings as a component of interest expense over five years.
ITC also entered into 5-year interest rate swap contracts in 2024 with a combined notional value of US$135 million. The swaps will be used to manage
interest rate risk associated with forecasted debt issuances. Fair value was measured using a discounted cash flow method based on secured overnight
financing rates ("SOFR"). Unrealized gains and losses associated with the changes in fair value are recognized in other comprehensive income, and will be
reclassified to earnings as a component of interest expense over the life of the debt. Unrealized gains of US$4 million were recorded in 2024.
In 2025, ITC entered into 5-year interest rate swap contracts with a notional value of US$95 million to manage interest rate risk associated with forecasted
debt issuances, increasing the total notional amount of interest rate swaps outstanding to US$230 million.
During 2024, the Corporation entered into and settled interest rate locks with a combined notional value of $250 million. These contract were used to
manage interest rate risk associated with the issuance of $500 million unsecured senior notes in September 2024. Realized losses of $2 million were
recognized in other comprehensive income, which will be reclassified to earnings as a component of interest expense over seven years.
Cross-Currency Interest Rate Swaps
The Corporation holds cross-currency interest rate swaps, maturing in 2029, to effectively convert its $500 million, 4.43% unsecured senior notes to
US$391 million, 4.34% debt. The Corporation has designated this notional U.S. debt as an effective hedge of its foreign net investments and unrealized
gains and losses associated with exchange rate fluctuations on the notional U.S. debt are recognized in other comprehensive income, consistent with the
translation adjustment related to the foreign net investments. Other changes in the fair value of the swaps are also recognized in other comprehensive
income but are excluded from the assessment of hedge effectiveness. Fair value is measured using a discounted cash flow method based on SOFR. In
2024, unrealized losses of $29 million (2023 - unrealized gains of $15 million) were recorded in other comprehensive income.
Notes to Consolidated Financial Statements
For the years ended December 31, 2024 and 2023
42
FORTIS INC.
DECEMBER 31, 2024
26. FAIR VALUE OF FINANCIAL INSTRUMENTS AND RISK MANAGEMENT (cont'd)
Recurring Fair Value Measures
The following table presents derivative assets and liabilities that are accounted for at fair value on a recurring basis.
($ millions)
Level 1 (1)
Level 2 (1)
Level 3 (1)
Total
As at December 31, 2024
Assets
Energy contracts subject to regulatory deferral (2) (3)
—
63
—
63
Energy contracts not subject to regulatory deferral (2)
—
7
—
7
Total return swaps and interest rate contracts (2)
—
16
—
16
Other investments (4)
150
—
—
150
150
86
—
236
Liabilities
Energy contracts subject to regulatory deferral (3) (5)
—
(197)
—
(197)
Energy contracts not subject to regulatory deferral (5)
—
(2)
—
(2)
Foreign exchange contracts and cross-currency interest rate swaps (5)
—
(45)
—
(45)
—
(244)
—
(244)
As at December 31, 2023
Assets
Energy contracts subject to regulatory deferral (2) (3)
—
49
—
49
Energy contracts not subject to regulatory deferral (2)
—
6
—
6
Foreign exchange contracts (2)
—
5
—
5
Other investments (4)
145
—
—
145
145
60
—
205
Liabilities
Energy contracts subject to regulatory deferral (3) (5)
—
(209)
—
(209)
Energy contracts not subject to regulatory deferral (5)
—
(3)
—
(3)
Total return and cross-currency interest rate swaps (5)
—
(6)
—
(6)
—
(218)
—
(218)
(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) UNS Energy holds investments in money market accounts, and ITC and Central Hudson hold investments in trust associated with supplemental retirement benefit plans for select employees,
which include mutual funds and money market accounts. The fair value of these investments is included in cash and cash equivalents and other assets, with gains and losses recognized in other
income, net
(5) Included in accounts payable and other current liabilities or other liabilities
Energy Contracts
The Corporation has elected gross presentation for its derivative contracts under master netting agreements and collateral positions, which apply only to
its energy contracts. The following table presents the potential offset of counterparty netting.
($ millions)
Gross Amount
Recognized In
Balance Sheet
Counterparty
Netting of
Energy Contracts
Cash Collateral
Posted/(Received)
Net Amount
As at December 31, 2024
Derivative assets
70
(30)
15
55
Derivative liabilities
(199)
30
—
(169)
As at December 31, 2023
Derivative assets
55
(24)
28
59
Derivative liabilities
(212)
24
(1)
(189)
Notes to Consolidated Financial Statements
For the years ended December 31, 2024 and 2023
43
FORTIS INC.
DECEMBER 31, 2024
26. FAIR VALUE OF FINANCIAL INSTRUMENTS AND RISK MANAGEMENT (cont'd)
Volume of Derivative Activity
As at December 31, 2024, 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.
2024
2023
Energy contracts subject to regulatory deferral (1)
Electricity swap contracts (GWh)
774
628
Electricity power purchase contracts (GWh)
430
588
Gas swap contracts (PJ)
236
228
Gas supply contracts (PJ)
105
134
Energy contracts not subject to regulatory deferral (1)
Wholesale trading contracts (GWh)
1,499
1,310
Gas swap contracts (PJ)
3
3
(1) GWh means gigawatt hours and PJ means petajoules
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. These customers have investment-grade credit
ratings and credit risk is further managed by MISO by requiring a letter of credit or cash deposit equal to the credit exposure, which is determined by a
credit-scoring model and other factors.
FortisAlberta has a concentration of credit risk as its distribution service billings are to a relatively small group of retailers. Credit risk is managed by
obtaining from the retailers either a cash deposit, letter of credit, an investment-grade credit rating, or a financial guarantee from an entity with an
investment-grade credit rating.
Central Hudson has seen an increase in accounts receivable since the suspension of collection efforts initially required in response to the COVID-19
pandemic. Central Hudson continues to contact customers regarding past-due balances and collection efforts continue to expand. Under its regulatory
framework, Central Hudson can defer uncollectible write-offs above the amounts collected in customer rates for future recovery.
UNS Energy, Central Hudson, FortisBC Energy, and Fortis may be exposed to credit risk from non-performance by counterparties to derivative contracts.
Credit risk is managed by net settling payments, when possible, and dealing only with counterparties that have investment-grade credit ratings. At UNS
Energy, Central Hudson and FortisBC Energy, certain contractual arrangements require counterparties to post collateral.
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 $117 million as at December 31, 2024 (2023 - $117 million).
Hedge of Foreign Net Investments
The reporting currency of ITC, UNS Energy, Central Hudson, Caribbean Utilities, FortisTCI, Fortis Belize Limited and Belize Electricity is, or is pegged to, the
U.S. dollar. The earnings and cash flow from, and net investments in, these entities are exposed to fluctuations in the U.S. dollar-to-Canadian dollar
exchange rate. The Corporation has reduced this exposure through hedging.
As at December 31, 2024, US$2.2 billion (2023 - US$2.6 billion) of corporately issued U.S. dollar-denominated long-term debt has been designated as an
effective hedge of net investments, leaving approximately US$12.6 billion (2023 - US$11.5 billion) unhedged. Exchange rate fluctuations associated with
the hedged net investment in foreign subsidiaries and the debt serving as the hedge are recognized in accumulated other comprehensive income.
Financial Instruments Not Carried at Fair Value
Excluding long-term debt, the consolidated carrying value of the Corporation's remaining financial instruments approximates fair value, reflecting their
short-term maturity, normal trade credit terms and/or nature.
As at December 31, 2024, the carrying value of long-term debt, including the current portion, was $33.4 billion (2023 - $29.7 billion) compared to an
estimated fair value of $31.3 billion (2023 - $27.9 billion).
Notes to Consolidated Financial Statements
For the years ended December 31, 2024 and 2023
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FORTIS INC.
DECEMBER 31, 2024
27. COMMITMENTS AND CONTINGENCIES
As at December 31, 2024, unconditional minimum purchase obligations were as follows.
($ millions)
Total
Year 1
Year 2
Year 3
Year 4
Year 5
Thereafter
Gas and fuel purchase obligations (1)
6,299
763
571
520
465
393
3,587
Renewable PPAs (2)
2,628
139
166
182
182
173
1,786
Waneta Expansion capacity agreement (3)
2,362
56
58
59
60
61
2,068
Power purchase obligations (4)
1,335
302
217
131
124
122
439
ITC easement agreement (5)
370
14
14
14
14
14
300
TEP EPC agreements (6)
308
307
1
—
—
—
—
Debt collection agreement (7)
99
3
3
3
3
3
84
Renewable energy credit purchase agreements (8)
58
18
7
6
6
6
15
Other (9)
140
32
11
11
12
10
64
13,599
1,634
1,048
926
866
782
8,343
(1) FortisBC Energy ($5,014 million): includes contracts of $2,792 million for the purchase of renewable natural gas expiring in 2045 and contracts of
$2,222 million for the purchase of gas, renewable gas, gas transportation and storage services, expiring in 2062. FortisBC Energy's gas purchase
obligations are based on gas commodity indices that vary with market prices and the obligations are based on index prices as at December 31, 2024.
The renewable gas supply obligations disclosed reflect the contracted price per gigajoule between the Corporation and the suppliers.
UNS Energy ($1,160 million): includes long-term contracts for the purchase and delivery of coal to fuel generating facilities, the purchase of gas
transportation services to meet load requirements, the purchase of transmission services for purchased power, as well as natural gas commodity
agreements based on projected market prices as of December 31, 2024. Amounts paid for coal depend on actual quantities purchased and delivered.
Certain contracts have price adjustment clauses that will affect future costs. These contracts have various expiry dates through 2048.
(2) TEP and UNS Electric are party to renewable PPAs, with expiry dates from 2027 through 2051, that require TEP and UNS Electric to purchase 100% of the
output of certain renewable energy generating facilities and RECs associated with the output delivered once commercial operation is achieved. The
agreements include purchase commitments that are contingent upon the developers obtaining commercial operation of the generating facilities,
which are expected to be placed in service in 2026 and 2027. Amounts are the estimated future payments.
(3) FortisBC Electric is a party to an agreement to purchase capacity from the Waneta Expansion hydroelectric generating facility for forty-years, beginning
April 2015.
(4) Maritime Electric ($563 million): includes an energy purchase agreement and transmission capacity contract for 30 MW of capacity to PEI with New
Brunswick Power, expiring December 2026 and November 2032, respectively. The agreements entitle Maritime Electric to approximately 4.55% of the
output of New Brunswick Power's Point Lepreau nuclear generating station and require Maritime Electric to pay its share of the station's capital
operating costs for the life of the unit.
FortisOntario ($374 million): an agreement with Hydro-Québec for the supply of up to 145 MW of capacity and a minimum of 537 GWh of associated
energy annually through December 2030.
FortisBC Electric ($301 million): an agreement with BC Hydro to purchase up to 200 MW of capacity and 1,752 GWh of associated energy annually for a
20-year term beginning October 1, 2013.
(5) ITC is party to an agreement with Consumers Energy, the primary customer of METC, which provides METC with an easement for transmission purposes
and rights-of-way, leasehold interests, fee interests and licenses associated with the land over which its transmission lines cross. The agreement expires
in December 2050, subject to 10 potential 50-year renewals thereafter unless METC gives notice of non-renewal at least one year in advance.
(6) TEP has entered into two engineering, procurement and construction ("EPC") agreements associated with the development of energy storage projects.
Roadrunner Reserve 1 is expected to be placed in service in 2025, with Roadrunner Reserve 2 to follow in 2026.
(7) Maritime Electric is party to a debt collection agreement with PEI Energy Corporation for the initial capital cost of the submarine cables and associated
parts of the New Brunswick transmission system interconnection. Payments under the agreement, which expires in February 2056, are collected in
customer rates.
(8) UNS Energy and Central Hudson are party to REC purchase agreements, mainly for the purchase of environmental attributions from retail customers
with solar installations or other renewable generation. Payments are primarily made at contractually agreed-upon intervals based on metered energy
production.
(9) Includes AROs and joint-use asset and shared service agreements.
Notes to Consolidated Financial Statements
For the years ended December 31, 2024 and 2023
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FORTIS INC.
DECEMBER 31, 2024
27. COMMITMENTS AND CONTINGENCIES (cont'd)
Other Commitments
Under a funding framework with the Governments of Ontario and Canada, Fortis will contribute a minimum of approximately $165 million of equity
capital to Wataynikaneyap Power, based on Fortis' proportionate 39% ownership interest and the final regulatory-approved capital cost of the related
project. Wataynikaneyap Power has construction financing loan agreements in place and it is expected that long-term operating financing will replace the
construction financing. In the event a lender under the loan agreements realizes security on the loans, Fortis may be required to accelerate its equity
capital contributions, which may be in excess of the amount otherwise required of Fortis under the funding framework, to a maximum total funding of
$235 million. Equity of $137 million has been contributed as of December 31, 2024.
UNS Energy has joint generation performance guarantees with participants at Four Corners and Luna, with agreements expiring in 2041 and 2046
respectively, and at San Juan and Navajo through decommissioning. The participants have guaranteed that in the event of payment default, each non-
defaulting participant will bear its proportionate share of expenses otherwise payable by the defaulting participant. In exchange, the non-defaulting
participants are entitled to receive their proportionate share of the generation capacity of the defaulting participant. In the case of San Juan and Navajo,
participants would seek financial recovery from the defaulting party. There is no maximum amount under these guarantees, except for a maximum of
$360 million for Four Corners. As at December 31, 2024, there was no obligation under these guarantees.
Contingency
In 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 across reserve lands. 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 2016, the Federal Court dismissed the Band's application for judicial review of the ministerial consent. In 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.
Notes to Consolidated Financial Statements
For the years ended December 31, 2024 and 2023
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FORTIS INC.
DECEMBER 31, 2024