.2
1
Management’s Discussion & Analysis
As at February 23, 2026
Management’s Discussion & Analysis
(“MD&A”) provides a review of the results of operations of Emera
Incorporated and its consolidated subsidiaries and investments
(collectively referred to as “Emera” or the
“Company”) during the fourth quarter of, and for the
full year of, 2025 relative to the same periods in 2024
and
selected financial information for 2023; and its financial position as at December 31, 2025 relative to
December 31, 2024. The Company’s activities are carried
out through five reportable segments: Florida
Electric Utility,
Canadian Electric Utilities, Gas Utilities and Infrastructure, Other Electric Utilities, and
Other.
This MD&A should be read in conjunction with the Emera
annual audited consolidated financial
statements and supporting notes as at and for the
year ended December 31, 2025. Emera follows United
States
Generally Accepted Accounting Principles (“USGAAP” or “GAAP”). Additional information related
to Emera, including the Company’s Annual Information
Form, can be found on SEDAR+ at
www.sedarplus.ca and on EDGAR
at www.sec.gov.
The accounting policies used by Emera’s
rate-regulated entities may differ from those used by Emera’s
non-rate-regulated businesses with respect to the timing of
recognition of certain assets, liabilities,
revenues and expenses. At December 31, 2025,
Emera’s rate-regulated subsidiaries and investments
include:
Rate-Regulated Subsidiary or Equity Investment
Accounting Policies Approved/Examined By
Subsidiary
Tampa Electric Company (“TEC”)
Florida Public Service Commission (“FPSC”) and the
Federal Energy Regulatory Commission (“FERC”)
Nova Scotia Power Inc. ("NSPI")
Nova Scotia
Energy Board (“NSEB”), formerly Nova Scotia
Utility and Review Board
Peoples Gas System, Inc. (“PGS”)
FPSC
New Mexico Gas Company, Inc.
(“NMGC”)
New Mexico Public Regulation Commission (“NMPRC”)
SeaCoast Gas Transmission, LLC ("SeaCoast")
FPSC
Emera Brunswick Pipeline Company Limited (“Brunswick
Pipeline”)
Canadian Energy Regulator ("CER")
Barbados
Light & Power Company Limited (“BLPC”)
Fair Trading Commission,
Barbados ("FTC")
Grand Bahama Power Company Limited (“GBPC”)
The Grand Bahama Port Authority (“GBPA”)
Equity Investments
NSP Maritime
Link Inc. (“NSPML”)
NSEB
Maritimes
& Northeast Pipeline Limited Partnership and
Maritimes & Northeast Pipeline, LLC (“M&NP”)
CER and FERC
St. Lucia Electricity Services
Limited (“Lucelec”)
National Utility Regulatory Commission
Wasoqonatl Transmission Incorporated ("WTI")
NSEB
All amounts are in
Canadian dollars (“CAD”), except for the Florida Electric Utility, Gas Utilities and
Infrastructure, and Other Electric Utilities sections of the
MD&A, which are reported in United States
dollars
(“USD”) unless otherwise stated.
2
TABLE OF CONTENTS
Forward-looking Information……………………......
2
Introduction and Strategic
Overview………….……
3
Non-GAAP Financial Measures and Ratios….…...
4
Consolidated Financial
Review……….……………
7
7
8
10
Business Overview and
Outlook…………….……..
13
13
13
16
17
18
Consolidated Balance Sheet Highlights…………..
19
Other
Developments…………………………………
20
Financial Highlights……………………………..…..
21
21
23
25
28
29
Liquidity and Capital Resources………..…………..
32
32
33
34
35
35
37
37
38
Pension Funding……………………………………..
39
Off-Balance Sheet
Arrangements………………….
40
Dividend Payout Ratio……………………………….
41
Transactions with Related
Parties….……………...
41
Enterprise Risk and Risk Management……………
42
Risk Management including
Financial
Instruments…………………………………………
52
Disclosure and Internal
Controls……………………
54
Critical Accounting Estimates….……………………
54
Changes in Accounting Policies and
Practices…...
60
60
Summary of Quarterly
Results……........................
61
FORWARD -LOOKING
INFORMATION
This MD&A contains “forward-looking information”
and “forward-looking statements” (collectively, “FLI”)
within the meaning of applicable Canadian and US securities
laws, including the United States Private
Securities Litigation Reform Act of 1995, which reflect
the current view with respect to the Company’s
expectations regarding future growth, results of operations,
performance, earnings, capital investment,
sales volumes, recovery of costs, timing of regulatory
decisions, the expected timing and outcome of the
pending
sale of NMGC, the expected impact of Cybersecurity Incident (as defined herein) on the
Company’s financial position and results of operations,
information technology (“IT”) systems restoration,
insurance recoveries, and business continuity processes
as well as other matters relating to the
Cybersecurity
Incident, business prospects and opportunities, and may not be appropriate for other
purposes. All such information and statements are made pursuant
to safe harbour provisions contained in
applicable securities legislation. The words
“anticipates”, “believes”, “budget”, “could”, “estimates”,
“expects”, “forecast”, “intends”, “may”, “might”,
“plans”, “projects”, “schedule”, “should”, “targets”, “will”,
“would” and similar expressions are often intended to
identify FLI, although not all FLI contains these
identifying
words. The FLI reflects management’s current beliefs and is based on information currently
available to Emera’s management and should not be read
as guarantees of future events, performance or
results, and
will not necessarily be accurate indications of whether, or the time at which, such events,
performance or results will be achieved.
3
FLI is based on
reasonable assumptions and is subject to risks, uncertainties and other factors that could
cause actual results to differ materially from historical
results or results anticipated by the FLI. Factors that
could cause results or events to differ from
current expectations include, without limitation: regulatory and
political risk; change in law risk; system operating and
maintenance risks; changes in economic
conditions; commodity price and availability risk;
liquidity and capital markets risk; changes in credit
ratings; future dividend growth, rate base growth, and
adjusted earnings per common share (“EPS”)
growth; timing and costs associated with certain
capital investments; expected impacts on Emera of
challenges
in the global economy; potential impacts of trade disputes and tariffs; estimated energy
consumption rates; maintenance of adequate insurance coverage
and receipt of proceeds; changes in
customer energy usage patterns; developments in
technology that could impact demand for electricity;
climate
risk; weather risk, including higher frequency and severity of weather events; risk of wildfires;
unanticipated maintenance and other expenditures; derivative
financial instruments and hedging; interest
rate risk; inflation risk; counterparty risk; disruption of
fuel supply; supply chain risk; environmental risks;
foreign
exchange (“FX”); regulatory and government decisions, including changes to environmental
legislation, financial reporting and tax legislation; risks
associated with pension plan performance and
funding requirements; loss of service area; risks
and costs associated with failure of IT infrastructure and
cybersecurity incidents including IT systems restoration and
business continuity processes; uncertainties
associated with infectious diseases, pandemics and
similar public health threats; risks associated with
health
and safety; market energy sales prices; labour relations; and availability of labour and
management resources.
Readers are cautioned not to place undue reliance on FLI, as
actual results could differ materially from
the plans, expectations, estimates or intentions and
statements expressed in the FLI. All FLI in this MD&A
is qualified in its entirety by the above cautionary statements
and, except as required by law, Emera
undertakes no
obligation to revise or update any FLI as a result of new information, future events or
otherwise.
INTRODUCTION AND STRATEGIC
OVERVIEW
Emera (TSX/NYSE: EMA) is a North American provider of
energy services, owning and operating a
portfolio of cost-of-service, rate-regulated electric and gas
utilities. Its largest operations are in Florida,
with
additional operations in Atlantic Canada, New Mexico, and the Caribbean. Emera is headquartered
in Halifax, Nova Scotia, Canada.
Emera’s business strategy is centred on continued
investment in its regulated utilities, combined with a
focus on operational excellence and
efficiency, to safely and reliably deliver energy to its 2.7 million
customers. Effective execution of these priorities supports
predictable and growing earnings, cash flow,
and dividends for
shareholders.
Earnings opportunities in regulated utilities
are a function of the magnitude of net investment in the utility
(known as “rate base”), the amount of equity in the capital
structure, and the targeted return on that equity
(“ROE”), all as established and approved through regulation.
Earnings are also affected by sales volumes
and operating
expenses. In 2025, Emera’s regulated cost -of-service utilities in Florida accounted for 67
per cent of average consolidated rate base, with Atlantic
Canada comprising 25 per cent, and the
Caribbean and New Mexico at 4 per cent
each.
Emera’s capital investment plan is forecasted to
be approximately $20 billion from 2026 through 2030 and
is
focused on delivering value for customers through prudent investments in reliability and system
resiliency, infrastructure modernization, expansion to
address customer growth, integration of
renewables, and
technological innovations to deliver better customer experiences. It is anticipated that
approximately 80 per cent of this capital investment will be made
in Emera’s Florida utilities, necessitated
by customer growth and system requirements at both TEC
and PGS.
4
As at
millions of dollars
2026
2027
2028
2029
2030
Total
Capital investment plan
$
$
$
$
$
$
Average consolidated rate base:
$
$
$
$
$
$
$
$
$
$
*Capital investment plan and average consolidated rate base
exclude NMGC. For more information on the pending sale of NMGC,
refer to “Other Developments” section.
Emera’s capital investment plan will be funded
primarily through internally generated cash flows, debt
raised at the operating company level consistent with regulated
capital structures, equity issuances, and
proceeds from the anticipated close of the NMGC
transact ion. Generally, Emera’s equity requirements
are expected to be funded through the issuance of hybrid
securities, and the issuance of common equity
through Emera’s dividend reinvestment plan
(“DRIP”) and its at-the-market program (“ATM program”).
Maintaining investment-grade credit ratings is a core strategic
priority of the Company.
Emera has increased dividends per common share paid
for 19 consecutive years and has provided
annual dividend
growth guidance of one to two per cent. Emera anticipates average adjusted EPS growth
of five to seven per cent through 2030, using 2024 as the
base year, which will support continued
reduction in
the ratio of dividend payout to adjusted net income over time. For further information on the
non-GAAP ratios “Adjusted EPS” and “Dividend
Payout Ratio of Adjusted Net Income”, refer to the
“Non-
GAAP Financial Measures and Ratios” section.
NON-GAAP FINANCIAL MEASURES AND
RATIOS
Emera uses financial measures and ratios that do not have
standardized meaning under USGAAP and
are calculated by adjusting certain GAAP measures for
specific items. They may not be comparable to
similar
measures presented by other entities. These measures and ratios are discussed and reconciled
below.
Adjusted Net Income, Adjusted EPS – Basic,
and Dividend Payout Ratio of
Adjusted Net Income
Emera calculates an adjusted net income attributable to
common shareholders (“adjusted net income”)
measure by excluding items below from net income
attributable to common shareholders. Management
believes
excluding these items better distinguishes ongoing operations of the business and allows
investors to better understand and evaluate the business.
Emera calculates adjusted net income for the Florida
Electric Utility, Gas Utilities and Infrastructure, Other
Electric Utilities, and Other segments. Reconciliation to
the nearest GAAP measure is included in each
segment. For more information refer to the Financial
Highlights section for each of Florida Electric Utility,
Gas
Utilities and Infrastructure, Other Electric Utilities, and Other.
Adjusted EPS – basic and dividend payout ratio of adjusted
net income are non-GAAP ratios which are
calculated using adjusted net income, as described above.
For further details on dividend payout ratio of
adjusted net
income, refer to the “Dividend Payout Ratio” section.
5
Adjusting Items Impacting All Periods
Mark-to-market (“MTM”) Adjustments:
Management believes excluding from net income the effect of
MTM valuations and changes thereto, until
settlement, better aligns the intent and financial
effect of these contracts with the underlying cash flows,
and therefore excludes MTM adjustments for evaluation of
performance and incentive compensation. The
MTM adjustments are related to the following:
●
price differential between the point where natural gas is
sourced and where it is delivered, and
the related amortization of transportation capacity
recognized as a result of certain Emera Energy
marketing and
trading transactions;
●
equity income;
●
●
Adjusting Items Impacting 2025 and 2024
Charges Related to the Pending Sale of NMGC:
On August 5, 2024, Emera entered into an agreement to sell
NMGC. In Q2 2025, the Company
recognized a $71 million non-cash impairment
charge, after-tax, and an additional loss of $1 million in
estimated transaction costs, after-tax, related to the pending
sale. In Q3 2024, the Company recognized
$206 million
in non-cash goodwill and other impairment charges, after-tax, and an additional loss of $19
million in estimated transaction costs, after-tax, related
to the pending sale. For further details, refer to the
“Significant Items Affecting Earnings” and
“Other Developments” sections.
Adjusting Items Impacting 2024
Gain on Sale of Emera’s Indirect Minority
Interest in the Labrador Island Link (“Gain on sale of LIL”):
In Q2 2024, Emera recognized a $107 million gain, after tax
and transaction costs, on the sale of LIL. In
Q4 2024, Emera recognized a $22 million tax benefit
related to the reversal of a prior year valuation
allowance.
A portion of the taxable capital gain on sale of LIL was offset by prior year loss carryforwards,
of which the tax benefit was subject to a valuation allowance
as at December 31, 2023. For further
details refer to
the “Significant Items Affecting Earnings” section.
Financing Structure Wind-Up:
In Q4 2024, Emera recognized a $58 million tax benefit
related to denied interest and financing expenses
and the wind-up of a specific financing structure. For
further details, refer to the “Significant Items
Affecting Earnings” section.
Charges Related to Wind-Down Costs and Certain
Asset Impairments:
In Q4 2024, the Company recognized $26 million,
after-tax, in wind-down costs and certain asset
impairments,
primarily at Block Energy LLC (“Block Energy”). For further details, refer to the “Significant
Items Affecting Earnings” section.
6
Reconciliation of Net Income Attributable to
Common Shareholders to Adjusted Net Income
Three months ended
Year ended
For the
December 31
December 31
millions of dollars (except per share amounts)
2025
2024
2025
2024
2023
Net income attributable to common
shareholders
$
$
$
$
$
MTM (loss) gain, after-tax
(1)
Charges related to the pending sale of NMGC, after-tax
(2)(3)
Gain on sale of LIL, after-tax
(4)
Financing structure wind-up
Charges related to wind-down costs and certain asset
impairments, after-tax
(5)
Adjusted net income
$
$
$
$
$
EPS – basic
$
$
$
$
$
Adjusted EPS – basic
$
$
$
$
$
(1) Net of income tax recovery of $39 million for the three
months ended December 31, 2025 (2024 – $57 million recovery) and $17
million expense for the year ended December 31, 2025 (2024
– $117 million recovery) (2023 – $68 million expense).
(2) Represents (i) $71 million non-cash
impairment charge, after-tax and $1 million in transaction costs, after-tax for the year ended
December 31, 2025 and (ii) $206 million in non-cash goodwill
and other impairment charges, after-tax and $19 million in transaction
costs, after-tax for the year ended December 31, 2024.
(3) Net of income tax recovery of $5 million for the year
ended December 31, 2025 (2024 – $21 million).
(4)
Includes an income tax recovery of $22 million for the three months ended December 31, 2024 and net of income
tax expense of
$53 million for the year ended December 31, 2024.
(5) Net of income tax recovery of $6 million for the three
months and year ended December 31, 2024.
EBITDA and Adjusted EBITDA
Earnings before interest, income taxes, depreciation and
amortization (“EBITDA”) and adjusted EBITDA
are
non-GAAP financial measures used by Emera. These financial measures are used by numerous
investors and lenders to better understand cash flows and
credit quality. EBITDA is useful to assess
Emera’s
operating performance and indicates the Company’s ability to service or incur debt, invest in
capital, and finance working capital requirements. Adjusted
EBITDA represents EBITDA absent the
income effect of MTM adjustments, charges
related to the pending sale of NMGC, the 2024 gain on sale
of LIL, and the 2024 charges related to wind-down costs and
certain asset impairments.
Reconciliation of Net Income to EBITDA and Adjusted
EBITDA
Three months ended
Year ended
For the
December 31
December 31
millions of dollars
2025
2024
2025
2024
2023
Net income
(1)
$
$
$
$
$
Interest expense, net
Income tax (recovery) expense
Depreciation and amortization
EBITDA
$
$
$
$
$
MTM (loss) gain, excluding income tax
Charges related to the pending sale of NMGC,
excluding income tax
Gain on sale of LIL, excluding income tax
Charges related to wind-down costs and certain asset
impairments, excluding income tax
Adjusted EBITDA
$
$
$
$
$
(1) Net income is before Non-controlling interest in
subsidiaries and Preferred stock dividends.
7
CONSOLIDATED FINANCIAL REVIEW
Significant Items Affecting
Earnings
The items detailed below have had a significant impact on
net income attributable to common
shareholders but have been excluded from adjusted
net income as described in the section entitled
“Non-
GAAP Financial Measures and Ratios”.
Earnings Impact of MTM (Loss) Gain, After-Tax
For Q4 2025, MTM loss, after-tax, decreased $47 million to
$99 million compared to $146 million in Q4
2024, primarily due to a gain on Corporate FX hedges
compared to a loss in prior year. For the year
ended 2025, the 2024 MTM loss, after-tax, of $291 million
decreased $332 million to a $41 million MTM
gain, after-tax primarily due to changes in existing
positions and lower amortization of gas transportation
assets at Emera Energy Services (“EES”) and a gain on
Corporate FX hedges compared to a loss in prior
year.
Charges Related to the Pending Sale of NMGC
2025:
In Q2 2025, Emera recognized a non-cash impairment charge of
$75 million ($71 million after-tax, or
$0.24 per common share) related to the remeasurement of
the NMGC disposal group to fair value (“FV”)
less costs to sell. This was recorded in “Impairment
charges” on the Consolidated Statements of Income
and
included in the Other Segment.
2024:
In Q3 2024, Emera recognized non-cash goodwill and other
impairment charges of $221 million ($206
million after-tax,
or $0.72 per common share) related to the NMGC reporting unit. These charges were
recorded in “Impairment charges” on the
Consolidated Statements of Income and included in
the Other and Gas Utilities and Infrastructure segments.
Additionally, in Q3 2024, Emera recorded a loss
of $24 million ($19 million after-tax, or $0.06 per common
share) in estimated transaction costs related to
the
pending sale. These transaction costs were included in “Other income, net” on the Consolidated
Statements of Income and included in the Other segment.
For further details on the pending sale of NMGC, refer to the
“Other Developments” section. For further
details on the non-cash impairment and goodwill charges,
refer to note 4 in the consolidated financial
statements.
Gain on Sale of LIL
On June 4, 2024, Emera completed the sale of its LIL equity
interest. A gain on sale of $182 million after
transaction costs ($107 million, after tax and
transaction costs, or $0.37 per common share), was
recognized in “Other Income, net” on the Consolidated
Statements of Income in Q2 2024 and included in
the Other segment. In Q4 2024, Emera recognized a
$22 million ($0.08 per common share) tax benefit
related to
the reversal of a prior year valuation allowance. A portion of the taxable capital gain on the sale
of the LIL equity interest was offset by prior year loss
carryforwards, of which the tax benefit had been
subject to a valuation allowance as at December 31, 2023.
This tax benefit was recorded in “Income tax
expense
(recovery)” on the Consolidated Statements of Income in Q4 2024 and included in the Other
segment. For further details on the transaction, refer to
note 4 in the consolidated financial statements.
8
Financing Structure Wind-Up
During 2024, the Company incurred $185 million of interest
and financing expenses in connection with a
specific financing structure. The current and future
interest and financing expenses were expected to be
denied
under the Excessive Interest and Financing Expenses Limitation (“EIFEL”) legislation and, as a
result, the financing structure was wound up. It was determined
that Emera was more likely than not to
realize the benefit of the current denied interest and
financing expenses in future periods and therefore a
$54
million deferred income tax asset and related income tax benefit ($0.19 per common share) was
recorded during Q4 2024. In addition, Emera recognized a $4
million income tax benefit ($0.01 per
common share) related to the reversal of a deferred
income tax liability on the wind-up of the financing
structure. The total tax benefit of $58 million was recorded
in “Income tax expense (recovery)” on the
Consolidated Statements of Income and included in
the Other segment during 2024.
Charges
Related to Wind-Down Costs and Certain Asset Impairments
In
Q4 2024, Emera recognized $32 million ($26 million after-tax, or $0.09 per common share) in
wind-
down costs and certain asset impairments, primarily at Block
Energy. These were recorded in “Other
income,
net” and “Impairment charges” on the Consolidated Statements of Income and included mainly in
the Other segment.
Consolidated Financial Highlights
For the
Three months ended
Year ended
millions of
dollars
December 31
December 31
Adjusted net
income
2025
2024
2025
2024
2023
Florida Electric Utility
$
$
$
$
$
Canadian Electric Utilities
Gas Utilities and Infrastructure
Other Electric Utilities
Other
Adjusted net income
$
$
$
$
$
MTM (loss) gain, after-tax
Charges related to the pending sale of NMGC, after-tax
Gain on sale of LIL, after-tax
Financing structure wind-up
Charges related to wind-down costs and
certain asset impairments, after-tax
Net income attributable to common shareholders
$
$
$
$
$
9
The following
table highlights significant changes in adjusted net income from 2024 to 2025:
For the
Three months ended
Year ended
millions of dollars
December 31
December 31
Adjusted net income – 2024
$
$
Operating Unit Performance
Increased earnings at TEC year-over-year due to higher revenue from
new base rates, customer growth, favourable weather, and the impact of
a weaker CAD. These were partially offset by higher operating,
maintenance and general expenses ("OM&G"), depreciation, interest
expense, and income tax expense
Increased earnings at EES due to favourable weather conditions that led
to higher natural gas prices and increased volatility that created
profitable opportunities
Decreased earnings at NMGC quarter-over-quarter due to higher
OM&G. Increased earnings year-over-year due to higher revenue from
new base rates, partially offset by higher OM&G and depreciation
expense
Decreased income from equity investments due to the sale of LIL in Q2
2024
Decreased earnings at NSPI quarter-over-quarter primarily due to lower
income tax recovery due to the utilization of tax loss carryforwards
recognized as a deferred income tax regulatory liability in 2024. For both
quarter-over-quarter and year-over-year, decreased earnings due to
higher OM&G and higher depreciation expense, partially offset by higher
revenue due to favourable weather
Corporate
Increased interest
expense due to increased Corporate debt and the
impact of a weaker CAD on USD interest expense, partially offset by
lower interest rates
Decreased income tax recovery due to decreased deferred income tax
asset valuation allowance adjustment
Other Variances
Adjusted net income – 2025
$
$
For the
Year ended December 31
millions of dollars
2025
2024
2023
Operating cash flow before changes in working capital
$
$
$
Change in working capital
Operating cash flow
$
$
$
Investing cash flow
$
$
$
Financing cash flow
$
$
$
For further discussion of cash flow, refer to the
"Consolidated Cash Flow Highlights" section.
As
at
December 31
millions of dollars
2025
2024
2023
Total assets
$
$
$
Total long-term debt (including current
portion)
$
$
$
(1) Excludes NMGC balances classified as held for sale at
December 31, 2025 and December 31, 2024. For further details, refer to
the "Other Developments" section and note 4 in the
consolidated financial statements.
10
Consolidated Income Statement Highlights
For the
Three months ended
Year ended
Year ended
millions of dollars
December 31
December 31
December 31
(except per share amounts)
2025
2024
Variance
2025
2024
Variance
2023
Operating revenues
$
$
$
$
$
$
$
Operating expenses
Income from operations
$
$
$
$
$
$
$
Other income (expense), net
$
$
$
$
$
$
$
Income tax (recovery) expense
$
$
$
$
$
$
$
Net income attributable to
common
shareholders
$
$
$
$
$
$
$
Adjusted net income
$
$
$
$
$
$
$
Weighted average shares of
common stock
outstanding
(in millions)
EPS – basic
$
$
$
(0.29)
$
$
$
1.68
$
EPS – diluted
$
$
$
(0.27)
$
$
$
1.67
$
Adjusted EPS – basic
$
$
$
(0.29)
$
$
$
0.55
$
Adjusted EBITDA
$
$
$
$
$
$
$
Dividends per common share
declared
$
$
$
$
$
$
$
Dividends per first preferred shares declared:
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
Trade Disputes and Tariffs
The extent of the future impact of trade disputes and tariffs
on the Company’s financial results and
business operations continues to evolve, cannot be
predicted at this time and will depend on future
developments. To date, there has been no material financial
impact on the Company. For information on
risks associated with trade disputes and the imposition of
tariffs, refer to the “Enterprise Risk and Risk
Management” section.
Operating Revenues
For Q4 2025, operating revenues increased $243 million
compared to Q4 2024 and, excluding decreased
MTM losses of $19 million, increased $224 million.
The increase was due to higher storm cost recoveries
at TEC
and NSPI (offset in OM&G); new base rates at TEC; and higher marketing and trading margin at
EES.
For
the year ended December 31, 2025, operating revenues increased $1,576 million compared to 2024
and, excluding increased MTM gains of $369 million, increased
$1,207 million. The increase was due to
higher storm cost recoveries at TEC and NSPI
(offset in OM&G); new base rates at TEC and NMGC; the
impact of a weaker CAD; higher fuel cost recoveries at TEC,
NSPI and NMGC; higher marketing and
trading margin at EES; and favourable weather at
NSPI and TEC.
11
Operating Expenses
For Q4 2025, operating expenses increased $207 million compared
to Q4 2024. Excluding charges
related to wind-down costs and certain asset
impairments of $4 million recognized in 2024, operating
expenses increased $211 million. For the year ended December
31, 2025, operating expenses increased
$681 million compared
to 2024. Excluding the change in the charges related to the pending sale of
NMGC of $146 million and charges related to wind-down costs
and certain asset impairments of $4
million recognized in 2024, operating expenses increased
$831 million. These increases were primarily
due to higher
storm cost recognition of $97 million quarter -over-quarter and $350 million year-over-year at
TEC and NSPI (offset in revenue); higher OM&G at NMGC
and NSPI; and increased depreciation
expense at TEC, PGS and NMGC. The
year-over-year increase was also due to higher natural gas prices
at TEC, PGS and NMGC; higher regulated fuel for generation
and purchase power at NSPI; and the
impact of a weaker CAD.
Other Income, net
For Q4 2025, other income, net increased $59 million compared
to Q4 2024, due to decreased FX losses
and the 2024 charges related to wind-down costs
and certain asset impairments.
For the year ended December
31, 2025, other income, net decreased $38 million compared to 2024, due
to the gain on sale of LIL in 2024, partially offset by
higher FX gains in 2025, the 2024 charges related to
wind-down costs and certain asset impairments and the 2024
transaction costs related to the pending
sale of NMGC.
Income Tax Expense (Recovery)
For Q4 2025, income tax recovery decreased $164 million compared
to Q4 2024, due to the recognition
of tax benefits associated with denied interest and
financing expenses in the prior year, decreased
deferred income tax asset valuation allowance adjustment and
increased income before provision for
income taxes.
For the year ended December 31, 2025, income tax expense
increased $240 million compared to 2024,
due to increased income before provision for income
taxes (excluding the gain on sale of LIL recognized
in 2024
and the charges related to the pending sale of NMGC), recognition of tax benefits associated with
denied interest and financing expenses in the prior year,
and decreased deferred income tax asset
valuation allowance adjustment. These were partially
offset by the tax impact on the gain on sale of LIL
recognized in 2024 and increased tax credits recognized at
NSPI and TEC.
Net Income and Adjusted Net Income
Net income attributable to common shareholders for Q4 2025,
compared to Q4 2024, was favourably
impacted by the $47
million decrease in MTM losses, the $26 million charges related to wind-down costs
and certain asset impairments in 2024, and unfavourably
impacted by the $58 million tax benefit related
to a specific financing structure and its wind-up
recognized in 2024 and the $22 million valuation
allowance
reversal related to the gain on sale of LIL recognized in 2024. Excluding these changes,
adjusted net income decreased $69 million due to decreased
earnings at NSPI and NMGC; and
increased Corporate costs. These were partially
offset by increased earnings at EES.
Net income attributable
to common shareholders for the year ended 2025, as compared to the same
period in 2024, was favourably impacted by the $332 million
decrease in MTM losses, the $153 million
change in the charges related to the pending sale of
NMGC, and the $26 million in charges related to
wind-down
costs and certain asset impairments and unfavourably impacted by the $129 million gain on
sale of LIL recognized in 2024 and the $58 million tax benefit
related to a specific financing structure and
its wind-up
recognized in 2024. Excluding these changes, adjusted net income increased $206 million.
The increase was primarily due to increased earnings at TEC,
EES and NMGC. These were partially
offset by lower equity earnings from LIL; higher
Corporate costs; and lower earnings at NSPI.
12
EPS and Adjusted EPS – Basic
For Q4 2025, EPS - basic and adjusted EPS were lower than Q4
2024 due to the impact of lower
earnings as discussed above and the impact of an
increase in weighted average shares outstanding.
For the
year ended December 31, 2025, EPS – basic and adjusted EPS were higher than 2024 due to the
impact of higher earnings as discussed above, partially offset
by the impact of an increase in weighted
average shares outstanding.
Effect of Foreign Currency Translation
Emera operates in the United States (“US”), Canada and
various Caribbean countries and, as such,
generates revenues
and incurs expenses denominated in local currencies which are translated into CAD
for financial reporting. Changes in translation rates, particularly
the value of the USD against the CAD,
can positively or
adversely affect results.
Results of foreign operations are translated at the
weighted average rate of exchange, and assets and
liabilities of foreign operations are translated at period end
rates. The relevant CAD/USD exchange rates
on net income
attributable to common shareholders for 2025 and 2024 are as follows:
Three
months ended
Year ended
December 31
December 31
2025
2024
2025
2024
Weighted average CAD/USD
$
1.36
$
1.37
$
1.41
$
1.36
Period end CAD/USD exchange rate
$
1.37
$
1.44
$
1.37
$
1.44
The table below includes Emera’s significant segments
whose contributions to adjusted net income are
recorded in USD
currency:
Three months ended
Year ended
For
the
December 31
December 31
millions of USD
2025
2024
2025
2024
Florida Electric Utility
$
85
$
85
$
607
$
470
Gas Utilities and
Infrastructure
50
56
179
178
Other Electric Utilities
11
15
31
35
Other segment
(3)
(26)
(33)
(123)
(131)
Total
(2)(4)
$
120
$
123
$
694
$
552
(1) Includes USD net income from PGS, NMGC, SeaCoast and
M&NP.
(2) Excludes $6 million USD, after-tax, in other
impairment charges associated with the pending sale of NMGC for the year ended
December 31, 2024.
(3) Includes Emera Energy's USD adjusted net income
from EES, Bear Swamp and interest expense on Emera Inc.'s USD
denominated debt.
(4) Excludes $73 million USD in MTM losses, after-tax, for
the three months ended December 31, 2025 (2024 – $84 million USD
MTM losses, after-tax) and $5 million in USD MTM gain,
after-tax, for the year ended December 31, 2025 (2024 – $189 million USD
MTM losses, after-tax).
In Q4 2025, the translation impact of a stronger CAD on USD
denominated earnings decreased adjusted
net income by $3 million and decreased net income
attributable to common shareholders by $3 million,
compared
to the same period in 2024. For the year ended December 31, 2025, the impact of a weaker
CAD on US denominated earnings increased adjusted net income
by $13 million and increased net
income attributable to common shareholders by $49 million,
compared to 2024. Impacts of the changes in
the translation
of the CAD include the impacts of Corporate FX hedges used to mitigate translation risk of
USD earnings in the Other segment.
13
BUSINESS OVERVIEW AND OUTLOOK
Florida Electric Utility
The Florida Electric Utility segment consists of TEC, a
vertically integrated regulated electric utility
engaged in the generation, transmission and
distribution of electricity, serving customers in West Central
Florida. With $14.5 billion USD of assets and approximately
866,000 customers at December 31, 2025,
TEC owns 6,771 megawatts (“MW”) of generating
capacity, of which 78 per cent is natural gas fired, 21
per
cent is solar and 1 per cent is energy storage. TEC owns approximately 2,200 kilometres of
transmission facilities and 21,100 kilometres of distribution
facilities. TEC meets the planning criteria for
reserve capacity established by the FPSC, which is a 20
per cent reserve margin over firm peak demand.
TEC’s
approved regulated ROE range is 9.50 per cent to 11.50 per cent based on an allowed equity
capital structure of 54 per cent. An ROE of 10.50 per cent
is used for the calculation of the return on
investments for clauses.
TEC anticipates earning within its allowed ROE range in 2026. USD
earnings are expected to be higher in
2026 than 2025 as a result of new base rates
effective January 1, 2026, and continued customer growth.
On
September 4, 2025, TEC petitioned the FPSC to increase base revenue by $88 million USD to reflect
the 2026 adjustment in accordance with its 2024 rate case
decision. On November 4, 2025, the FPSC
approved the adjustment, with new rates
effective January 1, 2026.
On February 3, 2025, the FPSC issued the final order
approving the 2024 rate case decision, effective
January 1,
2025. For additional details on the 2024 rate case, refer to note 7 in Emera’s consolidated
financial statements. In February 2025, a motion for
reconsideration on certain aspects of the final order
was
filed by an intervening party with the FPSC. On May 6, 2025, the FPSC denied the motion for
reconsideration, except with respect to immaterial calculation
corrections, and the final order was issued
on June 11,
2025. In March 2025, two intervening parties each filed a notice of appeal to the Florida
Supreme Court regarding the outcome of TEC’s 2024 base
rate proceeding. On January 12, 2026, the
intervening parties filed their briefs related to the
appeal. To date, the FPSC has not responded to the
briefs.
On February 4, 2025, the FPSC approved TEC’s
petition for the recovery of $466 million USD of costs
associated with Hurricane Idalia, Hurricane
Debby, Hurricane Helene and Hurricane Milton, and the
associated interest to replenish the storm reserve over an
18-month recovery period, which began in
March 2025. The amount of cost-recovery is
subject to a true-up mechanism with the FPSC. For
additional
details on the storm reserve, refer to note 7 in Emera’s consolidated financial statements.
In 2026, capital investment in the Florida Electric Utility
segment is expected to be $1.8 billion USD (2025
– $1.6 billion USD), including allowance for funds used during
construction (“AFUDC”). Capital projects
include
investment in generation reliability projects and storm hardening, grid modernization, and
transmission expansion.
Canadian Electric Utilities
The Canadian Electric Utilities segment includes NSPI and
NSPML. NSPI is a vertically integrated
regulated electric
utility engaged in the generation, transmission and distribution of electricity and the
primary electricity supplier to customers in Nova Scotia.
NSPML is a 100 per cent equity interest in the
Maritime Link Project (“Maritime Link”), a
transmission project between the island of Newfoundland and
Nova Scotia.
14
NSPI
With $8.1 billion of assets and approximately 565,000 customers
at December 31, 2025, NSPI owns
2,422 MW of generating
capacity, of which 44 per cent is coal and/or oil-fired; 28 per cent is natural gas
and/or oil; 19 per cent is hydro, wind, or solar; 7 per cent
is petroleum coke (“petcoke ”) and 2 per cent is
biomass-fueled generation. In 2025, NSPI began operations of
two 50 MW grid-scale battery facilities to
enhance reliability.
In addition, NSPI has contracts to purchase renewable energy from independent
power producers (“IPPs”) and community feed-in tariff
(“COMFIT") participants, which own 573 MW of
capacity. NSPI
also has rights to 153 MW of Maritime Link capacity, representing Newfoundland and
Labrador Hydro’s (“NLH”) Nova Scotia Block
(“NS Block”) delivery obligations, as discussed below. NSPI
owns approximately 5,400 kilometres of transmission facilities
and 28,700 kilometres of distribution
facilities.
NLH is obligated to provide NSPI with approximately 900 Gigawatt
hours (“GWh”) of energy annually over
35 years. In addition, until March 31, 2026, NLH is
obligated to provide approximately 240 GWh of
additional
energy from the Supplemental Energy Block transmitted through the Maritime Link. NSPI has
the option of purchasing additional market-priced energy
from NLH through the Energy Access
Agreement. The Energy Access Agreement enables
NSPI to access a market-priced bid from NLH for up
to 1.8
Terawatt hours (“TWh”) of energy in any given year and, on average, 1.2 TWh of energy per year
through August 31, 2041.
NSPI’s approved regulated ROE range is 8.75 per cent
to 9.25 per cent, based on an actual five-quarter
average regulated common equity component of up
to 40 per cent of approved rate base.
Assuming new base rates are approved by the NSEB in
the general rate application (“GRA”) and are
generally consistent with the settlement
agreement, NSPI anticipates earning at the low end of its allowed
ROE in 2026 and expects earnings in 2026 to be higher than
2025. Sales volumes are expected to be
higher in 2026 than 2025.
On September 18, 2025, NSPI filed a consensus GRA with the
NSEB, reflecting a settlement agreement
reached with customer representatives. The GRA
proposes average annual rate increases of 1.8 per cent
in
2026 and 2.4 per cent in 2027. The proposed rates would result in annual revenue (fuel and non-fuel)
increases of $62 million in 2026 and $108 million in 2027. The
hearing for the matter concluded in
January 2026 and a decision by the NSEB is
expected by early Q2 2026.
On March 5, 2025, NSPI, the
Canada Infrastructure Bank (“CIB”) and the Wskijinu’k Mtmo’taqnuow
Agency (“WMA”) announced the Wasoqonatl
transmission line project to create a reliability intertie
between Nova Scotia and New Brunswick. The
project is owned by a new regulated utility, WTI, which is
wholly-owned by a newly formed limited partnership between
NSPI, CIB and WMA. NSPI is responsible
for providing construction, operation, maintenance and
administrative services to WTI. NSPI has a 50 per
cent
indirect voting interest in WTI which is recorded as an “Investments subject to significant influence”
on Emera’s Consolidated Balance Sheets.
In 2026, capital investment is expected to be $720 million
(2025 – $712 million), including AFUDC. NSPI
is primarily investing in capital projects required to support
power system reliability and reliable service for
customers.
15
Environmental Legislation and Regulations
NSPI is subject to environmental laws and regulations set by
both the Government of Canada and the
Province of Nova Scotia (the “Province”). NSPI
continues to work with both levels of government to
comply
with these laws and regulations to maximize efficiency of emission control measures and
minimize customer cost. NSPI anticipates that costs prudently
incurred to achieve legislated compliance
will be recoverable under NSPI’s
regulatory framework. NSPI faces risks associated with achieving
climate-related and environmental legislative requirements,
including the risk of non-compliance, which
could adversely
affect NSPI’s operations and financial performance. For further discussion on these risks
and environmental legislation and regulations, refer to the
“Enterprise Risk and Risk Management”
section. Recent developments related to provincial and federal
environmental laws and regulations are
outlined below.
Nova Scotia Energy Reform Act:
On October 15, 2025, the Nova Scotia Independent Energy
System Operator (“IESO Nova Scotia”)
announced that the organization will be phased in
over two phases during an 18-month period. On
December 1,
2025, the first phase was complete following the transfer of system planning and
interconnection functions. The second phase is expected to
be complete in 2027 as IESO Nova Scotia
assumes responsibility for system operations. The
establishment of IESO Nova Scotia follows Bill 404 -
Energy
Reform (2024) Act enacted in April 2024, which established the NSEB, and phased transition to
IESO Nova Scotia.
Renewable Energy Regulations (“RER”):
On May 26, 2023, NSPI initiated an appeal, through a
proceeding with the NSEB, of the $10 million
penalty levied on NSPI by the Province for
non-compliance with the RER compliance period ending in
2022. The hearing concluded in 2025 and NSPI is awaiting a
decision.
NSPML
Equity earnings from the Maritime Link are dependent on the
approved ROE and operational
performance of NSPML. NSPML’s
approved regulated ROE range is 8.75 per cent to 9.25 per cent,
based on an actual five-quarter average regulated common
equity component of up to 30 per cent.
Equity earnings from NSPML in 2026 are expected
to be consistent with 2025. The NSPML investment is
recorded
as “Investments subject to significant influence” on Emera’s Consolidated Balance Sheets.
The Maritime Link assets entered service on January 15,
2018, enabling the transmission of energy
between Newfoundland and Nova Scotia, improved
reliability and ancillary benefits, supporting the
efficiency
and reliability of energy in both provinces. NLH’s NS Block delivery obligations commenced on
August 15, 2021 and will be delivered over the next 35 years
pursuant to the project agreements.
On December
23, 2025, NSPML received an interim order from the NSEB to collect up to $199 million
from NSPI for the recovery of costs associated with the
Maritime Link in 2026, subject to a monthly
holdback of up to $4
million. A final decision from the NSEB is pending. There was no holdback recorded
for the year ended December 31, 2025.
On February 4, 2026, NSPML submitted an application with
the NSEB requesting the termination of the
holdback mechanism. A decision is anticipated in
Q3 2026.
In 2026, the capital investment at NSPML is
expected to be approximately $40 million (2025 – $7 million).
16
Gas Utilities and Infrastructure
The Gas Utilities and Infrastructure segment includes PGS, NMGC,
SeaCoast, Brunswick Pipeline and
Emera’s equity investment in
M&NP. PGS is a regulated gas distribution utility engaged in the purchase,
distribution and sale of natural gas serving customers in Florida.
NMGC is an intrastate regulated gas
distribution utility engaged in the purchase, transmission,
distribution and sale of natural gas serving
customers in
New Mexico. SeaCoast is a regulated intrastate natural gas transmission company offering
services in Florida. Brunswick Pipeline is a regulated
145-kilometre pipeline delivering re-gasified
liquefied
natural gas from Saint John, New Brunswick, to markets in the northeastern US.
On August 5, 2024, Emera announced an agreement to sell
NMGC. As a result of the pending sale,
NMGC’s assets and liabilities were classified as
held for sale as of Q3 2024. The public hearing was held
in
November 2025. The transaction is expected to close in the first half of 2026. For more information on
the pending transaction, refer to the “Other
Developments” section.
PGS
With $3.3 billion USD of assets and approximately 523,000
customers, the PGS system includes
approximately 25,600
kilometres of natural gas mains and 14,800 kilometres of service lines. Natural gas
throughput (the amount of gas delivered to its customers,
including transportation-only service) was 2
billion therms in
2025.
Beginning in 2026, the approved ROE range for PGS
is 9.30 per cent to 11.30 per cent (2025 – 9.15 per
cent to 11.15 per cent) based on an allowed equity capital
structure of 54.7 per cent (2025 – 54.7 per
cent). An
ROE of 10.30 per cent (2025 – 10.15 per cent) is used for the calculation of return on
investments for clauses.
PGS anticipates earning within its allowed ROE range in
2026. USD earnings are expected to be higher
in 2026 than 2025, as a result of new base rates
effective January 1, 2026, and continued customer
growth.
On March 31, 2025, PGS filed a rate case with the FPSC for
new rates to become effective January 1,
2026. On August 13,
2025, PGS and the intervening parties filed a settlement agreement with the FPSC
for a $67 million USD increase in 2026 annual base rates,
which includes $7 million USD from the cast
iron and bare steel replacement
rider, and additional adjustments of $25 million USD in 2027 and up to $5
million USD in 2028 (subject to FPSC approval). This reflects
a 10.30 per cent midpoint ROE and 54.7
per cent equity thickness. On October 31, 2025, the
FPSC issued the final order approving the
settlement.
In 2026, capital investment is expected to be approximately
$445 million USD (2025 – $323 million USD),
including AFUDC. PGS will make investments to maintain the
reliability of their systems and support
customer
growth.
NMGC
With $1.6 billion USD of assets and approximately 553,000
customers, NMGC’s system includes
approximately 2,300
kilometres of transmission pipelines and 18,200 kilometres of distribution pipelines.
Annual natural gas throughput was approximately 1 billion
therms in 2025.
The approved ROE for NMGC is 9.375 per cent, on
an allowed equity capital structure of 52 per cent.
NMGC’s USD earnings contribution to Emera in 2026
are expected to be lower than in 2025 as a result of
the pending sale of NMGC, which is expected to close in the
first half of 2026.
17
Other Electric Utilities
Other Electric Utilities includes Emera (Caribbean) Incorporated
(“ECI”), a holding company with
regulated electric utilities. ECI’s regulated
utilities include vertically integrated regulated electric utilities of
BLPC on the island of Barbados, GBPC on Grand Bahama Island,
and an equity investment in Lucelec
on the island of St. Lucia.
Other Electric Utilities’ USD earnings in 2026 are expected
to be consistent with the prior year.
In 2026, capital investment in the Other Electric
Utilities segment is expected to be approximately $110
million USD (2025 – $67 million USD), including AFUDC,
primarily in more efficient and cleaner sources
of generation, including renewables and battery
storage.
BLPC
With $547 million USD of assets and approximately 137,000
customers, BLPC owns 243 MW of
generating capacity, of
which 96 per cent is oil-fired and 4 per cent is solar. BLPC owns approximately
200 kilometres of transmission facilities and 4,000 kilometres
of distribution facilities. BLPC’s approved
regulated return on rate base is 10 per cent.
In 2021, BLPC submitted a general rate review application to
the FTC. In September 2022, the FTC
granted BLPC interim rate relief, allowing an increase in base
rates of approximately $1 million USD per
month. On February
15, 2023, the FTC issued a decision on the application which included the following
significant items: an allowed regulatory ROE of 11.75 per
cent, an equity capital structure of 55 per cent,
a directive to update the major components of rate base to
September 16, 2022, and a directive to
establish regulatory
liabilities totalling approximately $71 million USD. On March 7, 2023, BLPC filed a
Motion for Review and Variation (the “Motion”)
and applied for a stay of the FTC’s decision, which was
subsequently granted. On November 20, 2023, the FTC issued
their decision dismissing the Motion.
Interim rates continue to be in effect through
to a date to be determined in a final decision and order.
On December 1, 2023, BLPC appealed certain aspects of
the FTC’s February 15 and November 20,
2023 decisions to the Supreme Court of Barbados in
the High Court of Justice (the “Court”) and
requested that they be stayed. On December 11, 2023, the
Court granted the stay. BLPC’s position is
that the
FTC made errors of law and jurisdiction in their decisions and believes the success of the appeal
is probable, and as a result, the adjustments to BLPC’s
final rates and rate base, including any
adjustments to regulatory assets and liabilities, have not been
recorded at this time. The appeal was
heard in December
2025, and will continue in early 2026. A decision is expected in 2026.
BLPC currently operates pursuant to a single integrated license
to generate, transmit and distribute
electricity on the island of Barbados until 2028. In 2019, the
Government of Barbados passed legislation
requiring multiple
licenses for the supply of electricity. In November 2025, the Government of Barbados
and BLPC agreed to new Transmission, Distribution, Sales and
Dispatch (“T&D”) and Generation and
Energy Storage (“G&S”) licenses. The
G&S license will be valid until 2047, unless otherwise extended.
The T&D License will be valid for 30 years. These new
non-exclusive licenses have since been signed
and will become effective upon the repeal of
the existing license. BLPC continues to operate under its
current statutory authority while preparing for the transition to
the new licensing framework.
GBPC
With $378 million USD of assets and approximately 20,000
customers, GBPC owns 98 MW of oil-fired
generation, approximately 100 kilometres of
transmission facilities and 1,000 kilometres of distribution
facilities. GBPC’s approved regulatory return on rate
base is 8.52 per cent.
18
On August 1,
2024, as required by the GBPA Operating Protocol and Regulatory Framework Agreement,
GBPC filed a rate plan proposal. A review of the proposal by
the GBPA is expected to commence in the
first half of 2026.
On June 1, 2024, the Electricity Act, 2024 took effect. The
legislation purports to remove the jurisdiction of
the GBPA
over GBPC and to have the Utilities Regulation and Competition Authority (“URCA”), another
Bahamian regulator, regulate GBPC. In 2024, URCA filed a
claim in the Supreme Court of the Bahamas,
seeking an order
that the GBPA be prohibited and restrained from considering and/or approving any
adjustment to rates sought by GBPC. URCA contends that it
has regulatory authority over electricity
provision on Grand Bahama pursuant to the Electricity Act.
Management does not expect that the
outcome of the
proceedings will have a material impact to Emera.
Other
The Other segment includes business operations that in a
normal year are below the required threshold
for reporting as separate segments; and corporate
expense and revenue items that are not directly
allocated to
Emera’s subsidiaries and investments.
Business operations in the Other segment include
Corporate; Emera Energy Services (“EES”), a physical
energy marketing and trading business; and a 50 per cent
joint venture interest in Bear Swamp, a 660
MW pumped storage hydroelectric facility in
northwestern Massachusetts.
Corporate
includes certain corporate-wide functions including executive management, strategic planning,
treasury services, legal, financial reporting, tax planning,
corporate business development, corporate
governance, investor relations, risk management,
insurance, acquisition and disposition related costs,
gains
or losses on select assets sales, and corporate human resource activities. It includes interest
revenue on intercompany financings and interest expense on
corporate debt in both Canada and the US.
Earnings from EES
are generally dependent on market conditions. In particular, volatility in natural gas
and electricity markets, which can be influenced by weather,
local supply constraints and other supply
and demand factors, can provide higher levels of
margin opportunity. The business is seasonal, with Q1
and Q4 usually providing the greatest opportunity for earnings.
EES is generally expected to deliver
annual adjusted net income of $15 million USD to $30
million USD. In light of strong market conditions in
early
2026, EES expects USD adjusted net income for 2026 to be in line with 2025 results.
The adjusted net loss from the Other segment in 2026 is
expected to be consistent with 2025.
In 2026, capital investment is expected to be
approximately $10 million (2025 – $6 million).
19
CONSOLIDATED BALANCE SHEET HIGHLIGHTS
Significant changes in the Consolidated Balance Sheets between
December 31, 2024 and December 31,
2025 include:
Total
Increase
millions of dollars
(Decrease)
Explanation of Increase (Decrease)
Assets
Cash and cash
equivalents
$
Increased due to higher cash from operations, increased
proceeds under committed credit facilities at TEC, proceeds from
debt issuances at TEC, and proceeds from common shares
issued. These were partially offset by investment in property,
plant and equipment ("PP&E"), repayment of committed credit
facilities at TECO Finance, Inc. ("TECO Finance") and Emera,
and dividends paid on Emera common stock
Regulatory assets (current and long-
term)
Decreased due to lower storm cost recovery assets at TEC and
NSPI and the effect of FX translation of Emera's non-Canadian
affiliates. These were partially offset by higher deferrals related to
the fuel adjustment mechanism ("FAM") and the deferred income
tax regulatory asset at NSPI
Receivables and
other assets
(current and long-term)
Increased trade receivables due to higher commodity prices at
EES, higher trade receivables at NSPI and TEC, higher right of
use assets related to new finance leases at TEC, and increased
pension assets due to higher return on assets in 2025 at TEC
Assets held for sale (current and
long-term),
net of liabilities
Decreased primarily due to non-cash impairment charge
recognized in 2025, and the effect of FX translation of NMGC
PP&E, net of accumulated
depreciation and
amortization
Increased due to capital additions in excess of depreciation,
partially offset by the effect of FX translation of Emera's
non-
Canadian affiliates
Goodwill
Decreased due to the effect of FX translation of Emera's
non-
Canadian affiliates
Liabilities and Equity
Short-term debt and long-term debt
(including
current portion)
$
Increased due to issuance of long-term debt at EUSHI Finance
Inc. ("EUSHI Finance") and TEC, proceeds from the issuance of
a non-revolving term credit facility at NSPI, and higher utilization
of committed credit facilities at TEC. These were partially offset
by the effect of FX translation of Emera's non-Canadian affiliates
and repayment of committed credit facilities at Corporate and
TECO Finance
Deferred income tax
liabilities, net of
deferred income tax assets
Increased due to tax deductions in excess of accounting
depreciation related to PP&E and changes in pension and
post-
retirement assets and liabilities. This was partially offset by
increased tax credits at TEC and the effect of FX translation of
Emera's non-Canadian affiliates
Regulatory
liabilities (current and
long-term)
Decreased due to lower FAM liability at NSPI, lower cost recovery
clause liabilities and lower deferred income tax regulatory
liabilities at TEC, and the effect of FX translation of Emera's
non-
Canadian affiliates
Other liabilities
(current and long-
term)
Increased due to finance leases entered into at TEC and timing of
interest payments at Corporate
Common stock
Increased due to shares issued
Accumulated
other comprehensive
income
Decreased due to the effect of FX translation of Emera's
non-
Canadian affiliates, partially offset by higher unrecognized
pension and post-retirement benefit costs due to higher
investment returns and favourable changes in actuarial
assumptions and amortization at NSPI
Retained earnings
Increased due to net income in excess of dividends paid
(1) On August 5, 2024, Emera announced the sale of NMGC. As
a result, NMGC's assets and liabilities were classified as held for sale
beginning in Q3 2024. For further details, refer to the
"Other Developments" section and note 4 in the consolidated financial statements.
20
OTHER DEVELOPMENTS
Increase in Common Dividend
On September 25, 2025, the Emera Board of Directors
approved an increase in the annual common
share dividend rate to $2.93 from $2.90 per common
share. The first payment was effective November
14,
2025.
Cybersecurity Incident
On April 25, 2025, Emera and NSPI discovered a cybersecurity
incident involving unauthorized access
into certain parts of its Canadian IT network and
servers supporting portions of its business applications
(the “Cybersecurity Incident’). There was no
disruption to the Canadian physical operations or Emera’s
US or Caribbean utilities’ operations.
The Company implemented business continuity processes
for certain impacted business and
administrative functions at its Canadian affiliates.
The systematic restoration of affected IT systems and
corresponding transition away from business continuity processes
continues to progress in a planned,
controlled and phased approach. For more information on
the impact on internal controls over financial
reporting,
refer to the “Disclosure and Internal Controls” section. The Company maintains cyber insurance
coverage and is working with its insurer on the claims
process. At this time, the Cybersecurity Incident is
not expected to have a material impact on the
Company’s financial position or results of operations. For
information on risks associated with cybersecurity incidents
generally, refer to the “Enterprise Risk and
Risk Management” section.
Pending Sale of NMGC
On August 5, 2024, Emera entered into an agreement to sell
its indirect wholly-owned subsidiary NMGC
for a total enterprise value of approximately $1.3
billion USD, consisting of cash proceeds and the
transfer of
debt and customary closing adjustments. As a result of the pending sale, NMGC’s assets and
liabilities were classified as held for sale in Q3 2024 and
the carrying value of the assets and liabilities
were adjusted to FV less cost to sell. The public hearing
was held in November 2025. The transaction is
expected to
close in the first half of 2026.
At each reporting date, the Company performs an assessment
of the FV of the disposal group by
comparing the FV of
expected transaction proceeds, less costs to sell, to the carrying value of net assets,
including goodwill ("carrying amount"). On June 30, 2025, the
Company remeasured the NMGC disposal
group at the lower of its carrying amount and FV less
costs to sell. As a result of the change in the
expected
timing of the transaction close, a non-cash impairment charge of $75 million ($71 million,
after-
tax), or $55 million USD ($52 million USD, after-tax), was
recorded in “Impairment charges” on the
Consolidated Statements of Income in Q2 2025. An
additional loss for estimated future transaction costs
of $2
million ($1 million after-tax) was recorded in “Other income, net” on the Consolidated Statements of
Income in Q2 2025. There were no additional adjustments recorded
in 2025.
The Company will continue to record depreciation on the
NMGC assets through the transaction closing
date, as the
depreciation continues to be reflected in customer rates and will be reflected in the carryover
basis of the assets when sold. Depreciation and amortization
of $97 million ($70 million USD) was
recorded on these assets from August 5, 2024, the
date they were classified as held for sale, through
December
31, 2025. Of the $97 million ($70 million USD) recorded to date, $71 million ($51 million USD)
was recorded in 2025.
21
US One Big Beautiful Bill Act (“OBBBA”)
On July 4, 2025, the OBBBA was signed into law. The OBBBA
makes permanent many of the expired
and expiring tax provisions originally enacted in the
Tax Cuts and Jobs Act of 2017. It also includes
significant
changes in future years to the timing and availability of several clean energy tax credits
previously enacted in the Inflation Reduction Act, including
the investment tax credit and production tax
credit. On August 15, 2025, the Internal Revenue
Service released guidance on determining when wind
and solar
projects have begun construction for purposes of qualifying for these tax credits. Emera’s 2025
financial statements were not materially impacted as a
result of the enacted changes. Emera will continue
to
evaluate the future impact as additional information and guidance becomes available.
New York Stock Exchange (“NYSE”)
Listing
Emera filed a registration statement dated May 1, 2025
on Form 40-F with the US Securities and
Exchange Commission (“SEC”) to register its
common shares under Section 12 of the Securities
Exchange
Act of 1934. Emera subsequently completed the listing of its common shares on the NYSE and
commenced trading on May 28, 2025. Emera’s common
shares continue to be listed and traded on the
Toronto Stock
Exchange.
Appointments
Executive
Effective March 1, 2026, Vivek Sood will become President
and CEO of NSPI, succeeding Peter Gregg.
Most recently,
Mr. Sood retired as Executive Vice President, Related Businesses from Sobeys Inc. in
2024, and has served as a member of the NSPI Board of
Directors since June 2024.
Effective December 1, 2025, Jared
Green became Emera’s new Chief Financial Officer, succeeding Greg
Blunden. Mr. Green most recently served as President and
Chief Executive Officer of TriSummit Utilities
(previously
AltaGas Canada).
Board of Directors
Effective September 17, 2025, Isabelle Courville joined the
Emera Board of Directors. Ms. Courville is
Chair of the Board of Canadian Pacific Kansas City
and previously served as President of Hydro-Québec
Distribution and Hydro Québec TransÉnergie, as
well as President of Bell Canada’s Enterprise Group.
FINANCIAL HIGHLIGHTS
Florida Electric Utility
Three months ended
Year ended
For the
December 31
December 31
millions of USD (except as
indicated)
2025
2024
2025
2024
Operating revenues – regulated electric
$
$
$
$
Regulated fuel for generation and purchased power
$
$
$
$
Contribution to consolidated adjusted net income
$
$
$
$
Contribution to consolidated adjusted net income - CAD
$
$
$
$
Charges related to wind-down costs and certain asset
impairments, after-tax
(1)
$
$
$
$
Contribution to consolidated net income
$
$
$
$
Contribution to consolidated net income – CAD
$
$
$
$
Average fuel costs in dollars per MWh
$
$
$
$
(1) Net of income tax recovery of $1 million for the three
months and year ended December 31, 2024.
22
The impact of the change in FX rates on CAD earnings was
minimal for the three months ended
December 31, 2025, and increased CAD earnings by $16
million for the year ended December 31, 2025.
Net Income
Highlights of net income changes are summarized in the
following table:
For the
Three months
ended
Year ended
millions of USD
December 31
December 31
Contribution to consolidated net income – 2024
$
83
$
Increased operating revenues primarily due to storm cost recovery
revenue (offset in OM&G), new base rates, higher regulatory deferral
revenue and customer growth. These were partially offset by
unfavourable weather of $10 million quarter-over-quarter. Year
-over-
year increase was also due to favourable weather of $10 million
Increased fuel for generation and purchased power year-over-year due
to higher natural gas prices and higher purchased power
Increased OM&G due to higher storm cost recognition (offset in
revenue), higher costs for employee benefits, operations related to
solar investments, and software maintenance. These were partially
offset by the timing of recognition of regulatory deferrals
Increased depreciation and amortization due to facilities and capital
projects placed in service
Increased interest expense due to higher borrowings
Increased state and municipal taxes due to higher revenues and higher
taxable plant in service
Increased income tax expense year-over-year primarily due to higher
income before provision for income taxes, partially offset by higher
benefit from production tax credits and increased amortization of
deferred investment tax credits
Other
Contribution to consolidated net income – 2025
$
$
Operating Revenues – Regulated Electric
Annual electric revenues and sales volumes are summarized in
the following table by customer class:
Electric Revenues
Electric Sales Volumes
(Gigawatt hours ("GWh"))
2025
2024
2025
2024
Residential
$
$
Commercial
Industrial
Other
(1)
Total
$
$
(1) Other includes regulatory deferrals related to clauses,
sales to public authorities, and off-system sales to other utilities.
23
Regulated Fuel for Generation and Purchased Power
Annual production volumes are summarized in the following
table:
Production Volumes (GWh)
2025
2024
Natural gas
Solar
Purchased power
Coal
Total
TEC’s fuel costs are affected by commodity prices and
generation mix that is largely dependent on
economic dispatch of the generating fleet, bringing the
lowest cost options on first (renewable energy
from solar or
battery storage), such that the incrementa l cost of production increases as sales volumes
increase. Generation mix may also be affected by plant
outages, plant performance, availability of lower
priced
short-term purchased power, availability of renewable solar generation, and compliance with
environmental standards and regulations.
Regulatory Environment
TEC is regulated by the FPSC and is also subject to regulation
by the FERC. The FPSC sets rates at a
level that allows utilities such as TEC to collect total
revenues or revenue requirements equal to their cost
of
providing service, plus an appropriate return on invested capital. Base rates are determined in FPSC
rate setting hearings which can occur at the initiative of
TEC, the FPSC, or other interested parties. For
further details on TEC’s regulatory
environment, base rates and recovery mechanisms, refer to note 7 in
the consolidated financial statements.
Canadian Electric
Utilities
Three months ended
Year ended
For the
December 31
December 31
millions of dollars (except as
indicated)
2025
2024
2025
2024
Operating revenues – regulated electric
$
$
$
$
Regulated fuel for generation and purchased power
(1)(2)
$
$
$
$
Contribution to consolidated net income
$
$
$
$
Average fuel costs in dollars per MWh
(2)
$
$
$
$
(1) Regulated fuel for generation and purchased power
includes NSPI's FAM deferral on the Consolidated Statements of Income,
however, it is excluded in the segment
overview.
(2) Regulated fuel for generation and purchased
power and average fuel costs for 2024 include a $486 million refund of previous
NSPML assessment payments ("NSPML Refund"), which decreased
average fuel costs by $164 per MWh and $43 per MWh for the
three months and year ended December 31, 2024,
respectively. For more information on the NSPML Refund, refer to note 7 in the
consolidated financial statements.
Canadian Electric Utilities' contribution to consolidated
net income is summarized in the following table:
Three months ended
Year ended
For the
December 31
December 31
millions of dollars
2025
2024
2025
2024
NSPI
$
$
$
$
Equity investment in NSPML
Equity investment in LIL
Contribution to consolidated net income
$
$
$
$
24
Net Income
Highlights of net income changes are summarized in the
following table:
For the
Three
months ended
Year ended
millions of
dollars
December 31
December 31
Contribution to consolidated net income – 2024
$
$
Increased operating revenues at NSPI due to higher fuel and storm cost
recoveries, favourable weather, and increased residential and
commercial sales volumes, partially offset by lower industrial sales
volumes
Increased regulated fuel for generation and purchased power at NSPI
due to the 2024 NSPML Refund
(1)
, changes in generation
mix, and
higher sales volumes, partially offset by lower commodity prices
Decreased FAM deferral at NSPI primarily due to the 2024 NSPML
Refund
(1)
Increased OM&G at NSPI quarter-over-quarter due to increased storm
costs and costs related to the Cybersecurity Incident. Year-over-year
increased due to higher costs for transmission and distribution
operations, costs related to the Cybersecurity Incident and power
generation operations, partially offset by higher administrative overhead
allocation to PP&E
Increased depreciation and amortization due to increased PP&E in
service
Decreased income from equity investments due to the sale of equity
interest in LIL
Decreased income tax recovery quarter-over-quarter at NSPI primarily
due to the utilization of tax loss carryforwards recognized as a deferred
income tax regulatory liability in the prior year and decreased tax
deductions in excess of accounting depreciation related to PP&E
Other
Contribution to consolidated net income – 2025
$
$
(1) For more information on the $486 million NSPML Refund
in 2024, refer to note 7 in the consolidated financial statements.
NSPI
Operating Revenues – Regulated Electric
Annual electric revenues and sales volumes are summarized
in the following tables by customer class:
Electric Revenues
Electric Sales Volumes
(millions of dollars)
(GWh)
2025
2024
2025
2024
Residential
$
$
Commercial
Industrial
Other
Total
$
$
25
Regulated Fuel for Generation and Purchased Power
Annual production volumes are summarized in the following table:
Production Volumes (GWh)
2025
2024
Coal
Natural gas
Purchased power
Oil
Petcoke
Total non-renewables
Purchased power - IPP, COMFIT and imports
Wind, hydro and solar
Biomass
Total renewables
Total production volumes
NSPI’s fuel costs are affected by commodity prices
and generation mix, which is largely dependent on
economic
dispatch of the generating fleet. NSPI brings the lowest cost options on stream first after
renewable energy from IPPs including COMFIT participants,
for which NSPI has power purchase
agreements in place, and the NS Block of
energy, including the Supplemental Energy Block, which
carries no additional fuel cost outside of the NSEB approved
annual assessments paid to NSPML for the
use of the Maritime
Link.
Generation mix may also be affected by
plant outages, carbon pricing programs, including the Nova
Scotia Output-Based Pricing System, availability of renewable
generation, availability of energy from the
NS Block, plant
performance, and compliance with environmental regulations.
Regulatory Environment – NSPI
NSPI is a public utility as defined in the Public Utilities
Act of Nova Scotia (“Public Utilities Act”) and is
subject to regulation by the NSEB. The Public
Utilities Act gives the NSEB supervisory powers over
NSPI’s operations and expenditures. NSPI is regulated
under a cost-of-service model, with rates set to
recover prudently incurred costs of providing electricity
service to customers and provide a reasonable
return to
investors. NSPI is not subject to a general annual rate review process but rather participates in
hearings held from time to time at NSPI’s or the
NSEB’s request. For further details on NSPI’s regulatory
environment and recovery mechanisms, refer to note 7 in the
consolidated financial statements.
Gas Utilities and Infrastructure
On August 5, 2024, Emera announced an agreement to sell
NMGC. As a result of the pending sale,
NMGC’s assets and liabilities were classified as
held for sale beginning in Q3 2024. The public hearing
was
held in November 2025. The transaction is expected to close in the first half of 2026, subject to
certain approvals, including regulatory approval by the
NMPRC. For more information on the pending
transaction, refer to the “Other Developments” section.
26
Three months ended
Year ended
For the
December 31
December 31
millions of USD (except as
indicated)
2025
2024
2025
2024
Operating revenues – regulated gas
(1)
$
$
$
$
Operating revenues – non-regulated
Total operating revenue
$
$
$
$
Regulated cost of natural gas
$
$
$
$
Contribution to consolidated adjusted net income
$
$
$
$
Contribution to consolidated adjusted net income – CAD
$
$
$
$
Charges related to the pending sale of NMGC, after-tax
(2)
$
$
$
$
Contribution to consolidated net income
$
$
$
$
Contribution to consolidated net income – CAD
$
$
$
$
(1) Operating revenues – regulated gas includes $12
million of finance income from Brunswick Pipeline (2024 – $12 million) for the
three months ended December 31, 2025 and $46 million (2024
– $46 million) for the year ended December 31 2025; however, it is
excluded from the gas revenues and cost of natural gas
analysis below.
(2) Includes an other impairment charge, net of
income tax recovery of $2 million for the year ended December 31, 2024.
Gas Utilities and Infrastructure's contribution to consolidated
adjusted net income is summarized in the
following table:
Three months ended
Year ended
For the
December 31
December 31
millions of USD
2025
2024
2025
2024
PGS
$
$
$
$
NMGC
Other
Contribution to consolidated adjusted net income
$
$
$
$
The impact of the change in FX rates on CAD earnings was
minimal for the three months ended
December 31, 2025, and increased CAD earnings by $7
million for the year ended December 31,
2025.
Net Income
Highlights of net income changes are summarized in the
following table:
For the
Three
months ended
Year ended
millions of USD
December 31
December 31
Contribution to consolidated net income – 2024
$
$
Increased gas revenues due to higher fuel revenue and higher
off-
system sales at PGS and new base rates at NMGC
Decreased cost of natural gas quarter-over-quarter primarily due to
timing of profit sharing with customers related to asset management
agreements at NMGC. Increased cost of natural gas year-over-year
due to higher natural gas prices at PGS
Increased OM&G primarily due to higher labour costs at NMGC
Increased depreciation primarily due to capital projects in service at
PGS and NMGC
Other
Contribution to consolidated net income – 2025
$
$
27
Operating Revenues – Regulated Gas
Annual gas revenues and sales volumes are summarized in the
following tables by customer class:
Gas Revenues
Gas Volumes
(millions of USD)
(millions of Therms)
2025
2024
2025
2024
Residential
$
$
Commercial
Industrial
(1)
Other
(2)
Total
(3)
$
$
(1) Industrial gas revenue includes sales to power
generation customers.
(2) Other gas revenue includes off-system sales to
other utilities and various other items.
(3) Total gas
revenue excludes $46 million of finance income from Brunswick Pipeline (2024 – $46 million).
Regulated Cost of Natural Gas
PGS and NMGC purchase gas from various suppliers depending
on the needs of their customers. In
Florida, gas is delivered to the PGS distribution
system through interstate pipelines on which PGS has
firm
transportation capacity for delivery by PGS to its customers. NMGC’s natural gas is transported on
major interstate pipelines and NMGC’s intrastate
transmission and distribution system for delivery to
customers.
In Florida, natural gas service is unbundled for
non-residential customers and residential customers who
use
more than 1,999 therms annually and elect the option. In New Mexico, NMGC is required, if
requested, to provide transportation-only services for all
customer classes. The commodity portion of
bundled sales is
included in operating revenues, at the cost of the gas on a pass-through basis, therefore
no net earnings effect when a customer shifts to
transportation-only sales.
Annual gas sales by type are summarized in the
following table:
Gas Volumes by
Type (millions of Therms)
2025
2024
Transportation
System supply
Total
Regulatory Environments
PGS is regulated by the FPSC. The FPSC sets rates at a
level that allows utilities such as PGS to collect
total revenues or revenue requirements equal to
their cost of providing service, plus an appropriate return
on invested capital.
NMGC is subject to regulation by the NMPRC. The NMPRC sets
rates at a level that allows NMGC to
collect total revenues or revenue requirements equal
to its cost of providing service, plus an appropriate
return on invested capital.
For further information on PGS’s and NMGC’s
regulatory environment and recovery mechanisms, refer to
note 7 in the consolidated financial statements.
28
Other Electric
Utilities
Three months ended
Year ended
For the
December 31
December 31
millions of USD (except as
indicated)
2025
2024
2025
2024
Operating revenues – regulated electric
$
$
$
$
Regulated fuel for generation and purchased power
$
$
$
$
Contribution to consolidated adjusted net income
$
$
$
$
Contribution to consolidated adjusted net income – CAD
$
$
$
$
Equity securities MTM loss
$
$
$
$
Contribution to consolidated net income
$
$
$
$
Contribution to consolidated net income – CAD
$
$
$
$
Electric sales volumes (GWh)
Electric production volumes (GWh)
Average fuel cost in dollars per MWh
$
$
$
$
The impact of the change in FX rates on CAD earnings and
adjusted net income for the three months and
year ended December 31, 2025 was minimal.
Other Electric Utilities' contribution to consolidated adjusted
net income is summarized in the following
table:
Three months ended
Year ended
For the
December 31
December 31
millions of USD
2025
2024
2025
2024
BLPC
$
$
$
$
GBPC
Other
Contribution to consolidated adjusted net income
$
$
$
$
Net Income
Highlights of net income changes are summarized in the
following table:
For the
Three
months ended
Year ended
millions of USD
December 31
December 31
Contribution to consolidated net income – 2024
$
$
Decreased operating revenues quarter-over-quarter due to lower fuel
revenue and lower miscellaneous revenue at BLPC
Decreased regulated fuel for generation and purchased power due to
lower fuel costs at BLPC and GBPC
Increased income tax expense year-over-year due to the 2025
remeasurement of deferred income tax liabilities as a result of a
corporate income tax rate change at BLPC
Increased depreciation and amortization expense at GBPC due to
increased generation units in service
Other
Contribution to consolidated net income – 2025
$
$
Regulatory
Environments
BLPC is regulated by the FTC. Rates are set to
recover prudently incurred costs of providing electricity
service to customers plus an appropriate return on capital
invested.
GBPC is regulated by the GBPA. Rates are
set to recover prudently incurred costs of providing electricity
service to customers plus an appropriate return on rate
base.
29
For
further details on BLPC and GBPC’s regulatory environments and recovery mechanisms, refer to note
7 in the consolidated financial
statements.
Other
Three
months ended
Year ended
For the
December 31
December 31
millions of dollars
2025
2024
2025
2024
Marketing and trading margin
(1)(2)
$
$
$
$
Other non-regulated operating revenue
Total operating revenues – non-regulated
$
$
$
$
Contribution to consolidated adjusted net (loss) income
$
$
$
$
MTM (loss) gain, after-tax
(3)
Charges related to the pending sale of NMGC, after-tax
(4)
Gain on sale of LIL, after-tax
(5)(6)
Financing structure wind-up
Charges related to wind-down costs and certain asset
impairments, after-tax
(7)
Contribution to consolidated net (loss) income
$
$
$
$
(1) Marketing and trading margin represents EES's purchases
and sales of natural gas and electricity, pipeline and storage
capacity costs and energy asset management
services’ revenues.
(2) Marketing and trading margin
excludes a MTM loss, pre-tax of $144 million in Q4 2025 (2024 – $159 million loss) and a MTM
gain, pre-tax of $16 million for the year ended December
31, 2025 (2024 – $357 million loss).
(3) Net of
income tax recovery of $39 million for the three months ended December 31, 2025 (2024 – $57 million
recovery) and $17
million expense for the year ended December 31,
2025 (2024 – $117 million recovery).
(4) Includes an impairment charge of $75 million
($71 million after-tax) and transaction costs of $2 million ($1 million after-tax) for
the year ended December 31, 2025, and impairment charges of
$210 million ($198 million, after-tax) and transaction costs of $25
million ($19 million after-tax) for the year ended December
31, 2024.
(5) On June 4, 2024, Emera completed the sale of
its LIL equity interest. For further details on the transaction, refer to note 4 in the
consolidated financial statements.
(6) Includes an income tax recovery of $22 million for the
three months ended December 31, 2024 and net income tax expense of
$53 million for the year ended December 31, 2024.
(7) Primarily relates to Block Energy, net of income tax recovery of
$6 million for the year ended December 31, 2024.
Other's
contribution to consolidated adjusted net (loss) income is summarized in the following table:
Three months ended
Year ended
For the
December 31
December 31
millions of dollars
2025
2024
2025
2024
Emera Energy:
$
$
$
$
Corporate – see breakdown below
Block Energy
Other
Contribution to consolidated adjusted net (loss) income
$
$
$
$
30
Net Income (Loss)
Highlights of net income (loss) changes are summarized in the
following table:
For the
Three
months ended
Year ended
millions of dollars
December 31
December 31
Contribution
to consolidated net (loss) income – 2024
$
$
Increased marketing and trading margin at EES due to favourable
weather conditions that led to higher natural gas prices and increased
volatility that created profitable opportunities
Decreased equity earnings at Bear Swamp due to lower generation as
a result of a prolonged unplanned outage
Increased interest expense primarily due to increased Corporate debt
and the impact of a weaker CAD on USD interest expense, partially
offset by lower interest rates
Decreased income tax recovery due to decreased loss before
provision for income taxes and decreased deferred income tax asset
valuation allowance adjustment
Decreased MTM loss, after-tax, due to a gain on Corporate FX
hedges compared to a loss in prior year. Year -over-year also
decreased due to changes in existing positions and lower amortization
of gas transportation assets at EES
Charges related to the pending sale of NMGC, after-tax
Gain on sale of LIL, after-tax in 2024
Financing structure wind-up in 2024
Charges related to wind-down costs and certain asset impairments,
after-tax in 2024
Other
Contribution to consolidated net (loss) income – 2025
$
$
Emera Energy
EES derives revenue and earnings from wholesale marketing
and trading of natural gas and electricity
within the Company’s risk tolerances, including
those related to value-at-risk (“VaR”) and credit exposure.
EES purchases and sells physical natural gas and electricity,
the related transportation and transmission
capacity rights, and provides energy asset
management services. The primary market area for the natural
gas and power marketing and trading business is northeastern
North America, including the Marcellus
and Utica shale supply areas. EES also participates in the
US Southeast, Gulf Coast and Midwest, and
Central Canadian
and Alberta natural gas markets. Its counterparties include electric and gas utilities,
natural gas producers, electricity generators and other marketing
and trading entities. EES operates in a
competitive environment, and the business relies on
knowledge of the region’s energy markets,
understanding of pipeline and transmission infrastructure,
a network of counterparty relationships and a
focus on customer service. EES manages its commodity
risk by limiting open positions, utilizing financial
products to hedge purchases and sales, and investing in
transportation capacity rights to enable
movement across
its portfolio.
In 2025, as a result of a strong Q1, EES adjusted
its annual earnings guidance range to $35 million USD
to
$45 million USD. EES’ contribution to consolidated adjusted net income was $33 million in Q4 2025,
compared to $16 million in Q4 2024; and $80 million ($57
million USD) for the year ended December 31,
2025, compared to $30 million ($21 million USD) for the
same period in 2024. Market conditions in 2025
were
favourable compared to 2024 due to weather conditions which led to higher natural gas prices and
volatility.
31
MTM Adjustments
Emera Energy’s “Marketing and trading margin”,
“Income from equity investments” and “Income tax
expense (recovery)” are affected by MTM adjustments.
Variance explanations of the MTM changes for
this
quarter and for the year are explained in the table above.
Emera Energy has a number of asset management agreements
(“AMA”) with counterparties, including
local gas distribution utilities, power utilities and natural
gas producers in North America. The AMAs
involve Emera
Energy buying or selling gas for a specific term, and the corresponding release of the
counterparties’ gas transportation/storage capacity to Emera
Energy. MTM adjustments on these AMAs
arise on the price
differential between the point where gas is sourced and where it is delivered. At
inception, the MTM adjustment is offset fully by the value
of the corresponding gas transportation asset,
which is amortized over the term of the AMA
contract.
Subsequent changes in gas price differentials,
to the extent they are not offset by the accounting
amortization of the gas transportation asset, will result in
MTM gains or losses recorded in income. MTM
adjustments may be substantial during the term of the
contract, especially in the winter months of a
contract
when delivered volumes and market pricing are usually at peak levels. As a contract is realized,
and volumes reduce, MTM volatility is expected to decrease.
Ultimately, the gas transportation asset and
the MTM
adjustment reduce to zero at the end of the contract term. As the business grows, and AMA
volumes increase, MTM volatility resulting in gains and
losses may also increase.
Emera Corporate has FX forwards to manage the
cash flow risk of forecasted USD cash inflows.
Fluctuations
in the FX rate result in MTM gains or losses , which are recorded in “Other income, net” on
the Consolidated Statements of Income.
Corporate
Corporate's adjusted loss is summarized in the following table:
Three months ended
Year ended
For the
December 31
December 31
millions of dollars
2025
2024
2025
2024
Operating
expenses
$
$
$
$
Interest expense
Income tax recovery
Preferred dividends
Other
Corporate adjusted net
loss
$
$
$
$
(1) Operating expenses include OM&G and depreciation.
(2) Other includes realized gains and losses on FX
hedges entered into to hedge USD denominated operating unit earnings
exposure.
(3) Includes a realized net loss, pre-tax of $4 million ($2
million after-tax) for the three months ended December 31, 2025 (2024 – $5
million net loss, pre-tax and $4 million loss, after-tax)
and a $16 million net loss, pre-tax ($11 million after-tax) for the year ended
December 31, 2025 (2024 – $12 million net loss,
pre-tax and $9 million loss after-tax) on FX hedges, as discussed above.
(4) Excludes a MTM gain, after-tax of $5 million for the
three months ended December 31, 2025 (2024 – $25 million loss, after-tax)
and a MTM gain, after-tax of $28 million for the year ended
December 31, 2025 (2024 – $31 million loss, after-tax).
(5) Excludes a gain on sale of LIL, after-tax, of $107
million for the year ended December 31, 2024.
(6) Excludes
certain charges related to the pending sale of NMGC of $77 million ($72 million after-tax) for the year ended
December
31, 2025 (2024 - $235 million, pre-tax and $217
million, after-tax).
(7) Excludes the tax recovery of $58
million related to a specific financing structure and its wind-up and $22 million on reversal of a
prior year valuation allowance related to the sale of LIL
for the three months and year ended December 31, 2024.
32
LIQUIDITY AND CAPITAL
RESOURCES
The Company generates internally sourced cash from
its various regulated and non-regulated energy
investments.
Utility customer bases are diversified by both sales volumes and revenues among customer
classes. Emera’s non-regulated businesses provide
diverse revenue streams and counterparties to the
business. Circumstances that could affect the
Company’s ability to generate cash include changes to
global macro-economic conditions, downturns in markets
served by Emera, impact of fuel commodity
price changes on collateral requirements and timely
recoveries of fuel and storm costs from customers,
the loss
of one or more large customers, regulatory decisions affecting customer rates and the recovery
of regulatory assets, and changes in environmental legislation.
Emera’s subsidiaries are generally in a
financial position to contribute cash dividends to Emera
provided they do not breach their debt covenants,
where
applicable, after giving effect to the dividend payment, and that they maintain their credit metrics.
Emera’s future liquidity and capital needs will be
predominately for working capital requirements, ongoing
rate base investment, business acquisitions,
greenfield development, dividends and debt servicing.
Emera
has an approximate $20 billion capital investment plan over the 2026 through 2030 period and
supports ongoing growth. Capital investments at Emera’s
regulated utilities are subject to regulatory
approval.
Emera has sufficient liquidity to service debt obligations
as they come due and to meet any near-term
capital investment requirements as currently planned.
Emera plans to use cash from operations, debt
raised at the
utilities, Corporate equity, and proceeds from the pending sale of NMGC to support normal
operations, repayment of existing debt, and capital requirements.
Debt raised at certain of the Company’s
utilities is subject to applicable regulatory approvals.
Generally, Corporate equity requirements in support
of the
Company’s capital investment plan are expected to be funded through issuance of hybrid securities
and issuance of common equity through Emera’s DRIP
and ATM programs.
Emera has total committed credit facilities with
varying maturities that cumulatively provide $2.8 billion
CAD and $2.1 billion USD of credit, with approximately $999
million CAD and $1,056 million USD
undrawn and available at December 31, 2025. The Company
was holding a cash balance of $355 million,
which includes
$6 million classified as assets held for sale, related to the pending sale of NMGC, at
December 31, 2025. For further discussion, refer to the
“Debt Management” section below.
Consolidated Cash Flow Highlights
Significant changes in the Consolidated Statements of Cash
Flows between the years ended December
31, 2025 and 2024 include:
millions of dollars
2025
2024
Change
Cash, cash equivalents, restricted cash, and cash associated with assets held
for sale, beginning of period
$
$
$
Provided by (used in):
Operating activities
$
$
$
Investing activities
Financing activities
Effect of exchange rate changes on cash, cash equivalents, restricted cash, and
cash associated with assets held for sale
Cash, cash equivalents, restricted cash, and cash associated with assets held
for sale, end of period
$
$
$
33
Cash Flow from Operating Activities
Net cash provided by operating activities decreased $844 million
to $1,802 million for the year ended
December 31, 2025, compared to $2,646 million in 2024.
Cash from operations before changes in working capital
increased $365 million for the year ended
December 31, 2025. This increase was due to
higher storm cost recoveries at TEC, new base rates at
TEC
and NMGC, and higher marketing and trading margin at EES. These were partially offset by
proceeds from the FAM asset sale at NSPI in Q2 2024 and
higher fuel under-recoveries at TEC.
Changes in working
capital decreased operating cash flows by $1,209 million for the year ended
December 31, 2025. This decrease was due to unfavourable
changes in accounts payable at TEC
reflecting the timing and payment of storm invoices,
unfavourable changes in accounts receivable at TEC
due to
increased base rates and storm cost recoveries, and unfavourable changes in accounts receivable
and fuel inventory at NSPI. These were partially offset by
favourable changes in accounts receivable at
PGS.
Cash Flow Used in Investing Activities
Net cash used in investing activities increased $1,264 million to
$3,482 million for the year ended
December 31, 2025, compared to $2,218 million in 2024.
The increase was due to the proceeds of $927
million
received in 2024 on the sale of LIL and higher capital investment, partially offset by proceeds on
the disposal of assets.
Capital expenditures for the year ended December 31, 2025,
including AFUDC, were $3,594 million
compared to $3,206 million in 2024. Details of capital
spending by segment are shown below:
●
●
●
●
●
Cash Flow from Financing Activities
Net cash provided by financing activities increased $2,659
million to $1,841 million for the year ended
December 31, 2025, compared to net cash used in
financing activities of $818 million in 2024. The
increase
was due to higher net borrowings on committed credit facilities at NSPI and TEC, higher
proceeds from Corporate debt, proceeds from short-term debt
issuances at NSPI and NMGC, retirement
of long-term debt at TEC and NMGC in 2024 and
higher proceeds from long-term debt at TEC. These
were
partially offset by lower proceeds from long-term debt at PGS, lower issuance of common stock, and
retirement of long-term debt at NSPI.
Working Capital
As at December 31, 2025, Emera’s cash and cash
equivalents were $349 million (2024 – $196 million)
and Emera’s investment in non-cash working
capital was $926 million (2024 – $224 million). Of the cash
and cash equivalents held at December 31, 2025, $279 million
was held by Emera’s foreign subsidiaries
(2024 – $185 million). A portion of these funds are
invested in countries that have certain exchange
controls,
approvals, and processes for repatriation. Such funds are available to fund local operating and
capital requirements unless repatriated.
34
Contractual Obligations
As at December 31, 2025, contractual commitments for each
of the next five years and in aggregate
thereafter consisted of the following:
millions of dollars
2026
2027
2028
2029
2030
Thereafter
Total
Long-term debt
principal
$
$
$
$
$
$
$
Interest payment obligations
(3)(4)
Purchased power
(5)
Transportation
(6)(7)
Fuel, gas supply and storage
(8)
Pension and post-retirement
obligations
(9)
Asset retirement obligations
Capital
projects
Other
$
$
$
$
$
$
$
As detailed below, contractual obligations at December 31, 2025
includes those related to NMGC. On completion of the sale of
NMGC, all remaining future contractual obligations will be
transferred to the buyer. For further details on the pending transaction,
refer to the "Other Developments" section.
(1) Includes $663 million related to NMGC (2026: $96
million, and $567 million thereafter).
(2) The Company’s $1.2 billion USD, $750 million
USD and $500 million USD hybrid notes mature in 2076, 2056 and 2054,
respectively, and these maturity dates have been used in the
computation of the Company’s long-term debt principal and interest
payment obligations at December 31, 2025. The Company has
the option to repay such notes in advance of maturity upon exercise
of the Company’s redemption rights in accordance with
the terms of the applicable indenture. Emera’s $1.2 billion USD hybrid notes
are redeemable, at Emera’s option, in June 2026.
(3) Future interest payments are calculated based on the
assumption that all debt is outstanding until maturity. For debt instruments
with variable rates, interest is calculated for all future
periods using the rates in effect at December 31, 2025, including any expected
required payment under associated swap agreements.
(4) Includes $311 million related to NMGC (2026: $25 million,
2027: $22 million, 2028: $22 million, 2029: $22 million, 2030: $22
million, and $198 million thereafter).
(5) Annual requirement to purchase electricity from IPPs or
other utilities over varying contract lengths.
(6) Purchasing commitments for transportation
of fuel and transportation capacity on various pipelines. Includes a commitment of
$121 million related to a gas transportation contract between
PGS and SeaCoast through 2040.
(7) Includes $61 million related to NMGC (2026:
$23 million, 2027: $15 million, 2028: $12 million, 2029: $3 million, 2030: $3 million
and $5 million thereafter).
(8) Includes $101 million related to NMGC (2026: $86
million, 2027: $12 million and, 2028: $3 million).
(9)
Includes the estimated contractual obligation, which is calculated as the current legislatively required
contributions to the
registered funded pension plans, plus the
estimated costs of further benefit accruals contracted under NSPI's Collective Bargaining
Agreement and estimated benefit payments related to other
unfunded benefit plans.
NSPI has a contractual obligation
to pay NSPML for use of the Maritime Link over approximately 38 years
from its January 15, 2018 in-service date. On December 23,
2025, NSPML received an interim order from
the NSEB to collect up to $199 million from NSPI for
the recovery of costs associated with the Maritime
Link in
2026, subject to a monthly holdback of up to $4 million. The timing and amounts payable to
NSPML for the remainder of the 38-year commitment period
are subject to NSEB approval.
Emera has committed to obtain certain transmission
rights in New Brunswick during summer periods
(April
through October, inclusive) for NLH’s use, if requested, effective August 15, 2021 and continuing for
50 years. As transmission rights are contracted, the obligations
are included within “Other” in the above
table.
35
Forecasted Consolidated Capital Investments
The 2026 forecasted consolidated capital investments,
including AFUDC, are as follows:
millions of dollars
Florida
Electric
Utility
Canadian
Electric
Utilities
Gas Utilities
and
Infrastructure
Other
Electric
Utilities
Other
Total
Generation
$
$
$
$
$
$
New renewable generation
Electric transmission
(1)
Electric distribution
Gas transmission and distribution
Facilities, equipment, vehicles, and other
$
$
$
$
$
$
(1) Electric transmission for the Canadian Electric Utilities
segment includes $40 million related to NSPML, which is recorded as
"Investments subject to significant influence" on Emera's
Consolidated Balance Sheets.
Debt
Management
In addition to funds generated from operations,
Emera and its subsidiaries have, in aggregate, access to
unsecured committed syndicated revolving and non-revolving
bank lines of credit in either CAD or USD
per the table below.
Undrawn
Credit
and
millions of dollars
in currency as noted below
Maturity
Facilities
Utilized
Available
In CAD:
June 2029
$
$
$
June 2029
May 2026
February 2027
In USD:
November 2030
November 2030
November 2030
December 2027
(1)
October 2026
Various
(1) On August 5, 2024, Emera announced an agreement to sell
NMGC. As a result, NMGC's assets and liabilities were classified as
held for sale beginning in Q3 2024. For further details on
the pending transaction, refer to the "Other Developments" section.
Emera and its subsidiaries have certain financial and other
covenants associated with their debt and
credit facilities. Covenants are tested
regularly, and the Company is in compliance with covenant
requirements as at December 31, 2025. Emera’s
significant covenant is listed below:
As at
Financial Covenant
Requirement
December 31, 2025
Emera
Syndicated credit
facilities
Debt to capital ratio
Less
than or equal to 0.70 to 1
0.53 : 1
36
Recent
significant financing activity for Emera and its subsidiaries are discussed below by segment:
Florida Electric Utility
On November 20, 2025, TEC amended and restated its $800
million USD committed revolving credit
facility to extend the maturity date from December 1,
2028, to November 20, 2030 and increased the
amount to $1.2
billion USD. There were no other material changes in commercial terms from the prior
agreement.
On March 6, 2025, TEC issued $600 million USD of senior
unsecured notes that bear interest at 5.15 per
cent with a maturity date of March 1, 2035. Proceeds
from this issuance were used for the repayment of a
portion
of TEC’s outstanding commercial paper.
Canadian Electric Utilities
On May 21, 2025, NSPI entered into a $500 million
non-revolving facility which matures on May 21, 2026.
The
credit agreement contains customary representations and warranties, events of default and financial
and other covenants. The non-revolving facility’s
interest rates are referenced to the Term CORRA or
prime rate, plus a margin. Proceeds from this facility were
used for general corporate purposes.
Gas
Utilities and Infrastructure
On November 20, 2025, PGS amended and restated
its $250 million USD unsecured committed revolving
credit
facility to extend the maturity date from December 1, 2028, to November 20, 2030. There were no
other changes in commercial terms from the prior agreement.
On October 23, 2025, NMGC entered into a $70 million USD,
364-day term loan agreement which
matures on October 22, 2026. The credit agreement
contains customary representations and warranties,
events
of default and financial and other covenants. The non-revolving facility’s interest rates are
referenced to the Term SOFR plus a margin. Proceeds from
this facility were used for general corporate
purposes.
On September 19, 2025, NMGC amended its $125 million
USD unsecured committed revolving credit
facility to extend the maturity date from December
17, 2026, to December 17, 2027. There were no other
changes
in commercial terms from the prior agreement.
Other
On February 20, 2026, Emera amended its $200 million
unsecured non-revolving facility to extend the
maturity
date from February 20, 2026 to February 19, 2027. There were no other material changes to the
terms from the prior agreement.
On November 20, 2025, TECO Finance amended and restated its
$400 million USD unsecured
committed revolving credit facility to extend the
maturity date from December 1, 2028, to November 20,
2030.
There were no other changes in commercial terms from the prior agreement.
On September 25, 2025, EUSHI Finance, Emera US Holdings
Inc. (“EUSHI”) and Emera filed a shelf
registration statement on Form F-10 and Form F-3
(“Registration Statement”), with the Nova Scotia
Securities Commission (“NSSC”) and the SEC under the
US/Canada Multijurisdictional Disclosure
System. The
Registration Statement was filed in connection with the prospective offer and issue by
EUSHI Finance of one or more series of senior and/or subordinated
unsecured debt securities (“Debt
Securities”), in an aggregate principal amount of up
to $3 billion USD, during the 25-month period that the
short form base shelf prospectus contained in the Registration
Statement (“Base Shelf Prospectus”),
including any further amendments thereto, remains
valid. The Debt Securities may be offered in one or
more
transactions, at prices, with maturities and on terms to be set forth in one or more prospectus
supplements to be filed with the NSSC and the SEC at the time
of any such offering.
37
On October
3, 2025, EUSHI Finance completed an issuance of $750 million USD fixed-to-fixed reset rate
junior subordinated notes, pursuant to the prospectus
supplement dated September 29, 2025, to the
Base Shelf Prospectus. The notes initially bear
interest at a rate of 6.25 per cent, and will reset on April 1,
2031, and every five years thereafter, to a rate per annum
equal to the five-year US treasury rate plus
2.509 per
cent, subject to an interest rate floor of 6.25 per cent. The notes mature on April 1, 2056.
EUSHI Finance, at its option, may redeem the notes, in
whole or in part, 90 days prior to the first interest
reset date, and any semi-annual interest
payment date thereafter, at a redemption price equal to the
principal amount, plus accrued and unpaid interest on the notes
to be redeemed, in accordance with the
terms of the prospectus supplement; and otherwise,
at the times and the redemption prices described in
the
prospectus supplement. The notes are fully and unconditionally guaranteed, on a joint, several and
subordinated basis, by Emera, and EUSHI. Proceeds from this
issuance were used for general corporate
purposes, including repayment of existing
debt.
On February 20, 2025, Emera amended its $200
million unsecured non-revolving facility to extend the
maturity date from February 20, 2025 to February 20, 2026.
There were no other material changes to the
terms from the prior agreement.
Credit Ratings
Emera and its subsidiaries have been assigned the following
senior unsecured debt ratings:
Fitch
S&P
Moody's
DBRS
Emera
(1)
BBB (Stable)
BBB- (Stable)
Baa3 (Negative)
N/A
TEC
(1)
A (Stable)
BBB+ (Stable)
A3 (Negative)
N/A
PGS
(1)
A (Stable)
N/A
N/A
N/A
NMGC
BBB+ (Stable)
N/A
N/A
N/A
NSPI
N/A
BBB- (Stable)
N/A
BBB (high)(stable)
(1)
On May 27, 2025, Fitch Ratings ("Fitch") revised its outlook on Emera, TEC and PGS to stable from negative with
no changes to
existing ratings.
Guaranteed Debt
As of December 31, 2025, the Company had $3.70 billion USD
(2024 – $2.95 billion USD) senior
unsecured notes and junior subordinated notes (collectively
referred to as the "US Notes”) outstanding.
The US
Notes are fully and unconditionally guaranteed, on a joint and several basis, and in the case of
the fixed-to-fixed reset rate junior subordinated notes due 2054
and 2056, on a joint, several and
subordinated basis, by Emera and EUSHI (in such
capacity, the “Guarantor Subsidiaries”). Emera owns,
directly or indirectly, all of the limited and general
partnership interests in Emera US Finance LP. EUSHI
Finance is owned indirectly by Emera through EUSHI.
Other subsidiaries of the Company do not guarantee the US
Notes (such subsidiaries are referred to as
the "Non-Guarantor Subsidiaries");
however, Emera has unrestricted access to the assets of consolidated
entities.
In compliance with Rule 13-01 of Regulation S-X, the
Company is including summarized financial
information for Emera, EUSHI, Emera US Finance
LP and EUSHI Finance (together, the "Obligor
Group"), on a combined basis after transactions and balances
between the combined entities have been
eliminated. Investments in and equity earnings of
the Non-Guarantor Subsidiaries have been excluded
from the
summarized financial information.
The Obligor Group was not determined using geographic,
service line or other similar criteria and, as a
result,
the summarized financial information includes portions of Emera’s domestic and international
operations. Accordingly, this basis of presentation is not
intended to present Emera’s financial condition
or
results of operations for any purpose other than to comply with the specific requirements for guarantor
reporting.
38
Summarized Statement of Income
The Company recognized income related to guaranteed debt
under the following categories:
For the
Year ended December 31
millions of dollars
2025
2024
Loss from operations
$
$
Net gains
(1)
$
$
(1) Includes $1,143 million (2024 – $1,352 million)
in interest and dividend income, net, from non-guarantor subsidiaries.
Summarized Balance Sheet
The Company has the following categories on the balance
sheet related to guaranteed debt:
As at
December 31
millions of dollars
2025
2024
Current
assets
$
$
Goodwill
Other assets
(2)
Total
assets
$
$
Current liabilities
(4)
$
$
Long-term liabilities
(5)
Total liabilities
$
$
(1) Includes $275 million (2024 – $217 million) in
amounts due from non-guarantor subsidiaries.
(2) Includes $4,714 million (2024 – $5,937
million) in amounts due from non-guarantor subsidiaries.
(3) Excludes investments in non-guarantor subsidiaries.
Consolidated Emera total assets are $44,817 million (2024 – $42,951 million).
(4) Includes $206 million (2024 – $184 million) due to
non-guarantor subsidiaries.
(5) Includes $4,609 million (2024 – $5,980
million) due to non-guarantor subsidiaries.
Outstanding Stock Data
Common Stock
millions of
millions of
Issued and outstanding:
shares
dollars
Balance, December 31, 2024
295.94
$
9,042
Conversion of Convertible Debentures
0.02
1
Issuance of common stock under ATM program
(1)
0.19
9
Issued under the
DRIP, net of discounts
4.83
293
Senior management stock options
exercised and Employee Share Purchase Plan
0.78
42
Balance, December 31,
2025
301.76
$
9,387
(1) For the year ended December 31, 2025, a total of
187,600 common shares were issued under Emera's ATM program at an
average price of $53.58 per share for gross proceeds of $10
million ($9 million, net of after-tax issuance costs). As at December 31,
2025, an aggregate gross sales limit of $600 million
remained available for issuance under the ATM program.
As at
February 18, 2026, the amount of issued and outstanding common shares was 303.0 million.
If all outstanding stock options were converted as at February
18, 2026, an additional 4.1 million common
shares would be issued and outstanding.
39
ATM Equity Program
On December 5, 2025, Emera renewed its ATM Program by
filing a prospectus supplement to the
Company's Canadian short form base shelf
prospectus with the securities regulatory authorities in each of
the provinces of Canada. At the same time, Emera filed a US
prospectus supplement to the Company’s
US base prospectus included in its US registration
statement on Form F-10 with the SEC. The ATM
Program allows
the Company to issue up to $600 million of common shares from treasury to the public
from time to time, at the Company’s discretion, at
the prevailing market price. The ATM Program is
expected to
remain in effect until January 5, 2029.
Preferred Stock
As at February 18, 2026, Emera had the following preferred
shares issued and outstanding: Series A –
6.0 million; Series C – 10.0 million; Series E – 5.0
million; Series F – 8.0 million; Series H – 12.0 million;
Series J – 8.0 million, and Series L – 9.0 million.
Emera’s preferred shares do not have voting rights
unless the Company fails to pay, in aggregate, eight
quarterly dividends.
On July 9, 2025, Emera announced it would not redeem
the currently outstanding Cumulative 5-Year
Rate Reset
Preferred Shares, Series A (“Series A Shares”) or the Cumulative Floating Rate First
Preferred Shares, Series B (“Series B Shares”) on August
15, 2025 (the “Conversion Date”).
On July 16, 2025, Emera announced a dividend rate of 4.951
per cent per annum on the Series A Shares
during the
five-year period commencing on August 15, 2025 and ending on (and inclusive of) August 14,
2030 ($0.3094 per Series A Share per quarter).
During the conversion period between July 16, 2025 and July
31, 2025, the holders of Series A Shares
had the right, at their option, to convert all or any of
their Series A Shares, on a one-for-one basis, into
Series
B Shares and the holders of Series B Shares had the right, at their option, to convert all or any of
their Series B Shares, on a one-for-one basis, into Series
A Shares. On August 7, 2025, Emera
announced, after having taken into account all
shares tendered for conversion by holders of its Series A
Shares and Series B Shares, as the case may be (collectively,
the “Holders”), by the end of the
conversion period, the Company
had determined that there would be outstanding on the Conversion Date
less than 1 million Series B Shares. Therefore, in accordance
with certain rights, privileges, restrictions
and conditions attaching to the Series A Shares and
the Series B Shares, the Company advised the
Holders that
no Series A Shares would be converted into Series B Shares and all remaining Series B
Shares would automatically be converted into Series A
Shares on a one-for-one basis on the Conversion
Date. On the Conversion Date, there were 6 million
Series A Shares and no Series B Shares outstanding.
On
January 16, 2025, Emera announced that the annual fixed dividend per share for Series F shares
would be reset from $1.0505 to $1.4372 for the five-year
period from and including February 15, 2025.
PENSION FUNDING
For funding purposes, Emera determines required contributions
to its largest defined benefit (“DB”)
pension plans based on smoothed asset values. This
reduces volatility in the cash funding requirement
as the
impact of investment gains and losses are recognized over a multi-year period. Expected cash flow
for DB pension plans is $34 million in 2026 (2025 – $38
million). All pension plan contributions are tax
deductible and will be funded with cash from operations.
Emera’s DB pension plans employ a long-term strategic
approach with respect to asset allocation, real
return and risk. The underlying objective is to earn an
appropriate return, given the Company’s goal of
preserving capital with an acceptable level of risk for the
pension fund investments.
40
To achieve the overall long-term asset allocation,
pension assets are managed by external investment
managers
per each pension plan’s investment policy and governance framework. The asset allocation
includes investments in the assets of domestic and global
equities, domestic and global bonds and short-
term investments. The Company reviews investment
manager performance on a regular basis and
adjusts the
plans’ asset mixes as needed in accordance with the pension plans’ investment policy.
Emera’s projected contributions to defined contribution
pension plans are $53 million for 2026 (2025 –
$51
million).
Defined Benefit Pension Plan
Summary
in millions of dollars
Plans by region
TECO Holdings
NSPI
Caribbean
Total
Assets as at
December 31, 2025
$
$
$
$
Accounting obligation at December 31, 2025
$
$
$
$
Accounting expense (income) during fiscal 2025
$
$
$
$
Off-Balance Sheet
Arrangements
Defeasance
Upon privatization in 1992, NSPI became responsible for
managing a portfolio of defeasance securities
that provide principal and interest streams to match
the related defeased debt, which at December 31,
2025
totalled $200 million (2024 – $200 million). The securities are held in trust for an affiliate of the
Province of Nova Scotia. Approximately 66 per cent of the
defeasance portfolio consists of investments in
the related debt, eliminating all risk associated with
this portion of the portfolio.
Guarantees
and Letters of Credit
Emera has guarantees and letters of credit on behalf of
third parties outstanding. The following significant
guarantees and letters of credit were not included within
the Consolidated Balance Sheets as at
December 31,
2025:
Emera, on behalf of Brunswick Pipeline, issued a standby
letter of credit for $22 million to secure
obligations under a non-revolving loan agreement.
This standby letter of credit has a one-year term,
expiring
on March 31, 2026, and will be renewed annually, as
required.
TECO Holdings Inc. (“TECO Holdings”), issued a
guarantee in connection with SeaCoast’s performance
of obligations under a gas transportation precedent agreement.
The guarantee is for a maximum potential
amount of $45 million USD if SeaCoast fails to pay or
perform under the contract. The guarantee expires
five years
after the gas transportation precedent agreement termination date, which was terminated on
January 1, 2022. The counterparty has the right to require
TECO Holdings to provide replacement credit
support either in the form of a substitute guarantee from
an affiliate with an investment grade credit rating
or a
letter of credit or cash deposit of $27 million USD.
TECO Holdings issued a guarantee in connection
with SeaCoast’s performance obligations under a firm
service agreement, which expires December 31, 2055, subject
to two extension terms at the option of the
counterparty with a final expiration date of December 31,
2071. The guarantee is for a maximum potential
amount of
$13 million USD if SeaCoast fails to pay or perform under the firm service agreement. The
counterparty has the right to require TECO Holdings to provide
replacement credit support in the form of
either a substitute guarantee from an
affiliate with an investment grade credit rating or a letter of credit or
cash deposit of $13 million
USD.
Emera has a guarantee of $66 million USD relating to
outstanding notes of ECI. This guarantee will
automatically terminate on the date upon which the
obligations have been repaid in full.
41
NSPI has
guarantees on behalf of its subsidiary, NS Power Energy Marketing Incorporated, in the amount
of $94 million USD (2024 – $104 million USD) with terms
of varying lengths.
Brunswick Pipeline, jointly and severally with Emera, have
an indemnity agreement in support of a $40
million surety
bond issued in Brunswick Pipeline’s favour to the CER. The purpose of the surety bond is to
satisfy Brunswick Pipeline’s regulatory obligation to
have funds set aside for the future abandonment of
the pipeline.
The Company has standby letters of credit and surety bonds
in the amount of $271 million USD
(December 31, 2024 – $105 million USD) to third
parties that have extended credit to Emera and its
subsidiaries. These letters of credit and surety bonds typically
have a one-year term and are renewed
annually as
required.
Emera, on behalf of NSPI, has a standby letter of credit to
secure obligations under a supplementary
retirement plan.
The expiry date of this letter of credit was extended to June 2026. The amount committed
as at December 31, 2025 was $70 million (December 31, 2024
– $58 million).
Emera has provided an indemnity to a counterparty in
relation to certain future tax amounts that could
arise
from specific future changes in Canadian federal law, subject to certain conditions and limitations.
No such changes in law have been proposed at this time. A
reasonable estimate of the potential amount
of future payments that could result from future
claims under this indemnity cannot be calculated, but the
risk of having to make any significant payments under this
indemnity is considered to be remote.
DIVIDEND
PAYOUT RATIO
Emera has provided annual dividend growth
guidance of one to two per cent per year. On September 25,
2025, the Board approved an increase in the annual common
share dividend rate to $2.9300 from
$2.9000 per common share. The first quarterly dividend
payment at the increased rate was paid on
November 15,
2025.
Emera’s common share dividends paid in 2025 were
$2.9075 ($0.7250 in Q1, Q2, and Q3 and $0.7325 in
Q4) per common share and for 2024 were $2.8775
($0.7175 in Q1, Q2, and Q3 and $0.7250 in Q4) per
common
share. This represents a dividend payout ratio of net income of 86 per cent in 2025 (2024 – 168
per cent) and a dividend payout ratio of adjusted net income
of 83 per cent in 2025 (2024 – 98 per cent).
TRANSACTIONS WITH RELATED PARTIES
In the ordinary course of business, Emera provides energy
and other services and enters into
transactions with its subsidiaries, associates and
other related companies on terms similar to those
offered
to non-related parties. Intercompany balances and intercompany transactions have been
eliminated on consolidation, except for the net profit on
certain transactions between non-regulated and
regulated entities in accordance with accounting
standards for rate-regulated entities. All material
amounts
are under normal interest and credit terms.
Significant
transactions between Emera and its associated companies are as follows:
●
Consolidated Statements of Income.
NSPI’s expense is reported in “Regulated fuel for generation
and purchased power” on the Consolidated Statements of
Income, totalling $185 million for the year
ended December
31, 2025 (2024 – $324 million recovery). NSPML is accounted for as an equity
investment, and therefore corresponding earnings related
to this revenue are reflected in “Income
from equity investments” on the Consolidated Statements of
Income . For further details, refer to the
“Contractual Obligations” section.
42
●
regulated” on the Consolidated Statements of Income,
totalled $16 million for the year ended
December 31, 2025 (2024 –
$11 million).
●
project to WTI for consideration of $15
million. The development assets were sold at cost with no gain
or loss recognized in the Consolidated Statements of Income.
As at December 31, 2025, Emera and its associated companies
had $32 million due to related parties
(December 31,
2024 – $24 million) recorded in “Other Current Liabilities” on the Consolidated Balance
Sheets.
ENTERPRISE RISK AND RISK MANAGEMENT
Emera has an enterprise-wide risk management process,
overseen by its Enterprise Risk Management
Committee (“ERMC”) and monitored by the Board, to
ensure risks are appropriately identified, assessed,
monitored and subject to appropriate controls. The Board has a
Safety and Risk Committee (“SRC”) to
assist the Board in carrying out its
safety, risk and sustainability oversight responsibilities. The SRC’s
mandate includes oversight of the Company’s
Enterprise Risk Management framework, including the
identification, assessment, monitoring and management of
enterprise risks.
The significant business risks to Emera are
described below, many of which are beyond the Company’s
control, and could have a material adverse effect on Emera
or its subsidiaries, or their business
operations, liquidity or access to or cost of capital,
financial position, prospects, reputation, and/or results
of operations (herein considered a “Material Adverse
Effect”). The nature of risk is such that no such list is
comprehensive, and the actual effect of any of the risks
discussed could be materially different from what
is
described below. Additionally, other risks not presently known may arise, risks not currently considered
material may become material in the future, or two or more risks
which are not themselves material, could
together be material.
Regulatory and Political Risk
The Company’s rate-regulated utilities and certain
investments are subject to complex legislative and
regulatory frameworks that cover material aspects of
their businesses. These frameworks influence key
factors
such as rates and cost structures, revenue requirements, allowed ROEs, capital structures, rate
base and capital investments, and the recovery of purchased
electricity and fuel costs and other costs.
Regulators also review the prudency of costs and make
other decisions that can impact customer rates
and the
reliability of service. Emera’s rate-regulated utilities must obtain regulatory approvals for material
aspects of their businesses, including changing or adding
rates and/or riders. Such approvals often
require public hearing proceedings involving
numerous stakeholders, and there is no assurance in the
outcomes or impact of any regulatory process or decision.
If Emera’s rate-regulated utilities are unable to
recover a material amount of costs in a timely manner, are
unable to earn a return on invested capital, are disallowed the
recovery of certain costs, are subject to
regulatory penalties, are not permitted to make
certain capital investments, or are not permitted to invest
in or divest certain utility assets, it could result in a
Material Adverse Effect, including valuation
impairments.
Regulatory lag, the time between the incurrence of costs and the granting of the rates to
recover those costs by regulators, may also result in a Material
Adverse Effect.
Aspects of the acquisition, ownership, operations, siting,
planning, construction, and decommissioning of
electric
generation, storage, transmission and distribution facilities and natural gas transportation and
distribution systems are also subject to regulatory processes
and approvals of regulators, government
departments and agencies, and other third parties. The
failure to obtain, maintain, and renew such
approvals or
significant changes in the terms and conditions thereof could have a Material Adverse Effect.
43
The
regulatory framework, process and regulatory decisions may also be adversely affected by changes
in government, shifts in government or public policy,
legislative changes, regulatory decisions, geopolitical
changes, changes in the economic environment, or
other factors. Government interference in the
regulatory
process or regulatory decisions can undermine regulatory stability, predictability, and
independence. Any such changes could have a Material
Adverse Effect.
Change in Law Risk
The Company is also exposed to changes in the political
environment and leadership, changes in law or
regulations, changes to governmental policies, trade
disputes, and the imposition of tariffs, any of which
may
impact the Company’s businesses, the markets for energy and inputs thereto, or general economic
conditions, and which may result in a Material Adverse
Effect. This may include initiatives regarding
deregulation or restructuring of the energy
industry, which may result in increased competition, and
increased or unrecovered costs. State and local policies in
some US jurisdictions have sought to prevent
or limit the ability of utilities to provide customers with the
choice to use natural gas while in other
jurisdictions
policies have been adopted to prevent limitations on the use of natural
gas.
Emerging laws
and policies addressing data center development may impact
load growth and the need for additional
utility infrastructure.
Emera cannot predict future legislative, policy, or
regulatory changes, whether caused by economic,
political or other factors, or the resulting operating or
compliance costs or other impacts. It may be difficult
for
Emera to respond in an effective and timely manner to such future legislative, policy or regulatory
changes.
Environmental
Legislation
:
Emera is subject to extensive regulation by federal, provincial,
state, regional and local authorities
regarding environmental matters, primarily related to
its utility operations. This includes laws, regulations
and
policies relating to GHG emissions, renewable energy standards, climate, air quality, water quality
and usage, waste management, wastewater discharges, soil
quality, aquatic and terrestrial habitats,
hazardous waste,
health, endangered species, and wildlife mortality.
In
some jurisdictions where Emera operates, government legislation and policy have mandated timelines
for the shutdown of coal-fired generating facilities, set
renewable energy generation targets, and
introduced carbon pricing, and emissions limits. Over
time, these could potentially lead to a portion of
hydrocarbon infrastructure assets being subject to additional
regulation and limitations in respect of GHG
emissions and
operations.
Both the Government of Nova Scotia and the
Government of Canada have enacted or introduced
legislation
that includes goals of net-zero GHG emissions by 2050. The Province of Nova Scotia has
established targets with respect to the percentage of renewable
energy in NSPI’s generation mix and
reductions in GHG emissions, as well as the goal to phase
out coal-fired electricity generation by 2030.
The
Government of Canada has also enacted regulations imposing emissions standards on coal-fired
generation that would effectively require the decommissioning
of such facilities. While Nova Scotia is
exempted from such regulations through 2029, there
is no guarantee that such exemption will continue
into the
future. Failure to meet such goals by 2030 or comply with applicable legislation or regulation
could result in a Material Adverse Effect.
Per- and polyfluoroalkyl substances (“PFAS”)
are man-made chemicals that are widely used in consumer
products and can persist and bio-accumulate in the
environment. The Company does not manufacture
PFAS but
because these contaminants are ubiquitous in products and the environment, they could impact
Emera’s operations. Changes in environmental laws and
regulations related to PFAS could result in new
costs or
obligations for investigation and cleanup and change the Company’s land acquisition strategy for
projects such as solar generation, which could result in a
Material Adverse Effect.
44
These and
new or revised environmental laws, regulations, policies, or interpretations of those laws,
regulations or policies could result in a Material Adverse
Effect by, among other things, preventing or
delaying
the development of energy infrastructure projects, restricting the use or output of certain
facilities, requiring the early retirement of certain generation
facilities that could result in stranded costs,
limiting the availability or use of certain fuels required
for the production of electricity, requiring additional
pollution control equipment, curtailing sales of natural gas
to new customers which could reduce future
customer growth in Emera’s natural gas
businesses, changing the nature and timing of capital
investments, requiring significant capital investments, imposing
operating or other costs associated with
compliance including carbon taxes or emissions
allowances, or by limiting or eliminating certain
operations or rendering such operations uneconomical.
Impacts could be more significant in the future as
the result of new or revised laws or requirements or
stricter or more expansive application of existing
environmental laws, regulations and policies. Failure to recover
environmental costs in a timely manner
through rates may also result in a Material Adverse Effect.
In addition to imposing continuing compliance obligations,
there are permit requirements, laws and
regulations authorizing the imposition of penalties for
non-compliance, exposing Emera to legal or
regulatory
proceedings, disputes, civil fines, injunctive relief, criminal penalties and other sanctions, which
could result in a Material Adverse Effect.
Weather Risk
A Material Adverse Effect may arise from seasonal weather
variations impacting energy consumption, as
well as severe weather events, changing air
temperatures, wildfires and other severe weather conditions
that are expected to become more frequent and intense in
the future. Refer to “Climate Risk”.
The temperature, seasonal variations, and other
weather conditions significantly influence the availability
and demand for electricity and natural gas by customers, the
price of energy commodities, such as fuel
used by the
Company’s rate regulated utilities, and the production of electricity at power generation
facilities. For example, NSPI could see lower sales in
winter months if temperatures are warmer than
expected.
Severe weather events or conditions such as hurricanes,
floods, storm surge, tornadoes, droughts, fires,
extreme temperatures, snow or ice storms, and
other natural disasters create a risk of physical damage to
the Company’s assets and a risk of extended service
outages or fuel supply disruptions. For example,
high
winds can cause widespread damage to transmission and distribution infrastructure, solar
generation, and wind-powered generation. Substantially all
of the Company’s fossil fueled generation
assets are located at or near coastal sites and, as such,
are exposed to the separate and combined
effects of rising
sea levels and increasing storm intensity, including storm surges and flooding.
Severe weather events or conditions could reduce revenues
and require the Company to incur additional
costs, such as
repair and replacement costs, costs of replacement power and fuel, and increased
insurance costs, impacting cash flows and resulting in the
need to access additional financing sources.
These could result in a Material Adverse
Effect if not resolved or mitigated in a timely and efficient
manner through insurance or regulatory cost recovery. This
risk to transmission and distribution facilities
is typically not insured and, as
such, the restoration cost is generally recovered through regulatory
processes, either in advance through reserves, or after the
fact through the establishment of regulatory
assets. Recovery is not assured, is subject to prudency
review, and may be subject to delay resulting in
increased
debt and debt servicing costs.
Severe weather events or other catastrophic natural
disasters could also result in long-term reductions in
demand for electricity or natural gas or the slowing of customer
growth in one or more of the Company’s
service territories, which could have a Material
Adverse Effect. The impact of extreme weather events
would
be amplified if the same events affect multiple utilities in the Company’s portfolio.
45
High
winds, lack of precipitation, and accumulation of fallen dead vegetation also increase the risk of
wildfires resulting from the Company’s infrastructure
or for which the Company may otherwise have
responsibility. If
found to be responsible for such a fire, the Company could suffer material costs, losses
and damages, all or some of which may not be recoverable through
insurance, legal, regulatory cost
recovery or other processes. If not recovered through these
means, or if recovery is delayed, these could
result in a
Material Adverse Effect. Resulting costs could include fire suppression costs, regeneration,
timber value, increased insurance costs and costs arising
from damages and losses incurred by third
parties.
The Company purchases power from third-party owned
hydroelectricity sources and operates
hydroelectric generation in certain of its markets.
Such generation depends on availability of water and
the
hydrological profile of water sources. Changes in precipitation patterns, water temperatures and air
temperatures could adversely affect the availability of
water and consequently the amount of electricity
that may be produced from such
facilities.
Climate Risk
Physical Risk:
Changes in climate may negatively impact the Company’s
operations as a result of increased frequency
and intensity of weather events and related physical
risks, any of which could result in a Material Adverse
Effect (for more information refer to “Weather
Risk” and “System Operating and Maintenance Risks”). An
increase in physical risk associated with climate change can also
adversely impact the cost and
availability of insurance, insurance deductibles and
self-retention, as well as credit ratings, which could
affect credit risk spreads on new long-term debt and credit
facilities, as well as their availability (refer to
“Liquidity and Capital Markets
Risk”).
Transition Risk:
As government policy related to the environment, renewable
energy, and decarbonization continues to
shift in
various operating jurisdictions, the Company is exposed to increased uncertainty and risk arising
from policy, legal,
regulatory, technology, and market changes, which could result in a Material Adverse
Effect. The energy transition will require the Company to
address changes to environmental policies, laws
and regulations which vary widely in operating
jurisdictions (refer to “Environmental Legislation”). The
Company’s ability to address transition risk for the
long-term is impacted by this increased policy
uncertainty and the need to balance stakeholder
expectations for reliability and affordability of energy.
The Company will be required to manage the impacts of these
ongoing changes on customer demand
and rates, while maintaining and integrating
intermittent renewable energy and new technologies, making
investments required to meet new resiliency and security
standards, and adapting the Company’s
infrastructure
and generating capacity to meet load growth, changing customer demands, and usage
patterns. The energy transition and the ability of the Company to
achieve government mandated
environmental requirements, will require significant
capital investment, and is dependent upon many
factors
which are outside of the Company’s direct control, including the actions of governments,
regulators, independent system operators, independent power
producers, interconnected utilities,
Indigenous communities,
and other stakeholders; the development and commercialization of new and
emerging technologies; and the use of offsets. These
external factors and legislative, policy, or regulatory
changes may cause the pace of the energy transition (including
emissions reductions and the addition of
more renewable energy) to materially differ from
some stakeholder expectations. Depending on the
regulatory
response to government legislation and regulations, the Company may be exposed to the risk
of reduced recovery through rates in respect of the affected
assets.
Given concerns regarding carbon-emitting
generation, assets and businesses may, over time, become
difficult or uneconomic to insure in commercial insurance
markets. Some insurance companies have
limited their exposure to coal-fired electricity
generation and are evaluating the medium and long-term
impacts of changes in climate which may result in less insurance
capacity, more restrictive coverage and
increased
premiums in the future. The Company could also face litigation or regulatory action related to
environmental harms from GHG emissions or failure to substantiate
certain environmental claims.
46
The
failure to effectively respond to risks associated with changes in climate could adversely affect the
Company’s ability to deliver safe, reliable, and
cost-effective service, the Company’s reputation with
stakeholders, its ability to operate and grow, and the
Company’s access to, and cost of, capital, each of
which could result in a Material Adverse Effect.
Cybersecurity Risk
Emera is exposed to potential risks related to cyberattacks,
data breaches, cyber-extortion, and
unauthorized access that could result in a Material
Adverse Effect. The Company increasingly relies on IT
systems, networks and cloud infrastructure, and third-party
service providers to effectively manage and
safely operate its assets. This includes controls for
interconnected systems of generation, distribution and
transmission as well as financial, billing and other enterprise
systems. As the Company operates critical
energy
infrastructure, it may be at greater risk of cyberattacks, which could include those from
nation-
state cyber threat actors. Major emerging and ongoing
global conflicts may also elevate this risk, by
increasing the sophistication, magnitude, and
frequency of cyberattacks.
Cyberattacks can reach the Company’s assets and
information via their interfaces with third parties or the
public internet and gain access to critical and
non-critical infrastructures. Cyberattacks can also occur via
personnel with access to critical assets or trusted networks.
Methods used to attack critical assets could
include generic or energy-sector-specific malware
delivered via network transfer, removable media,
attachments, links in e-mails or other communications, or social
engineering. The methods used by
attackers are continuously evolving and can be
difficult to predict and detect and may become more
sophisticated, frequent, severe, and difficult to stop to
the extent that attackers are able to leverage
evolving artificial intelligence (“AI”) models or
tools.
Despite security measures in place, the
Company’s systems, assets and information could experience
security breaches that could cause system failures, disrupt
energy supply and delivery, business
operations, or
adversely affect safety. Such breaches could compromise customer, employee-related or
other information systems and could result in loss of service
to customers, unavailability of critical assets,
safety issues, compromise billing and customer-facing
information, such as outage maps, disrupt internal
control
and financial and back office processes, or result in the release, loss, corruption, destruction,
and/or misuse of critical, sensitive, confidential or proprietary
information, intellectual property, or personal
information of customers or employees. These breaches could
also delay delivery or result in
contamination or degradation of hydrocarbon
products the Company transports, stores or distributes.
Cyberattacks or unauthorized access may cause lost
revenues, costs, losses, regulatory penalties and
third-party damages, all or some of which, may not be
recoverable through insurance, legal, regulatory
cost recovery or other processes.
To the extent that Emera maintains cybersecurity insurance coverage,
such coverage is subject to aggregate limits that, depending on
the scope and scale of impacts to the
Company, are more
likely to be exhausted as a result of a sophisticated single cyberattack or if multiple
events were to occur within a single policy period. There is
no guarantee that the Company will be able to
renew such coverage on acceptable terms in the
future. Resulting costs could include, amongst others,
response, recovery and remediation costs, increased
protection or insurance costs, and costs arising
from damages and losses incurred by third parties.
This could result in a Material Adverse Effect and
there is
no assurance that cyberattacks or other security breaches can be adequately addressed in a
timely manner.
47
The
Company seeks to manage these risks by aligning to a common set of cybersecurity standards and
policies derived, in part, on the National Institute of Standards
and Technology’s Cyber Security
Framework, by
following program maturity objectives, through periodic security assessments, by
exercising and improving cybersecurity incident readiness
and response programs, by hiring third-party
cybersecurity experts, and through employee
communication and training. With respect to certain of its
assets, the Company is required to comply with rules and
standards relating to cybersecurity and IT
including, but not limited to, those mandated by
bodies such as the North American Electric Reliability
Corporation, Northeast Power Coordinating Council, and the United
States Department of Homeland
Security. The status of
key elements of the Company’s cybersecurity program is reported to the SRC on a
quarterly basis. The Board also oversees cybersecurity
risk, which is included in a risk dashboard at each
regularly scheduled Board meeting. The recruitment and
retention of qualified cybersecurity talent is a
global
issue, and difficulties in securing such resources may adversely impact the Company’s ability to
address these risks.
Energy Consumption Risk
Emera’s rate-regulated utilities are affected by
demand for energy based on changing customer patterns
due
to fluctuations in a number of factors including general economic conditions, weather events,
customers’ focus on energy efficiency, changes in
rates, and advancements in new technologies such as
rooftop
solar, electric vehicles, data centers, and battery storage. Government policies promoting energy
efficiency, distributed generation, and new
technology developments that enable those policies, have the
potential to impact how electricity enters the system and how
it is bought and sold. In addition, increases
in distributed generation may impact demand resulting
in lower load and revenues. These changes could
negatively
impact Emera’s operations, rate base, net earnings, and cash flows and result in a Material
Adverse Effect.
Foreign Exchange Risk
The Company is exposed to foreign currency exchange rate
changes. Emera operates internationally,
with a significant
amount of the Company’s net income earned outside of Canada. As such, Emera is
exposed to movements in exchange rates between the CAD and,
particularly, the USD, which could
positively or adversely
affect results.
Emera manages currency risks through
matching US denominated debt to finance its US operations and
may use foreign currency derivative instruments to hedge specific
transactions and earnings exposure.
The Company may enter FX forward and swap
contracts to limit exposure on certain foreign currency
transactions such as fuel purchases, revenue streams and
capital expenditures, and on net income
earned outside of Canada. The regulatory framework
for the Company’s rate-regulated utilities permits
the recovery of prudently incurred costs, including FX.
The Company does not utilize derivative financial instruments
for foreign currency trading or speculative
purposes or to hedge the value of its investments in foreign
subsidiaries. Exchange gains and losses on
net investments
in foreign subsidiaries do not impact net income as they are reported in Accumulated
Other Comprehensive Income (Loss) ("AOCI”).
Liquidity and Capital Markets Risk
Liquidity risk relates to Emera’s ability to ensure
sufficient funds are available to meet its financial
obligations. Emera’s access to capital and cost of
borrowing is subject to several risk factors, including
financial market conditions, market disruptions and ratings
assigned by various market analysts, including
credit
rating agencies. Disruptions in capital markets could prevent Emera from issuing new securities or
cause the Company to issue securities with less than preferred
terms and conditions. Emera’s growth
plan requires significant capital investments and the
risk associated with changes in interest rates could
have
an adverse effect on the cost of financing. The Company’s future access to capital and cost of
borrowing may be impacted by various market disruptions.
The inability to access cost-effective capital
could have a Material Adverse Effect on
Emera’s ability to fund its growth plan.
48
Emera is
subject to financial risk associated with changes in its credit ratings. There are a number of
factors that rating agencies evaluate to determine credit
ratings, including the Company’s business, its
regulatory framework and legislative environment, political
interference in the regulatory process, the
ability to recover costs and earn returns,
diversification, leverage, liquidity and increased exposure to
impacts related to changes in climate, including increased
frequency and severity of hurricanes and other
severe
weather events. A decrease in a credit rating could result in higher interest rates in future
financings, increased borrowing costs under certain existing
credit facilities, limit access to the
commercial paper market, or limit the availability of
adequate credit support for subsidiary operations. For
certain derivative instruments, if the credit ratings of the
Company were reduced below investment grade,
the full value
of the net liability of these positions could be required to be posted as collateral.
The Company has exposure to its own common share
price through the issuance of various forms of
stock-based compensation, which affect
earnings through revaluation of the outstanding units every
period. The Company uses equity derivatives to reduce the
earnings volatility derived from stock-based
compensation.
General Economic Risk
The Company has exposure to the macro-economic conditions
in North America and in other geographic
regions in which Emera operates. Like most utilities,
economic factors such as consumer income,
employment and
housing affect demand for electricity and natural gas and, in turn, the Company’s
financial results. Adverse changes in general economic
conditions and inflation may impact the ability of
customers to afford rate increases arising
from increases to fuel, operating, capital, environmental
compliance, and other costs, which could result in a Material
Adverse Effect. This may also result in
higher credit and counterparty risk, adverse shifts in
government policy and legislation, and/or increased
risk to
full and timely recovery of costs and regulatory assets.
Interest Rate Risk:
Emera utilizes a combination of fixed and floating rate
debt financing for operations and capital
expenditures, resulting in an exposure to interest rate
risk.
For Emera’s rate-regulated utilities, the cost of
debt is a component of rates and prudently incurred debt
costs are recovered from customers. Regulatory
ROE will generally follow the direction of interest rates,
such that regulatory ROEs are likely to fall in times of reducing
interest rates and rise in times of
increasing interest rates, albeit not directly and generally
with a lag period reflecting the regulatory
process. Rising
interest rates may also negatively affect the economic viability of project development
and acquisition initiatives.
Interest rates could also be impacted by changes in credit
ratings. For more information, refer to “Liquidity
and Capital Markets
Risk”.
As with most other utilities and other similar
yield-returning investments, Emera’s share price may be
affected by changes in interest rates and could underperform
the market in an environment of rising
interest rates.
Inflation Risk:
The Company may be exposed to changes in inflation that may
result in increased operating and
maintenance costs, capital investment, and fuel
costs compared to the revenues provided by customer
rates.
49
Public Health Crisis Risk
An outbreak of infectious disease, a pandemic or other public
health threats, or a fear of any of the
foregoing, could result in a Material Adverse
Effect. This could include causing operating, supply chain
and project development delays and disruptions, labour
shortages and shutdowns (including as a result of
government regulation and prevention measures),
which could have a negative impact on the Company’s
operations.
Any
adverse changes in general economic and market conditions arising as a result of a public health
threat could negatively impact demand for electricity and natural
gas, revenue, operating costs, timing
and extent of capital investments, capital market activities,
and counterparty risk; which could result in a
Material
Adverse Effect.
Health and Safety
The Company’s operations inherently involve risk
to the health and safety of employees, contractors and
members of the public. Personal injury or loss of life
resulting from failure to implement or observe
appropriate
health and safety procedures or comply with health and safety laws and regulations could
result in adverse operational, reputational, legal, regulatory,
or financial impacts, any of which could have
a Material Adverse
Effect.
Project Development and Land Use
Rights Risk
The Company’s capital plan includes significant
investment in generation, infrastructure modernization,
and customer-focused technologies. Any projects planned
or currently in construction, particularly
significant
capital projects, may be subject to risks that could result in a Material Adverse Effect including,
but not limited to, impact on costs from schedule delays,
increased demand for renewable energy inputs,
risk of cost overruns, ensuring compliance with
operating and environmental requirements and other
events
within or beyond the Company’s control. The Company’s projects may also require approvals and
permits at the federal, provincial, state, regional and local
levels. There is no assurance that Emera will
be able to
obtain the necessary project approvals or applicable permits or receive regulatory approval to
recover the costs in rates.
Some of the Company’s assets are located on land
owned by third parties, including Indigenous Peoples,
and may be subject to land claims. Present or future
assets may be located on lands that have been used
for
traditional purposes and therefore subject to specific consultations, consents, or conditions for
development or operation. If the Company’s rights to
locate and operate its assets on any such lands are
subject
to expiry or become invalid, it may incur material costs to renew rights or obtain such rights. If
reasonable terms for land-use rights cannot be negotiated, the
Company may incur significant costs to
remove and relocate its assets and restore the land.
Additional costs incurred could cause projects to be
uneconomical to proceed.
Counterparty Risk
Emera is exposed to risk related to its reliance on certain
key partners, suppliers, and customers, any of
which may endure financial challenges resulting from
commodity price and market volatility, economic
instability or adversity, adverse political or regulatory
changes and other causes which may cause or
contribute to
such parties’ insolvency, bankruptcy, restructuring or default on their contractual obligations
to Emera. Emera is also exposed to potential losses related
to amounts receivable from customers,
energy marketing
collateral deposits and derivative assets due to a counterparty’s non-performance
under an agreement.
There is no assurance that management strategies will be
effective, and significant counterparty defaults
could result in a Material Adverse Effect.
50
Supply Chain Risk
Emera’s ability to meet customer energy requirements,
respond to storm-related disruptions and execute
on the capital investment program in a
cost-effective and timely manner are dependent on maintaining an
efficient supply chain. Domestic and global supply chain
issues may delay the delivery, increase the cost,
or result
in shortages of certain materials, fuel, equipment and other resources that are critical to the
Company’s operations. These disruptions may be
further exacerbated by trade restrictions, inflationary
pressures, labour shortages, more frequent and severe
weather events, government incentives
increasing demand for
clean energy projects, changes in carbon-related costs, policies and regulations,
and the impact of international conflicts. In addition, the
imposition of custom duties or other tariffs, or an
increase in trade restrictions in the future could have a
Material Adverse Effect.
Fuel Supply Disruptions:
Emera’s electric and natural gas utilities are exposed
to the risk of fuel supply chain disruptions, both
within and outside their service territories. Fuel supply
disruptions may be caused by damage to,
operational issues
with, terrorist or cyberattacks on, impacts of severe weather or natural disasters on,
third party fuel production, storage, pipeline, and distribution
facilities. A significant unanticipated fuel
supply disruption could result in increased exposure
to commodity price risk for Emera’s regulated electric
and gas utilities and Emera Energy, disruption to utility
operations, and adverse reputational impacts, any
of which
could have a Material Adverse Effect.
Commodity Price Risk
The Company’s utility fuel supply and purchase of
other commodities is subject to commodity price risk.
In addition, Emera Energy is subject to commodity price
risk through its portfolio of commodity contracts
and
arrangements.
Regulated Utilities:
The Company’s utility fuel supply is exposed to
broader global market conditions, which may include
impacts on delivery reliability and price, despite contracted
terms. Supply and demand dynamics in fuel
markets can be
affected by a wide range of factors which are difficult to predict and may change rapidly,
including but not limited to, currency fluctuations, changes
in global economic conditions, natural
disasters, transportation or production disruptions,
and geo-political risks, such as political instability,
conflicts, changes to international trade agreements, tariffs,
trade sanctions or embargos.
Prolonged and
substantial increases in fuel prices could result in decreased rate affordability, increased
risk of recovery of costs or regulatory assets, and/or negative
impacts on customer consumption patterns
and sales, any of which could result in a Material
Adverse Effect.
Emera Energy Marketing
and Trading:
The majority of Emera Energy’s portfolio of
electricity and gas marketing and trading contracts and, in
particular, its natural gas asset management arrangements,
are contracted on a back -to-back basis,
avoiding any
material long or short commodity positions. However, the portfolio is subject to commodity
price risk, particularly with respect to basis point
differentials between relevant markets in the event of an
operational issue, imposition of tariffs, or counterparty
default. Changes in commodity prices can also
result in increased collateral requirements associated
with physical contracts and financial hedges,
resulting in
higher liquidity requirements and increased costs to the business.
51
Future Employee Benefit Plan Performance and
Funding Risk
Emera subsidiaries have both defined benefit
and defined contribution employee pension plans that cover
employees and retirees. All defined benefit plans are closed to
new entrants, except for the TECO
Holdings Group Retirement Plan and the Grand
Bahama Power Company Limited Union Employees’
Pension
Plan. The cost of providing these benefit plans varies depending on plan provisions, interest
rates, inflation, investment performance and actuarial
assumptions concerning the future. Actuarial
assumptions
include earnings on plan assets, discount rates (interest rates used to determine funding
levels, contributions to the plans and the pension and
post-retirement liabilities) and expectations around
future salary growth, inflation and
mortality. The three largest drivers of cost are investment performance,
interest rates and inflation, which are affected by global
financial and capital markets. Depending on
future interest rates and future inflation and actual
versus expected investment performance, Emera could
be
required to make larger contributions in the future to fund these plans, which could have a Material
Adverse Effect.
Labour Risk
Emera’s ability to deliver service to its customers and
to execute its growth plan depends on attracting,
developing and retaining a skilled workforce. Utilities
are faced with demographic challenges related to
trades,
technical staff and engineers with an increasing number of employees expected to retire over the
next several years. Failure to attract, develop and retain an
appropriately qualified workforce could have a
Material Adverse
Effect.
Approximately 30 per cent of Emera’s labour
force is represented by unions and subject to collective
labour agreements. The inability to maintain or negotiate
future agreements on acceptable terms could
result in higher labour costs and work disruptions,
which could adversely affect service to customers and
have a
Material Adverse Effect.
Technology Risk
Emera relies on various technology systems to manage
operations, including increasing reliance on
solutions operated by third parties, such as software
as a service and third-party cloud hosting. This
subjects
Emera to inherent costs and risks associated with maintaining, upgrading, replacing and
changing these systems. This includes impairment of its
operations, potential disruption of internal control
systems, substantial capital expenditures, demands on
management time and other risks of delays,
difficulties in
upgrading existing systems, transitioning to new systems or integrating new systems into its
current systems. Technological reliance may increase
vulnerability to cyberattacks and data breaches
and
increase operational reliance on technology systems and third parties. The rapid evolution of AI has
the potential to disrupt existing business models and markets
and could result in a Material Adverse
Effect. If the Company does not
successfully integrate AI in a timely and cost-effective manner, it may not
fully realize anticipated efficiencies, cost savings, or
service improvements.
If AI systems or tools do not
operate as expected, it could result in adverse operational,
safety, reputational, financial, legal, privacy,
data
security, or other outcomes. Emera’s digital transformation strategy, including investment in
infrastructure modernization, emerging technologies such as
Generative AI, and customer focused
technologies, is driving increased investment in
technology solutions, resulting in increased project risks
associated with the implementation of these solutions.
Income Tax Risk
The computation of the Company’s provision for income
taxes is impacted by changes in tax legislation in
Canada, the US and the Caribbean and any such
changes could have a Material Adverse Effect. The
value of
Emera’s existing deferred income tax assets and liabilities are determined by existing tax laws
and could be negatively impacted by changes in laws.
52
System Operating and Maintenance Risks
The safe and reliable operation of electric generation and
electric and natural gas transmission and
distribution systems is critical to Emera’s
operations. There are a variety of hazards and operational risks
inherent in operating electric utilities and natural gas
transmission and distribution pipelines. Electric
generation, transmission and distribution operations can be
impacted by risks such as mechanical
failures, supply chain
issues impacting timely access to critical equipment, activities of third parties,
terrorism, cyberattacks, human error, damage to facilities,
and infrastructure caused by hurricanes,
storms, falling trees, lightning strikes, floods, fires
and other natural disasters. Natural gas pipeline
operations can be impacted by risks such as leaks,
explosions, mechanical failures, activities of third
parties, terrorism, cyberattacks, and damage to the pipeline
facilities and equipment caused by
hurricanes, storms,
floods, fires and other natural disasters. Electric utility and natural gas transmission
and distribution pipeline operation interruption could negatively
affect customer and public confidence,
and public safety,
cause damage to Company infrastructure or third-party property, and have a Material
Adverse Effect.
Insurance, warranties, or recovery through regulatory mechanisms
may not cover any or all these losses,
which could have a Material Adverse
Effect.
Uninsured Risk
Emera and its subsidiaries maintain insurance to cover
accidental loss suffered to its facilities and to
provide indemnity in the event of liability to third parties. A
significant portion of Emera’s electric utilities’
transmission and distribution assets and its gas utilities’
distribution assets are not insured, as is
customary in the
industry, as the cost of coverage is prohibitive. In addition, Emera accepts deductibles
and self-insured retentions under its various insurance policies.
Insurance is subject to coverage limits as
well as time sensitive claims discovery and reporting
provisions and there can be no assurance that the
types of
liabilities or losses that may be incurred will be covered by insurance.
The occurrence of significant uninsured claims, claims in
excess of the insurance coverage limits, or
claims that fall within a significant self-insured
retention could have a Material Adverse Effect, if regulatory
recovery is not available.
RISK MANAGEMENT INCLUDING FINANCIAL
INSTRUMENTS
The Company uses financial instruments as a method to
manage its exposure to normal operating and
market risks relating to commodity prices, interest
rates, FX on forecast USD earnings and cash flows
and
forecast future cash settlements of deferred compensation obligations. In addition, the Company has
contracts for the physical purchase and sale of commodities.
Collectively, these contracts and financial
instruments are
considered derivatives.
The Company recognizes the FV of all its derivatives
on its balance sheet, except for non-financial
derivatives
that meet the normal purchases and normal sales (“NPNS”) exception. Physical contracts that
meet the NPNS exception are not recognized on the balance
sheet; these contracts are recognized in
income when they settle. A physical contract generally
qualifies for the NPNS exception if the transaction
is
reasonable in relation to the Company’s business needs, the counterparty owns or controls resources
within the proximity to allow for physical delivery, the
Company intends to receive physical delivery of the
commodity, and
the Company deems the counterparty creditworthy. The Company continually assesses
contracts designated under the NPNS exception and will
discontinue the treatment of these contracts
under this
exemption if the criteria are no longer met.
53
Derivatives qualify for hedge accounting if they meet stringent
documentation requirements and can be
proven to effectively hedge identified risk both
at the inception and over the term of the instrument.
Specifically, for cash flow hedges, change in the FV of
derivatives is deferred to AOCI and recognized in
income in
the same period the related hedged item is realized. Where documentation or effectiveness
requirements are not met, the derivatives are recognized at
FV with any changes in FV recognized in net
income in the reporting period, unless deferred as a result
of regulatory accounting.
Derivatives entered into by NSPI,
NMGC and GBPC that are documented as economic hedges or for
which the NPNS exception has not been taken, are subject to
regulatory accounting treatment. The
change in FV of the derivatives is deferred to a
regulatory asset or liability. The gain or loss is recognized
in the hedged item when the hedged item is settled. Any
gains or losses resulting from settlement of
these derivatives related to fuel for generation and
purchased power or cost of natural gas are expected
to be
refunded to or collected from customers in future rates. TEC and PGS have no derivatives related to
hedging.
Derivatives that do not meet any of the above criteria are
designated as HFT, with changes in FV
normally recorded in net income of the period. The Company
has not elected to designate any derivatives
to be included in the HFT category where another
accounting treatment would apply.
Derivative Assets and Liabilities Recognized on
the Balance Sheet
As at
December 31
December 31
millions of dollars
2025
2024
Regulatory
Deferral:
Derivative instrument assets
(1)
$
$
Derivative instrument liabilities
(2)
Regulatory assets
(1)
Regulatory
liabilities
Net asset
$
$
HFT Derivatives:
Derivative instrument
assets
$
$
Derivatives instruments liabilities
(2)
Net liability
$
$
Other Derivatives:
Derivative instrument assets
(1)
$
$
Derivatives instruments
liabilities
Net asset (liability)
$
$
(1) Current, other and assets held for sale.
(2) Current, long-term and liabilities associated with
assets held for sale.
Realized and Unrealized Gains (Losses) Recognized
in Net Income
For the
Year ended December 31
millions of dollars
2025
2024
Regulatory Deferral:
Regulated fuel for generation and purchased power
(1)
$
$
HFT Derivatives:
Non-regulated operating revenues
$
$
Other Derivatives:
OM&G
$
$
Other income, net
Net gains (losses)
$
$
Total net gains
$
$
(1) Realized gains (losses) on derivative instruments
settled and consumed in the period, hedging relationships that have been
terminated or the hedged transaction is no longer probable.
Realized gains (losses) recorded in inventory will be recognized in
“Regulated fuel for generation and purchased power”
when the hedged item is consumed.
54
As of
December 31, 2025, the unrealized gain in AOCI was $10 million, after-tax (December 31, 2024 –
$12 million, after-tax). For the year ended December 31,
2025, unrealized gains of $2 million (December
31, 2024 – $2 million) were reclassified into interest expense.
DISCLOSURE AND INTERNAL
CONTROLS
Management is responsible for establishing and
maintaining adequate disclosure controls and
procedures
(“DC&P”) and internal control over financial reporting (“ICFR”), as defined in National
Instrument 52-109 Certification of Disclosure in Issuers’
Annual and Interim Filings (“NI 52-109”). The
Company’s internal control framework is based on
criteria published in the Internal Control Integrated
Framework (2013), a report issued by the Committee
of Sponsoring Organizations (“COSO”) of the
Treadway Commission. Management, including the Chief
Executive Officer and Chief Financial Officer,
evaluated
the design and effectiveness of the Company’s DC&P and ICFR as at December 31, 2025 to
provide reasonable assurance regarding the reliability of
financial reporting in accordance with USGAAP.
Management
recognizes the inherent limitations in internal control systems, no matter how well designed.
Control systems determined to be appropriately designed can
only provide reasonable assurance with
respect to the reliability of financial reporting and
may not prevent or detect all misstatements.
Change in
ICFR
In April 2025, the Company experienced a Cybersecurity
Incident that impacted certain financial systems
and processes at its Canadian affiliates. As a
result, the Company transitioned these to business
continuity processes and implemented additional ICFR during
this period. This transition to business
continuity processes resulted in a material change in
the Company’s ICFR at Canadian affiliates during
the quarter ended June 30, 2025. Since this time, the
Company has restored certain financial systems
and transitioned back from corresponding business
continuity processes, which resulted in a material
change
in the Company’s ICFR at its Canadian affiliates during the second half of 2025. For more
information on the Cybersecurity Incident, refer to the
“Other Developments” section.
There were no other changes in the Company’s ICFR,
during the year ended December 31, 2025, that
have materially affected, or are reasonably
likely to materially affect, the Company’s internal control over
financial reporting.
CRITICAL ACCOUNTING ESTIMATES
The preparation of consolidated financial statements in
accordance with USGAAP requires management
to make estimates and assumptions. These may
affect reported amounts of assets and liabilities at the
date of the financial statements and reported amounts of
revenues and expenses during the reporting
periods. Significant areas requiring use of
management estimates relate to rate-regulated assets and
liabilities, accumulated reserve for cost of removal, pension
and post-retirement benefits, unbilled
revenue, useful lives for depreciable assets, goodwill and
long-lived assets impairment assessments,
income taxes,
asset retirement obligations (“ARO”), and valuation of financial instruments. Management
evaluates the Company’s estimates on an ongoing basis
based upon historical experience, current and
expected conditions and assumptions believed to be
reasonable at the time the assumption is made, with
any
adjustments recognized in income in the year they arise.
55
Rate
Regulation
The rate-regulated accounting policies of Emera’s
rate-regulated subsidiaries and regulated equity
investments are subject to examination and
approval by their respective regulators and may differ from
the accounting policies of non-rate-regulated companies.
Differences occur when regulators render their
decisions on
rate applications or other matters, and generally involve a difference in the timing of revenue
and expense recognition. The accounting for these items is
based on expectations of the future actions of
the regulators. Assumptions and judgments used by
regulatory authorities continue to have an impact on
recovery of costs, rates earned on invested capital, and
the timing and amount of assets to be recovered.
Application of regulatory accounting guidance is a critical
accounting policy as a change in these
assumptions may
result in a material impact on reported assets, liabilities and the results of operations.
As at December 31, 2025, the Company had recorded $3,198
million (2024 – $3,427 million) of regulatory
assets and $1,669 million (2024 – $1,880 million) of
regulatory liabilities.
Accumulated Reserve
– Cost of Removal
TEC, PGS, NMGC and NSPI recognize non-ARO
costs of removal (“COR”) as regulatory liabilities. The
non-ARO COR represents estimated funds received from
customers through depreciation rates to cover
future COR of
PP&E upon retirement that are not legally required. The companies accrue for COR over
the life of the related assets based on depreciation studies
approved by their respective regulators. Costs
are estimated based on historical experience and
future expectations, including expected timing and
estimated future cash outlays. As at December 31, 2025, the
balance of the accumulated reserve – COR
within regulatory liabilities was $729 million (2024 –
$733 million).
Pension and Other
Post-Retirement Employee Benefits
The Company provides post-retirement benefits to
employees, including defined benefit pension plans.
The
cost of providing these benefits is dependent upon many factors that result from actual plan
experience and assumptions of future expectations.
The accounting related to employee post-retirement benefits
is a critical accounting estimate. Changes in
the estimated benefit obligation, affected by
employee demographics - including age, compensation
levels,
employment periods, contribution levels and earnings - could have a material impact on reported
assets, liabilities, accumulated other comprehensive income
and results of operations. Changes in key
actuarial assumptions, including anticipated rates of return
on plan assets and discount rates used in
determining the
accrued benefit obligation and benefit costs, could change annual funding requirements.
This could have a significant impact on the Company’s
annual earnings and cash requirements.
Pension plan assets are comprised primarily of
equity and fixed income investments. Fluctuations in
actual
equity market returns and changes in interest rates may result in changes to pension costs in
future periods.
The Company’s accounting policy is to amortize the
net actuarial gain or loss that exceeds 10 per cent of
the
greater of the projected benefit obligation / accumulated post-retirement benefit obligation (“PBO”)
and the market-related value of assets, over active plan
members’ average remaining service period, or
over expected average remaining lifetime of inactive
members, depending on the makeup of Plan
memberships.
For the largest plans this is currently 16.4 years (8.0 years for 2025 benefit cost) for
Canadian plans and a weighted average of 11.5 years for US
plans. The Company’s use of smoothed
asset values
reduces volatility related to amortization of actuarial investment experience. As a result, the
main cause of volatility in reported pension cost is the discount
rate used to determine the PBO.
56
The discount rate used to determine benefit costs is based on
the yield of high quality long-term corporate
bonds in each operating entity’s country and is
determined with reference to bonds which have the same
duration as the PBO as at January 1 of the fiscal year. The
following table shows the discount rate for
benefit cost purposes and the expected return on
plan assets for each plan:
2025
2024
Discount rate for
benefit cost
purposes
Expected
return on
plan assets
Discount rate for
benefit
cost
purposes
Expected
return on
plan assets
TECO Holdings Group
Retirement Plan
5.66%
7.05%
5.27%
TECO Holdings Group Supplemental
Executive
Retirement Plan
(1)
5.41%
N/A
5.15%
N/A
TECO Holdings Group Benefit
Restoration Plan (1)
5.55%
N/A
5.18%
N/A
TECO Holdings Post-retirement Health
and Welfare Plan
5.69%
N/A
5.28%
N/A
NMGC Retiree Medical Plan
5.67%
4.25%
5.28%
4.25%
NSPI
4.63%, 4.72%
6.00%
4.63%, 4.62%
6.00%
GBPC Salaried
5.75%
5.75%
6.00%
5.75%
5.75%
5.35%
(1) The discount rate for benefit cost purposes is updated
throughout the year as special events occur, such as settlements and
curtailments
Based on management’s estimate, the reported benefit
cost for defined benefit and defined contribution
plans was $51 million in 2025 (2024 – $56 million). The
reported benefit cost is impacted by numerous
assumptions,
including the discount rate and asset return assumptions. A 0.25 per cent change in the
discount rate and asset return assumptions would have had
+/- impact on the 2025 benefit cost of $0.5
million and $2.0
million, respectively (2024 – $0.5 million and $3.0 million).
Unbilled Revenue
Electric and gas revenues are billed on a systematic basis
over a one or two-month period for NSPI and a
one-month period for other Emera utilities. At the end
of each month, the Company must make an
estimate of energy
delivered to customers since the date their meter was last read and determine related
revenues earned but not yet billed. The unbilled revenue is
estimated based on several factors, including
current month’s generation, estimated
customer usage by class, weather, line losses, inter-period
changes to customer classes and applicable customer rates.
Based on the extent of estimates included in
determination of unbilled revenue, actual results may
differ from the estimate. At December 31, 2025,
unbilled
revenues totalled $400 million (2024 – $342 million) on total regulated operating revenues of
$8,571 million (2024 – $7,447 million).
PP&E
PP&E
represents 61 per cent of total assets on the Company’s consolidated balance sheet and includes
generation, transmission and distribution, and other assets
of the Company.
Depreciation is determined by the straight-line method,
based on the estimated remaining service lives of
depreciable assets in each category. The service lives of
regulated PP&E are determined based on
depreciation
studies and require appropriate regulatory approval. Due to the magnitude of the Company’s
PP&E, changes in estimated depreciation rates can have
a material impact on depreciation expense and
accumulated depreciation.
Depreciation expense was $1,259 million for the year ended
December 31, 2025 (2024 – $1,135 million).
57
Goodwill Impairment
Assessments
Goodwill is calculated as the excess of the purchase
price of an acquired entity over the estimated FV of
identifiable assets acquired, and liabilities assumed at the
acquisition date.
Goodwill is subject to assessment for
impairment at the reporting unit level annually, or if an event or
change in circumstances indicates that the FV of a reporting
unit may be below its carrying value.
Application of the goodwill impairment test requires
management judgment on significant assumptions
and
estimates. When assessing goodwill for impairment, the Company has the option of first performing a
qualitative assessment to determine whether a quantitative
assessment is necessary. In performing a
qualitative
assessment, management considers, among other factors, macroeconomic conditions,
industry and market considerations and overall financial performance.
If the Company performs a qualitative assessment and
determines it is more likely than not that its FV is
less than its carrying amount, or if the Company
chooses to bypass the qualitative assessment, a
quantitative test is performed. The quantitative test compares
the FV of the reporting unit to its carrying
amount, including goodwill. If the carrying amount of
the reporting unit exceeds its FV, an impairment loss
is recorded. Significant assumptions used in estimating the
FV of a reporting unit include discount and
growth rates, rate case assumptions including future
cost of capital, valuation of the reporting units' net
operating loss (“NOL”), and projected operating and
capital cash flows. Adverse changes in these
assumptions
could result in a future material impairment of the goodwill assigned to Emera’s reporting
units.
As of December 31, 2025, Emera’s goodwill represents
the excess of the acquisition purchase price for
the TEC and PGS reporting units over the FV
assigned to identifiable assets acquired and liabilities
assumed. In Q3 2024, Emera entered into an agreement to
sell NMGC. As a result, a quantitative
goodwill impairment assessment was performed on the
NMGC reporting unit at that time and the
Company recorded a
goodwill impairment charge of $210 million ($198 million, after-tax) or $155 million
USD ($146 million USD, after-tax) in Q3 2024. The reduced
NMGC goodwill balance of $289 million is
included in the NMGC disposal unit classified as held
for sale. For further details, refer to note 23 in the
consolidated financial statements.
In Q4 2025, a qualitative assessment was performed for PGS
and TEC, given the significant excess of
FV over carrying amounts calculated during the last
quantitative tests in Q4 2024 and Q4 2023,
respectively.
Management concluded it was more likely than not that the FV of these reporting units
exceeded their carrying amounts, including goodwill. As
such, no quantitative testing was required.
As of December 31, 2025, the Company had
goodwill with a total carrying amount of $5,580 million (2024
– $5,858 million). The change in the carrying value of goodwill
from 2024 to 2025 was a result of the
effect of the FX
translation of Emera’s foreign affiliates.
Long-Lived Assets Impairment Assessments
The Company assesses whether there has been an impairment
of long-lived assets and intangibles when
a triggering event occurs, such as a significant
market disruption or the sale of a business. The
assessment
involves comparing undiscounted expected future cash flows, to the carrying value of the
asset. When the undiscounted cash flow analysis indicates a
long-lived asset is not recoverable, the
amount of the impairment loss is determined by
measuring the excess of the carrying amount of the
long-
lived asset over its estimated FV.
58
The
Company believes accounting estimates related to asset impairments are critical estimates, as they
are highly susceptible to change and the impact of an impairment
on reported assets and earnings could
be material. Management is required to make
assumptions based on expectations regarding results of
operations for significant/indefinite future periods and current
and expected market conditions in such
periods. Markets can experience significant
uncertainties. Estimates based on the Company’s
assumptions relating to future results of operations or other
recoverable amounts are based on a
combination of historical experience, fundamental
economic analysis, observable market activity and
independent market studies. The Company’s expectations
regarding uses and holding periods of assets
are based on internal long-term budgets and
projections, which consider external factors and market
forces, as of the end of each reporting period. Assumptions
made by management are consistent with
generally accepted industry approaches and
assumptions used for valuation and pricing activities.
In
2025, impairment charges of $75 million ($71 million after-tax) were recognized related to the NMGC
disposal group classified as held for sale and were recorded
in “Impairment charges” on the Consolidated
Income Statement. In 2024, impairment charges of
$19 million ($14 million after-tax) were recognized on
certain assets, $8 million of which was included in “Other
income, net” with $11 million included in
“Impairment charges” on the Consolidated Statements
of Income.
Income
Taxes
Income taxes are determined based on expected tax treatment
of transactions recorded in the
consolidated financial statements. In determining income
taxes, tax legislation is interpreted in a variety of
jurisdictions, the likelihood that deferred income tax assets
will be recovered from future taxable income is
assessed, and assumptions are made about
expected timing of reversal of deferred income tax assets
and liabilities. Uncertainty associated with application of
tax statutes and regulations and outcomes of tax
audits and appeals, requires that judgments and
estimates be made in the accrual process and in
calculation
of effective tax rates. Only income tax benefits that meet the “more likely than not” threshold
may be recognized or continue to be recognized. Unrecognized
tax benefits are evaluated quarterly and
changes are recorded based on new information,
including issuance of relevant guidance by the courts or
tax
authorities and developments occurring in examinations of the Company’s tax returns.
The Company believes accounting estimates related to income
taxes are critical estimates. Realization of
deferred income tax assets depends on the
generation of sufficient taxable income, both operating and
capital, in future periods. A change in estimated valuation
allowance could have a material impact on
reported assets and results of operations.
Administrative actions of tax authorities, changes in tax law or
regulation, and uncertainty associated with the application of
tax statutes and regulations, could change
the
Company’s estimate of income taxes, including the potential for elimination or reduction of the
Company’s ability to realize tax benefits and to
utilize deferred income tax assets.
Asset Retirement Obligations
Measurement of the FV of AROs requires the Company to make
reasonable estimates concerning the
method and timing of settlement associated with
legally obligated costs. There are uncertainties in
estimating future asset-retirement costs due to potential
events, such as changing legislation or
regulations, and advances in remediation
technologies. Emera has AROs associated with remediation of
generation, transmission, distribution and pipeline assets.
59
An ARO
represents the FV of estimated cash flows necessary to discharge the future obligation using the
Company’s credit-adjusted risk-free rate. The amounts
are reduced by actual expenditures incurred.
Estimated future cash flows are based on completed
depreciation studies, remediation reports, prior
experience,
estimated useful lives, and governmental regulatory requirements. The present value of the
liability is recorded and the carrying amount of the related
long-lived asset is correspondingly increased.
The amount
capitalized at inception is depreciated in the same manner as the related long-lived asset.
Over time, the liability is accreted to its estimated future
value. Accretion expense is included as part of
“Depreciation and amortization expense”. Any accretion
expense not yet approved by the regulator is
recorded in “PP&E” and included in the next
depreciation study. Accordingly, changes to the ARO or cost
recognition attributable to changes in the factors discussed
above, should not impact the results of
operations of the Company.
Some of the Company’s transmission and distribution
assets may have conditional AROs that are not
recognized in the consolidated financial statements
as the FV of these obligations could not be
reasonably
estimated given insufficient information to do so. A conditional ARO refers to a legal obligation
to perform an asset retirement activity in which the timing
and/or method of settlement are conditional on
a future event that may or may not be within the
control of the entity. Management monitors these
obligations and a liability is recognized at FV when an
amount can be determined.
As at December 31, 2025, AROs recorded on the
balance sheet were $228 million (2024 – $217 million).
The Company estimates the undiscounted amount of cash flow
required to settle the obligations is
approximately $474 million (2024 – $453 million), which
will be incurred between 2026 and 2061. The
majority of
these costs will be incurred between 2035 and 2051.
Financial Instruments
The Company is required to determine the FV of all derivatives
except those that qualify for the NPNS
exception. FV is the price that would be received for the
sale of an asset or paid to transfer a liability in an
orderly arms-length transaction between market participants
at the measurement date. FV measurements
are required to reflect assumptions that market participants
would use in pricing an asset or liability based
on the
best available information, including the risks inherent in a particular valuation technique, such as
a pricing model, and the risks inherent in the inputs to
the model.
Level Determinations and Classifications
The Company uses Level 1, 2, and 3 classifications in the
FV hierarchy. The FV measurement of a
financial instrument
is included in only one of the three levels and is based on the lowest level input
significant to the derivation of the FV. FV is determined,
directly or indirectly, using inputs that are
observable
for the asset or liability. Only in limited circumstances does the Company enter into
commodity transactions involving non-standard features
where market observable data is not available or
have contract terms that extend beyond five years.
60
CHANGES IN ACCOUNTING POLICIES AND PRACTICES
The new USGAAP accounting policy that is applicable to, and
adopted by the Company in 2025, is
described as follows:
Improvements to Income Tax
Disclosures
The Company adopted Accounting Standard Update (“ASU”)
2023-09, Income Taxes (Topic 740),
Improvements to Income Tax Disclosures, effective December
31, 2025. The standard enhances the
transparency,
decision usefulness and effectiveness of income tax disclosures by requiring consistent
categories and greater disaggregation of information in the
reconciliation of income taxes computed using
the enacted statutory income tax rate to the actual income
tax provision and effective income tax rate, as
well as the
disaggregation of income taxes paid (refunded) by jurisdiction. Adoption of the standard
resulted in additional disclosures provided in note 11 and
note 31 of Emera’s consolidated financial
statements.
Future Accounting
Pronouncements
The Company considers the applicability and impact
of all ASUs issued by the Financial Accounting
Standards
Board (“FASB”). The following updates have been issued by the FASB but, as allowed, have
not yet been adopted by Emera. Any ASUs not included below
were assessed and determined to be
either not applicable to the Company or to have an
insignificant impact on the consolidated financial
statements.
Accounting for Government Grants Received by
Business Entities
In December 2025, the FASB issued ASU 2025-10,
Government Grants (Topic 832) – Accounting for
Government Grants Received by Business Entities. The ASU
adds guidance to ASC 832 on the
recognition, measurement, and presentation of
government grants. The guidance will be effective for
annual reporting periods beginning after December 15, 2028,
and interim reporting periods within those
annual reporting periods. Early adoption is permitted. The
standard updates are to be applied using either
a modified
prospective, modified retrospective, or full retrospective approach, as detailed in the ASU. The
Company is currently evaluating the impact of adoption of
the standard update on its consolidated
financial statements.
Targeted Improvements to the Accounting
for Internal-Use Software
In September 2025, the FASB issued
ASU 2025-06, Intangibles – Goodwill and Other – Internal-Use
Software (Subtopic 350-40): Targeted Improvements to the
Accounting for Internal-Use Software. The
standard update
modernizes accounting for internal-use software by eliminating references to project
stages and clarifying the threshold to begin capitalizing
costs. The standard update also specifies that the
disclosure requirements under ASC 360,
Property, Plant and
Equipment
,
apply
to
capitalized software
costs accounted under ASC 350-40. The guidance will be
effective for annual reporting periods beginning
after December 15, 2027, and interim reporting
periods within those annual reporting periods. Early
adoption is permitted. The standard updates are to be applied
using either a prospective, retrospective, or
modified transition approach. The Company is
currently evaluating the impact of adoption of the standard
update on its consolidated financial statements.
61
Disaggregation of Income Statement Expenses
In November 2024, the FASB issued ASU 2024-03, Income
Statement Reporting – Comprehensive
Income –
Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement
Expenses. The standard update improves the disclosures about
a public business entity’s expenses by
requiring more detailed information about the types
of expenses (including purchases of inventory,
employee
compensation, depreciation and amortization) included within income statement expense
captions. The guidance will be effective for annual
reporting periods beginning after December 15, 2026,
and interim reporting periods beginning after
December 15, 2027. Early adoption is permitted. The
standard updates are to be applied prospectively with the option
for retrospective application. The
Company is currently evaluating the impact of
adoption of the standard update on its consolidated
financial statements disclosures.
SUMMARY OF QUARTERLY RESULTS
For the quarter ended
millions of
dollars
Q4
Q3
Q2
Q1
Q4
Q3
Q2
Q1
(except per share amounts)
2025
2025
2025
2025
2024
2024
2024
2024
Operating revenues
$
$
$
$
$
$
$
$
Net income attributable to common
shareholders
$
$
$
$
$
$
$
$
EPS – basic
$
0.23
$
$
$
$
$
$
$
EPS – diluted
$
0.25
$
$
$
$
$
$
$
Quarterly operating revenues and adjusted net income are affected
by seasonality. The first quarter
provides strong
earnings contributions due to a significant portion of the Company’s operations being in
northeastern North America, where winter is the peak electricity
usage season. The third quarter provides
strong earnings contributions due to summer being the
heaviest electric consumption season in Florida.
Seasonal
and other weather patterns, as well as the number and severity of storms, can affect demand
for energy and the cost of service. Quarterly results could
also be affected by items outlined in the
“Significant Items Affecting Earnings” section.
Quarter -over-quarter variances are discussed further
below.
Q4 2025 compared to Q4 2024
For explanation of variances, refer to the “Consolidated
Income Statement Highlights” section.
Q3 2025 compared to Q3 2024
For Q3 2025, net income attributable to common shareholders,
compared to Q3 2024, increased $224
million primarily due to charges related to the pending sale
of NMGC recognized in Q3 2024; and
increased earnings at
TEC. These were partially offset by increased MTM losses; lower earnings at NSPI
and NMGC; and higher Corporate costs. The change in EPS was
also impacted by an increase in
weighted average shares outstanding.
Q2 2025 compared to Q2 2024
Q2 2025 net income attributable to common shareholders
increased by $6 million primarily due to
decreased MTM losses; increased earnings at TEC, EES,
and NMGC; higher Corporate income tax
recovery; and
decreased Corporate OM&G. These were partially offset by the gain on sale of LIL
recognized in Q2 2024; charges related to the pending sale
of NMGC recognized in Q2 2025; lower
earnings at NSPI; decreased equity earnings from
LIL; and increased Corporate interest expense. Q2
2025 EPS
– basic and diluted were consistent with Q2 2024.
62
Q1 2025 compared to Q1 2024
Q1 2025 net income attributable to common shareholders
increased by $376 million and EPS – basic and
diluted increased by $1.23 compared to Q1 2024. The
increases were primarily due to decreased MTM
losses;
increased earnings at TEC, NSPI, EES and NMGC; the impact of a weaker CAD; and decreased
Corporate OM&G. These changes were partially offset by
decreased income from equity investments due
to the sale of LIL. The change in EPS was also
impacted by an increase in weighted average shares
outstanding.