1.2 25.5 25 25 25.5 http://fasb.org/us-gaap/2024#PropertyPlantAndEquipmentNet http://fasb.org/us-gaap/2024#PropertyPlantAndEquipmentNet http://fasb.org/us-gaap/2024#PropertyPlantAndEquipmentNet http://fasb.org/us-gaap/2024#PropertyPlantAndEquipmentNet August 15, 2025 August 15, 2028 February 15, 2025 August 15, 2025 August 15, 2028 five P3Y P3Y P3Y P3Y
Exhibit 99.3
1
EMERA INCORPORATED
Consolidated
Financial Statements
December 31,
2024
and 2023
2
MANAGEMENT REPORT
Management's Responsibility for Financial Reporting
The accompanying consolidated financial statements of Emera
Incorporated and the information in this
annual report are the responsibility of management and have
been approved by the Board of Directors
(“Board”).
The consolidated financial statements have been prepared
by management in accordance with United
States Generally Accepted Accounting Principles. When alternative
accounting methods exist,
management has chosen those it considers most appropriate
in the circumstances. In preparation of
these consolidated financial statements, estimates are sometimes
necessary when transactions affecting
the current accounting period cannot be finalized with
certainty until future periods. Management
represents that such estimates, which have been properly reflected
in the accompanying consolidated
financial statements, are based on careful judgments and
are within reasonable limits of materiality.
Management has determined such amounts on a reasonable
basis in order to ensure that the
consolidated financial statements are presented fairly in
all material respects. Management has prepared
the financial information presented elsewhere in the annual report
and has ensured that it is consistent
with that in the consolidated financial statements.
Emera Incorporated maintains effective systems
of internal accounting and administrative controls,
consistent with reasonable cost. Such systems are designed to
provide reasonable assurance that the
financial information is reliable and accurate, and that
Emera Incorporated's assets are appropriately
accounted for and adequately safeguarded.
The Board is responsible for ensuring that management
fulfils its responsibilities for financial reporting
and is ultimately responsible for reviewing and approving
the consolidated financial statements. The
Board carries out this responsibility principally through its
Audit Committee.
The Audit Committee is appointed by the Board, and its
members are directors who are not officers or
employees of Emera Incorporated. The Audit Committee meets
periodically with management, as well as
with the internal auditors and with the external auditors, to discuss
internal controls over the financial
reporting process, auditing matters and financial reporting
issues, to satisfy itself that each party is
properly discharging its responsibilities, and to review the annual
report, the consolidated financial
statements and the external auditors' report. The Audit
Committee reports its findings to the Board for
consideration when approving the consolidated financial statements
for issuance to the shareholders.
The Audit Committee also considers, for review by the Board
and approval by the shareholders, the
appointment of the external auditors.
The consolidated financial statements have been audited
by Ernst & Young
LLP,
the external auditors, in
accordance with Canadian Generally Accepted Auditing Standards
and with the standards of the Public
Company Accounting Oversight Board. Ernst & Young
LLP has full and free access to the Audit
Committee.
February 21, 2025
“Scott Balfour”
“Gregory Blunden”
President and Chief Executive Officer
President and Chief Executive Officer
Chief Financial Officer
3
Report of Independent Registered Public Accounting Firm
To
the Shareholders and the Board of Directors of Emera
Incorporated
Opinion on the Consolidated Financial Statements
We have audited the accompanying Consolidated
Balance Sheets of Emera Incorporated (the
“Company“) as of December 31, 2024 and 2023, the related Consolidated
Statements of Income,
Consolidated Statements of Comprehensive Income,
Consolidated Statements of Changes in Equity and
Consolidated Statements of Cash Flows for the years
then ended, and the related notes (collectively
referred to as the “consolidated financial statements“).
In our opinion, the consolidated financial
statements present fairly,
in all material respects, the consolidated financial position
of the Company as of
December 31, 2024 and 2023, and the consolidated results
of its operations and its consolidated cash
flows for each of the two years in the period ended December
31, 2024, in conformity with United States
generally accepted accounting principles.
Basis for Opinion
These consolidated financial statements are the responsibility
of the Company‘s management. Our
responsibility is to express an opinion on the Company‘s
consolidated financial statements based on our
audits. We are a public accounting firm registered
with the Public Company Accounting Oversight Board
(United States) (“PCAOB”) and are required to be independent
with respect to the Company in
accordance with the U.S. federal securities laws and the
applicable rules and regulations of the Securities
and Exchange Commission and the PCAOB.
We conducted our audits in accordance with
the standards of the PCAOB. Those standards require
that
we plan and perform the audits to obtain reasonable
assurance about whether the consolidated financial
statements are free of material misstatement, whether
due to error or fraud. The Company is not required
to have, nor were we engaged to perform, an audit of its
internal control over financial reporting. As part
of our audits we are required to obtain an understanding
of internal control over financial reporting but not
for the purpose of expressing an opinion on the effectiveness
of the Company's internal control over
financial reporting. Accordingly,
we express no such opinion.
Our audits included performing procedures to assess
the risks of material misstatement of the
consolidated financial statements, whether due to error
or fraud, and performing procedures that respond
to those risks. Such procedures included examining, on a test
basis, evidence regarding the amounts and
disclosures in the consolidated financial statements. Our
audits also included evaluating the accounting
principles used and significant estimates made by management,
as well as evaluating the overall
presentation of the consolidated financial statements. We
believe that our audits provide a reasonable
basis for our opinion.
Critical Audit Matters
The critical audit matters communicated below are matters
arising from the current period audit of the
financial statements that were communicated or required
to be communicated to the audit committee and
that: (1) relate to accounts or disclosures that are material
to the financial statements and (2) involved our
especially challenging, subjective or complex judgments.
The communication of critical audit matters
does not alter in any way our opinion on the consolidated financial
statements, taken as a whole, and we
are not, by communicating the critical audit matters
below, providing separate opinions
on the critical
audit matters or on the accounts or disclosures to which
they relate.
4
Accounting for the effects of rate regulation
Description
of the Matter
As disclosed in note 7 of the consolidated financial statements,
the Company has $3.4
billion in regulatory assets and $1.9 billion in regulatory
liabilities. The Company’s rate-
regulated subsidiaries are subject to regulation by various
federal, state and provincial
regulatory authorities in the geographic regions in which
they operate. The regulatory
rates are designed to recover the prudently incurred costs
of providing the regulated
products or services and provide a reasonable return on
the equity invested or assets, as
applicable. In addition to regulatory assets and liabilities,
rate regulation impacts multiple
financial statement line items, including, but not limited to,
property, plant
and equipment
(“PP&E”), operating revenues and expenses, income taxes,
and depreciation expense.
Auditing the impact of rate regulation on the Company’s
financial statements is complex
and highly judgmental due to the significant judgments
made by the Company to support
its accounting and disclosure for regulatory matters when
final regulatory decisions or
orders have not yet been obtained or when regulatory
formulas are complex. There is
also subjectivity involved in assessing the potential
impact of future regulatory decisions
on the financial statements. Although the Company
expects to recover costs from
customers through rates, there is a risk that the regulator
will not approve full recovery of
the costs incurred. The Company’s judgments
include making an assessment of the
probability of recovery of and return on costs incurred, of the
potential disallowance of
part of the cost incurred, or of the probable refund of
gains or amounts previously
collected from customers through future rates.
How We
Addressed
the Matter in
Our Audit
We performed audit procedures that included,
amongst others, assessing the Company’s
evaluation of the probability of future recovery for regulatory
assets, PP&E, and refund of
regulatory liabilities by obtaining and reviewing relevant
regulatory orders, filings,
testimony, hearings
and correspondence, and other publicly available
information. For
regulatory matters for which regulatory decisions or orders
have not yet been obtained,
we inspected the rate-regulated subsidiaries’ filings for
any evidence that might contradict
the Company’s assertions, and reviewed other regulatory
orders, filings and
correspondence for other entities within the same or similar
jurisdictions to assess the
likelihood of recovery or refund in future rates based on
the regulator’s treatment of
similar costs under similar circumstances. We obtained
and evaluated an analysis from
the Company and corroborated that analysis with letters
from legal counsel, when
appropriate, regarding cost recoveries, gains or amounts
previously collected from
customers or future changes in rates. We also assessed
the methodology,
accuracy and
completeness of the Company’s calculations of regulatory
asset and liability balances
based on provisions and formulas outlined in rate orders
and other correspondence with
the regulators. We evaluated the Company's
disclosures related to the impacts of rate
regulation.
Fair Value (“FV”) measurement of derivative
financial instruments
Description
of the Matter
Held-for-trading (“HFT”) derivative assets of $270 million
and liabilities of $690 million,
disclosed in note 16 to the consolidated financial statements,
are measured at FV.
The
Company recognized $207 million in realized and unrealized
gains during the year with
respect to HFT derivatives.
Auditing the Company’s valuation of HFT derivatives
is complex and highly judgmental
due to the complexity of the contract terms and valuation models,
and the significant
estimation required in determining the FV of the contracts.
In determining the FV of HFT
derivatives, significant assumptions about future economic
and market assumptions with
uncertain outcomes are used, including third-party sourced
forward commodity pricing
curves based on illiquid markets, internally developed correlation
factors and basis
differentials. These assumptions have a significant
impact on the FV of the HFT
derivatives.
5
How We
Addressed
the Matter in
Our Audit
We performed audit procedures that included,
amongst others, reviewing executed
contracts and agreements for the identification of inputs
and assumptions impacting the
valuation of derivatives. With the support of our valuation
specialists, we assessed the
methodology and mathematical accuracy of the Company’s
valuation models and
compared the commodity pricing curves used by the Company
to current market and
economic data. For the forward commodity pricing curves,
we compared the Company’s
pricing curves to independently sourced pricing curves.
We also assessed the
methodology and mathematical accuracy of the Company’s
calculations to develop
correlation factors and basis differentials. In
addition, we assessed whether the FV
hierarchy disclosures in note 17 to the consolidated financial
statements were consistent
with the source of the significant inputs and assumptions
used in determining the FV of
derivatives.
/s/
Ernst & Young LLP
Chartered Professional Accountants
We have served as the Company‘s auditor since
1998.
Halifax, Canada
February 21, 2025
6
Emera Incorporated
Consolidated Statements of Income
For the
Year ended December 31
millions of dollars (except per share amounts)
2024
2023
Operating revenues
Regulated electric
$
5,872
$
5,746
Regulated gas
1,575
1,489
Non-regulated
(247)
328
Total
operating revenues (note 6)
7,200
7,563
Operating expenses
Regulated fuel for generation and purchased power
1,992
1,881
Regulated cost of natural gas
396
527
Operating, maintenance and general expenses ("OM&G")
1,918
1,879
Provincial, state, and municipal taxes
427
433
Depreciation and amortization
1,162
1,049
Impairment charges (note 23)
225
-
Total
operating expenses
6,120
5,769
Income from operations
1,080
1,794
Income from equity investments (note 8)
99
146
Other income, net (note 9)
203
158
Interest expense, net (note 10)
973
925
Income before provision for income taxes
409
1,173
Income tax (recovery) expense (note 11)
(159)
128
Net income
568
1,045
Non-controlling interest in subsidiaries ("NCI")
1
1
Preferred stock dividends
73
66
Net income attributable to common shareholders
$
494
$
978
Weighted average shares of common stock outstanding (in millions) (note 13)
Basic
289
274
Diluted
289
274
Earnings per common share (note 13)
Basic
$
1.71
$
3.57
Diluted
$
1.71
$
3.57
Dividends per common share declared
$
2.8775
$
2.7875
The accompanying notes are an integral part of these consolidated financial statements.
7
Emera Incorporated
Consolidated Statements of Comprehensive Income
For the
Year ended December 31
millions of dollars
2024
2023
Net income
$
568
$
1,045
Other comprehensive income (loss) ("OCI"), net of tax
Foreign currency translation adjustment
(1)
1,027
(270)
Unrealized (losses) gains on net investment hedges
(2)
(139)
38
Cash flow hedges – reclassification adjustment for gains included in income
(2)
(2)
Unrealized gains on available-for-sale investment
2
-
Net change in unrecognized pension and post-retirement benefit obligation
(3)
68
(39)
OCI
(4)
956
(273)
Comprehensive income
1,524
772
Comprehensive income attributable to NCI
1
1
Comprehensive Income of Emera Incorporated
$
1,523
$
771
The accompanying notes are an integral part of these consolidated financial statements.
1) Net of tax expense of $
10
million for the year ended December 31, 2024 (2023
– $
7
million recovery).
2) The Company has designated $
1.2
billion United States dollar (USD) denominated
Hybrid Notes as a hedge of the foreign
currency exposure of its net investment in USD
denominated operations.
3) Net of tax expense of
nil
for the year ended December 31, 2024 (2023 – $
1
million expense).
4) Net of tax expense of $
10
million for the year ended December 31, 2024 (2023
– $
6
million recovery).
8
Emera Incorporated
Consolidated Balance Sheets
As at
December 31
December 31
millions of dollars
2024
2023
Assets
Current assets
Cash and cash equivalents
$
196
$
567
Restricted cash
17
21
Inventory (note 15)
781
790
Derivative instruments (notes 16 and 17)
115
174
Regulatory assets (note 7)
595
339
Receivables and other current assets (note 19)
1,811
1,817
Assets held for sale (note 4)
173
-
3,688
3,708
Property, plant and equipment ("PP&E"),
net of accumulated depreciation
and amortization of $
10,442
and $
9,994
, respectively (note 21)
26,168
24,376
Other assets
Deferred income taxes (note 11)
392
208
Derivative instruments (notes 16 and 17)
51
66
Regulatory assets (note 7)
2,832
2,766
Net investment in direct finance and sales type leases (note 20)
610
621
Investments subject to significant influence (note 8)
654
1,402
Goodwill (note 23)
5,858
5,871
Other long-term assets (note 33)
538
462
Assets held for sale (note 4)
2,160
-
13,095
11,396
Total assets
$
42,951
$
39,480
The accompanying notes are an integral part of these consolidated financial statements.
9
Emera Incorporated
Consolidated Balance Sheets – Continued
As at
December 31
December 31
millions of dollars
2024
2023
Liabilities and Equity
Current liabilities
Short-term debt (note 24)
$
1,400
$
1,433
Current portion of long-term debt (note 26)
234
676
Accounts payable
1,992
1,454
Derivative instruments (notes 16 and 17)
526
386
Regulatory liabilities (note 7)
262
168
Other current liabilities (note 25)
489
427
Liabilities associated with assets held for sale (note 4)
212
-
5,115
4,544
Long-term liabilities
Long-term debt (note 26)
18,173
17,689
Deferred income taxes (note 11)
2,331
2,352
Derivative instruments (notes 16 and 17)
91
118
Regulatory liabilities (note 7)
1,618
1,604
Pension and post-retirement liabilities (note 22)
274
265
Other long-term liabilities (note 8 and 27)
910
820
Liabilities associated with assets held for sale (note 4)
1,148
-
24,545
22,848
Equity
Common stock (note 12)
9,042
8,462
Cumulative preferred stock (note 29)
1,422
1,422
Contributed surplus
84
82
Accumulated other comprehensive income ("AOCI') (note 14)
1,261
305
Retained earnings
1,468
1,803
Total
Emera Incorporated equity
13,277
12,074
NCI (note 30)
14
14
Total
equity
13,291
12,088
Total liabilities and equity
$
42,951
$
39,480
Commitments and contingencies
(note 28)
nil
nil
The accompanying notes are an integral part of these consolidated financial statements.
Approved on behalf of the Board of Directors
“Karen Sheriff”
“Scott Balfour”
Chair of the Board
President and Chief Executive Officer
10
Emera Incorporated
Consolidated Statements of Cash Flows
For the
Year ended December 31
millions of dollars
2024
2023
Operating activities
Net income
$
568
$
1,045
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization
1,165
1,060
Income from equity investments, net of dividends
(8)
(22)
Allowance for funds used during construction ("AFUDC") – equity
(53)
(38)
Deferred income taxes, net
(191)
97
Net change in pension and post-retirement liabilities
(46)
(68)
NSPI fuel adjustment mechanism ("FAM")
451
(88)
Net change in fair value ("FV") of derivative instruments
228
(666)
Net change in regulatory assets and liabilities
(226)
554
Net change in capitalized transportation capacity
175
434
Goodwill impairment charge
214
-
Gain on sale of LIL, excluding transaction costs
(191)
-
Other operating activities, net
108
28
Changes in non-cash working capital (note 31)
452
(95)
Net cash provided by operating activities
2,646
2,241
Investing activities
Additions to PP&E
(3,151)
(2,937)
Proceeds from disposal of investment subject to significant influence
927
-
Other investing activities
6
20
Net cash used in investing activities
(2,218)
(2,917)
Financing activities
Change in short-term debt, net
56
(66)
Proceeds from short-term debt with maturities greater than 90 days
-
548
Repayment of short-term debt with maturities greater than 90 days
-
(1,086)
Proceeds from long-term debt, net of issuance costs
1,361
1,932
Retirement of long-term debt
(1,086)
(151)
Net repayments under committed credit facilities
(825)
(96)
Issuance of common stock, net of issuance costs
284
424
Dividends on common stock
(538)
(488)
Dividends on preferred stock
(73)
(66)
Other financing activities
3
(12)
Net cash (used in) provided by financing activities
(818)
939
Effect of exchange rate changes on cash, cash equivalents, restricted cash and
cash associated with assets held for sale
23
(7)
Net (decrease) increase in cash, cash equivalents, restricted cash and cash
associated with assets held for sale
(367)
256
Cash, cash equivalents, and restricted cash, beginning of year
588
332
Cash, cash equivalents, restricted cash, and cash associated with assets held for
sale, end of year
$
221
$
588
Cash, cash equivalents, restricted cash and cash associated with assets held
for sale consists of:
Cash
$
191
$
559
Short-term investments
5
8
Restricted cash
17
21
Assets held for sale
8
-
Cash, cash equivalents, restricted cash and cash associated with assets held for
sale
$
221
$
588
Supplementary Information to Consolidated Statements of Cash Flows (note 31)
The accompanying notes are an integral part of these consolidated financial statements.
11
Emera Incorporated
Consolidated Statements of Changes in Equity
Common
Preferred
Contributed
Retained
Total
Stock
Stock
Surplus
AOCI
Earnings
NCI
Equity
millions of dollars
Balance, December 31, 2023
$
8,462
$
1,422
$
82
$
305
$
1,803
$
14
$
12,088
Net income of Emera Inc.
-
-
-
-
567
1
568
Other comprehensive income, net of
tax expense of $
10
million
-
-
-
956
-
-
956
Dividends declared on preferred stock
(note 29)
-
-
-
-
(73)
-
(73)
Dividends declared on common stock
($
2.8775
/share)
-
-
-
-
(829)
-
(829)
Issued under the at-the-market
program ("ATM"), net of after-tax
issuance costs
261
-
-
-
-
-
261
Issued under the Dividend
Reinvestment Program ("DRIP"), net of
discount
291
-
-
-
-
-
291
Senior management stock options
exercised and Employee Common
Share Purchase Plan ("ECSPP")
28
-
2
-
-
-
30
Other
-
-
-
-
-
(1)
(1)
Balance, December 31, 2024
$
9,042
$
1,422
$
84
$
1,261
$
1,468
$
14
$
13,291
Balance, December 31, 2022
$
7,762
$
1,422
$
81
$
578
$
1,584
$
14
$
11,441
Net income of Emera Inc.
-
-
-
-
1,044
1
1,045
Other comprehensive loss, net of tax
recovery of $
6
million
-
-
-
(273)
-
-
(273)
Dividends declared on preferred stock
(note 29)
-
-
-
-
(66)
-
(66)
Dividends declared on common stock
($
2.7875
/share)
-
-
-
-
(759)
-
(759)
Issued under the ATM, net of after-tax
issuance costs
397
-
-
-
-
-
397
Issued under the DRIP, net of discount
272
-
-
-
-
-
272
Senior management stock options
exercised and ECSPP
31
-
1
-
-
-
32
Other
-
-
-
-
-
(1)
(1)
Balance, December 31, 2023
$
8,462
$
1,422
$
82
$
305
$
1,803
$
14
$
12,088
The accompanying notes are an integral part of these consolidated financial statements.
12
Emera Incorporated
Notes to the Consolidated Financial Statements
As at December 31, 2024 and 2023
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Nature of Operations
Emera Incorporated (“Emera” or the “Company”) is an
energy and services company that invests in
electricity generation, transmission and distribution, and
gas transmission and distribution.
At December 31, 2024, Emera’s reportable segments
include the following:
●
Florida Electric Utility,
which consists of Tampa
Electric (“TEC”), a vertically integrated regulated
electric utility, serving
approximately
855,000
customers in West Central Florida;
●
Canadian Electric Utilities, which includes:
●
Nova Scotia Power Inc. (“NSPI”), a vertically integrated regulated
electric utility and the
primary electricity supplier in Nova Scotia, serving approximately
557,000
customers; and
●
a
100
per cent equity interest in NSP Maritime Link Inc. (“NSPML”),
which developed the
Maritime Link Project, a $
1.8
billion, including AFUDC, transmission project between the
island of Newfoundland and Nova Scotia.
On June 4, 2024, Emera completed the sale of its
31.1
per cent indirect minority equity interest in the
Labrador Island Link Partnership (“LIL”), which was previously
included in the Canadian Electric
Utilities segment. For further details, refer to note 4.
●
Gas Utilities and Infrastructure, which includes:
●
Peoples Gas System Inc. (“PGS”), a regulated gas distribution
utility, serving
approximately
508,000
customers across Florida;
●
New Mexico Gas Company,
Inc. (“NMGC”), a regulated gas distribution utility,
serving
approximately
550,000
customers in New Mexico. On August 5, 2024,
Emera announced an
agreement to sell NMGC. The transaction is expected to
close in late 2025, subject to certain
approvals, including approval by the New Mexico Public
Regulation Commission (“NMPRC”).
For further details, refer to note 4.
●
Emera Brunswick Pipeline Company Limited (“Brunswick
Pipeline”), a
145
-kilometre pipeline
delivering re-gasified liquefied natural gas from Saint John,
New Brunswick to the United
States (“US”) border under a
25
-year firm service agreement with Repsol Energy
North
America Canada Partnership (“Repsol Energy Canada”),
which expires in 2034;
●
SeaCoast Gas Transmission, LLC (“SeaCoast”),
a regulated intrastate natural gas
transmission company offering services in Florida;
and
●
a
12.9
per cent equity interest in Maritimes & Northeast
Pipeline (“M&NP”), a
1,400
-kilometre
pipeline that transports natural gas throughout markets
in Atlantic Canada and the
northeastern US.
●
Other Electric Utilities, which includes Emera (Caribbean)
Incorporated (“ECI”), a holding company
with regulated electric utilities that include:
●
The Barbados Light & Power Company Limited (“BLPC”),
a vertically integrated regulated
electric utility on the island of Barbados, serving approximately
135,000
customers;
●
Grand Bahama Power Company Limited (“GBPC”), a vertically
integrated regulated electric
utility on Grand Bahama Island, serving approximately
19,500
customers; and
●
a
19.5
per cent equity interest in St. Lucia Electricity Services
Limited (“Lucelec”), a vertically
integrated regulated electric utility on the island of St.
Lucia.
13
●
Emera’s other segment includes investments in
energy-related non-regulated companies that are
below the required threshold for reporting as separate
segments and corporate expense and revenue
items that are not directly allocated to the operations of Emera’s
subsidiaries and investments. This
includes:
●
Emera Energy, which
consists of:
●
Emera Energy Services (“EES”), a physical energy business
that purchases and sells
natural gas and electricity and provides related energy
asset management services;
●
Brooklyn Power Corporation (“Brooklyn Energy”), a
30
MW biomass co-generation
electricity facility in Brooklyn, Nova Scotia; and
●
a
50.0
per cent joint venture interest in Bear Swamp Power
Company LLC (“Bear
Swamp”), a
660
MW pumped storage hydroelectric facility in northwestern
Massachusetts.
●
Emera US Finance LP (“Emera Finance”), EUSHI Finance, Inc.
and TECO Finance, Inc.
(“TECO Finance”), financing subsidiaries of Emera;
●
Emera US Holdings Inc., a wholly owned holding company
for certain of Emera’s assets
located in the US; and
●
Other investments.
Basis of Presentation
These consolidated financial statements are prepared
and presented in accordance with United States
Generally Accepted Accounting Principles (“USGAAP”)
and, in the opinion of management, include all
adjustments that are of a recurring nature and necessary
to fairly state the financial position of Emera.
All dollar amounts are presented in Canadian dollars (“CAD”),
unless otherwise indicated.
Principles of Consolidation
These consolidated financial statements include the accounts
of Emera Incorporated, its majority-owned
subsidiaries, and a variable interest entity (“VIE”) in which
Emera is the primary beneficiary.
Emera uses
the equity method of accounting to record investments
in which the Company has the ability to exercise
significant influence, and for VIEs in which Emera is not
the primary beneficiary.
The Company performs ongoing analysis to assess whether
it holds any VIEs or whether any
reconsideration events have arisen with respect to existing
VIEs.
To
identify potential VIEs, management
reviews contractual and ownership arrangements such
as leases, long-term purchase power agreements,
tolling contracts, guarantees, jointly owned facilities and
equity investments. VIEs of which the Company
is deemed the primary beneficiary must be consolidated.
The primary beneficiary of a VIE has both the
power to direct the activities of the VIE that most significantly
impacts its economic performance and the
obligation to absorb losses or the right to receive benefits
of the VIE that could potentially be significant to
the VIE. In circumstances where Emera has an investment
in a VIE but is not deemed the primary
beneficiary, the VIE
is accounted for using the equity method. For further
details on VIEs, refer to note 33.
Intercompany balances and transactions have been
eliminated on consolidation, except for the net profit
on certain transactions between certain non-regulated and regulated
entities in accordance with
accounting standards for rate-regulated entities. The net profit
on these transactions, which would be
eliminated in the absence of the accounting standards
for rate-regulated entities, is recorded in non-
regulated operating revenues. An offset is recorded
to PP&E, regulatory assets, regulated fuel for
generation and purchased power,
or OM&G, depending on the nature of the transaction.
14
Use of Management 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.
Regulatory Matters
Regulatory accounting applies where rates are established
by, or subject to
approval by, an
independent
third-party regulator. Rates
are designed to recover prudently incurred costs of providing
regulated
products or services and provide an opportunity for a reasonable
rate of return on invested capital, as
applicable. For further detail, refer to note 7.
Foreign Currency Translation
Monetary assets and liabilities denominated in foreign
currencies are converted to CAD at the rates of
exchange prevailing at the balance sheet date. The resulting differences
between the translation at the
original transaction date and the balance sheet date are
included in income.
Assets and liabilities of foreign operations whose functional
currency is not the Canadian dollar are
translated using exchange rates in effect at the balance
sheet date and the results of operations at the
average exchange rate in effect for the period. The
resulting exchange gains and losses on the assets
and liabilities are deferred on the balance sheet in AOCI.
The Company designates certain USD denominated debt
held in CAD functional currency companies as
hedges of net investments in USD denominated foreign
operations. The change in the carrying amount of
these investments, measured at exchange rates in effect
at the balance sheet date, is recorded in OCI.
Revenue Recognition
Regulated Electric and Gas Revenue:
Electric and gas revenues, including energy charges, demand
charges, basic facilities charges and
clauses and riders, are recognized when obligations under the
terms of a contract are satisfied, which is
when electricity and gas are delivered to customers over
time as the customer simultaneously receives
and consumes the benefits. Electric and gas revenues
are recognized on an accrual basis and include
billed and unbilled revenues. Revenues related to the
sale of electricity and gas are recognized at rates
approved by the respective regulators and recorded
based on metered usage, which occurs on a
periodic, systematic basis, generally monthly or bi-monthly.
At the end of each reporting period, electricity
and gas delivered to customers, but not billed, is estimated
and corresponding unbilled revenue is
recognized. The Company’s estimate of unbilled
revenue at the end of the reporting period
is calculated
by estimating the megawatt hours (“MWh”) or therms delivered
to customers at the established rates
expected to prevail in the upcoming billing cycle. This
estimate includes assumptions as to the pattern of
energy demand, weather, line
losses and inter-period changes to customer classes.
15
Non-regulated Revenue:
Marketing and trading margins are comprised of Emera
Energy’s corresponding purchases and sales
of
natural gas and electricity,
pipeline capacity costs and energy asset management
revenues. Revenues
are recorded when obligations under terms of the contract
are satisfied and are presented on a net basis
reflecting the nature of contractual relationships with customers
and suppliers.
Energy sales are recognized when obligations under the
terms of the contracts are satisfied, which is
when electricity is delivered to customers over time.
Other non-regulated revenues are recorded when obligations
under the terms of the contract are
satisfied.
Other:
Sales, value add, and other taxes, except for gross receipts
taxes discussed below,
collected by the
Company concurrent with revenue-producing activities
are excluded from revenue.
Franchise Fees and Gross Receipts
TEC and PGS recover from customers certain costs incurred,
on a dollar-for-dollar basis, through prices
approved by the Florida Public Service Commission (“FPSC”).
The amounts included in customers’ bills
for franchise fees and gross receipt taxes are included
as “Regulated electric” and “Regulated gas”
revenues in the Consolidated Statements of Income.
Franchise fees and gross receipt taxes payable by
TEC and PGS are included as an expense on the Consolidated
Statements of Income in “Provincial, state
and municipal taxes”.
NMGC is an agent in the collection and payment of franchise
fees and gross receipt taxes and is not
required by a tariff to present the amounts on
a gross basis. Therefore, NMGC’s franchise
fees and gross
receipt taxes are presented net with no line item impact
on the Consolidated Statements of Income.
PP&E
PP&E is recorded at original cost, including AFUDC or
capitalized interest, net of contributions received in
aid of construction.
The cost of additions, including betterments and replacements
of units, are included in “PP&E” on the
Consolidated Balance Sheets. When units of regulated PP&E
are replaced, renewed or retired, their cost,
plus removal or disposal costs, less salvage proceeds,
is charged to accumulated depreciation, with no
gain or loss reflected in income. Where a disposition of
non-regulated PP&E occurs, gains and losses are
included in income as the dispositions occur.
The cost of PP&E represents the original cost of materials,
contracted services, direct labour,
AFUDC for
regulated property or interest for non-regulated property,
ARO, and overhead attributable to the capital
project. Overhead includes corporate costs such as finance,
information technology and labour costs,
along with other costs related to support functions, employee
benefits, insurance, procurement, and fleet
operating and maintenance. Expenditures for project development
are capitalized if they are expected to
have a future economic benefit.
Normal maintenance projects and major maintenance
projects that do not increase overall life of the
related assets are expensed as incurred. When a major
maintenance project increases the life or value of
the underlying asset, the cost is capitalized.
Depreciation is determined by the straight-line method, based
on the estimated remaining service lives of
the depreciable assets in each functional class of depreciable
property. For some
of Emera’s rate-
regulated subsidiaries, depreciation is calculated using
the group remaining life method, which is applied
to the average investment, adjusted for anticipated costs
of removal less salvage, in functional classes of
depreciable property.
The service lives of regulated assets require
regulatory approval.
16
Intangible assets, which are included in “PP&E” on the Consolidated
Balance Sheets, consist primarily of
computer software and land rights. Amortization is determined
by the straight-line method, based on the
estimated remaining service lives of the asset in each category.
For some of Emera’s rate-regulated
subsidiaries, amortization is calculated using the amortizable
life method which is applied to the net book
value to date over the remaining life of those assets. The
service lives of regulated intangible assets
require regulatory approval.
Goodwill
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 carried at initial
cost less any write-down for impairment and is adjusted
for the impact of foreign exchange (“FX”).
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. 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
value, including goodwill (“carrying amount”). If the carrying
amount of the reporting unit exceeds its FV,
an impairment loss is recorded. Management estimates
the FV of the reporting unit by using the income
approach, or a combination of the income and market
approach. The income approach uses a discounted
cash flow analysis which relies on management’s
best estimate of the reporting unit’s projected
cash
flows. The analysis includes an estimate of terminal values
based on these expected cash flows using a
methodology which derives a valuation using an assumed
perpetual annuity based on the reporting unit’s
residual cash flows. The discount rate used is a market participant
rate based on a peer group of publicly
traded comparable companies and represents the weighted
average cost of capital of comparable
companies. For the market approach, management estimates
FV based on comparable companies and
transactions within comparable industries, or in the case
of the NMGC quantitative assessment in 2024,
transactions involving the reporting unit. Significant assumptions
used in estimating the FV of a reporting
unit using an income approach include discount and growth
rates, rate case assumptions including future
cost of capital, valuation of the reporting unit’s 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, 2024, Emera’s goodwill represented
the excess of the acquisition purchase price for
TECO Energy, Inc.
(TEC, PGS and NMGC 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 and the
Company recorded a goodwill impairment charge of $
210
million ($
198
million, after-tax) or $
155
million
USD ($
146
million USD, after-tax). The reduced NMGC goodwill
balance of $
303
million is included in the
NMGC disposal unit classified as held for sale. For further
details, refer to note 23.
In Q4 2024, a qualitative assessment was performed for
TEC given the significant excess of FV over
carrying amounts calculated during the last quantitative test
in Q4 2023. Management concluded it was
more likely than not that the FV of this reporting unit exceeded
its carrying amount, including goodwill. As
such, no quantitative testing was required. Given the length
of time passed since the last quantitative
impairment test for the PGS reporting unit, Emera elected
to bypass a qualitative assessment and
performed a quantitative impairment assessment in Q4
2024 using a combination of the income and
market approach. This assessment estimated that the
FV of the PGS reporting unit exceeded its carrying
amount, including goodwill, and as a result, no impairment
charges were recognized.
17
Income Taxes and
Investment Tax
Credits
Emera recognizes deferred income tax assets and liabilities
for the future tax consequences of events
that have been included in financial statements or income tax
returns. Deferred income tax assets and
liabilities are determined based on the difference
between the carrying value of assets and liabilities on
the Consolidated Balance Sheets, and their respective
tax bases using enacted tax rates in effect
for the
year in which the differences are expected to reverse.
The effect of a change in income tax rates on
deferred income tax assets and liabilities is recognized
in earnings in the period when the change is
enacted, unless required to be offset to a regulatory
asset or liability by law or by order of the regulator.
Emera recognizes the effect of income tax positions
only when it is more likely than not that they will be
realized. Management reviews all readily available current and
historical information, including forward-
looking information, and the likelihood that deferred income
tax assets will be recovered from future
taxable income is assessed and assumptions are made
about the expected timing of reversal of deferred
income tax assets and liabilities. If management subsequently
determines it is likely that some or all of a
deferred income tax asset will not be realized, a valuation
allowance is recorded to reflect the amount of
deferred income tax asset expected to be realized.
Generally, investment
tax credits are recorded as a reduction to income
tax expense in the current or
future periods to the extent that realization of such benefit
is more likely than not. Investment tax credits
earned on regulated assets by TEC, PGS and NMGC are
deferred and amortized as required by
regulatory practices.
TEC, PGS, NMGC and BLPC collect income taxes from
customers based on current and deferred income
taxes. NSPI, NSPML and Brunswick Pipeline collect income taxes
from customers based on income tax
that is currently payable, except for the deferred income taxes
on certain regulatory balances specifically
prescribed by regulators. For the balance of regulated
deferred income taxes, NSPI, NSPML and
Brunswick Pipeline recognize regulatory assets or liabilities
where the deferred income taxes are
expected to be recovered from or returned to customers
in future years. These regulated assets or
liabilities are grossed up using the respective income tax
rate to reflect the income tax associated with
future revenues that are required to fund these deferred
income tax liabilities, and the income tax benefits
associated with reduced revenues resulting from the realization
of deferred income tax assets. GBPC is
not subject to income taxes.
Emera classifies interest and penalties associated with
unrecognized tax benefits as interest and
operating expense, respectively.
For further detail, refer to note 11.
Derivatives and Hedging Activities
The Company manages its exposure to normal operating and
market risks relating to commodity prices,
FX, interest rates and share prices through contractual
protections with counterparties where practicable,
and by using financial instruments consisting mainly of
FX forwards and swaps, interest rate options and
swaps, equity derivatives, and coal, oil and gas futures,
options, forwards and swaps. In addition, the
Company has contracts for the physical purchase and sale of
natural gas. These physical and financial
contracts are classified as HFT.
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.
18
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. Management
believes any gains or losses resulting
from settlement of these derivatives related to fuel for
generation and purchased power will 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.
Emera classifies gains and losses on derivatives as a component
of non-regulated operating revenues,
fuel for generation and purchased power,
other expenses, inventory,
and OM&G, depending on the
nature of the item being economically hedged. Transportation
capacity arising as a result of marketing
and trading derivative transactions is recognized as an asset
in “Receivables and other current assets”
and amortized over the period of the transportation contract
term. Cash flows from derivative activities are
presented in the same category as the item being hedged within
operating activities on the Consolidated
Statements of Cash Flows. Non-hedged derivatives are included
in operating cash flows on the
Consolidated Statements of Cash Flows.
Derivatives, as reflected on the Consolidated Balance
Sheets, are not offset by the FV amounts of cash
collateral with the same counterparty.
Rights to reclaim cash collateral are recognized
in “Receivables
and other current assets” and obligations to return cash
collateral are recognized in “Accounts payable”.
Leases
The Company determines whether a contract contains
a lease at inception by evaluating whether the
contract conveys the right to control the use of an identified
asset for a period of time in exchange for
consideration.
Emera has leases with independent power producers (“IPP”)
and other utilities for annual requirements to
purchase wind and hydro energy over varying contract
lengths which are classified as finance leases.
These finance leases are not recorded on the Company’s
Consolidated Balance Sheets as payments
associated with the leases are variable in nature and there
are no minimum fixed lease payments. Lease
expense associated with these leases is recorded as “Regulated
fuel for generation and purchased
power” on the Consolidated Statements of Income.
Operating lease liabilities and right-of-use assets are recognized
on the Consolidated Balance Sheets
based on the present value of the future minimum lease payments
over the lease term at commencement
date. As most of Emera’s leases do not provide
an implicit rate, the incremental borrowing rate
at
commencement of the lease is used in determining
the present value of future lease payments. Lease
expense is recognized on a straight-line basis over the
lease term and is recorded as “OM&G” on the
Consolidated Statements of Income.
Where the Company is the lessor,
a lease is a sales-type lease if certain criteria are met
and the
arrangement transfers control of the underlying asset
to the lessee. For arrangements where the criteria
are met due to the presence of a third-party residual value
guarantee, the lease is a direct financing
lease.
19
For direct finance leases, a net investment in the lease
is recorded that consists of the sum of the
minimum lease payments and residual value, net of estimated
executory costs and unearned income.
The difference between the gross investment
and the cost of the leased item is recorded as unearned
income at the inception of the lease. Unearned income
is recognized in income over the life of the lease
using a constant rate of interest equal to the internal
rate of return on the lease.
For sales-type leases, the accounting is similar to the accounting
for direct finance leases however,
the
difference between the FV and the carrying value
of the leased item is recorded at lease commencement
rather than deferred over the term of the lease.
Emera has certain contractual agreements that include lease and non-lease components, which
management has elected to account for as a single lease component.
Cash, Cash Equivalents and Restricted Cash
Cash equivalents consist of highly liquid short-term investments
with original maturities of three months or
less at acquisition.
Receivables and Allowance for Credit Losses
Utility customer receivables are recorded at the invoiced
amount and do not bear interest. Standard
payment terms for electricity and gas sales are approximately
30 days. A late payment fee may be
assessed on account balances after the due date. The
Company recognizes allowances for credit losses
to reduce accounts receivable for amounts expected to
be uncollectable. Management estimates credit
losses related to accounts receivable by considering historical
loss experience, customer deposits,
current events, the characteristics of existing accounts
and reasonable and supportable forecasts that
affect the collectability of the reported amount.
Provisions for credit losses on receivables are expensed
to maintain the allowance at a level considered adequate
to cover expected losses. Receivables are
written off against the allowance when they are
deemed uncollectible.
Inventory
Fuel and materials inventories are valued at the lower
of weighted-average cost or net realizable value,
unless evidence indicates the weighted-average cost
will be recovered in future customer rates.
Asset Impairment
Long-Lived Assets:
Emera 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 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.
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. The
assumptions made are consistent with generally accepted
industry approaches and assumptions used for
valuation and pricing activities.
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 Income Statement.
No
impairment charges related to long-lived assets were recognized
in
2023.
20
Equity Method Investments:
The carrying value of investments accounted for under
the equity method are assessed for impairment by
comparing the FV of these investments to their carrying values,
if a FV assessment was completed, or by
reviewing for the presence of impairment indicators. If
an impairment exists, and it is determined to be
other-than-temporary,
a charge is recognized in earnings equal to the
amount the carrying value exceeds
the investment’s FV.
No
impairment of equity method investments was required
in either 2024 or 2023.
Financial Assets:
Equity investments, other than those accounted for under
the equity method, are measured at FV,
with
changes in FV recognized in the Consolidated Statements of Income.
Equity investments that do not
have readily determinable FV are recorded at cost minus
impairment, if any,
plus or minus changes
resulting from observable price changes in orderly transactions
for the identical or similar investments.
No
impairment of financial assets was required in either
2024 or 2023.
Asset Retirement Obligations
An ARO is recognized if a legal obligation exists in connection
with the future disposal or removal costs
resulting from the permanent retirement, abandonment
or sale of a long-lived asset. A legal obligation
may exist under an existing or enacted law or statute,
written or oral contract, or by legal construction
under the doctrine of promissory estoppel.
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.
AROs are included in “Other long-term
liabilities” and accretion expense is included as part of
“Depreciation and amortization”. Any regulated
accretion expense not yet approved by the regulator is
recorded in “PP&E” and included in the next
depreciation study.
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
in the period in which an amount can be
determined.
Cost of Removal (“COR”)
TEC, PGS, NMGC and NSPI recognize non-ARO COR
as regulatory liabilities or regulatory assets. The
non-ARO COR represent funds received from customers
through depreciation rates to cover estimated
future non-legally required COR of PP&E upon retirement. The
companies accrue for COR over the life of
the related assets based on depreciation studies approved
by their respective regulators. The costs are
estimated based on historical experience and future
expectations, including expected timing and
estimated future cash outlays.
21
Stock-Based Compensation
The Company has several stock-based compensation
plans: a common share option plan for senior
management; an employee common share purchase plan;
a deferred share unit (“DSU”) plan; a
performance share unit (“PSU”) plan; and a restricted
share unit (“RSU”) plan. The Company accounts for
its plans in accordance with the FV-based method of
accounting for stock-based compensation. Stock-
based compensation cost is measured at the grant date,
based on the calculated FV of the award, and is
recognized as an expense over the employee’s or
director’s requisite service period using the graded
vesting method. Stock-based compensation plans recognized as
liabilities are initially measured at FV
and re-measured at FV at each reporting date, with the
change in liability recognized in income.
Employee Benefits
The costs of the Company’s pension and other
post-retirement benefit programs for employees are
expensed over the periods during which employees render service.
The Company recognizes the funded
status of its defined-benefit and other post-retirement plans on
the balance sheet and recognizes
changes in funded status in the year the change occurs.
The Company recognizes unamortized gains
and losses and past service costs in “AOCI” or “Regulatory
assets” on the Consolidated Balance Sheets.
The components of net periodic benefit cost other than
the service cost component are included in “Other
income, net” on the Consolidated Statements of Income.
For further detail, refer to note 22.
Government Grants
The Company accounts for government grants by applying
a grant accounting model by analogy to
International Accounting Standards (“IAS”) 20, Accounting
for Government Grants and Disclosure of
Government Assistance. A grant relating to an asset is
reflected in the determination of the carrying
amount of the asset. A grant relating to income is presented
as a deduction from the related expense it is
intended to compensate.
In 2024, the Company received an aggregate of $
47
million (2023 – $
7
million) of government grants from
various Canadian and US government agencies towards
capital projects included in
PP&E
. The capital
projects receiving grants primarily relate to the Company’s
decarbonization and environmental
compliance initiatives. Further details on significant grant programs
utilized in 2024 and 2023 are noted
below.
Natural Resources Canada (“NRCan”) Smart Renewables
& Electrification Pathways (“SREP”):
On March 27, 2024, NSPI was approved for a grant under the
NRCan SREPs to fund the construction of
three
50 MW battery storage systems in Nova Scotia.
NSPI can make claims under the grant for
33
per
cent of eligible project costs to a maximum $
109
million. Eligible costs can be incurred until March
31,
2027. For the year-end December 31, 2024, NSPI received
$
26
million (2023 –
nil
) in funding under the
grant, which has been recorded as a reduction to the carrying
amount of the project in
PP&E
.
2.
CHANGE IN ACCOUNTING POLICY
The new USGAAP accounting policy that is applicable
to, and adopted by the Company in 2024, is
described as follows:
Improvements to Reportable Segment Disclosures
The Company adopted Accounting Standard Update (“ASU”) 2023-07,
Segment Reporting (Topic
280),
Improvements to Reportable Segment Disclosures. The change
in the standard improves reportable
segment disclosure requirements, primarily through enhanced
disclosures about significant segment
expenses. The changes improve financial reporting by
requiring disclosure of incremental segment
information on an annual and interim basis for all public
entities to enable investors to develop more
decision-useful financial analyses. The guidance was
effective for annual reporting periods beginning
after December 15, 2023, and for interim periods beginning
after December 15, 2024. Adoption of the
standard resulted in additional qualitative disclosures provided
in note 5.
22
3. 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.
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.
Improvements to Income Tax
Disclosures
In December 2023, the FASB
issued ASU 2023-09, Income Taxes
(Topic
740): Improvements to Income
Tax
Disclosures. 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. The standard also requires disclosure of income
(loss) before provision for income taxes
and income tax expense (recovery) in accordance with
U.S. Securities and Exchange Commission
Regulation S-X 210.4-08(h), Rules of General Application
– General Notes to Financial Statements:
Income Tax
Expense, and the removal of disclosures no longer considered
cost beneficial or relevant.
The guidance will be effective for annual reporting periods
beginning after December 15, 2024. Early
adoption is permitted. The standard will be applied on
a prospective basis, with retrospective application
permitted. The Company is currently evaluating the impact of
adoption of the standard on its consolidated
financial statements disclosures.
4.
DISPOSITIONS
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. The
transaction is expected to close in late 2025,
subject to certain approvals, including approval by the
NMPRC. As a result of the pending sale, NMGC’s
assets and liabilities are classified as held for sale.
As the transaction proceeds will be lower than the carrying amount
of the assets and liabilities being sold,
Emera assessed the NMGC reporting unit for goodwill impairment
by comparing the FV of expected
transaction proceeds to the carrying value of net assets,
including goodwill of $
366
million USD (“NMGC
carrying amount”). The goodwill of the reporting unit was
determined to be impaired and a non-cash
goodwill impairment charge of $
210
million ($
198
million, after-tax) or $
155
million USD ($
146
million
USD, after-tax) was recorded in “Impairment Charges” on the Consolidated
Statements of Income in Q3
2024.
23
Following the goodwill impairment assessment, the held for
sale assets and liabilities were measured at
the lower of their carrying amount or fair value less costs
to sell. The measurement resulted in an
additional loss for the estimated future transaction costs
of $
16
million ($
12
million after-tax), in addition to
incurred transaction costs of $
9
million ($
7
million after-tax) recorded in “Other Income, net” on the
Consolidated Statements of Income in Q3 2024.
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 $
26
million ($
19
million USD) was
recorded on these assets from August 5, 2024, the date
they were classified as held for sale, through
December 31, 2024.
Details of the assets and liabilities classified as held for
sale are as follows:
As at
December 31
millions of dollars
2024
Cash and cash equivalents
$
8
Inventory
9
Derivative instruments
1
Regulatory assets
28
Receivables and other current assets
127
Current assets held for sale
$
173
PP&E
1,828
Regulatory assets
6
Goodwill
303
Other long-term assets
23
Long-term assets held for sale
$
2,160
Total assets held for sale
$
2,333
Short-term debt
$
46
Derivative instruments
1
Regulatory liabilities
10
Accounts payable and other current liabilities
155
Current liabilities associated with assets held for sale
212
Long-term debt
696
Deferred income taxes
167
Regulatory liabilities
274
Other long-term liabilities
11
Long-term liabilities associated with assets held for sale
$
1,148
Total liabilities associated with assets held for sale
$
1,360
Sale of LIL Equity Interest
On June 4, 2024, Emera completed the sale of its
31.1
per cent indirect minority equity interest in the LIL
for a total transaction value of $
1.2
billion, including cash proceeds of $
957
million and $
235
million for
assuming Emera’s contractual obligation to fund the
remaining initial capital investment, which represents
additional LIL equity interest for the acquirer.
Cash proceeds from the sale in the amount of $
30
million is
held in escrow pending finalization of certain agreements
with the LIL general partner. The
escrow
proceeds receivable is held at FV and included in the gain
on sale, after transaction costs. As of
December 31, 2024, the estimated FV of the escrow proceeds
receivable is $
25
million. In Q2 2024, a
gain on sale, after transaction costs, of $
182
million, ($
107
million, after tax and transaction costs), was
recognized in “Other Income, net” on the Consolidated
Statements of Income and included in the Other
segment. In Q4 2024, Emera recognized a $
22
million tax benefit due to the reversal of a prior year
valuation allowance related to loss carryforwards applied against
a portion of the taxable capital gain on
the sale of LIL. This tax benefit was recorded in “Income Tax
(Recovery) Expense” on the Consolidated
Statements of Income in Q4 2024 and included in the
Other segment.
24
5. SEGMENT INFORMATION
Emera manages its reportable segments separately due in part to their different operating, regulatory and
geographical environments. Segments are reported based on each subsidiary’s contribution of revenues,
net income attributable to common shareholders and total assets, as reported to the Company’s chief
operating decision maker (“CODM”). Emera’s CODM is the Chief Executive Officer.
For the Company’s reportable segments, the CODM uses several measures to allocate capital and
resources for each segment, predominantly in the annual budget and forecasting processes. The CODM
evaluates segment performance by considering budget-to-actual variances for these measures monthly.
The measure used by the CODM that is the most consistent with USGAAP measurement principles is net
income attributable to common shareholders.
Florida
Canadian
Gas Utilities
Other
Inter-
Electric
Electric
and
Electric
Segment
millions of dollars
Utility
Utilities
Infrastructure
Utilities
Other
Eliminations
Total
For the year ended December 31, 2024
Operating revenues from
external customers (1)
$
3,451
$
1,855
$
1,595
$
566
$
(267)
$
-
$
7,200
Inter-segment revenues
(1)
9
-
14
-
19
(42)
-
Total operating revenues
3,460
1,855
1,609
566
(248)
(42)
7,200
Regulated fuel for generation
and purchased power
852
859
-
295
-
(14)
1,992
Regulated cost of natural gas
-
-
396
-
-
-
396
OM&G
779
408
454
143
154
(20)
1,918
Provincial, state and municipal
taxes
273
48
103
3
-
-
427
Depreciation and amortization
622
282
182
69
7
-
1,162
Impairment charges
-
-
11
-
214
-
225
Income from equity
investments
-
73
20
4
2
-
99
Other income, net
66
28
16
12
73
8
203
Interest expense, net
(2)
265
168
151
22
367
-
973
Income tax expense
(recovery)
94
(41)
89
1
(302)
-
(159)
NCI in subsidiaries
-
-
-
1
-
-
1
Preferred stock dividends
-
-
-
-
73
-
73
Net income (loss) attributable
to common shareholders
$
641
$
232
$
259
$
48
$
(686)
$
-
$
494
Capital expenditures
$
1,942
$
481
$
619
$
81
$
4
$
-
$
3,127
As at December 31, 2024
Total assets
$
24,375
$
7,609
$
8,439
$
1,444
$
1,810
$
(726)
$
42,951
Investments subject to
significant influence
$
-
$
475
$
124
$
55
$
-
$
-
$
654
Goodwill
$
5,035
$
-
$
823
$
-
$
-
$
-
$
5,858
(1) All significant inter-company balances and transactions
have been eliminated on consolidation except
for certain transactions
between non-regulated and regulated entities. Management
believes elimination of these transactions would
understate PP&E,
OM&G, or regulated fuel for generation and purchased
power. Inter-company transactions that have not been eliminated
are
measured at the amount of consideration established
and agreed to by the related parties. Eliminated
transactions are included in
determining reportable segments.
(2) Segment net income is reported on a basis
that includes internally allocated financing
costs of $
29
million for the year ended
December 31, 2024, between the Gas Utilities
and Infrastructure and Other segments.
25
Florida
Canadian
Gas Utilities
Other
Inter-
Electric
Electric
and
Electric
Segment
millions of dollars
Utility
Utilities
Infrastructure
Utilities
Other
Eliminations
Total
For the year ended December 31, 2023
Operating revenues from
external customers
(1)
$
3,548
$
1,671
$
1,510
$
526
$
308
$
-
$
7,563
Inter-segment revenues
(1)
8
-
14
-
31
(53)
-
Total operating revenues
3,556
1,671
1,524
526
339
(53)
7,563
Regulated fuel for generation
and purchased power
920
699
-
275
-
(13)
1,881
Regulated cost of natural gas
-
-
527
-
-
-
527
OM&G
830
384
405
130
151
(21)
1,879
Provincial, state and municipal
taxes
289
45
91
3
5
-
433
Depreciation and amortization
571
276
126
68
8
-
1,049
Income from equity
investments
-
109
21
4
12
-
146
Other income, net
69
32
11
7
20
19
158
Interest expense, net
(2)
271
170
129
23
332
-
925
Income tax expense (recovery)
117
(9)
64
-
(44)
-
128
NCI in subsidiaries
-
-
-
1
-
-
1
Preferred stock dividends
-
-
-
-
66
-
66
Net income (loss) attributable
to common shareholders
$
627
$
247
$
214
$
37
$
(147)
$
-
$
978
Capital expenditures
$
1,736
$
450
$
664
$
63
$
8
$
-
$
2,921
As at December 31, 2023
Total assets
$
21,119
$
8,634
$
7,735
$
1,311
$
1,938
$
(1,257)
$
39,480
Investments subject to
significant influence
$
-
$
1,236
$
118
$
48
$
-
$
-
$
1,402
Goodwill
$
4,628
$
-
$
1,240
$
-
$
3
$
-
$
5,871
(1) All significant inter-company balances and transactions
have been eliminated on consolidation except
for certain transactions
between non-regulated and regulated entities. Management
believes elimination of these transactions would
understate PP&E,
OM&G, or regulated fuel for generation and purchased
power. Inter-company transactions that have not been eliminated
are
measured at the amount of consideration established
and agreed to by the related parties. Eliminated
transactions are included in
determining reportable segments.
(2) Segment net income is reported on a basis
that includes internally allocated financing
costs of $
95
million for the year ended
December 31, 2023, between the Florida Electric
Utility, Gas Utilities and Infrastructure and Other segments.
Geographical Information
Revenues (based on country of origin of the product or service sold)
For the
Year ended December 31
millions of dollars
2024
2023
United States
4,712
$
5,310
Canada
1,922
1,727
Barbados
427
389
The Bahamas
139
137
$
7,200
$
7,563
PP&E:
As at
December 31
December 31
millions of dollars
2024
2023
United States
(1)
$
20,084
$
18,588
Canada
5,068
4,878
Barbados
645
576
The Bahamas
371
334
$
26,168
$
24,376
(1) On August 5, 2024, Emera announced an agreement to sell
NMGC. As at December 31, 2024, NMGC's assets
and liabilities were classified as held
for sale and excluded from the table above. For further
details on the pending transaction, refer to note 4.
26
6. REVENUE
The following disaggregates the Company’s revenue
by major source:
Electric
Gas
Other
Florida
Canadian
Other
Gas Utilities
Inter-
Electric
Electric
Electric
and
Segment
millions of dollars
Utility
Utilities
Utilities
Infrastructure
Other
Eliminations
Total
For the year ended December 31, 2024
Regulated Revenue
Residential
$
2,063
$
997
$
203
$
712
$
-
$
-
$
3,975
Commercial
939
499
300
496
-
-
2,234
Industrial
223
276
28
94
-
(14)
607
Other electric
372
41
7
-
-
-
420
Regulatory deferrals
(157)
-
15
-
-
-
(142)
Other (1)
20
42
13
224
-
(9)
290
Finance income (2)(3)
-
-
-
63
-
63
Regulated revenue
$
3,460
$
1,855
$
566
$
1,589
$
-
$
(23)
$
7,447
Non-Regulated Revenue
Marketing and trading margin (4)
-
-
-
-
77
-
77
Other non-regulated operating
revenue
-
-
-
20
32
(24)
28
Mark-to-market (3)
-
-
-
-
(357)
5
(352)
Non-regulated revenue
$
-
$
-
$
-
$
20
$
(248)
$
(19)
$
(247)
Total operating revenues
$
3,460
$
1,855
$
566
$
1,609
$
(248)
$
(42)
$
7,200
For the year ended December 31, 2023
Regulated Revenue
Residential
$
2,307
$
910
$
183
$
724
$
-
$
-
$
4,124
Commercial
1,083
463
285
425
-
-
2,256
Industrial
274
219
33
93
-
(13)
606
Other electric
395
41
7
-
-
-
443
Regulatory deferrals
(522)
-
12
-
-
-
(510)
Other (1)
19
38
6
199
-
(8)
254
Finance income (2)(3)
-
-
-
62
-
-
62
Regulated revenue
$
3,556
$
1,671
$
526
$
1,503
$
-
$
(21)
7,235
Non-Regulated
Marketing and trading margin (4)
-
-
-
-
96
-
96
Other non-regulated operating
revenue
-
-
-
21
27
(23)
25
Mark-to-market (3)
-
-
-
-
216
(9)
207
Non-regulated revenue
$
-
$
-
$
-
$
21
$
339
$
(32)
328
Total operating revenues
$
3,556
$
1,671
$
526
$
1,524
$
339
$
(53)
$
7,563
(1) Other includes rental revenues, which do not
represent revenue from contracts with customers.
(2) Revenue related to Brunswick Pipeline's service agreement
with Repsol Energy Canada.
(3) Revenue which does not represent revenues
from contracts with customers.
(4) Includes gains (losses) on settlement of energy
related derivatives, which do not represent
revenue from contracts with
customers.
Remaining Performance Obligations:
Remaining performance obligations primarily represent
gas transportation contracts, lighting contracts,
and long-term steam supply arrangements with fixed contract
terms. As of December 31, 2024, the
aggregate amount of the transaction price allocated to
remaining performance obligations was $
495
million (2023 – $
488
million), including $
3
million related to NMGC. This amount includes
$
135
million of
future performance obligations related to a gas transportation
contract between SeaCoast and PGS
through
2040
. This amount excludes contracts with an original
expected length of one year or less and
variable amounts for which Emera recognizes revenue at the
amount to which it has the right to invoice
for services performed. Emera expects to recognize revenue for
the remaining performance obligations
through
2044
.
27
7. REGULATORY
ASSETS AND LIABILITIES
Regulatory assets represent prudently incurred costs that have
been deferred because it is probable they
will be recovered through future rates or tolls collected from customers.
Management believes existing
regulatory assets are probable for recovery either because
the Company received specific approval from
the applicable regulator, or
due to regulatory precedent established for similar circumstances.
If
management no longer considers it probable that an asset
will be recovered, deferred costs are charged
to income.
Regulatory liabilities represent obligations to make refunds
to customers or to reduce future revenues for
previous collections. If management no longer considers
it probable that a liability will be settled, the
related amount is recognized in income.
For regulatory assets and liabilities that are amortized, the amortization
is as approved by the respective
regulator.
As at
December 31
December 31
millions of dollars
2024 (1)
2023
Regulatory assets
Deferred income tax regulatory assets
$
1,227
$
1,233
TEC capital cost recovery for early retired assets
737
671
Storm cost recovery clauses
613
52
Pension and post-retirement medical plan
395
364
TEC capital cost recovery for retired Polk Unit 1 components
205
-
Deferrals related to derivative instruments
42
88
Cost recovery clauses
33
151
Environmental remediations
29
26
Stranded cost recovery
27
25
NSPI FAM
-
395
Other
(2)
119
100
$
3,427
$
3,105
Current
$
595
$
339
Long-term
2,832
2,766
Total
regulatory assets
$
3,427
$
3,105
Regulatory liabilities
Deferred income tax regulatory liabilities
828
830
Accumulated reserve – COR
733
849
Cost recovery clauses
121
32
NSPI FAM
56
-
Deferrals related to derivative instruments
44
17
BLPC Self-insurance fund ("SIF") (note 33)
32
29
Other
(2)
66
15
$
1,880
$
1,772
Current
$
262
$
168
Long-term
1,618
1,604
Total
regulatory liabilities
$
1,880
$
1,772
(1) On August 5, 2024, Emera announced an
agreement to sell NMGC. As at December
31, 2024, NMGC's assets and liabilities
were classified as held for sale and excluded from
the table above.
For further details on the pending transaction, refer
to note 4.
(2) Comprised of regulatory assets and liabilities
that are not individually significant.
Deferred Income Tax
Regulatory Assets and Liabilities
To
the extent deferred income taxes are expected to be recovered
from or returned to customers in future
years, a regulatory asset or liability is recognized as appropriate
.
28
TEC Capital Cost Recovery for Early Retired Assets
Represents the remaining net book value of Big Bend Power
Station Units 1 through 3 and smart meter
assets that were early retired. The balance earns a rate of return
as permitted by the FPSC and is
recovered as a separate line item on customer bills for
a period of
15
years, beginning in January 2022.
Storm Cost Recovery Clauses
TEC and PGS Storm Reserve:
The storm reserve is for hurricanes and other named storms
that cause significant damage to TEC and
PGS systems. As allowed by the FPSC, if charges to the
storm reserve exceed the storm reserve liability,
the excess is to be carried as a regulatory asset. TEC
and PGS can petition the FPSC to seek recovery
of restoration costs over a 12-month period or longer,
as determined by the FPSC, as well as replenish
the reserve.
NSPI Storm Rider:
NSPI has a UARB approved storm rider for each of 2023,
2024 and 2025, which gives NSPI the ability to
apply to the UARB for recovery of costs if major storm
restoration expenses exceed approximately $
10
million in a given year. The
storm rider was effective as of the General Rate
Application (“GRA”) decision
date. The application for deferral and recovery of the storm rider
is made in the year following the year of
the incurred cost, with recovery beginning in the year
after the application.
GBPC Storm Restoration:
This asset includes storm restoration costs incurred by
GBPC related to Hurricane Dorian in 2020 and
Hurricane Matthew in 2016.
Pension and Post-Retirement Medical Plan
This asset is primarily related to the deferred costs of pension and
post-retirement benefits at TEC, PGS
and, in 2023, NMGC. Deferred costs of postretirement
benefits that are included in expense are
recognized as cost of service for rate-making purposes
as permitted by the FPSC and New Mexico Public
Regulation Commission (“NMPRC”), as applicable and
amortized over the remaining service life of plan
participants.
TEC Capital Cost Recovery for Retired Polk Unit 1
Components
This regulatory asset relates to the remaining net book value
of certain components of Polk Unit 1 that
were early retired on December 31, 2024. The balance earns a
rate of return as permitted by the FPSC
and will be recovered through base rates over an
11
-year recovery period beginning on January 1, 2025.
Deferrals Related to Derivative Instruments
This asset is primarily related to NSPI deferring changes in FV
of derivatives that are documented as
economic hedges or that do not qualify for NPNS exemption,
as a regulatory asset or liability as approved
by the UARB. The realized gain or loss is recognized
when the hedged item settles in regulated fuel for
generation and purchased power,
other income, inventory,
or OM&G, depending on the nature of the item
being economically hedged.
Cost Recovery Clauses
These assets and liabilities are clauses and riders related to
TEC, PGS and, in 2023, NMGC.
They are
recovered or refunded through cost-recovery mechanisms
approved by the FPSC or NMPRC, as
applicable, on a dollar-for-dollar basis in a subsequent
period.
29
Environmental Remediations
This asset is primarily related to PGS costs associated with environmental
remediation at Manufactured
Gas Plant sites. The balance is included in rate base, partially
offsetting the related liability,
and earns a
rate of return as permitted by the FPSC. The timing of recovery
is based on a settlement agreement
approved by the FPSC.
Stranded Cost Recovery
Due to decommissioning of a GBPC steam turbine in 2012,
the GBPA approved
recovery of a $
21
million
USD stranded cost through electricity rates; it is included in
rate base and expected to be included in
rates in future years.
NSPI FAM
NSPI has a FAM, approved
by the UARB, allowing NSPI to recover fluctuating fuel
and certain fuel-
related costs from customers through regularly scheduled
fuel rate adjustments. Differences between
prudently incurred fuel costs and amounts recovered from customers
through electricity rates in a year
are deferred to a FAM regulatory
asset or liability and recovered from or returned to
customers in
subsequent periods.
Accumulated Reserve – COR
This regulatory asset or liability represents the non-ARO
COR reserve in TEC, PGS, NSPI and in 2023,
NMGC. AROs represent the FV of estimated cash flows
associated with the Company’s legal obligation to
retire its PP&E.
Non-ARO COR represent estimated funds received
from customers through depreciation
rates to cover future COR of PP&E value upon retirement
that are not legally required. This reduces rate
base for ratemaking purposes. This liability is reduced
as COR are incurred and increased as
depreciation is recorded for existing assets and as new
assets are put into service.
Regulatory Environments and Updates
Florida Electric Utility
TEC is regulated by the FPSC and is also subject to regulation
by the Federal Energy Regulatory
Commission. 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.
TEC’s approved regulated return on equity (“ROE”)
range for 2024 and 2023 was
9.25
per cent to
11.25
per cent based on an allowed equity capital structure of
54
per cent. An ROE of
10.20
per cent (2023 –
10.20
per cent) is used for the calculation of the return
on investments for clauses.
Base Rates:
On April 2, 2024, TEC filed a rate case with the FPSC for
new base rates. On December 3, 2024, the
FPSC rendered a decision which includes annual base
rate increases of $
185
million USD in 2025 and
adjustments of $
87
million USD and $
9
million USD in 2026 and 2027, respectively.
The allowed equity in
the capital structure will continue to be
54
per cent from investor sources of capital and the allowed
regulatory ROE range is
9.50
per cent to
11.50
per cent with a
10.50
per cent midpoint. On February 3,
2025, the FPSC issued the final order approving the decision,
effective January 1, 2025. On February 18,
2025, a motion for reconsideration on certain aspects of the
rate case order was filed with the FPSC.
On August 16, 2023, TEC filed a petition to implement the
2024 Generation Base Rate Adjustment
provisions pursuant to the 2021 rate case settlement agreement.
Inclusive of TEC’s ROE adjustment, the
increase of $
22
million USD was approved by the FPSC on November
17, 2023.
30
Fuel Recovery and Other Cost Recovery Clauses:
TEC has a fuel recovery clause approved by the FPSC,
allowing the opportunity to recover fluctuating
fuel expenses from customers through annual fuel rate
adjustments. The FPSC annually approves cost-
recovery rates for purchased power,
capacity, environmental
and conservation costs, including a return
on capital invested. Differences between prudently
incurred fuel costs and the cost-recovery rates
and
amounts recovered from customers through electricity
rates in a year are deferred to a regulatory asset or
liability and recovered from or returned to customers
in subsequent periods.
On April 2, 2024, TEC requested a mid-course adjustment
to its fuel and capacity charges, reflecting a
$
138
million USD reduction over
12 months
, from June 2024 through May 2025. The requested
reduction
was due to a decrease in actual and projected 2024 natural
gas prices since TEC submitted its projected
2024 costs in the fall of 2023. On May 7, 2024, the FPSC
approved the mid-course adjustment.
On January 23, 2023, TEC requested an adjustment
to its fuel charges to recover the 2022 fuel under-
recovery of $
518
million USD over a period of
21 months
. The request also included an adjustment to
2023 projected fuel costs to reflect the reduction in natural gas
prices since September 2022 for a
projected reduction of $
170
million USD for the balance of 2023. The changes were
approved by the
FPSC on March 7, 2023, and were effective
beginning on April 1, 2023.
Storm Reserve:
On
September 26, 2024, Hurricane Helene passed 100 miles west
of Tampa
and made landfall
approximately 200 miles north of Tampa,
in Taylor
County, as a Category
4 hurricane. TEC’s service
territory was impacted by the tropical storm force winds
and storm surge which resulted in a peak number
of customers out of 100,000. As of December 31, 2024, TEC
deferred $
49
million USD to the storm
reserve for future recovery.
On October 9, 2024, Hurricane Milton made landfall approximately
50 miles south of Tampa,
near
Sarasota, and was the worst weather event to impact the
area in over 100 years. The Category 3
hurricane had a significant impact on TEC’s service
territory which resulted in a peak number of
customers out of 600,000. As of December 31, 2024, TEC deferred
$
340
million USD to the storm
reserve for future recovery
.
As at December 31, 2024, total restoration costs charged
to the storm reserve account have exceeded
the storm reserve balance, and therefore $
377
million USD has been deferred as a regulatory asset
for
future recovery. On February
4, 2025, the FPSC approved TEC’s petition, filed
on December 27, 2024,
for the recovery of $
466
million USD for costs associated with Hurricane Idalia, Hurricane
Debby,
Hurricane Helene and Hurricane Milton and the associated
interest which will replenish the storm reserve
over an 18-month recovery period beginning March 2025.
The amount of cost-recovery is subject to a
true-up mechanism with the FPSC.
In September 2022, TEC was impacted by Hurricane Ian, with
$
119
million USD of restoration costs
charged against TEC’s FPSC approved storm reserve.
On January 23, 2023, TEC petitioned the FPSC
for recovery of the storm reserve regulatory asset and the replenishment
of the balance in the storm
reserve to the approved storm reserve level of $
56
million USD, for a total of $
131
million USD. The storm
cost recovery surcharge was approved by the FPSC on March
7, 2023, and TEC began applying the
surcharge in April 2023. Subsequently,
on November 9, 2023, the FPSC approved TEC’s
petition, filed on
August 16, 2023, to update the total storm cost collection
to $
134
million USD. The remaining balance of
$
29
million USD as of December 31, 2023, was collected over
12 months in 2024.
31
Storm Protection Cost Recovery Clause and Settlement
Agreement:
The Storm Protection Plan Cost Recovery Clause provides
a process for Florida investor-owned utilities,
including TEC, to recover transmission and distribution
storm hardening costs for incremental activities
not already included in base rates. Differences between
prudently incurred clause-recoverable costs and
amounts recovered from customers through electricity
rates in a year are deferred and recovered from or
returned to customers in a subsequent year.
The current approved plan addressed the years 2023,
2024
and 2025 and was approved by the FPSC in October,
2022.
Canadian Electric Utilities
NSPI
NSPI is a public utility as defined in the Public Utilities
Act of Nova Scotia (“Public Utilities Act”) and is
subject to regulation under the Public Utilities Act by the UARB.
The Public Utilities Act gives the UARB
supervisory powers over NSPI’s operations and
expenditures. Electricity rates for NSPI’s customers
are
also subject to UARB approval. 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 UARB’s request.
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’s approved
regulated ROE range for 2024 and 2023 was
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.
GRA:
On February 2, 2023, the UARB approved the GRA settlement
agreement between NSPI, key customer
representatives and participating interest groups. This resulted
in average customer rate increases of
6.9
per cent effective on February 2, 2023, and further
average increases of
6.5
per cent on January 1, 2024,
with any under or over-recovery of fuel costs addressed through
the UARB’s established FAM
process. It
also established a storm rider and a demand-side management
rider. On March 27,
2023, the UARB
issued a final order approving the electricity rates effective
on February 2, 2023.
Fuel Recovery:
On April 17, 2024, the UARB approved the sale of $
117
million of the FAM regulatory
asset to Invest
Nova Scotia, a provincial Crown corporation. On April
30, 2024, the transaction closed and the $
117
million was remitted to NSPI, which resulted in a corresponding
decrease of the FAM regulatory
asset.
NSPI is collecting the amortization and financing costs
related to the $
117
million from customers on
behalf of Invest Nova Scotia over a
10
-year period, which began in Q2 2024, and is
remitting those
amounts to Invest Nova Scotia quarterly.
Federal Loan Guarantee (“FLG”):
On September 24, 2024, the Government of Canada finalized
an agreement with NSPI, NSPML and the
Province of Nova Scotia (the “Province”) on terms and
conditions for a FLG of $
500
million in debt to be
issued by NSPML to help Nova Scotia customers manage
unrecovered costs of the replacement energy
that was required during the several years of delay in the
Muskrat Falls hydroelectricity project. On
September 25, 2024, NSPI and NSPML filed applications
with the UARB related to the FLG. On
November 29, 2024, the UARB approved NSPML’s
application to issue the debt, transfer the proceeds
to
NSPI as a refund of a portion of previous NSPML assessment
payments, and to increase its annual
assessment charge to NSPI to recover the refund and
related financing costs over a
28
-year period. On
December 16, 2024, the net proceeds of the NSPML debt
issuance were transferred to NSPI and applied
against the FAM regulatory
asset balance. On February 18, 2025, the UARB approved
NSPI's application
to increase 2025 fuel rates to service the incremental
NSPML debt.
Storm Rider:
On December 2, 2024, the UARB approved the recovery
of $
24
million of major storm restoration and
incremental financing costs deferred to NSPI’s storm
rider in 2023 to be recovered over a
12
-month
period beginning on January 1, 2025.
32
Hurricane Fiona:
On June 27, 2024, the UARB approved the deferred recognition
of $
25
million in incremental operating
costs incurred during the Hurricane Fiona storm restoration
efforts in September 2022. Following UARB
approval, the $
25
million was reclassified to “Regulatory assets”
from “Other long-term assets”. The
UARB also directed NSPI to reclassify $
10
million of undepreciated costs related to assets retired
because of Hurricane Fiona to “Regulatory assets” from “PP&E”
on the Consolidated Balance Sheets.
NSPI began amortizing both of these regulatory assets
over a
10
-year period beginning July 1, 2024.
Nova Scotia Cap-and-Trade
(“Cap-and-Trade”)
Program:
On December 31, 2022, the FAM
included a cumulative $
166
million in fuel costs related to the accrued
purchase of emissions credits and $
6
million related to credits purchased from provincial auctions.
On
March 16, 2023, the Province provided NSPI with emissions
allowances sufficient to achieve compliance
for the 2019 through 2022 period. As such, compliance costs
accrued of $
166
million were reversed in Q1
2023. The credits NSPI purchased from provincial auctions
in the amount of $
6
million were not refunded
and no further costs were incurred to achieve compliance
with the Cap-and-Trade Program.
Extra Large Industrial Active Demand Tariff:
On July 5, 2023, NSPI received approval from the UARB to
change the methodology in which fuel cost
recovery from an industrial customer is calculated. Due to significant
volatility in commodity prices in
2022, the previous methodology did not result in a reasonable
determination of the fuel cost to serve this
customer. The change in methodology,
effective January 1, 2022, results in a shifting
of fuel costs from
this industrial customer to the FAM.
This adjustment was recorded in Q2 2023 resulting
in a $
51
million
increase to the FAM regulatory
asset and an offsetting decrease to unbilled revenue
within Receivables
and other current assets. This adjustment had minimal
impact on earnings.
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.
Newfoundland and Labrador Hydro’s (“NLH”) Nova
Scotia Block (“NS Block”) delivery obligations
commenced in 2021 and delivery will continue over the next
35 years
pursuant to the agreements.
On September 24, 2024, the Government of Canada finalized
an agreement with NSPI, NSPML, and the
Province on terms and conditions for a FLG of $
500
million in debt to be issued by NSPML. For further
information, refer to the NSPI section above.
On November 29, 2024, NSPML received approval from the
UARB to collect up to $
197
million in 2025
from NSPI; which includes $
158
million for the recovery of costs associated with the Maritime
Link, and
$
39
million associated with the additional FLG debt and financing costs
noted in the NSPI section above.
Payments from NSPI are subject to a holdback of up to $
4
million per month. There was
no
holdback
recorded for the year ended December 31, 2024.
On December 21, 2023, NSPML received approval from the
UARB to collect up to $
164
million in 2024
from NSPI for the recovery of costs associated with the
Maritime Link subject to a holdback of $
4
million
per month.
33
On October 4, 2023 and January 31, 2024, the UARB issued
decisions providing clarification on
remaining aspects of the Maritime Link holdback mechanism
primarily relating to release of past and
future holdback amounts and requirements to end the holdback
mechanism. In these decisions, the
UARB agreed with the Company’s submission that
$
12
million ($
8
million related to 2022 and $
4
million
related to 2023) of the previously recorded holdback remain
credited to NSPI’s FAM,
with the remainder
released to NSPML and recorded in Emera’s “Income
from equity investments”. The UARB also
confirmed that NSPML can apply for termination of the
holdback mechanism upon
90
per cent of NS
Block deliveries being achieved for 12 consecutive months (subject
to potential relief for planned outages
or exceptional circumstances) and the net outstanding
balance of previously underdelivered NS Block
energy is less than
10
per cent of the contracted annual amount. In addition,
the UARB increased the
monthly holdback amount from $
2
million to $
4
million beginning December 1, 2023.
Gas Utilities and Infrastructure
PGS
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.
PGS’s approved ROE range for 2024 and 2023
was
9.15
per cent to
11.15
per cent with a
10.15
per cent
midpoint, based on an allowed equity capital structure
of
54.7
per cent.
Base Rates:
On April 4, 2023, PGS filed a rate case with the FPSC
and a hearing for the matter was held in
September 2023. On November 9, 2023, the FPSC approved
a $
118
million USD increase to base
revenues which includes $
11
million USD transferred from the cast iron and bare
steel replacement rider,
for a net incremental increase to base revenues of $
107
million USD. This reflects a
10.15
per cent
midpoint ROE with an allowed equity capital structure of
54.7
per cent. A final order was issued on
December 27, 2023, with the new rates effective January
2024.
Fuel Recovery:
PGS recovers the costs it pays for gas supply and
interstate transportation for system supply through its
Purchased Gas Adjustment Clause (“PGAC”). This clause is designed
to recover actual costs incurred by
PGS for purchased gas, gas storage services, interstate pipeline
capacity, and
other related items
associated with the purchase, distribution, and sale of
natural gas to its customers.
These charges may
be adjusted monthly based on a cap approved annually
by the FPSC.
Recovery of Energy Conservation and Pipeline Replacement
Programs:
The FPSC annually approves a conservation charge that
is intended to permit PGS to recover prudently
incurred expenditures in developing and implementing
cost effective energy conservation programs
which
are required by Florida law and approved and monitored
by the FPSC. PGS also has a Cast Iron/Bare
Steel Pipe Replacement clause to recover the cost of accelerating
the replacement of cast iron and bare
steel distribution lines in the PGS system. In February 2017,
the FPSC approved expansion of the Cast
Iron/Bare Steel clause to allow recovery of accelerated
replacement of certain obsolete plastic pipe. The
majority of cast iron and bare steel pipe has been removed
from its system, with replacement of obsolete
plastic pipe continuing until 2028 under the rider.
NMGC
NMGC is subject to regulation by the NMPRC. The NMPRC
sets rates at a level that allows NMGC to
collect total revenues equal to its cost of providing service,
plus an appropriate return on invested capital.
NMGC’s approved ROE for 2024 and 2023
was
9.375
per cent on an allowed equity capital structure of
52
per cent.
34
Base Rates:
On September 14, 2023, NMGC filed a rate case with
the NMPRC for new base rates.
On March 1, 2024,
NMGC filed with the NMPRC a settlement with the support
of all parties in the case for an increase of $
30
million USD in annual base revenues and maintaining
NMGC’s ROE at
9.375
per cent. The rates reflect
the recovery of increased operating costs and capital investments
in pipeline projects and related
infrastructure, as well as a new customer information and
billing system. NMGC also agreed to withdraw,
and to not reassert in a future rate case application,
its request for a regulatory asset for costs associated
with its 2022 application for a certificate of public convenience
and necessity for a liquefied natural gas
storage facility in New Mexico. The NMPRC approved
the rate case settlement on July 25, 2024. New
rates became effective October 1, 2024.
Fuel Recovery:
NMGC recovers gas supply costs through a PGAC. This
clause recovers actual costs for purchased gas,
gas storage services, interstate pipeline capacity,
and other related items associated with the purchase,
transmission, distribution, and sale of natural gas to its
customers. On a monthly basis, NMGC can adjust
charges based on the next month’s expected cost
of gas and any prior month under-recovery or over-
recovery. The NMPRC
requires that NMGC annually file a reconciliation
of the PGAC period costs and
recoveries. NMGC must file a PGAC Continuation Filing
with the NMPRC every four years to establish
that the continued use of the PGAC is reasonable and
necessary. NMGC
received approval of its PGAC
Continuation in December 2024, for the four-year period
ending December 2028.
Brunswick Pipeline
Brunswick Pipeline is a
145
-kilometre pipeline delivering natural gas from the Saint
John LNG import
terminal near Saint John, New Brunswick to markets in
the northeastern US. Brunswick Pipeline entered
into a
25
-year firm service agreement commencing in July
2009 with Repsol Energy Canada. The
agreement provides for a predetermined toll increase
in the fifth and fifteenth year of the contract. The
pipeline is considered a Group II pipeline regulated by
the Canada Energy Regulator (“CER”). The CER
Gas Transportation Tariff
is filed by Brunswick Pipeline in compliance with the
requirements of the CER
Act and sets forth the terms and conditions of the transportation
rendered by Brunswick Pipeline.
Other Electric Utilities
BLPC
BLPC is regulated by the Fair Trading
Commission (“FTC”), under the Utilities Regulation (Procedural)
Rules 2003. BLPC is regulated under a cost-of-service model,
with rates set to recover prudently incurred
costs of providing electricity service to customers plus
an appropriate return on capital invested. BLPC’s
approved regulated return on rate base was
10
per cent for 2024 and 2023.
Licenses:
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 2021, BLPC reached commercial agreement with
the Government of Barbados for each of the license types,
subject to the passage of implementing
legislation. The timing of the final enactment is unknown at
this time, but BLPC will work towards the
implementation of the licenses once enacted.
35
Base Rates:
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 is
currently scheduled to be heard in 2025.
Fuel Recovery:
BLPC’s fuel costs flow through a fuel pass-through
mechanism which provides opportunity to recover
all
prudently incurred fuel costs from customers in a timely
manner. The calculation of the fuel
charge is
adjusted on a monthly basis and reported to the FTC for
approval.
Clean Energy Transition
Rider (“CETR”):
On May 31, 2023, the FTC approved BLPC’s
application to establish an alternative cost recovery
mechanism to recover prudently incurred costs associated
with its CETR (the “Decision”). The
mechanism is intended to facilitate the timely recovery between
rate cases of costs associated with
approved renewable energy assets. BLPC will be required
to submit an individual application for the
recovery of costs of each asset through the cost recovery
mechanism, meeting the minimum criteria as
set out in the Decision. On October 5, 2023, BLPC applied
to the FTC to recover the costs of a battery
storage system through the CETR. On May 6, 2024, the
FTC approved the recovery of a
15
MW battery
storage system through the CETR.
Barbados Domestic Tax
Rate Change:
On May 24, 2024, the Government of Barbados signed
the Income Tax
(Amendment and Validation)
Act
into law. The legislation, effective
January 1, 2024, implemented a corporate income
tax rate of
9
per
cent, requiring BLPC to remeasure its deferred income
tax liabilities. On July 18, 2024, BLPC requested
the deferred recovery of the $
5
million USD remeasurement. BLPC is seeking amortization
of the costs
over a period to be approved by the FTC during a future
rate setting process.
GBPC
GBPC is regulated by the GBPA.
The GBPA
has granted GBPC a licensed, regulated and exclusive
franchise to produce, transmit and distribute electricity
on the island until 2054. Rates are set to recover
prudently incurred costs of providing electricity service
to customers plus an appropriate return on rate
base. GBPC’s approved regulated return on rate base
was
8.52
per cent for 2024 (2023 –
8.32
per cent).
Electricity Act, 2024:
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, another
Bahamian
regulator, regulate GBPC.
Base Rates:
There is a fuel pass-through mechanism and tariff review
policy with new rates submitted every three
years. On August 1, 2024, as required by the GBPA
Operating Protocol and Regulatory Framework
Agreement, GBPC filed a rate plan proposal and is awaiting
regulatory review.
36
Fuel Recovery:
GBPC’s fuel costs flow through a fuel pass-through
mechanism which provides the opportunity to recover
all prudently incurred fuel costs from customers in a timely
manner. In 2023 and 2024,
the fuel pass
through charge was adjusted monthly,
in-line with actual fuel costs.
8. INVESTMENTS SUBJECT TO SIGNIFICANT INFLUENCE AND EQUITY INCOME
Equity Income
Percentage
Carrying Value
For the year ended
of
As at December 31
December 31
Ownership
millions of dollars
2024
2023
2024
2023
2024
NSPML
$
475
$
489
$
44
$
46
100.0
M&NP
(1)
124
118
20
21
12.9
Lucelec
(1)
55
48
4
4
19.5
LIL
(2)
-
747
29
63
-
Bear Swamp
(3)
-
-
2
12
50.0
$
654
$
1,402
$
99
$
146
(1) Emera has significant influence over the operating
and financial decisions of these companies through
Board representation
and therefore, records its investment in these
entities using the equity method.
(2) On June 4, 2024, Emera completed the sale
of its equity interest in the LIL. For further
details, refer to note 4.
(3) The investment balance in Bear Swamp is
in a credit position primarily as a result
of a $
179
million distribution received in 2015.
Bear Swamp's credit investment balance of $
92
million (2023 – $
81
million) is recorded in Other long-term liabilities
on the
Consolidated Balance Sheets.
Equity investments include a $
9
million difference between the cost and the
underlying FV of the
investees' assets as at the date of acquisition. The excess
is attributable to goodwill.
Emera accounts for its variable interest investment in
NSPML as an equity investment (note 33).
NSPML's consolidated summarized balance sheets are illustrated
as follows:
As at
December 31
December 31
millions of dollars
2024
2023
Balance Sheets
Current assets
$
37
$
21
PP&E
1,425
1,473
Regulatory assets
(1)
778
272
Non-current assets
27
29
Total
assets
$
2,267
$
1,795
Current liabilities
$
55
$
48
Long-term debt
(2)
1,570
1,109
Non-current liabilities
167
149
Equity
475
489
Total
liabilities and equity
$
2,267
$
1,795
(1) On November 29, 2024, the UARB approved
the creation of a $
500
million regulatory asset for debt issued as a
result of the
FLG. For further details, refer to note 7.
(2) On December 16, 2024, NSPML issued a
$
500
million bond under the FLG. For further details
refer to note 7.
37
9. OTHER INCOME, NET
For the
Year ended December 31
millions of dollars
2024
2023
Gain on sale of LIL, net of transaction costs
(1)
$
182
$
-
AFUDC
53
38
Pension non-current service cost recovery
35
35
Interest income
23
43
Transaction costs related to the pending sale of NMGC
(1)
(25)
-
Charges related to wind-down costs and certain asset impairments (2)
(29)
-
FX (losses) gains
(58)
20
Other
22
22
$
203
$
158
(1) For more information related to the gain
on sale, after transaction costs, of Emera's indirect
minority interest in the LIL and the
pending sale of NMGC, refer to note 4.
(2) Primarily related to the wind-down of Block
Energy LLC
10. INTEREST EXPENSE, NET
Interest expense, net consisted of the following:
For the
Year ended December 31
millions of dollars
2024
2023
Interest on debt
$
1,004
$
954
Allowance for borrowed funds used during construction
(23)
(16)
Other
(8)
(13)
$
973
$
925
11. INCOME TAXES
The income tax provision, for the years ended December
31, differs from that computed using the
enacted combined Canadian federal and provincial statutory
income tax rate for the following reasons:
millions of dollars
2024
2023
Income before provision for income taxes
$
409
$
1,173
Statutory income tax rate
29.0%
29.0%
Income taxes, at statutory income tax rate
119
340
Deferred income taxes on regulated income recorded as regulatory assets and
regulatory liabilities
(90)
(72)
Interest and financing expenses
(58)
-
Valuation allowance
(58)
3
Tax
credits
(57)
(53)
Goodwill impairment charge
49
-
Amortization of deferred income tax regulatory liabilities
(36)
(33)
Foreign tax rate variance
(31)
(36)
Additional impact from the sale of LIL equity interest
22
-
Tax
effect of equity earnings
(14)
(15)
Manufacturing allowance
(9)
(8)
Other
4
2
Income tax (recovery) expense
$
(159)
$
128
Effective income tax rate
(39%)
11%
Bahamian Domestic Minimum Top
-up Tax
Act (“Domestic Top
-up Tax
Act”):
On November 28, 2024, the Domestic Top
-up Tax
Act was enacted with an effective date of January
1,
2024.The Domestic Top
-up Tax
Act did not have an impact on the Company.
38
Excessive Interest and Financing Expenses Limitation
(“EIFEL”) Regime:
On June 20, 2024, Bill C-59, an Act to implement certain provisions
of the fall economic statement tabled
in Parliament on November 21, 2023, and certain provisions
of the budget tabled in Parliament on March
28, 2023, was enacted.
Bill C-59 includes the EIFEL regime, which is effective
January 1, 2024. EIFEL
applies to limit a company’s net interest and financing
expense deduction to no more than 30 per cent of
earnings before interest, income taxes, depreciation, and amortization
for tax purposes. Any denied
interest and financing expenses under the EIFEL regime can
be carried forward indefinitely.
During 2024, the Company incurred $
185
million of interest and financing expenses in connection with
a
specific financing structure. The interest and financing expenses
related to the financing structure as well
as $
88
million of other interest and financing expenses are expected
to be denied under the EIFEL
regime. It was determined that the Company is more likely
than not to realize the tax benefit of the denied
interest and financing expenses in future periods and therefore
a $
79
million deferred income tax asset
has been recorded as at December 31, 2024. In Q4 2024, the
Company recognized a $
58
million tax
benefit related to the denied interest and financing expenses
and the reversal of the related deferred
income tax liability in connection with the financing structure
and its wind-up.
Canadian Global Minimum Tax
Act (“GMTA”):
On June 20, 2024, the GMTA
was enacted with an effective date of January
1, 2024. The GMTA
did not
have an impact on the Company.
Barbados Domestic Tax
Rate Change:
On May 24, 2024, the Government of Barbados signed the
Income Tax
(Amendment and Validation)
Act
into law. The legislation, effective
January 1, 2024, implemented a corporate income tax
rate of
9
per
cent, requiring BLPC to remeasure its deferred income
tax liabilities.
Barbados Corporation Top
-up Tax
(Amendment) Act (“Top
-up Tax
Act”):
On May 24, 2024, the Top
-up Tax
Act was enacted with an effective date of January
1, 2024. The Top
-up
Tax
Act did not have an impact on the Company
.
United States Inflation Reduction Act (“IRA”):
On August 16, 2022, the IRA was signed into legislation.
The IRA includes numerous tax incentives for
clean energy, such
as the extension and modification of existing investment
and production tax credits for
projects placed in service through 2024, and introduces
new technology-neutral clean energy related tax
credits beginning in 2025. As of December 31, 2024, the
Company has recorded a $
82
million (December
31, 2023 – $
30
million) regulatory liability on the Consolidated Balance
Sheets in recognition of its
obligation to pass the incremental tax benefits realized
to customers.
The following table reflects the composition of taxes on
income from continuing operations presented in
the Consolidated Statements of Income for the years ended
December 31:
millions of dollars
2024
2023
Current income taxes
Canada
$
29
$
26
United States
4
5
Deferred income taxes
Canada
(200)
93
United States
155
128
Adjustments to beginning of the year valuation allowance
Canada
(61)
-
Investment tax credits
United States
(6)
(29)
Operating loss carryforwards
Canada
(4)
(93)
United States
(76)
(2)
Income tax (recovery) expense
$
(159)
$
128
39
The following table reflects the composition of income
before provision for income taxes presented in the
Consolidated Statements of Income for the years ended
December 31:
millions of dollars
2024
2023
Canada
$
156
$
171
United States
203
964
Other
50
38
Income before provision for income taxes
$
409
$
1,173
The deferred income tax assets and liabilities presented in
the Consolidated Balance Sheets as at
December 31 consisted of the following:
millions of dollars
2024
2023
Deferred income tax assets:
Tax
loss carryforwards
$
1,118
$
1,195
Tax
credit carryforwards
534
454
Regulatory liabilities
225
175
Derivative instruments
144
205
Other
462
372
Total
deferred income tax assets before valuation allowance
2,483
2,401
Valuation allowance
(322)
(363)
Total
deferred income tax assets after valuation allowance
$
2,161
$
2,038
Deferred income tax liabilities:
PP&E
$
(3,421)
$
(3,223)
Regulatory assets
(198)
(196)
Derivative instruments
(105)
(235)
Investments subject to significant influence
(46)
(216)
Other
(330)
(312)
Total
deferred income tax liabilities
$
(4,100)
$
(4,182)
Consolidated Balance Sheets presentation:
Long-term deferred income tax assets
$
392
$
208
Long-term deferred income tax liabilities
(2,331)
(2,352)
Net deferred income tax liabilities
$
(1,939)
$
(2,144)
Considering all evidence regarding the utilization of the Company’s
deferred income tax assets, it has
been determined that Emera is more likely than not to realize
all recorded deferred income tax assets,
except for certain loss carryforwards and unrealized capital
losses on long-term debt and investments. A
valuation allowance of $
322
million has been recorded as at December 31, 2024 (2023
– $
363
million)
related to the loss carryforwards, long-term debt and investments.
During 2024, the Company recognized
a $
58
million tax benefit primarily due to the utilization of certain
loss carryforwards, which were subject to
a valuation allowance as at December 31, 2023.
The Company intends to indefinitely reinvest earnings
from certain foreign operations. Accordingly,
$
4.7
billion as at December 31, 2024 (2023 – $
4.7
billion) in cumulative temporary differences for which
deferred taxes might otherwise be required, have not
been recognized. It is impractical to estimate the
amount of income and withholding tax that might be payable
if a reversal of temporary differences
occurred.
40
Emera’s NOL, capital loss and tax credit carryforwards
and their expiration periods as at December 31,
2024 consisted of the following:
Subject to
Tax
Valuation
Net Tax
Expiration
millions of dollars
Carryforwards
Allowance
Carryforwards
Period
Canada
NOL
$
2,420
$
(967)
$
1,453
2026 - 2044
Capital loss
55
(55)
-
Indefinite
Tax Credit
2
(1)
1
2028 - 2042
United States
Federal NOL
$
1,587
$
(1)
$
1,586
2036 - Indefinite
State NOL
1,351
(1)
1,350
2026 - Indefinite
Tax credit
533
(3)
530
2025 - 2044
Other
NOL
$
91
$
(23)
$
68
2025 - 2031
The following table provides details of the change in unrecognized
tax benefits for the years ended
December 31 as follows:
millions of dollars
2024
2023
Balance, January 1
$
37
$
33
Increases due to tax positions related to current year
6
5
Increases due to tax positions related to a prior year
2
1
Decreases due to tax positions related to a prior year
(3)
(2)
Balance, December 31
$
42
$
37
Unrecognized tax benefits relate to the timing of certain
tax deductions at NSPI and research and
development tax credits primarily at TEC. The total amount
of unrecognized tax benefits as at December
31, 2024 was $
42
million (2023 – $
37
million), which would affect the effective
tax rate if recognized. The
total amount of accrued interest with respect to unrecognized tax
benefits was $
10
million (2023 – $
9
million) with $
1
million interest expense recognized in the Consolidated
Statements of Income (2023 – $
2
million).
No
penalties have been accrued. The balance of unrecognized
tax benefits could change in the
next 12 months as a result of resolving Canada Revenue
Agency (“CRA”) and Internal Revenue Service
audits. A reasonable estimate of any change cannot be made
at this time.
NSPI and the CRA are currently in a dispute with respect
to the timing of certain tax deductions for
its 2006 through 2010 and 2013 through 2016 taxation
years. The ultimate permissibility of the tax
deductions is not in dispute; rather,
it is the timing of those deductions. The cumulative net
amount in
dispute to date is $
126
million (2023 – $
126
million), including interest. NSPI has prepaid $
55
million
(2023 – $
55
million) of the amount in dispute, as required by
CRA.
On November 29, 2019, NSPI filed a Notice of Appeal
with the Tax
Court of Canada with respect to its
dispute of the 2006 through 2010 taxation years. Should
NSPI be successful in defending its position, all
payments including applicable interest will be refunded.
If NSPI is unsuccessful in defending any portion
of its position, the resulting taxes and applicable interest
will be deducted from amounts previously paid,
with the difference, if any,
either owed to, or refunded from, the CRA. The related
tax deductions will be
available in subsequent years.
Should NSPI be similarly reassessed by the CRA for years
not currently in dispute, further payments will
be required; however, the
ultimate permissibility of these deductions would be
similarly not in dispute.
NSPI and its advisors believe that NSPI has reported
its tax position appropriately.
NSPI continues to
assess its options to resolving the dispute; however,
the outcome of the Notice of Appeal process is not
determinable at this time.
41
Emera files a Canadian federal income tax return, which
includes its Nova Scotia provincial income tax.
Emera’s subsidiaries file Canadian, US, Barbados,
and St. Lucia income tax returns. As at December
31,
2024, the Company’s tax years still open to examination
by taxing authorities include 2006 and
subsequent years.
12. COMMON STOCK
Authorized
: Unlimited number of non-par value common shares.
2024
2023
Issued and outstanding:
millions
of shares
millions of
dollars
millions of
shares
millions of
dollars
Balance, January 1
284.12
$
8,462
269.95
$
7,762
Issuance of common stock under ATM program
(1)(2)
5.12
261
8.29
397
Issued under the DRIP,
net of discounts
6.10
291
5.26
272
Senior management stock options exercised and Employee Share
Purchase Plan
0.60
28
0.62
31
Balance, December 31
295.94
$
9,042
284.12
$
8,462
(1) For the year ended December 31, 2023, a
total of
8,287,037
common shares were issued under Emera's ATM program at an
average price of $
48.27
per share for gross proceeds of $
400
million ($
397
million net of after-tax issuance costs).
(2) For the year ended December 31, 2024, a
total of
5,117,273
common shares were issued under Emera's ATM program at an
average price of $
51.52
per share for gross proceeds of $
264
million ($
261
million net of after-tax issuance costs). As at December
31, 2024, an aggregate gross sales limit of $
336
million remained available for issuance under the
ATM program.
As at December 31, 2024, the following common shares
were reserved for issuance:
6
million (2023 –
6
million) under the senior management stock option plan,
2
million (2023 –
2
million) under the employee
common share purchase plan and
12
million (2023 –
18
million) under the DRIP.
The issuance of common shares under the common share compensation
arrangements does not allow
the plans to exceed
10
per cent of Emera's outstanding common shares. As at
December 31, 2024,
Emera was in compliance with this requirement.
ATM Equity Program
On November 18, 2024, Emera increased the size of
the ATM Program to
allow the Company to issue up
to $
1
billion 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 was increased by an amendment dated November 18,
2024 to its prospectus supplement dated November 14, 2023 and
an amendment dated November 13,
2024 to its short form base shelf prospectus dated October 3,
2023.
13. EARNINGS PER SHARE
Basic earnings per share is determined by dividing net income
attributable to common shareholders by
the weighted average number of common shares outstanding
during the period. Diluted EPS is computed
by dividing net income attributable to common shareholders
by the weighted average number of common
shares outstanding during the period, adjusted for the exercise
and/or conversion of all potentially dilutive
securities. Such dilutive items include Company contributions
to the senior management stock option
plan, convertible debentures and shares issued under the DRIP.
42
The following table reconciles the computation of basic
and diluted earnings per share:
For the
Year ended December 31
millions of dollars (except per share amounts)
2024
2023
Numerator
Net income attributable to common shareholders
$
493.6
$
977.7
Diluted numerator
493.6
977.7
Denominator
Weighted average shares of common stock outstanding – basic
289.1
273.6
Stock-based compensation
0.1
0.2
Weighted average shares of common stock outstanding – diluted
289.2
273.8
Earnings per common share
Basic
$
1.71
$
3.57
Diluted
$
1.71
$
3.57
14. ACCUMULATED OTHER
COMPREHENSIVE INCOME
The components of AOCI are as follows:
millions of dollars
Unrealized gain
(loss) on
translation of
self-sustaining
foreign
operations
Net change
in net
investment
hedges
Gains (losses)
on derivatives
recognized
as cash flow
hedges
Net change
on available-
for-sale
investments
Net change in
unrecognized
pension and
post-retirement
benefit costs
Total
AOCI
For the year ended December 31, 2024
Balance, January 1, 2024
$
369
$
(24)
$
14
$
(2)
$
(52)
$
305
OCI before
reclassifications
1,027
(139)
-
2
-
890
Amounts reclassified from
AOCI
-
-
(2)
-
68
66
Net current period OCI
1,027
(139)
(2)
2
68
956
Balance, December 31, 2024
$
1,396
$
(163)
$
12
$
-
$
16
$
1,261
For the year ended December 31, 2023
Balance, January 1, 2023
$
639
$
(62)
$
16
$
(2)
$
(13)
$
578
OCI before
reclassifications
(270)
38
-
-
-
(232)
Amounts reclassified from
AOCI
-
-
(2)
-
(39)
(41)
Net current period OCI
(270)
38
(2)
-
(39)
(273)
Balance, December 31, 2023
$
369
$
(24)
$
14
$
(2)
$
(52)
$
305
The reclassifications out of AOCI are as follows:
For the
Year ended December 31
millions of dollars
2024
2023
Affected line item in the Consolidated Financial Statements
Gains on derivatives recognized as cash flow hedges
Interest rate hedge
Interest expense, net
$
(2)
$
(2)
Net change in unrecognized pension and post-retirement benefit costs
Actuarial losses
Other income, net
$
2
$
-
Past service (gains) costs
Other income, net
(2)
2
Amounts reclassified into obligations
Pension and post-retirement benefits
68
(40)
Total
before tax
68
(38)
Income tax expense
-
(1)
Total
net of tax
$
68
$
(39)
Total reclassifications out of AOCI, net of tax, for the period
$
66
$
(41)
43
15. INVENTORY
As at
December 31
December 31
millions of dollars
2024
2023
Materials
$
453
$
408
Fuel
328
382
Total
$
781
$
790
16. DERIVATIVE
INSTRUMENTS
Derivative assets and liabilities relating to the foregoing categories
consisted of the following:
Derivative Assets
Derivative Liabilities
As at
December 31
December 31
December 31
December 31
millions of dollars
2024
2023
2024
2023
Regulatory deferral:
Commodity swaps and forwards
$
25
$
16
$
44
$
76
FX forwards
27
3
3
3
52
19
47
79
HFT derivatives:
Power swaps and physical contracts
34
29
30
36
Natural gas swaps, futures, forwards, physical
contracts
236
319
660
531
270
348
690
567
Other derivatives:
Equity derivatives
-
4
2
-
FX forwards
-
18
34
7
-
22
36
7
Total
gross current derivatives
322
389
773
653
Impact of master netting agreements:
Regulatory deferral
(7)
(3)
(7)
(3)
HFT derivatives
(148)
(146)
(148)
(146)
Total
impact of master netting agreements
(155)
(149)
(155)
(149)
Less: Derivatives classified as held for sale
(1)
(1)
-
(1)
-
Total derivatives
$
166
$
240
$
617
$
504
Current
(2)
115
174
526
386
Long-term
(2)
51
66
91
118
Total derivatives
$
166
$
240
$
617
$
504
(1) On August 5, 2024, Emera announced an
agreement to sell NMGC. As at December
31, 2024, NMGC's assets and liabilities
were classified as held for sale. For further details
on the pending transaction, refer to note 4.
(2) Derivative assets and liabilities are classified
as current or long-term based upon the maturities
of the underlying contracts.
Cash Flow Hedges
On May 26, 2021, a treasury lock was settled for a
gain of $
19
million that is being amortized through
interest expense over
10 years
as the underlying hedged item settles. As of December 31,
2024, the
unrealized gain in AOCI was $
12
million, after-tax (December 31, 2023 – $
14
million, after-tax). For the
year ended December 31, 2024, unrealized gains of $
2
million (2023 – $
2
million) have been reclassified
from AOCI into interest expense, net. The Company expects
$
2
million of unrealized gains currently in
AOCI to be reclassified into net income within the next
twelve months.
44
Regulatory Deferral
The Company has recorded the following changes with
respect to derivatives receiving regulatory
deferral:
Commodity
Physical
Commodity
swaps and
FX
natural gas
swaps and
FX
millions of dollars
forwards
forwards
purchases
forwards
forwards
For the year ended December 31
2024
2023
Unrealized gain (loss) in regulatory assets
$
(27)
$
5
$
-
$
(109)
$
(3)
Unrealized gain (loss) in regulatory liabilities
11
33
(3)
(73)
-
Realized gain in regulatory assets
(8)
-
-
(5)
-
Realized loss in regulatory liabilities
4
-
-
2
-
Realized (gain) loss in inventory
(1)
11
(8)
-
4
(10)
Realized (gain) loss in regulated fuel for generation
and purchased power
(2)
50
(6)
(49)
(9)
(4)
Other
-
-
-
(14)
-
Total
change in derivative instruments
$
41
$
24
$
(52)
$
(204)
$
(17)
(1) Realized (gains) losses will be recognized in
fuel for generation and purchased power when
the hedged item is consumed.
(2) Realized (gains) losses on derivative instruments
settled and consumed in the period and hedging relationships
that have been
terminated or the hedged transaction is no longer
probable.
As at December 31, 2024, the Company had the following
notional volumes designated for regulatory
deferral that are expected to settle as outlined below:
millions
2025
2026-2027
Physical natural gas purchases:
Natural gas (MMBtu)
6
-
Commodity swaps and forwards purchases:
Natural gas (MMBtu)
21
23
Power (MWh)
1
-
Coal (metric tonnes)
1
-
FX forwards:
FX contracts (millions of USD)
$
208
$
69
Weighted average rate
1.3361
1.3296
% of USD requirements
50%
17%
HFT Derivatives
The Company has recognized the following realized and
unrealized gains (losses) with respect to HFT
derivatives:
For the
Year ended December 31
millions of dollars
2024
2023
Power swaps and physical contracts in non-regulated operating revenues
$
12
$
(6)
Natural gas swaps, forwards, futures and physical contracts in non-regulated
operating revenues
195
1,043
Total
gains in net income
$
207
$
1,037
As at December 31, 2024, the Company had the following
notional volumes of outstanding HFT
derivatives that are expected to settle as outlined below:
2029 and
millions
2025
2026
2027
2028
thereafter
Natural gas purchases (Mmbtu)
262
111
43
30
73
Natural gas sales (Mmbtu)
299
69
16
8
4
Power purchases (MWh)
1
-
-
-
-
Power sales (MWh)
1
-
-
-
-
45
Other Derivatives
As at December 31, 2024, the Company had equity
derivatives in place to manage cash flow risk
associated with forecasted future cash settlements of deferred
compensation obligations and FX forwards
in place to manage cash flow risk associated with forecasted
USD cash inflows.
The equity derivatives
hedge the return on
2.9
million shares and extends until December 2025. The
FX forwards have a
combined notional amount of $
520
million USD and expire in 2025 through 2026.
For the
Year ended December 31
millions of dollars
2024
2023
FX
Equity
FX
Equity
Forwards
Derivatives
Forwards
Derivatives
Unrealized gain (loss) in OM&G
$
-
$
(2)
$
-
$
4
Unrealized gain (loss) in other income, net
(44)
-
28
-
Realized gain (loss) in OM&G
-
16
-
(13)
Realized loss in other income, net
(12)
-
(11)
-
Total
gains (losses) in net income
$
(56)
$
14
$
17
$
(9)
Credit Risk
The Company is exposed to credit risk with respect to
amounts receivable from customers, energy
marketing collateral deposits and derivative assets. Credit risk
is the potential loss from a counterparty’s
non-performance under an agreement. The Company manages
credit risk with policies and procedures
for counterparty analysis, exposure measurement, and
exposure monitoring and mitigation. Credit
assessments are conducted on all new customers and
counterparties, and deposits or collateral are
requested on any high-risk accounts.
The Company assesses the potential for credit losses
on a regular basis and, where appropriate,
maintains provisions. With respect to counterparties, the Company
has implemented procedures to
monitor the creditworthiness and credit exposure of counterparties
and to consider default probability in
valuing the counterparty positions. The Company monitors
counterparties’ credit standing, including those
that are experiencing financial problems, have significant swings
in default probability rates, have credit
rating changes by external rating agencies, or have changes
in ownership. Net liability positions are
adjusted based on the Company’s current default probability.
Net asset positions are adjusted based on
the counterparty’s current default probability.
The Company assesses credit risk internally for
counterparties that are not rated.
As at December 31, 2024, the maximum exposure the
Company had to credit risk was $
1.3
billion (2023
– $
1.2
billion), which included accounts receivable net
of collateral/deposits and assets related to
derivatives.
It is possible that volatility in commodity prices could cause
the Company to have material credit risk
exposures with one or more counterparties. If such counterparties
fail to perform their obligations under
one or more agreements, the Company could suffer
a material financial loss. The Company transacts with
counterparties as part of its risk management strategy for managing
commodity price, FX and interest
rate risk. Counterparties that exceed established credit
limits can provide a cash deposit or letter of credit
to the Company for the value in excess of the credit limit where
contractually required. The total cash
deposits/collateral on hand as at December 31, 2024 was
$
303
million (2023 – $
310
million), which
mitigated the Company’s maximum credit risk
exposure. The Company uses the cash as payment for the
amount receivable or returns the deposit/collateral to the
customer/counterparty where it is no longer
required by the Company.
46
The Company enters into commodity master arrangements
with its counterparties to manage certain
risks, including credit risk to these counterparties. The
Company generally enters into International Swaps
and Derivatives Association agreements, North American Energy
Standards Board agreements and, or
Edison Electric Institute agreements. The Company believes
entering into such agreements offers
protection by creating contractual rights relating to creditworthiness,
collateral, non-performance and
default.
As at December 31, 2024, the Company had $
140
million (2023 – $
142
million) in financial assets,
considered to be past due, which have been outstanding for
an average
61
days. The FV of these
financial assets was $
128
million (2023 – $
127
million), the difference of which was included
in the
allowance for credit losses. These assets primarily relate
to accounts receivable from electric and gas
revenue.
Concentration Risk
The Company's concentrations of risk consisted of the
following:
As at
December 31, 2024
December 31, 2023
millions of
dollars
% of total
exposure
millions of
dollars
% of total
exposure
Receivables, net
Regulated utilities:
Residential
$
376
22%
$
476
31%
Commercial
184
11%
194
13%
Industrial
73
4%
84
5%
Other
105
6%
103
7%
Cash collateral
46
3%
94
6%
784
46%
951
62%
Trading group:
Credit rating of A- or above
88
5%
47
3%
Credit rating of BBB- to BBB+
42
2%
33
2%
Not rated
165
10%
108
7%
295
17%
188
12%
Other accounts receivable
331
20%
151
10%
Classification as assets held for sale
(1)
118
7%
-
0%
1,528
90%
1,290
84%
Derivative Instruments
(current and long-term)
Credit rating of A- or above
91
5%
138
9%
Credit rating of BBB- to BBB+
1
0%
7
1%
Not rated
74
5%
95
6%
166
10%
240
16%
$
1,694
100%
$
1,530
100%
(1) On August 5, 2024, Emera announced the
sale of NMGC. As at December 31, 2024
NMGC's assets and liabilities were
classified as held for sale. For further details, refer
to note 4.
Cash Collateral
The Company’s cash collateral positions consisted
of the following:
As at
December 31
December 31
millions of dollars
2024
2023
Cash collateral provided to others
$
198
$
101
Cash collateral received from others
$
5
$
22
47
Collateral is posted in the normal course of business based
on the Company’s creditworthiness, including
its senior unsecured credit rating as determined by certain
major credit rating agencies. Certain
derivatives contain financial assurance provisions that require
collateral to be posted if a material adverse
credit-related event occurs. If a material adverse event resulted
in the senior unsecured debt falling below
investment grade, the counterparties to such derivatives
could request ongoing full collateralization.
As at December 31, 2024, the total FV of derivatives
in a liability position was $
617
million (December 31,
2023
–
$
504
million). If the credit ratings of the Company
were reduced below investment grade, the full
value of the net liability position could be required to be
posted as collateral for these derivatives.
17. FV MEASUREMENTS
The Company is required to determine the FV of all derivatives
except those which qualify for the NPNS
exemption (see note 1) and uses a market approach
to do so. The three levels of the FV hierarchy are
defined as follows:
Level 1 – Where possible, the Company bases the fair valuation
of its financial assets and liabilities on
quoted prices in active markets (“quoted prices”) for identical
assets and liabilities.
Level 2 – Where quoted prices for identical assets and
liabilities are not available, the valuation of certain
contracts must be based on quoted prices for similar assets
and liabilities with an adjustment related to
location differences. Also, certain derivatives are valued
using quotes from over-the-counter clearing
houses.
Level 3 – Where the information required for a Level 1
or Level 2 valuation is not available, derivatives
must be valued using unobservable or internally developed inputs.
The primary reasons for a Level 3
classification are as follows:
●
While valuations were based on quoted prices, significant assumptions
were necessary to reflect
seasonal or monthly shaping and locational basis differentials.
●
The term of certain transactions extends beyond the period when
quoted prices are available and,
accordingly, assumptions
were made to extrapolate prices from the last quoted
period through the
end of the transaction term.
●
The valuations of certain transactions were based on internal
models, although quoted prices were
utilized in the valuations.
Derivative assets and liabilities are classified in their entirety,
based on the lowest level of input that is
significant to the FV measurement.
48
The following tables set out the classification of the methodology
used by the Company to FV its
derivatives:
As at
December 31, 2024
millions of dollars
Level 1
Level 2
Level 3
Total
Assets
Regulatory deferral:
Commodity swaps and forwards
$
15
$
3
$
-
$
18
FX forwards
-
27
-
27
15
30
-
45
HFT derivatives:
Power swaps and physical contracts
2
23
5
30
Natural gas swaps, futures, forwards, physical
contracts and related transportation
13
52
27
92
15
75
32
122
Less: Derivatives classified as held for sale
(1)
-
(1)
-
(1)
Total assets
30
104
32
166
Liabilities
Regulatory deferral:
Commodity swaps and forwards
$
18
$
19
$
-
$
37
FX forwards
-
3
-
3
18
22
-
40
HFT derivatives:
Power swaps and physical contracts
2
21
4
27
Natural gas swaps, futures, forwards and physical
contracts
(11)
89
437
515
(9)
110
441
542
Other derivatives:
FX forwards
-
34
-
34
Equity derivatives
2
-
-
2
2
34
-
36
Less: Derivatives classified as held for sale
(1)
-
(1)
-
(1)
Total liabilities
11
165
441
617
Net assets (liabilities)
$
19
$
(61)
$
(409)
$
(451)
(1) On August 5, 2024, Emera announced an
agreement to sell NMGC. As at December
31, 2024, NMGC's assets and liabilities
were classified as held for sale. For further details
on the pending transaction, refer to note 4
49
As at
December 31, 2023
millions of dollars
Level 1
Level 2
Level 3
Total
Assets
Regulatory deferral:
Commodity swaps and forwards
$
7
$
6
$
-
$
13
FX forwards
-
3
-
3
7
9
-
16
HFT derivatives:
Power swaps and physical contracts
(5)
23
-
18
Natural gas swaps, futures, forwards, physical
contracts and related transportation
42
108
34
184
37
131
34
202
Other derivatives:
FX forwards
-
18
-
18
Equity derivatives
4
-
-
4
4
18
-
22
Total assets
48
158
34
240
Liabilities
Regulatory deferral:
Commodity swaps and forwards
43
30
-
73
FX forwards
-
3
-
3
43
33
-
76
HFT derivatives:
Power swaps and physical contracts
-
24
-
24
Natural gas swaps, futures, forwards and physical
contracts
13
19
365
397
13
43
365
421
Other derivatives:
FX forwards
-
7
-
7
-
7
-
7
Total liabilities
56
83
365
504
Net assets (liabilities)
$
(8)
$
75
$
(331)
$
(264)
The change in the FV of the Level 3 financial assets and liabilities
for the year ended December 31, 2024
was as follows:
HFT Derivatives
millions of dollars
Power
Natural gas
Total
Assets
Balance, beginning of period
$
-
$
34
$
34
Total
realized and unrealized gains (losses) included in non-regulated operating
revenues
5
(7)
(2)
Balance, December 31, 2024
$
5
$
27
$
32
Liabilities
Balance, beginning of period
$
-
$
365
$
365
Total
realized and unrealized gains (losses) included in non-regulated operating
revenues
4
72
76
Balance, December 31, 2024
$
4
$
437
$
441
Significant unobservable inputs used in the FV measurement
of Emera’s natural gas and power
derivatives include third-party sourced pricing for instruments based
on illiquid markets. Significant
increases (decreases) in any of these inputs in isolation would result
in a significantly lower (higher) FV
measurement. Other unobservable inputs used include internally
developed correlation factors and basis
differentials; own credit risk; and discount rates.
Internally developed correlations and basis differentials
are reviewed on a quarterly basis based on statistical analysis
of the spot markets in the various illiquid
term markets.
Discount rates may include a risk premium for those
long-term forward contracts with
illiquid future price points to incorporate the inherent uncertainty
of these points. Any risk premiums for
long-term contracts are evaluated by observing similar
industry practices and in discussion with industry
peers.
50
The Company uses a modelled pricing valuation technique for
determining the FV of Level 3 derivative
instruments. The following table outlines quantitative information
about the significant unobservable
inputs used in the FV measurements categorized within Level
3 of the FV hierarchy:
Significant
Weighted
millions of dollars
FV
Unobservable Input
Low
High
average
(1)
Assets
Liabilities
As at December 31, 2024
HFT derivatives – Power
5
4
Third-party pricing
$25.60
$139.65
$82.63
swaps and physical contracts
HFT derivatives – Natural
27
437
Third-party pricing
$2.20
$17.54
$8.57
gas swaps, futures, forwards
and physical contracts
Total
$
32
$
441
Net liability
$
409
As at December 31, 2023
HFT derivatives – Natural
34
365
Third-party pricing
$1.27
$16.25
$4.85
gas swaps, futures, forwards
and physical contracts
Total
$
34
$
365
Net liability
$
331
(1) Unobservable inputs were weighted by the
relative FV of the instruments.
Long-term debt is a financial liability not measured at
FV on the Consolidated Balance Sheets. The
balance consisted of the following:
As at
Carrying
millions of dollars
Amount
FV
Level 1
Level 2
Level 3
Total
December 31, 2024
$
18,407
$
17,941
$
-
$
17,688
$
253
$
17,941
December 31, 2023
$
18,365
$
16,621
$
-
$
16,363
$
258
$
16,621
The Company has designated $
1.2
billion USD denominated Hybrid Notes as a hedge of the
foreign
currency exposure of its ne
t investment
in USD denominated operations. The Company’s Hybrid Notes
are contingently convertible into preferred shares in the
event of bankruptcy or other related events. A
redemption option on or after June 15, 2026 is available
and at the control of the Company.
The Hybrid
Notes are classified as Level 2 financial assets. As at
December 31, 2024, the FV of the Hybrid Notes
was $
1.2
billion (2023 – $
1.2
billion). An after-tax foreign currency loss of $
139
million was recorded in
AOCI for the year ended December 31, 2024 (2023
– $
38
million after-tax gain).
18. RELATED PARTY
TRANSACTIONS
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:
●
Transactions between NSPI and NSPML
related to the Maritime Link assessment are reported
in the
Consolidated Statements of Income. NSPI’s expense
is reported in Regulated fuel for generation and
purchased power, totalling
a recovery of $
324
million for the year ended December 31, 2024 (2023
–
$
163
million expense). NSPML is accounted for as an
equity investment, and therefore corresponding
earnings related to this revenue are reflected in Income
from equity investments.
51
●
Natural gas transportation capacity purchases from M&NP
are reported in the Consolidated
Statements of Income. Purchases from M&NP reported
net in Operating revenues, Non-regulated,
totalled $
11
million for the year ended December 31, 2024 (2023
– $
14
million).
There were no significant receivables or payables between
Emera and its associated companies reported
on Emera’s Consolidated Balance Sheets as at December
31, 2024 and at December 31, 2023.
19. RECEIVABLES AND OTHER CURRENT ASSETS
As at
December 31
December 31
millions of dollars
2024
2023
Customer accounts receivable – billed
$
834
$
805
Customer accounts receivable – unbilled
342
363
Capitalized transportation capacity
(1)
216
358
Cash collateral provided to others
198
101
Prepaid expenses
105
105
Income tax receivable
22
10
Allowance for credit losses
(12)
(15)
Other
106
90
Total
receivables and other current assets
$
1,811
$
1,817
(1) Capitalized transportation capacity represents the
value of transportation/storage received by EES
on asset management
agreements at the inception of the contracts. The
asset is amortized over the term of each contract.
20. LEASES
Lessee
The Company has operating leases for buildings, land, telecommunication services, and rail cars.
Emera’s leases have remaining lease terms of 1 year to 61 years, some of which include options to
extend the leases for up to 65 years. These options are included as part of the lease term when it is
considered reasonably certain they will be exercised.
As at
December 31
December 31
millions of dollars
Classification
2024
2023
Right-of-use asset
Other long-term assets
$
52
$
54
Lease liabilities
Current
Other current liabilities
3
3
Long-term
Other long-term liabilities
54
55
Total
lease liabilities
$
57
$
58
The Company recorded lease expense of $
123
million for the year ended December 31, 2024 (2023
–
$
127
million), of which $
112
million (2023 – $
119
million) related to variable costs for power generation
facility finance leases, recorded in “Regulated fuel for
generation and purchased power” in the
Consolidated Statements of Income.
Future minimum lease payments under non-cancellable operating
leases for each of the next five years
and in aggregate thereafter are as follows:
millions of dollars
2025
2026
2027
2028
2029
Thereafter
Total
Minimum lease payments
$
5
$
3
$
3
$
3
$
3
$
115
$
132
Less imputed interest
(75)
Total
$
57
52
Additional information related to Emera's leases is as follows:
Year ended December 31
For the
2024
2023
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows for operating leases (millions of dollars)
$
10
$
8
Right-of-use assets obtained in exchange for lease obligations:
Operating leases (millions of dollars)
$
-
$
1
Weighted average remaining lease term (years)
44
44
Weighted average discount rate-
operating leases
3.96%
3.93%
Lessor
The Company’s net investment in direct finance
and sales-type leases primarily relates to Brunswick
Pipeline, Seacoast, compressed natural gas (“CNG”)
stations, a renewable natural gas (“RNG”) facility
and heat pumps.
The Company manages its risk associated with the residual
value of the Brunswick Pipeline lease
through proper routine maintenance of the asset.
Customers have the option to purchase CNG station assets
by paying a make-whole payment at the date
of the purchase based on a targeted internal rate of return
or may take possession of the CNG station
asset at the end of the lease term for no cost. Customers
have the option to purchase heat pumps at the
end of the lease term for a nominal fee.
Commencing in October 2023, the Company leased a RNG
facility to a biogas producer that is classified
as a sales-type lease. The term of the facility lease is
15 years
, with a nominal value purchase at the end
of the term and a net investment of approximately $
35
million USD.
Direct finance and sales-type lease unearned income is recognized
in income over the life of the lease
using a constant rate of interest equal to the internal
rate of return on the lease and is recorded as
“Operating revenues – regulated gas” and “Other income,
net” on the Consolidated Statements of
Income.
The total net investment in direct finance and sales-type
leases consist of the following:
As at
December 31
December 31
millions of dollars
2024
2023
Total
minimum lease payment to be received
$
1,310
$
1,360
Less: amounts representing estimated executory costs
(182)
(190)
Minimum lease payments receivable
$
1,128
$
1,170
Estimated residual value of leased property (unguaranteed)
183
183
Less: Credit loss reserve
(2)
(2)
Less: unearned finance lease income
(655)
(693)
Net investment in direct finance and sales-type leases
$
654
$
658
Principal due within one year (included in "Receivables and other
current assets")
44
37
Net Investment in direct finance and sales type leases – long-term
$
610
$
621
As at December 31, 2024, future minimum lease payments
to be received for each of the next five years
and in aggregate thereafter were as follows:
millions of dollars
2025
2026
2027
2028
2029
Thereafter
Total
Minimum lease payments to be
received
$
99
$
100
$
99
$
97
$
96
$
819
$
1,310
Less: executory costs
(182)
Total
$
1,128
53
21. PROPERTY,
PLANT AND EQUIPMENT
PP&E consisted of the following regulated and non-regulated
assets:
As at
December 31
December 31
millions of dollars
Estimated useful life
2024 (1)
2023
Generation
5
to
131
$
14,297
$
13,500
Transmission
10
to
80
3,106
2,835
Distribution
10
to
65
8,512
7,417
Gas transmission and distribution
15
to
75
4,658
5,536
General plant and other
(2)
2
to
60
3,078
2,985
Total
cost
33,651
32,273
Less: Accumulated depreciation
(2)
(10,442)
(9,994)
23,209
22,279
Construction work in progress
(2)
2,959
2,097
Net book value
$
26,168
$
24,376
(1) On August 5, 2024, Emera announced an
agreement to sell NMGC. As at December
31, 2024, NMGC's assets and liabilities
were classified as held for sale and excluded from
the table above.
For further details on the pending transaction, refer
to note 4.
(2) SeaCoast owns a
50
% undivided ownership interest in a jointly
owned
26
-mile pipeline lateral located in Florida, which went
into
service in 2020. At December 31, 2024, SeaCoast’s
share of plant in service was $
27
million USD (2023 – $
27
million USD), and
accumulated depreciation of $
3
million USD (2023 – $
2
million USD). SeaCoast’s undivided ownership interest
is financed with its
funds and all operations are accounted for as
if such participating interest were a wholly
owned facility. SeaCoast’s share of direct
expenses of the jointly owned pipeline is included
in "OM&G" in the Consolidated Statements
of Income.
54
22. EMPLOYEE BENEFIT PLANS
Emera maintains a number of contributory defined-benefit (“DB”) and defined-contribution (“DC”) pension
plans, which cover substantially all of its employees. The Company also provides non-pension benefits
for its retirees.
Emera’s net periodic benefit cost included the following:
Benefit Obligation and Plan Assets:
Changes in the benefit obligation and plan assets, and
the funded status for plans were as follows:
For the
Year ended December 31
millions of dollars
2024
2023
DB pension
plans
Non-pension
benefit plans
DB pension
plans
Non-pension
benefit plans
Change in Projected Benefit Obligation ("PBO") and Accumulated Post-retirement Benefit Obligation
("APBO"):
Balance, January 1
$
2,273
$
227
$
2,158
$
243
Service cost
35
3
30
3
Plan participant contributions
6
5
6
6
Interest cost
110
12
111
13
Plan amendments
-
-
-
(14)
Benefits paid
(153)
(21)
(147)
(29)
Actuarial losses (gains)
(1)
13
(3)
146
10
Settlements and curtailments
-
-
(8)
-
FX translation adjustment
83
18
(23)
(5)
Balance, December 31
$
2,367
$
241
$
2,273
$
227
Change in plan assets:
Balance, January 1
$
2,298
$
48
$
2,163
$
46
Employer contributions
36
13
42
23
Plan participant contributions
6
5
6
6
Benefits paid
(153)
(21)
(147)
(29)
Actual return on assets, net of expenses
226
4
262
3
Settlements and curtailments
-
-
(8)
-
FX translation adjustment
80
5
(20)
(1)
Balance, December 31
$
2,493
$
54
$
2,298
$
48
Funded status, end of year
$
126
$
(187)
$
25
$
(179)
(1) The actuarial losses recognized in the period
are primarily due to changes in the discount
rate, higher than expected indexation,
and compensation-related assumption changes.
Plans with PBO/APBO
in Excess of Plan Assets:
The aggregate financial position for pension plans where
the PBO or APBO (for post-retirement benefit
plans) exceeded the plan assets for the years ended December
31 were as follows:
millions of dollars
2024
2023
DB pension
plans
Non-pension
benefit plans
DB pension
plans
Non-pension
benefit plans
PBO/APBO
$
95
$
219
$
120
$
205
FV of plan assets
11
-
37
-
Funded status
$
(84)
$
(219)
$
(83)
$
(205)
55
Plans with Accumulated Benefit Obligation (“ABO”)
in Excess of Plan Assets:
The ABO for the DB pension plans was $
2,255
million as at December 31, 2024 (2023 – $
2,172
million).
The aggregate financial position for those plans with an ABO
in excess of the plan assets for the years
ended December 31 were as follows:
millions of dollars
2024
2023
DB pension
plans
DB pension
plans
ABO
$
90
$
114
FV of plan assets
11
37
Funded status
$
(79)
$
(77)
Balance Sheet:
The amounts recognized in the Consolidated Balance Sheets
consisted of the following:
As at
December 31
December 31
millions of dollars
2024
2023
DB pension
plans
Non-pension
benefit plans
DB pension
plans
Non-pension
benefit plans
Other current liabilities
$
(5)
$
(21)
$
(5)
$
(18)
Liabilities associated with assets held for
sale
(1)
-
(1)
-
-
Long-term liabilities
(78)
(196)
(78)
(187)
Other long-term assets
208
-
108
26
Assets held for sale
(1)
1
31
-
-
AOCI, net of tax and regulatory assets
354
22
385
20
Deferred income tax expense in AOCI
(8)
(1)
(8)
(1)
Net amount recognized
$
472
$
(166)
$
402
$
(160)
(1) On August 5, 2024, Emera announced an
agreement to sell NMGC. As at December
31, 2024, NMGC's assets and liabilities
were classified as held for sale. For further details
on the pending transaction, refer to note 4.
Amounts Recognized in AOCI and Regulatory Assets:
Unamortized gains and losses and past service costs
arising on post-retirement benefits are recorded in
AOCI or regulatory assets. The following table summarizes
the change in AOCI and regulatory assets:
Regulatory assets
Actuarial
(gains) losses
Past service
gains
millions of dollars
DB Pension Plans:
Balance, January 1, 2024
$
324
$
53
$
-
Amortized in current period
(9)
(3)
-
Current year additions
19
(67)
-
Change in FX rate
29
-
-
Balance, December 31, 2024
$
363
$
(17)
$
-
Non-pension benefits plans:
Balance, January 1, 2024
$
29
$
(8)
$
(2)
Amortized in current period
2
1
2
Current year reductions
(5)
(1)
-
Change in FX rate
3
-
-
Balance, December 31, 2024
$
29
$
(8)
$
-
56
As at
December 31
December 31
millions of dollars
2024
2023
DB pension
plans
Non-pension
benefit plans
DB pension
plans
Non-pension
benefit plans
Actuarial (gains) losses
$
(17)
(8)
$
53
(8)
Past service gains
-
-
-
(2)
Deferred income tax expense
8
1
8
1
AOCI, net of tax
(9)
(7)
61
(9)
Regulatory assets
363
29
324
29
AOCI, net of tax and regulatory assets
$
354
$
22
$
385
$
20
Benefit Cost Components:
Emera's net periodic benefit cost included the following:
As at
Year ended December 31
millions of dollars
2024
2023
DB pension
plans
Non-pension
benefit plans
DB pension
plans
Non-pension
benefit plans
Service cost
$
35
$
3
$
30
$
3
Interest cost
110
12
111
13
Expected return on plan assets
(160)
(2)
(161)
(2)
Current year amortization of:
Actuarial losses (gains)
3
(2)
1
(3)
Past service gains
-
(2)
-
-
Regulatory assets
9
(2)
6
(2)
Settlement, curtailments
-
1
2
-
Total
$
(3)
$
8
$
(11)
$
9
The expected return on plan assets is determined based on
the market-related value of plan assets of
$
2,571
million as at January 1, 2024 (2023 – $
2,577
million), adjusted for interest on certain cash flows
during the year.
The market-related value of assets is based on a smoothed asset value. Any investment
gains (or losses) in excess of (or less than) the expected return on plan assets are recognized on a
straight-line basis into the market-related value of assets over a multi-year period.
Pension Plan Asset Allocations:
Emera’s investment policy includes discussion
regarding the investment philosophy,
the level of risk
which the Company is prepared to accept with respect
to the investment of the Pension Funds, and the
basis for measuring the performance of the assets. Central to
the policy is the target asset allocation by
major asset categories. The objective of the target asset allocation
is to diversify risk and to achieve asset
returns that meet or exceed the plan’s actuarial
assumptions. The diversification of assets reduces the
inherent risk in financial markets by requiring that assets
be spread out amongst various asset classes.
Further, within each asset class,
a diversification is undertaken through the investment
in a broad range
of investment and non-investment grade securities. Emera’s
target asset allocation is as follows:
Asset Class
Target
Range at Market
Canadian Pension Plans:
Short-term securities
0%
to
10%
Fixed income
34%
to
49%
Equities:
Canadian
5%
to
15%
Non-Canadian
37%
to
61%
Non-Canadian Pension Plans:
Cash and cash equivalents
0%
to
10%
Fixed income
29%
to
49%
Equities
48%
to
68%
57
Pension plan assets are overseen by the respective
management pension committees in the sponsoring
companies. All pension investments are in accordance with policies
approved by the respective Board of
Directors of each sponsoring company.
The following tables set out the classification of the methodology
used by the Company to FV its
investments (for more information on the FV hierarchy
and measurement, refer to note 17):
millions of dollars
NAV
Level 1
Level 2
Total
Percentage
As at
December 31, 2024
Cash and cash equivalents
$
-
$
39
$
-
$
39
2
%
Net in-transits
-
(27)
-
(27)
(1)
%
Equity securities:
Canadian equity
-
109
-
109
4
%
United States equity
-
312
-
312
12
%
Other equity
-
140
-
140
5
%
Fixed income securities:
Government
-
-
132
132
5
%
Corporate
-
-
92
92
4
%
Other
-
-
22
22
1
%
Mutual funds
-
13
-
13
1
%
Open-ended investments
measured at NAV
(1)
1,142
-
-
1,142
46
%
Common collective trusts
measured at NAV
(2)
519
-
-
519
21
%
Total
$
1,661
$
586
$
246
$
2,493
100
%
As at
December 31, 2023
Cash and cash equivalents
$
-
$
40
$
-
$
40
2
%
Net in-transits
-
(9)
-
(9)
-
%
Equity securities:
Canadian equity
-
96
-
96
4
%
United States equity
-
141
-
141
6
%
Other equity
-
112
-
112
5
%
Fixed income securities:
Government
-
-
172
172
8
%
Corporate
-
-
90
90
4
%
Other
-
4
5
9
-
%
Mutual funds
-
50
-
50
2
%
Other
-
6
(1)
5
-
%
Open-ended investments
measured at NAV
(1)
1,006
-
-
1,006
44
%
Common collective trusts
measured at NAV
(2)
586
-
-
586
25
%
Total
$
1,592
$
440
$
266
$
2,298
100
%
(1) Net asset value ("NAV") investments are open-ended registered and non-registered
mutual funds, collective investment trusts,
or pooled funds. NAV’s are calculated at least monthly and the funds honour
subscription and redemption activity regularly.
(2) The common collective trusts are private funds
valued at NAV.
The NAVs are calculated based on bid prices of the underlying
securities. Since the prices are not published to external
sources, NAV is used as a practical expedient. Certain funds invest
primarily in equity securities of domestic and
foreign issuers while others invest in long duration
U.S. investment grade fixed
income assets and seeks to increase return through
active management of interest rate and
credit risks. The funds honour
subscription and redemption activity regularly.
Non-Pension Benefit Plans:
There are no assets set aside to pay for most of the Company’s
non-pension benefit plans. As is common
practice, post-retirement health benefits are paid from
general accounts as required. The exception to this
is the NMGC Retiree Medical Plan, which is fully funded.
58
Investments in Emera:
As at December 31, 2024 and 2023, assets related to the
pension funds and post-retirement benefit plans
did not hold any material investments in Emera or its subsidiaries
securities. However,
as a significant
portion of assets for the benefit plan are held in pooled
assets, there may be indirect investments in these
securities.
Cash Flows:
The following table shows expected cash flows for DB pension
and other post-retirement benefit plans:
millions of dollars
DB pension
plans
Non-pension
benefit plans
Expected employer contributions
2025
$
41
$
21
Expected benefit payments
2025
175
23
2026
179
23
2027
182
23
2028
184
23
2029
186
22
2030 – 2034
950
103
Assumptions:
The following table shows the assumptions that have been
used in accounting for DB pension and other
post-retirement benefit plans:
2024
2023
(weighted average assumptions)
DB pension
plans
Non-pension
benefit plans
DB pension
plans
Non-pension
benefit plans
Benefit obligation – December 31:
Discount rate - past service
5.07
%
4.91
%
4.89
%
4.89
%
Discount rate - future service
5.12
%
5.00
%
4.88
%
4.89
%
Rate of compensation increase
3.73
%
3.72
%
3.87
%
3.85
%
Health care trend
- initial (next year)
-
6.53
%
-
6.04
%
- ultimate
-
3.77
%
-
3.76
%
- year ultimate reached
2044
2043
Benefit cost for year ended December 31:
Discount rate - past service
4.89
%
4.89
%
5.33
%
5.31
%
Discount rate - future service
4.88
%
4.89
%
5.34
%
5.32
%
Expected long-term return on plan assets
6.43
%
3.69
%
6.56
%
2.16
%
Rate of compensation increase
3.87
%
3.85
%
3.62
%
3.61
%
Health care trend
- initial (current year)
-
6.04
%
-
5.40
%
- ultimate
-
3.76
%
-
3.77
%
- year ultimate reached
2043
2043
Actual assumptions used differ by plan.
The expected long-term rate of return on plan assets is based on historical and projected real rates of
return for the plan’s current asset allocation, and assumed inflation. A real rate of return is determined for
each asset class. Based on the asset allocation, an overall expected real rate of return for all assets is
determined. The asset return assumption is equal to the overall real rate of return assumption added to
the inflation assumption, adjusted for assumed expenses to be paid from the plan.
The discount rate is based on high-quality long-term corporate
bonds, with maturities matching the
estimated cash flows from the pension plan.
DC Pension Plan:
Emera also provides a DC pension plan for certain employees.
The Company’s contribution for the year
ended December 31, 2024 was $
51
million (2023 – $
45
million).
59
23. GOODWILL
The change in goodwill for the year ended December 31
was due to the following:
millions of dollars
2024
2023
Balance, January 1
$
5,871
$
6,012
Change in FX rate
504
(141)
Impairment charges
(214)
-
Classified as assets held for sale
(1)
(303)
-
Balance, December 31
$
5,858
$
5,871
(1) As at December 31, 2024, NMGC's assets
and liabilities were classified as held for
sale. For further details on the pending
transaction, refer to note 4.
Goodwill is subject to an annual assessment for impairment
at the reporting unit level. The goodwill on
Emera’s Consolidated Balance Sheets at December
31, 2024, related to TECO Energy,
Inc. (reporting
units with goodwill are TEC, PGS, and NMGC).
On August 5, 2024, Emera announced an agreement to sell
NMGC. As the expected transaction
proceeds on the pending sale will be less than the NMGC carrying
amount, the Company performed a
quantitative goodwill impairment assessment for the NMGC
reporting unit. It was determined that the
NMGC carrying amount exceeded the FV of the expected transaction
proceeds, and as a result, a non-
cash goodwill impairment charge of $
210
million, pre-tax, was recorded in Q3 2024, reducing the
NMGC
reporting unit goodwill balance to $
303
million as at December 31, 2024. This non-cash charge
is
included in “Impairment charges” on the Consolidated
Statements of Income.
In 2024, a qualitative assessment was performed for TEC
given the significant excess of FV over carrying
amounts calculated during the last quantitative test in
Q4 2023. Management concluded it was more likely
than not that the FV of this reporting unit exceeded
its carrying amount, including goodwill. As such, no
quantitative testing was required. Given the length of time
passed since the last quantitative impairment
test for the PGS reporting unit, Emera elected to bypass
a qualitative assessment and performed a
quantitative impairment assessment in Q4 2024 using a combination
of the income and market approach.
This assessment estimated that the FV of the PGS reporting
unit exceeded its carrying amount, including
goodwill, and as a result, no impairment charges were
recognized.
60
24. SHORT-TERM DEBT
Emera’s short-term borrowings consist of commercial
paper issuances, advances on revolving and non-
revolving credit facilities and short-term notes. Short-term
debt and the related weighted-average interest
rates as at December 31 consisted of the following:
millions of dollars
2024
Weighted
average
interest rate
2023
Weighted
average
interest rate
Florida Electric Utility
Advances on revolving credit facilities
$
915
4.77
%
$
277
5.68
%
Gas Utilities and Infrastructure
PGS – Advances on revolving credit facilities
199
5.36
%
73
6.36
%
NMGC – Advances on revolving credit facilities
46
5.52
%
25
6.46
%
Other Electric Utilities
GBPC – Advances on revolving credit facilities
19
7.20
%
8
5.54
%
Other
TECO Finance – Advances on revolving credit and term facilities
265
5.53
%
245
6.54
%
Emera – Bank indebtedness
2
-
%
9
-
%
Emera – Non-revolving term facilities
-
-
%
796
6.07
%
$
1,446
$
1,433
Adjustment
Classification as liabilities held for sale
(1)
(46)
-
Short-term debt
$
1,400
$
1,433
(1) On August 5, 2024, Emera announced an agreement
to sell NMGC. As at December 31, 2024,
NMGC's liabilities were classified
as held for sale. For further details on the pending
transaction, refer to note 4.
The Company’s total short-term unsecured revolving
and non-revolving credit facilities, outstanding
borrowings and available capacity as at December 31 were
as follows:
millions of dollars
Maturity
2024
2023
TEC – committed revolving credit facility
2028
$
1,151
$
401
TECO Finance – committed revolving credit facility
2028
576
529
PGS – revolving credit facility
2028
360
331
NMGC – revolving credit facility
2026
180
165
Emera – non-revolving term facility
2024
-
400
Emera – non-revolving term facility
2024
-
400
TEC – revolving facility
2024
-
265
TEC – revolving facility
2024
-
265
Other – committed revolving credit facilities
Various
35
17
Total
$
2,302
$
2,773
Less:
Advances under revolving credit and term facilities
1,400
1,433
Letters of credit issued within the credit facilities
4
3
Total
advances under available facilities
1,404
1,436
Available capacity under existing agreements
$
898
$
1,337
The weighted average interest rate on outstanding short-term
debt at December 31, 2024 was
5.05
per
cent (2023 –
5.95
per cent).
61
Recent Significant Financing Activity by Segment
Florida Electric Utilities
On April 1, 2024, TEC amended its $
800
million USD unsecured committed revolving credit facility
to
extend the maturity date from
December 17, 2026
to
December 1, 2028
. There were no other changes in
commercial terms from the prior agreement.
Other
On June 24, 2024, Emera repaid its $
400
million unsecured non-revolving term facility set to mature in
August 2024.
On June 17, 2024, Emera repaid $
200
million on the December 2024 unsecured non-revolving
term
facility, decreasing
the facility from $
400
million to $
200
million. In December 2024, Emera repaid the
$
200
million upon maturity.
On April 1, 2024, TECO Finance amended its $
400
million USD unsecured committed revolving credit
facility to extend the maturity date from
December 17, 2026
to
December 1, 2028
. There were no other
changes in commercial terms from the prior agreement.
25. OTHER CURRENT LIABILITIES
As at
December 31
December 31
millions of dollars
2024
2023
Accrued charges
$
189
$
172
Accrued interest on long-term debt
106
107
Pension and post-retirement liabilities (note 22)
26
23
Sales and other taxes payable
11
11
Income tax payable
4
2
Other
153
112
$
489
$
427
62
26. LONG-TERM DEBT
Bonds, notes and debentures are at fixed interest rates
and are unsecured unless noted below.
Included
are certain bankers’ acceptances and commercial paper
where the Company has the intention and the
unencumbered ability to refinance the obligations for a period
greater than one year.
Long-term debt as at December 31 consisted of the following:
Weighted average interest
rate
(1)
millions of dollars
2024
2023
Maturity
2024
2023
Florida Electric Utility
Senior unsecured notes
4.36%
4.61%
2029 - 2051
$
5,720
$
5,654
Canadian Electric Utilities
NSPI – Commercial paper
(2)
Variable
Variable
2029
$
177
$
721
NSPI – Senior unsecured notes
5.12%
5.13%
2025 - 2097
3,184
3,165
$
3,361
$
3,886
Gas Utilities and Infrastructure
PGS – Senior unsecured notes
5.63%
5.63%
2028 - 2053
$
1,331
$
1,223
NMGC – Senior unsecured notes
3.78%
3.78%
2026 - 2051
698
642
NMGC – Unsecured loan notes
N/A
Variable
2024
-
30
NMGI – Senior unsecured notes
N/A
3.64%
2024
-
198
EBP – Secured loan notes
Variable
Variable
2028
250
246
$
2,279
$
2,339
Other Electric Utilities
Unsecured loan notes
4.06%
4.78%
2025 - 2028
$
143
$
121
Unsecured loan notes
Variable
Variable
2025 - 2027
104
104
Secured senior notes and debentures
(3)
2.38%
3.06%
2026 - 2040
169
197
$
416
$
422
Other
Unsecured loan notes
Variable
Variable
2026 - 2029
$
992
$
465
Senior unsecured notes
3.99%
3.65%
2026 - 2046
3,525
3,637
Senior unsecured notes
4.84%
4.84%
2030
500
500
Fixed to floating subordinated notes
(4)
6.75%
6.75%
2076
1,727
1,587
Junior subordinated notes
7.63%
0.00%
2054
720
-
$
7,464
$
6,189
Adjustments
Debt issuance costs
(137)
(125)
Classification as liabilities held for sale
(5)
(696)
-
Amount due within one year
(6)
(234)
(676)
$
(1,067)
$
(801)
Long-Term Debt
$
18,173
$
17,689
(1) Weighted average interest rate of fixed rate long-term debt.
(2) Discount notes are backed by a revolving
credit facility which matures in 2029.
(3) Notes are issued and payable in either USD
or BBD.
(4) In 2024, the Company recognized $
110
million in interest expense (2023 – $
109
million) related to its fixed to floating
subordinated notes.
(5) On August 5, 2024, Emera announced an
agreement to sell NMGC. As at December
31, 2024, NMGC's liabilities were
classified as held for sale.
For further details on the pending transaction,
refer to note 4.
(6) Excludes NMGC amounts which are classified
as current liabilities associated with assets held
for sale.
63
The Company’s total long-term revolving credit facilities,
outstanding borrowings and available capacity as
at December 31 were as follows:
millions of dollars
Maturity
2024
2023
Emera – committed revolving credit facility
(1)
June 2029
$
1,300
$
900
NSPI – revolving credit facility
(1)
June 2029
800
800
Emera – Unsecured non-revolving credit facility
February 2026
200
400
TEC – Unsecured committed revolving credit facility
December 2026
-
657
NSPI – non-revolving credit facility
July 2024
-
400
NMGC – Unsecured non-revolving credit facility
March 2024
-
30
ECI – revolving credit facilities
October 2024
-
10
Total
$
2,300
$
3,197
Less:
Borrowings under credit facilities
1,169
1,884
Letters of credit issued inside credit facilities
12
6
Use of available facilities
$
1,181
$
1,890
Available capacity under existing agreements
$
1,119
$
1,307
(1) Advances on the revolving credit facility can be
made by way of overdraft on accounts up to
$
50
million.
Debt Covenants
Emera and its subsidiaries have debt covenants associated
with their credit facilities. Covenants are
tested regularly and the Company is in compliance with
covenant requirements. Emera’s significant
covenants are listed below:
As at
Financial Covenant
Requirement
December 31, 2024
Emera
Syndicated credit facilities
Debt to capital ratio
Less than or equal to
0.70
to 1
0.55
: 1
Recent Significant Financing Activity by Segment
Florida Electric Utility
On July 12, 2024, TEC repaid a $
300
million USD note upon maturity.
This note was repaid with
proceeds from commercial paper.
On January 30, 2024, TEC issued $
500
million USD of senior unsecured bonds that bear interest
at
4.90
per cent with a maturity date of
March 1, 2029
. Proceeds from the issuance were primarily used for the
repayment of short-term borrowings outstanding under the
5
-year credit facility.
Canadian Electric Utilities
On June 24, 2024, NSPI amended its unsecured non-revolving
credit facility to extend the maturity date
from
July 15, 2024
to
June 24, 2025
and reduce the facility from $
400
million to $
300
million. On
December 16, 2024, NSPI repaid the $
300
million unsecured non-revolving credit facility.
On June 24, 2024, NSPI amended its unsecured committed
revolving credit facility to extend the maturity
date from
December 16, 2027
to
June 24, 2029
. There were no other material changes in commercial
terms from the prior agreement.
On June 13, 2024, NSPI entered a non-revolving credit
facility to finance the Battery Energy Storage
Project. NSPI can request funds under the facility quarterly
for amounts related to incurred project costs
up to the total commitment of the lessor of $
120
million and
45.06
per cent of the total eligible project
costs over the term of the agreement. The facility will be
available until
6
months after completion of the
project, not to exceed
May 21, 2027
, and matures
20
years following the end of the period. As at
December 31, 2024, NSPI had utilized $
19
million from the facility,
which bears interest at
2.51
per cent.
64
Gas Utilities and Infrastructure
On December 10, 2024, Brunswick Pipeline amended
its non-revolving loan agreement. The maturity
date was extended to December 2028 and now includes
annual principal repayments.
On July 30, 2024, New Mexico Gas Intermediate, Inc. repaid
its $
150
million USD fixed rate notes upon
maturity.
Other Electric Utilities
On May 2, 2024, BLPC amended its $
92
million Barbadian dollar ($
46
million USD) loan facility to extend
the maturity date from
February 19, 2025
to
July 19, 2028
. There were no other material changes in
commercial terms from the prior agreement.
Other
On June 24, 2024, Emera amended its unsecured committed
revolving credit facility increasing the facility
from $
900
million to $
1,300
million. Emera also extended the maturity date from
June 24, 2027
to
June
24, 2029
. There were no other material changes in commercial terms
from the prior agreement.
On June 15, 2024, Emera Finance repaid its $
300
million USD senior notes upon maturity.
On June 18, 2024, EUSHI Finance, Inc., completed an issuance
of $
500
million USD fixed-to-fixed reset
rate junior subordinated notes. The notes initially bear
interest at a rate of
7.625
per cent, and will reset
on December 15, 2029, and every
five years
thereafter, to a rate per annum
equal to the five-year U.S.
treasury rate plus
3.136
per cent. The notes mature on
December 15, 2054
. EUSHI Finance, Inc., 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.
On February 16, 2024, Emera amended its $
400
million unsecured non-revolving facility to extend the
maturity date from
February 19, 2024
to
February 19, 2025
. There were no other changes in commercial
terms from the prior agreement. On July 19, 2024, Emera reduced
the amount of the facility from $
400
million to $
200
million. On February 20, 2025, Emera extended the agreement
for an additional year to
February 2026 with no other changes in terms. This facility
was classified as long-term debt at December
31, 2024.
Long-Term Debt Maturities
As at December 31, 2024, long-term debt maturities, including
capital lease obligations, for each of the
next five years and in aggregate thereafter are as follows:
millions of dollars
2025
2026
2027
2028
2029
Thereafter
Total
Florida Electric Utility
$
-
$
-
$
-
$
-
$
720
$
5,000
$
5,720
Canadian Electric Utilities
125
40
-
-
217
2,979
3,361
Gas Utilities and
Infrastructure
31
132
31
535
31
1,519
2,279
Other Electric Utilities
78
101
89
116
4
28
416
Other
-
3,006
-
-
792
3,666
7,464
Total
$
234
$
3,279
$
120
$
651
$
1,764
$
13,192
$
19,240
65
27. ASSET RETIREMENT OBLIGATIONS
AROs mostly relate to reclamation of land at the thermal, hydro
and combustion turbine sites; and the
disposal of polychlorinated biphenyls in transmission and distribution
equipment and a pipeline site.
Certain hydro, transmission and distribution assets may have additional
AROs that cannot be measured
as these assets are expected to be used for an indefinite
period and, as a result, a reasonable estimate of
the FV of any related ARO cannot be made.
The change in ARO for the years ended December 31
is as follows:
millions of dollars
2024
2023
Balance, January 1
$
192
$
174
Additions
11
-
Accretion included in depreciation expense
10
9
Change in FX rate
5
(1)
Revisions in estimated cash flows
2
-
Accretion deferred to regulatory asset (included in PP&E)
-
18
Classified as assets held for sale
(1)
(1)
-
Liabilities settled
(2)
(8)
Balance, December 31
$
217
$
192
(1) As at December 31, 2024, NMGC's assets
and liabilities were classified as held for
sale. For further details on the pending
transaction, refer to note 4.
28. COMMITMENTS AND CONTINGENCIES
A.
Commitments
As at December 31, 2024, contractual commitments (excluding
pensions and other post-retirement
obligations, long-term debt and asset retirement obligations) for
each of the next five years and in
aggregate thereafter consisted of the following:
millions of dollars
2025
2026
2027
2028
2029
Thereafter
Total
Purchased power
(1)
$
307
$
277
$
368
$
368
$
369
$
4,487
$
6,176
Transportation
(2)(3)
742
545
544
454
412
3,228
5,925
Capital projects
604
287
24
-
-
-
915
Fuel, gas supply and storage
(4)
591
94
21
5
-
-
711
Other
160
95
80
59
59
264
717
$
2,404
$
1,298
$
1,037
$
886
$
840
$
7,979
$
14,444
As detailed below, contractual obligations at December 31, 2024 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 note 4.
(1) Annual requirement to purchase electricity production
from IPPs or other utilities over varying contract lengths.
(2) Includes $
86
million related to NMGC (2025: $
30
million, 2026: $
24
million, 2027: $
16
million, 2028: $
12
million, 2029: $
4
million).
(3) Purchasing commitments for transportation of
fuel and transportation capacity on various pipelines.
Includes a commitment of
$
135
million related to a gas transportation contract between
PGS and SeaCoast through 2040.
(4) Includes $
177
million related to NMGC (2025: $
109
million, 2026: $
52
million, 2027: $
13
million, 2028: $
3
million)
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. In November
2024, the UARB approved the collection of up to
$
197
million from NSPI for the recovery of Maritime Link
costs in 2025. The timing and amounts payable
to NSPML for the remainder of the
38
-year commitment period are subject to UARB
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.
66
B.
Legal Proceedings
Superfund and Former Manufactured Gas Plant Sites
Previously, TEC had
been a potentially responsible party (“PRP”) for certain superfund
sites through its
Tampa
Electric and former PGS divisions, as well as for certain
former manufactured gas plant sites
through its PGS division. As a result of the separation of the PGS
division into a separate legal entity,
Peoples Gas System, Inc. is also now a PRP for those sites (in
addition to third party PRPs for certain
sites).
While the aggregate joint and several liability associated with
these sites has not changed as a
result of the PGS legal separation, the sites continue to present
the potential for significant response
costs. As at December 31, 2024, the aggregate financial
liability of the Florida utilities is estimated to be
$
17
million ($
12
million USD), primarily at PGS. This estimate assumes
that other involved PRPs are
credit-worthy entities. This amount has been accrued and
is primarily reflected in the long-term liability
section under “Other long-term liabilities” on the Consolidated
Balance Sheets. The environmental
remediation costs associated with these sites are expected
to be paid over many years.
The estimated amounts represent only the portion of the cleanup
costs attributable to the Florida utilities.
The estimates to perform the work are based on the Florida
utilities’ experience with similar work,
adjusted for site-specific conditions and agreements with
the respective governmental agencies. The
estimates are made in current dollars, are not discounted
and do not assume any insurance recoveries.
In instances where other PRPs are involved, most of those
PRPs are believed to be currently credit-
worthy and are likely to continue to be credit-worthy for
the duration of the remediation work. However,
in
those instances that they are not, the Florida utilities could be
liable for more than their actual percentage
of the remediation costs. Other factors that could impact
these estimates include additional testing and
investigation which could expand the scope of the cleanup activities,
additional liability that might arise
from the cleanup activities themselves or changes in
laws or regulations that could require additional
remediation. Under current regulations, these costs are recoverable
through customer rates established
in base rate proceedings.
Other Legal Proceedings
Emera and its subsidiaries may,
from time to time, be involved in other legal proceedings,
claims and
litigation that arise in the ordinary course of business
which the Company believes would not reasonably
be expected to have a material adverse effect on the
financial condition of the Company.
C.
Principal Financial Risks and Uncertainties
Emera believes the following principal financial risks 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, and/or results of operations (herein considered a “Material
Adverse Effect”). Risks associated
with derivative instruments and FV measurements are
discussed in note 16 and note 17.
Sound risk management is an essential discipline for running
the business efficiently and pursuing the
Company’s strategy successfully.
Emera has an enterprise-wide risk management process,
overseen by
its Enterprise Risk Management Committee (“ERMC”)
and monitored by the Board of Directors, to ensure
risks are appropriately identified, assessed, monitored
and subject to appropriate controls. The Board of
Directors has a Risk and Sustainability Committee (‘RSC”)
to assist in carrying out its risk and
sustainability oversight responsibilities. The RSC’s
mandate includes oversight of the Company’s
Enterprise Risk Management framework, including the
identification, assessment, monitoring and
management of enterprise risks.
67
Regulatory and Political Risk
The Company’s rate-regulated subsidiaries 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 cost
-of-service 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 is unable to recover in a timely manner a material
amount of costs or a return on invested capital
through regulatory mechanisms or otherwise, is disallowed
the recovery of certain costs, is subject to
regulatory penalties, is not permitted to make certain capital
investments, or is 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.
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.
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 subsidiaries
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 AOCI.
68
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 in PP&E 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 impact on Emera’s
ability to fund its growth plan.
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
climate change-related impacts, 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, and therefore could have
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 regulated subsidiaries, 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.
69
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.
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.
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.
D.
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, 2024
:
TECO Holdings, Inc. (“TECO Holdings”) has 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.
70
TECO Holdings has 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.
NSPI has guarantees on behalf of its subsidiary,
NS Power Energy Marketing Incorporated, in the amount
of $
104
million USD (2023 – $
104
million USD) with terms of varying lengths.
The Company has standby letters of credit and surety
bonds in the amount of $
105
million USD
(December 31, 2023 – $
103
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 2025. The amount committed
as at December 31, 2024 was $
58
million (December 31, 2023 – $
56
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.
Collaborative Arrangements
For the years ended December 31, 2024 and 2023, the
Company has identified the following material
collaborative arrangements:
Through NSPI, the Company is a participant in three
wind energy projects in Nova Scotia. The
percentage ownership of the wind project assets is based on
the relative value of each party’s project
assets by the total project assets. NSPI has power
purchase arrangements to purchase the entire net
output of the projects and, therefore, NSPI’s portion
of the revenues are recorded net within regulated fuel
for generation and purchased power.
NSPI’s portion of operating expenses is recorded
in “OM&G” on the
Consolidated Statements of Income. In 2024, NSPI recognized
$
12
million net expense (2023 – $
8
million) in “Regulated fuel for generation and purchased
power” and $
3
million (2023 – $
3
million) in
“OM&G” on the Consolidated Statements of Income.
71
29. CUMULATIVE PREFERRED STOCK
Authorized:
Unlimited number of First Preferred shares, issuable in
series.
Unlimited number of Second Preferred shares, issuable in
series.
December 31, 2024
December 31, 2023
Annual Dividend
Redemption
Issued and
Net
Issued and
Net
Per Share
Price per share
Outstanding
Proceeds
Outstanding
Proceeds
Series A
$
0.5456
$
25.00
4,866,814
$
119
4,866,814
$
119
Series B
Floating
$
25.00
1,133,186
$
28
1,133,186
$
28
Series C
$
1.6085
$
25.00
10,000,000
$
245
10,000,000
$
245
Series E
$
1.1250
$
25.00
5,000,000
$
122
5,000,000
$
122
Series F
$
1.0505
$
25.00
8,000,000
$
195
8,000,000
$
195
Series H
$
1.5810
$
25.00
12,000,000
$
295
12,000,000
$
295
Series J
$
1.0625
$
25.00
8,000,000
$
196
8,000,000
$
196
Series L
$
1.1500
$
26.00
9,000,000
$
222
9,000,000
$
222
Total
58,000,000
$
1,422
58,000,000
$
1,422
Characteristics of the First Preferred Shares:
First Preferred Shares
(1)(2)
Annual
Dividend
Rate
(%)
Current
Annual
Dividend
($)
Minimum
Reset
Dividend
Yield (%)
Earliest Redemption
and/or Conversion
Option Date
Redemption
Value
($)
Right to
Convert on
a one for
one basis
Fixed rate reset
(3)(4)
Series A
2.182
0.5456
1.84
August 15, 2025
25.00
Series B
Series C
6.434
1.6085
2.65
August 15, 2028
25.00
Series D
Series F
(5)(6)
4.202
1.0505
2.63
February 15, 2025
25.00
Series G
Minimum rate reset
(3)(4)
Series B
2.393
Floating
1.84
August 15, 2025
25.00
Series A
Series H
6.324
1.5810
4.90
August 15, 2028
25.00
Series I
Series J
4.250
1.0625
4.25
May 15, 2026
25.00
Series K
Perpetual fixed rate
Series E
(7)
4.500
1.1250
25.00
Series L
(8)
4.600
1.1500
November 15, 2026
26.00
(1) Holders are entitled to receive fixed or
floating cumulative cash dividends when declared
by the Board of Directors of the Corporation.
(2) On or after the specified redemption dates,
the Corporation has the option to redeem
for cash the outstanding First Preferred Shares,
in
whole or in part, at the specified per share redemption
value plus all accrued and unpaid dividends up
to but excluding the dates fixed for
redemption.
(3) On the redemption and/or conversion option
date the reset annual dividend per share
will be determined by multiplying $
25.00
per share
by the annual fixed or floating dividend rate,
which for Series A, C, F and H is the sum
of the five-year Government of Canada
Bond Yield on the applicable reset date, plus the applicable
reset dividend yield (Series H annual
reset rate must be a minimum of
4.90
per
cent) and for Series B equals the Government
of Treasury Bill Rate on the applicable reset date,
plus
1.84
per cent.
(4) On each conversion option date, the holders
have the option, subject to certain conditions,
to convert any or all of their Shares into an
equal number of Cumulative Redeemable
First Preferred Shares of a specified
series. The Company has the right to redeem
the outstanding Preferred Shares, Series
D, Series G and Series I shares without
the consent of the holder every five years
thereafter for
cash, in whole or in part at a price of
$
25.00
per share plus all accrued and unpaid dividends
up to but excluding the date fixed for redemption
and $
25.50
per share plus all accrued and unpaid dividends
up to but excluding the date fixed for redemption
in the case
of redemptions on any other date after August
15, 2028, February 15, 2025 and August
15, 2028, respectively. The reset dividend yield for
Series I equals the Government of Treasury Bill Rate on
the applicable reset date, plus
2.54
per cent.
(5) On January 8, 2025, Emera announced
that it would not redeem the outstanding Preferred
Shares, Series F on February 15, 2025.
During
the conversion period between January 15,
2025 and January 31,2025, subject to
certain conditions, the holders of Series
F shares had the
right, at their option, to convert all or
any of their Series F shares, on a one-for-one
basis into Cumulative Floating Rate
First Preferred Shares,
Series G on February 15, 2025. On February
6, 2025, Emera announced after having taken
into account all conversion notices received
from
holders, no Series F were converted
into Series G shares.
(6) On January 16, 2025, Emera announced
that the annual fixed dividend per share
for Series F shares will be reset from $
1.0505
to $
1.4372
for the five-year period from and including
February 15, 2025.
(7) First Preferred Shares, Series E are redeemable
at $
25.00
per share.
(8) First Preferred Shares, Series L are redeemable
at $
26.00
on or after November 15, 2026 to
November 15, 2027, decreasing $
0.25
each
year until November 15, 2030 and $
25.00
per share thereafter.
72
First Preferred Shares are neither redeemable at the option of the shareholder nor have a mandatory
redemption date. They are classified as equity and the associated dividends are deducted on the
Consolidated Statements of Income before arriving at “Net income attributable to common shareholders”
and shown on the Consolidated Statement of Changes in Equity as a deduction from retained earnings.
The First Preferred Shares of each series rank on a parity with the First Preferred Shares of every other
series and are entitled to a preference over the Second Preferred Shares, the Common Shares, and any
other shares ranking junior to the First Preferred Shares with respect to the payment of dividends and the
distribution of the remaining property and assets or return of capital of the Company in the liquidation,
dissolution or wind-up, whether voluntary or involuntary.
In the event the Company fails to pay, in aggregate, eight quarterly dividends on any series of the First
Preferred Shares, the holders of the First Preferred Shares, for only so long as the dividends remain in
arrears, will be entitled to attend any meeting of shareholders of the Company at which directors are to be
elected and to vote for the election of two directors out of the total number of directors elected at any such
meeting.
30. NON-CONTROLLING INTEREST IN SUBSIDIARIES
As at
December 31
December 31
millions of dollars
2024
2023
Preferred shares of GBPC
$
14
$
14
$
14
$
14
Preferred shares of GBPC:
Authorized:
10,000
non-voting cumulative redeemable variable perpetual
preferred shares.
2024
2023
Issued and outstanding:
number of
shares
millions of
dollars
number of
shares
millions of
dollars
Outstanding as at December 31
10,000
$
14
10,000
$
14
GBPC Non–Voting
Cumulative Variable
Perpetual Preferred Stock:
The preferred shares are redeemable by GBPC after June 17, 2021
, at $
1,000
Bahamian per share plus
accrued and unpaid dividends and are entitled to a
6.0 per cent per annum fixed cumulative preferential
dividend to be paid semi-annually
.
The Preferred Shares rank behind GBPC’s current
and future secured and unsecured debt and ahead of
all of GBPC’s current and future common stock.
73
31. SUPPLEMENTARY
INFORMATION TO CONSOLIDATED
STATEMENTS
OF
CASH FLOWS
For the
Year ended December 31
millions of dollars
2024
2023
Changes in non-cash working capital:
Inventory
$
38
$
(31)
Receivables and other current assets
(1)
(154)
653
Accounts payable
536
(538)
Other current liabilities
(2)
32
(179)
Total
non-cash working capital
$
452
$
(95)
(1) The year ended December 31, 2023, includes $
162
million related to the January 2023 NMGC gas
hedges. Offsetting change in
regulatory liabilities is included in operating cash
flow before working capital resulting in no
impact to net cash provided by operating
activities.
(2) The year ended December 31, 2023, includes ($
166
) million related to the decreased accrual for
the Nova Scotia Cap-
and-Trade emissions compliance charges. Offsetting regulatory asset (FAM) balance is included
in operating cash flow before
working capital resulting in no impact to net
cash provided by operating activities.
For the
Year ended December 31
millions of dollars
2024
2023
Supplemental disclosure of cash paid:
Interest
$
989
$
930
Income taxes
$
34
$
43
Supplemental disclosure of non-cash activities:
Accrued proceeds from disposal of investment subject to significant influence
$
25
$
-
Common share dividends reinvested
$
291
$
271
Reclassification of short-term debt to long-term debt
$
-
$
657
Decrease in accrued capital expenditures
$
-
$
(19)
Supplemental disclosure of operating activities:
Net change in short-term regulatory assets and liabilities
$
(118)
$
123
32. STOCK-BASED COMPENSATION
ECSPP and Common Shareholders DRIP
Eligible employees can participate in the ECSPP. As of December 31, 2024, the plan allows employees
to make cash contributions of a minimum of $25 per month to a maximum of $20,000 CAD or $15,000
USD per year for the purpose of purchasing common shares of Emera. The Company also contributes 20
per cent of the employees’ contributions to the plan.
The plan allows reinvestment of dividends for all participants except for where prohibited by law.
The
maximum aggregate number of Emera common shares
reserved for issuance under this plan is
7
million
common shares. As at December 31, 2024, Emera was
in compliance with this requirement.
Compensation cost for shares issued under the ECSPP for the
year ended December 31, 2024 was $
4
million (2023 – $
3
million) and was included in “OM&G” on the Consolidated
Statements of Income.
The Company also has a Common Shareholders DRIP, which provides an opportunity for shareholders
residing in Canada to reinvest dividends and purchase common shares. This plan provides for a discount
of up to 5 per cent from the average market price of Emera’s common shares for common shares
purchased with the reinvestment of cash dividends. The discount was 2 per cent in 2024.
74
Stock-Based Compensation Plans
Stock Option Plan
The Company has a stock option plan that grants options to senior management of the Company for a
maximum term of 10 years. The option price of the stock options is the closing price of the Company’s
common shares on the Toronto Stock Exchange on the last business day on which such shares were
traded before the date on which the option is granted. The maximum aggregate number of shares
issuable under this plan is 14.7 million shares. As at December 31, 2024, Emera was in compliance with
this requirement.
Stock options granted in 2021 and prior vest in 25 per cent increments on the first, second, third and
fourth anniversaries of the date of the grant. Stock options granted in 2022 and thereafter vest in 20 per
cent increments on the first, second, third, fourth and fifth anniversaries of the date of the grant. If an
option is not exercised within 10 years, it expires and the optionee loses all rights thereunder. The holder
of the option has no rights as a shareholder until the option is exercised and shares have been issued.
The total number of stocks to be optioned to any optionee shall not exceed five per cent of the issued and
outstanding common stocks on the date the option is granted.
For stock options granted in 2021 and prior,
unless a stock option has expired, vested options may
be
exercised within the
27 months
following the option holder’s date of retirement,
six months
following a
termination without just cause or death, and within
sixty days
following the date of termination for just
cause or resignation. Commencing with the 2022 stock
option grant, vested options may be exercised
during the full term of the option following the option holders
date of retirement,
six months
following a
termination without just cause or death, and within
sixty days
following the date of termination for just
cause or resignation. If stock options are not exercised
within such time, they expire.
The Company uses the Black-Scholes valuation model to estimate
the compensation expense related to
its stock-based compensation and recognizes the expense
over the vesting period on a straight-line
basis.
The following table shows the weighted average FV per
stock option along with the assumptions
incorporated into the valuation models for options granted, for
the year-ended December 31:
2024
2023
Weighted average FV per option
$
4.66
$
6.32
Expected term
(1)
5
years
5
years
Risk-free interest rate
(2)
3.56
%
3.53
%
Expected dividend yield
(3)
6.11
%
5.05
%
Expected volatility
(4)
20.67
%
20.07
%
(1) The expected term of the option awards is
calculated based on historical exercise behaviour
and represents the period of time
that the options are expected to be outstanding.
(2) Based on the Bank of Canada five-year government
bond yields.
(3) Incorporates current dividend rates and historical
dividend increase patterns.
(4) Estimated using the five-year historical volatility.
75
The following table summarizes stock option information for
2024:
Total
Options
Non-Vested Options
(1)
Number of
Options
Weighted
average exercise
price per share
Number of
Options
Weighted
average grant
date fair-value
Outstanding as at December 31, 2023
3,095,604
$
51.20
1,253,255
$
5.17
Granted
792,600
46.97
792,600
4.66
Exercised
(78,839)
39.86
N/A
N/A
Forfeited
(13,325)
56.14
-
N/A
Vested
N/A
N/A
(438,365)
4.58
Options outstanding December 31, 2024
3,796,040
$
50.53
1,607,490
$
5.08
Options exercisable December 31, 2024
(2)(3)
2,188,550
$
50.07
(1) As at December 31, 2024, there was $
6
million of unrecognized compensation related to
stock options not yet vested which is
expected to be recognized over a weighted
average period of approximately
3
years (2023 – $
5
million,
3
years).
(2) As at December 31, 2024, the weighted
average remaining term of vested options was
4
years with an aggregate intrinsic value of
$
11
million (2023 –
5
years, $
8
million).
(3) As at December 31, 2024, the FV of options
that vested in the year was $
2
million (2023 – $
2
million).
Compensation cost recognized for stock options for the year
ended December 31, 2024 was $
2
million
(2023 – $
2
million), which was included in “OM&G” on the Consolidated
Statements of Income.
As at December 31, 2024, cash received from option exercises
was $
3
million (2023 – $
6
million). The
total intrinsic value of options exercised for the year ended
December 31, 2024 was $
1
million (2023 – $
2
million). The range of exercise prices for the options outstanding
as at December 31, 2024 was $
39.93
to
$
60.03
(2023 – $
32.35
to $
60.03
).
Share Unit Plans
The Company has DSU, PSU and RSU plans. The plans and the liabilities are marked-to-market at the
end of each period based on an average common share price at the end of the period.
Deferred Share Unit Plans
Under the Directors’ DSU plan, Directors of the Company may elect to receive all or any portion of their
compensation in DSUs in lieu of cash compensation, subject to requirements to receive a minimum
portion of their annual retainer in DSUs. Directors’ fees are paid on a quarterly basis and, at the time of
each payment of fees, the applicable amount is converted to DSUs. A DSU has a value equal to one
Emera common share. When a dividend is paid on Emera’s common shares, the Director’s DSU account
is credited with additional DSUs. DSUs cannot be redeemed for cash until the Director retires, resigns or
otherwise leaves the Board. The cash redemption value of a DSU equals the market value of a common
share at the time of redemption, pursuant to the plan. Following retirement or resignation from the Board,
the value of the DSUs credited to the participant’s account is calculated by multiplying the number of
DSUs in the participant’s account by Emera’s closing common share price on the date DSUs are
redeemed.
Under the executive and senior management DSU plan, each participant may elect to defer all or a
percentage of their annual incentive award in the form of DSUs with the understanding, for participants
who are subject to executive share ownership guidelines, a minimum of 50 per cent of the value of their
actual annual incentive award (25 per cent in the first year of the program) will be payable in DSUs until
the applicable guidelines are met.
76
When short-term incentive awards are determined, the amount elected is converted to DSUs, which have
a value equal to the market price of an Emera common share. When a dividend is paid on Emera’s
common shares, each participant’s DSU account is allocated additional DSUs equal in value to the
dividends paid on an equivalent number of Emera common shares. Unless otherwise determined by the
Management Resources and Compensation Committee (“MRCC”), following termination of employment
or retirement, and by December 15 of the calendar year after termination or retirement, the value of the
DSUs credited to the participant’s account is calculated by multiplying the number of DSUs in the
participant’s account by the average of Emera’s stock closing price for the fifty trading days prior to a
given calculation date. Payments are made in cash.
In addition, special DSU awards may be made from time to time by the MRCC to selected executives and
senior management to recognize singular achievements or by achieving certain corporate objectives.
A summary of the activity related to employee and director
DSUs for the year ended December 31, 2024
is presented in the following table:
Employee
DSU
Weighted
Average
Grant Date
FV
Director
DSU
Weighted
Average
Grant Date
FV
Outstanding as at December 31, 2023
712,963
$
42.29
729,058
$
46.24
Granted including DRIP
86,417
45.20
134,795
48.98
Exercised
(10,292)
38.77
(34,997)
36.04
Outstanding and exercisable as at December 31, 2024
789,088
$
42.65
828,856
$
47.12
Compensation cost recognized for employee and director
DSU’s for the year ended December 31, 2024
was $
13
million (2023 – $
2
million cost recovery). Tax
benefits related to this compensation cost for share
units realized for the year ended December 31, 2024
were $
4
million (2023 – $
1
million tax expense). The
aggregate intrinsic value of the outstanding shares for the year
ended December 31, 2024 for employees
was $
43
million (2023 – $
36
million). The aggregate intrinsic value of the outstanding
shares for the year
ended December 31, 2024 for directors was $
45
million (2023 – $
37
million). Cash payments made
during the year ended December 31, 2024 associated with
the DSU plan were $
2
million (2023 – $
3
million).
Performance Share Unit Plan
Under the PSU plan, certain executive and senior employees are eligible for long-term incentives payable
through the plan. PSUs are granted annually for
three-year
overlapping performance cycles, resulting in a
cash payment. Unless otherwise determined by the MRCC, PSUs are granted based on the average of
Emera’s stock closing price for the fifty trading days prior to the effective grant date. Dividend equivalents
are awarded and paid in the form of additional PSUs. The PSU value varies according to the Emera
common share market price and corporate performance.
PSUs vest at the end of the
three-year
cycle and the payouts will be calculated and approved by the
MRCC early in the following year. The value of the payout considers actual service over the performance
cycle and may be pro-rated in certain departure scenarios. In the case of retirement, as defined in the
PSU plan, grants may continue to vest in full and payout in normal course post-retirement.
77
A summary of the activity related to employee PSUs for
the year ended December 31, 2024 is presented
in the following table:
Employee PSU
Weighted Average
Grant Date FV
Aggregate intrinsic value
Outstanding as at December 31, 2023
743,365
$
55.13
$
41
Granted including DRIP
354,793
48.69
Exercised
(253,136)
54.66
Forfeited
(12,929)
52.53
Outstanding as at December 31, 2024
832,093
$
52.57
$
50
Compensation cost recognized for the PSU plan for the
year ended December 31, 2024 was $
18
million
(2023 – $
11
million). Tax
benefits related to this compensation cost for share
units realized for the year
ended December 31, 2024 were $
5
million (2023 – $
3
million). Cash payments made during the year
ended December 31, 2024 associated with the PSU plan were
$
14
million (2023 – $
19
million).
Restricted Share Unit Plan
Under the RSU plan, certain executive and senior employees are eligible for long-term incentives payable
through the plan. RSUs are granted annually for
three-year
overlapping performance cycles, resulting in a
cash payment. Unless otherwise determined by the MRCC, RSUs are granted based on the average of
Emera’s stock closing price for the fifty trading days prior to the effective grant date. Dividend equivalents
are awarded and paid in the form of additional RSUs. The RSU value varies according to the Emera
common share market price.
RSUs vest at the end of the
three-year
cycle and the payouts will be calculated and approved by the
MRCC early in the following year. The value of the payout considers actual service over the performance
cycle and may be pro-rated in certain departure scenarios. In the case of retirement, as defined in the
RSU plan, grants may continue to vest in full and payout in normal course post-retirement.
A summary of the activity related to employee RSUs for
the year ended December 31, 2024 is presented
in the following table:
Employee RSU
Weighted Average
Grant Date FV
Aggregate intrinsic value
Outstanding as at December 31, 2023
562,641
$
55.01
$
32
Granted including DRIP
287,976
48.65
Exercised
(183,241)
54.66
Forfeited
(14,228)
52.45
Outstanding as at December 31, 2024
653,148
$
52.36
$
41
Compensation cost recognized for the RSU plan for the
year ended December 31, 2024 was $
15
million
(2023 – $
10
million). Tax
benefits related to this compensation cost for share
units realized for the year
ended December 31, 2024 were $
4
million (2023 – $
3
million). Cash payments made during the year
ended December 31, 2024 associated with the RSU plan were
$
10
million (2023– $
10
million).
33. VARIABLE INTEREST ENTITIES
Emera holds a variable interest in NSPML, a VIE for which
it was determined that Emera is not the
primary beneficiary since it does not have the controlling
financial interest of NSPML. When the critical
milestones were achieved, NLH was deemed the primary
beneficiary of the asset for financial reporting
purposes as it has
authority over the majority of the direct activities that
are expected to most significantly
impact the economic performance of the Maritime Link. Thus,
Emera began recording the Maritime Link
as an equity investment.
78
BLPC has established a SIF,
primarily for the purpose of building a fund to cover risk
against damage and
consequential loss to certain generating, transmission
and distribution systems. ECI holds a variable
interest in the SIF for which it was determined that ECI
was the primary beneficiary and, accordingly,
the
SIF must be consolidated by ECI. In its determination that
ECI controls the SIF,
management considered
that, in substance, the activities of the SIF are being conducted
on behalf of ECI’s subsidiary BLPC and
BLPC, alone, obtains the benefits from the SIF’s
operations. Additionally,
because ECI, through BLPC,
has rights to all the benefits of the SIF,
it is also exposed to the risks related to the activities
of the SIF.
Any withdrawal of SIF fund assets by the Company would
be subject to existing regulations. Emera’s
consolidated VIE in the SIF is recorded as “Other long-term
assets”, “Restricted cash” and “Regulatory
liabilities” on the Consolidated Balance Sheets. Amounts
included in restricted cash represent the cash
portion of funds required to be set aside for the BLPC
SIF.
The Company has identified certain long-term purchase power
agreements that meet the definition of
variable interests as the Company has to purchase all
or a majority of the electricity generation at a fixed
price. However, it was determined
that the Company was not the primary beneficiary
since it lacked the
power to direct the activities of the entity,
including the ability to operate the generating facilities
and make
management decisions.
The following table provides information about Emera’s
portion of material unconsolidated VIEs:
As at
December 31, 2024
December 31, 2023
Maximum
Maximum
millions of dollars
Total
assets
exposure to
loss
Total
assets
exposure to
loss
Unconsolidated VIEs in which Emera has variable interests
NSPML (equity accounted)
$
475
$
6
$
489
$
6
34. SUBSEQUENT EVENTS
These financial statements and notes reflect the Company’s
evaluation of events occurring subsequent to
the balance sheet date through February 21, 2025, the date
the financial statements were issued.