1
EMERA INCORPORATED
Consolidated
Financial Statements
December 31, 2022 and 2021
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 23, 2023
“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, 2022 and 2021, 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, 2022 and 2021, and the consolidated results of its operations and its consolidated cash
flows for each of the two years in the period ended December 31, 2022, 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 $3.6 billion in regulatory assets and $2.3 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 to 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 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
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 measurement of derivative financial instruments
Description of the
Matter
Held-for-trading (“HFT”) derivative assets of $429 million and liabilities of
$1,301 million, disclosed in note 15 to the consolidated financial statements,
are measured at fair value. The Company recognized $64 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 fair value
of the contracts. In determining the fair value of HFT derivatives, significant
assumptions about future economic and market assumptions with uncertain
outcomes are used, including third-party sourced forward commodity pricing
5
curves based on illiquid markets, internally developed correlation factors
and basis differentials. These assumptions have a significant impact on the
fair value of the HFT derivatives.
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 fair value hierarchy disclosures in note 16 to the
consolidated financial statements were consistent with the source of the
significant inputs and assumptions used in determining the fair value of
derivatives.
/s/ Ernst & Young LLP
Chartered Professional Accountants
We have served as the Company‘s auditor since 1998.
Halifax, Canada
February 23, 2023
6
Emera Incorporated
Consolidated Statements of Income
For the
Year ended December 31
millions of dollars (except per share amounts)
2022
2021
Operating revenues
$
5,473
$
4,665
1,681
1,261
434
(161)
7,588
5,765
Operating expenses
2,171
1,763
800
472
1,596
1,368
367
330
952
902
73
-
5,959
4,835
Income from operations
1,629
930
Income from equity investments (note 8)
129
143
Other income, net (note 9)
145
93
Interest expense, net
709
611
Income before provision for income taxes
1,194
555
Income tax expense (recovery) (note 10)
185
(6)
Net income
1,009
561
Non-controlling interest in subsidiaries
1
1
Preferred stock dividends
63
50
Net income attributable to common shareholders
$
945
$
510
Weighted average shares of common stock outstanding (in millions) (note 12)
266
257
266
258
Earnings per common share (note 12)
$
3.56
$
1.98
$
3.55
$
1.98
Dividends per common share declared
$
2.6775
$
2.5750
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
2022
2021
Net income
$
1,009
$
561
Other comprehensive income (loss), net of tax
Foreign currency translation adjustment
(1)
629
(42)
Unrealized (losses) gains on net investment hedges
(2) (3)
(97)
5
Cash flow hedges
-
18
(2)
(1)
(2)
17
Unrealized losses on available-for-sale investment
(1)
-
Net change in unrecognized pension and post-retirement benefit obligation
(5)
24
124
Other comprehensive income
(6)
553
104
Comprehensive income
1,562
665
Comprehensive income attributable to non-controlling interest
1
1
Comprehensive Income of Emera Incorporated
$
1,561
$
664
The accompanying notes are an integral part of these consolidated financial statements.
1) Net of tax expense of $
7
5
2) The Company has designated $
1.2
currency exposure of its net investment in USD denominated operations.
3) Net of tax recovery of $
6
1
4) Net of tax recovery of $
1
6
5) Net of tax expense of $
1
2
6) Net of tax expense of $
1
14
8
Emera Incorporated
Consolidated Balance Sheets
As at
December 31
December 31
millions of dollars
2022
2021
Assets
Current assets
$
310
$
394
22
23
769
538
296
195
602
253
2,897
1,733
4,896
3,136
Property, plant and equipment ("PP&E"),
net of accumulated depreciation
and amortization of $
9,574
8,739
, respectively (note 20)
22,996
20,353
Other assets
237
295
100
106
3,018
2,313
604
503
1,418
1,382
6,012
5,696
461
460
11,850
10,755
Total assets
$
39,742
$
34,244
Liabilities and Equity
Current liabilities
$
2,726
$
1,742
574
462
2,025
1,485
888
533
495
290
579
366
7,287
4,878
Long-term liabilities
15,744
14,196
2,196
1,868
190
149
1,778
1,765
281
370
825
868
21,014
19,216
Equity
7,762
7,242
1,422
1,422
81
79
578
25
1,584
1,348
11,427
10,116
14
34
11,441
10,150
Total liabilities and equity
$
39,742
$
34,244
Commitments and contingencies (note 27)
Approved on behalf of the Board of Directors
The accompanying notes are an integral part of
these consolidated financial statements.
9
Emera Incorporated
Consolidated Statements of Cash Flows
For the
Year ended December 31
Year ended December 31
millions of dollars
2022
2021
Operating activities
Net income
$
1,009
$
561
Adjustments to reconcile net income to net cash provided by operating activities:
959
915
(61)
(69)
(52)
(61)
152
(37)
(48)
(23)
(162)
(166)
206
404
(471)
(176)
(445)
(107)
73
-
(13)
96
Changes in non-cash working capital (note 30)
(234)
(152)
Net cash provided by operating activities
913
1,185
Investing activities
(2,596)
(2,359)
27
27
Net cash used in investing activities
(2,569)
(2,332)
Financing activities
1,028
(155)
544
640
(680)
(377)
784
2,554
(367)
(1,660)
511
82
277
317
-
416
(472)
(443)
(63)
(50)
(7)
(13)
Net cash provided by financing activities
1,555
1,311
Effect of exchange rate changes on cash, cash equivalents, and restricted cash
16
(1)
Net increase (decrease) in cash, cash equivalents, and restricted cash
(85)
163
Cash, cash equivalents, and restricted cash, beginning of year
417
254
Cash, cash equivalents, and restricted cash, end of year
$
332
$
417
Cash, cash equivalents, and restricted cash consists of:
Cash
$
302
$
237
Short-term investments
8
157
Restricted cash
22
23
Cash, cash equivalents, and restricted cash
$
332
$
417
Supplementary Information to Consolidated Statements of Cash Flows (note 30)
The accompanying notes are an integral part of these consolidated financial statements.
10
Emera Incorporated
Consolidated Statements of Changes in Equity
Non-
Common
Preferred
Contributed
Retained
Controlling
Total
Stock
Surplus
AOCI
Earnings
Interest
Equity
millions of dollars
Balance, December 31, 2021
$
7,242
$
1,422
$
79
$
25
$
1,348
$
34
$
10,150
Net income of Emera Inc.
-
-
-
-
1,008
1
1,009
Other comprehensive income, net of
tax expense of $
1
-
-
-
553
-
-
553
Dividends declared on preferred stock
(note 28)
-
-
-
-
(63)
-
(63)
Dividends declared on common stock
($
2.6775
/share)
-
-
-
-
(709)
-
(709)
Issued under the at-the-market
program ("ATM"), net of after-tax
issuance costs
248
-
-
-
-
-
248
Issued under the Dividend
Reinvestment Program ("DRIP"), net of
discount
238
-
-
-
-
-
238
Senior management stock options
exercised and Employee Share
Purchase Plan
34
-
2
-
-
-
36
Disposal of non-controlling interest of
Dominica Electricity Services Ltd
("Domlec")
-
-
-
-
-
(20)
(20)
Other
-
-
-
-
-
(1)
(1)
Balance, December 31, 2022
$
7,762
$
1,422
$
81
$
578
$
1,584
$
14
$
11,441
Balance, December 31, 2020
$
6,705
$
1,004
$
79
$
(79)
$
1,495
$
34
$
9,238
Net income of Emera Inc.
-
-
-
-
560
1
561
Other comprehensive income, net of tax
expense of $
14
-
-
-
104
-
-
104
Issuance of preferred stock, net of after-
tax issuance costs
-
418
-
-
-
-
418
Dividends declared on preferred stock
(note 28)
-
-
-
-
(50)
-
(50)
Dividends declared on common stock
($
2.5750
/share)
-
-
-
-
(657)
-
(657)
Issued under the ATM, net of after-tax
issuance costs
284
-
-
-
-
-
284
Issued under the DRIP, net of discount
215
-
-
-
-
-
215
Senior management stock options
exercised and Employee Share
Purchase Plan
38
-
-
-
-
-
38
Other
-
-
-
-
-
(1)
(1)
Balance, December 31, 2021
$
7,242
$
1,422
$
79
$
25
$
1,348
$
34
$
10,150
The accompanying notes are an integral part of these consolidated financial statements.
11
Emera Incorporated
Notes to the Consolidated Financial Statements
As at December 31, 2022 and 2021
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Nature of Operations
Emera Incorporated (“Emera” or the “Company”) is an energy and services company which invests in
electricity generation, transmission and distribution, and gas transmission and distribution.
At December 31, 2022, Emera’s reportable segments include the following:
●
utility, serving approximately
827,000
●
●
primary electricity supplier in Nova Scotia, serving approximately
541,000
●
investments related to an
824
Falls on the Lower Churchill River in Labrador, owned and constructed by Nalcor Energy.
ENL’s two investments are:
●
100
Maritime Link Project, a $
1.8
construction (“AFUDC”)) transmission project; and
●
31.9
Partnership (“LIL”), a $
3.7
Labrador.
●
●
468,000
●
approximately
545,000
●
145
-kilometre pipeline
delivering re-gasified liquefied natural gas (“LNG”) from Saint John, New Brunswick to the
United States border under a
25
-year firm service agreement with Repsol Energy North
America Canada Partnership, which expires in 2034;
●
transmission company in Florida; and
●
12.9
1,400
-kilometre
pipeline that transports natural gas throughout markets in Atlantic Canada and the
northeastern United States.
●
with regulated electric utilities that include:
●
electric utility on the island of Barbados, serving approximately
133,000
●
utility on Grand Bahama Island, serving approximately
19,000
●
19.5
integrated regulated electric utility on the island of St. Lucia.
12
●
which includes:
●
●
natural gas and electricity and provides related energy asset management services;
●
30
electricity facility in Brooklyn, Nova Scotia; and
●
50.0
Swamp”), a
660
Massachusetts.
●
financing subsidiaries of Emera;
●
deliver renewables and resilient energy to customers;
●
located in the United States; and
●
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 entity that most significantly impacts its economic performance and the
obligation to absorb losses of the entity that could potentially be significant to the entity. 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 32.
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.
13
Use of Management Estimates
The preparation of consolidated financial statements in accordance with USGAAP requires management
to make estimates and assumptions. These may affect the 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. The rates are designed to recover prudently incurred costs of providing the 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 the exchange rates in effect at the balance sheet date is recorded in
Other Comprehensive Income (“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 regulator 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, the electricity and
gas delivered to customers, but not billed, is estimated and the corresponding unbilled revenue is
recognized. The Company’s estimate of unbilled revenue at the end of the reporting period is calculated
by estimating the number of 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.
14
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 the terms of the contract are satisfied and are presented on a net
basis, reflecting the nature of the 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.
Leases
The Company determines whether a contract contains a lease at inception by evaluating if 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 with annual requirements
to purchase wind and hydro energy over varying contract lengths that 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 “Operating,
maintenance and general” 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.
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 fair value 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.
15
Franchise Fees and Gross Receipts
Tampa Electric 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 Tampa Electric 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.
Property, Plant and Equipment
PP&E are 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 “Property, plant
and equipment”. 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 the 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.
Intangible assets, which are included in “Property, plant and equipment,” 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.
16
Goodwill
Goodwill is calculated as the excess of the purchase price of an acquired entity over the estimated fair
values 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. Under
the applicable accounting guidance, goodwill is subject to assessment for impairment at the reporting unit
level annually, or if an event or change in circumstances indicates that the fair value 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 the qualitative assessment and determines that it is more likely than not that its
fair value 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 fair value of the
reporting unit to its carrying amount, including goodwill. If the carrying amount of the reporting unit
exceeds its fair value, an impairment loss is recorded. Management estimates the fair value of the
reporting unit by using the income approach, or a combination of the income and market approach. The
income approach is applied using a discounted cash flow analysis which relies on management’s best
estimate of the reporting units’ 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. When using the market approach,
management estimates fair value based on comparable companies and transactions within the utility
industry. Significant assumptions used in estimating the fair value include discount and growth rates, rate
case assumptions including future cost of capital, valuation of the reporting units' net operating loss
(“NOL”) and projected operating and capital cash flows. Adverse changes in these assumptions could
result in a future material impairment of the goodwill assigned to Emera’s reporting units.
As of December 31, 2022, $
6,009
purchase price for TECO Energy (Tampa Electric, PGS and NMGC reporting units) over the fair values
assigned to identifiable assets acquired and liabilities assumed. In Q4 2022, qualitative assessments
were performed for Tampa Electric and PGS given the significant excess of fair value over carrying
amounts calculated during the last quantitative test in Q4 2019. Management concluded it was more likely
than not that the fair value of these reporting units exceeded their respective carrying amounts, including
goodwill. As such, no quantitative testing was required. For the NMGC reporting unit, Emera elected to
bypass a qualitative assessment and performed a quantitative impairment assessment using a
combination of the income and market approach. This assessment estimated that the fair value of the
NMGC reporting unit exceeded its carrying amount, including goodwill. As a result of this assessment,
no
impairment charges were recognized.
In Q4 2022, the Company elected to bypass a qualitative assessment and performed a quantitative
impairment assessment for GBPC, using the income approach, as this reporting unit is sensitive to
changes in assumptions due to limited excess of fair value over the carrying value, including goodwill.
Although the cash flows of GBPC have not changed significantly compared to previous periods, it was
determined that the carrying amount, including goodwill, exceeded the fair value, due to an increase in
discount rates. The discount rate for the reporting unit was negatively impacted by changes in the macro-
economic environment, including the risk-free rate assumption. As a result of this assessment, a goodwill
impairment charge of $
73
nil
December 31, 2022. No impairment was recorded in 2021. For further detail, refer to note 22.
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 the 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 tax assets will be recovered from future taxable
income is assessed and assumptions about the expected timing of the reversal of deferred tax assets and
liabilities are made. If management subsequently determines that it is likely that some or all of a deferred
income tax asset will not be realized, then 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 by Tampa Electric, PGS and NMGC on regulated assets are deferred and amortized over the
estimated service lives of the related properties, as required by regulatory practices.
Tampa Electric, PGS, NMGC and BLPC collect income taxes from customers based on current and
deferred income taxes. NSPI, ENL 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 the regulator. For the balance of regulated deferred income taxes, NSPI, ENL
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 10.
Derivatives and Hedging Activities
The Company manages its exposure to normal operating and market risks relating to commodity prices,
foreign exchange, interest rates and share prices through contractual protections with counterparties
where practicable, and by using financial instruments consisting mainly of foreign exchange 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 held-for-trading (“HFT”). Collectively, these
contracts and financial instruments are considered derivatives.
The Company recognizes the fair value 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 where 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 the identified risk both at the inception and over the term of the instrument.
Specifically, for cash flow hedges, the change in the fair value of derivatives is deferred to AOCI and
recognized in income in the same period the related hedged item is realized. Where the documentation or
effectiveness requirements are not met, the derivatives are recognized at fair value with any changes in
fair value 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 fair value 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. Tampa Electric has no derivatives related
to hedging as a result of a FPSC approved five-year moratorium on hedging of natural gas purchases
which ends on December 31, 2022. Tampa Electric’s moratorium on hedging of natural gas purchases
will continue through December 31, 2024, as a result of Tampa Electric’s 2021 rate case settlement
agreement.
Derivatives that do not meet any of the above criteria are designated as HFT, with changes in fair value
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 fuel for generation and purchased
power, other expenses, inventory, OM&G and PP&E, 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 or investing 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 fair value 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”.
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.
19
Inventory
Fuel and materials inventories are valued at the lower of weighted-average cost or net realizable value,
unless evidence indicates that 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 the 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 fair value. 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.
As at December 31, 2022, there are no indications of impairment of Emera’s long-lived assets.
No
impairment charges related to long-lived assets were recognized in 2022 or 2021.
Equity Method Investments:
The carrying value of investments accounted for under the equity method are assessed for impairment by
comparing the fair value of these investments to their carrying values, if a fair value 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 fair value.
No
required in either 2022 or 2021.
Financial Assets:
Equity investments, other than those accounted for under the equity method, are measured at fair value,
with changes in fair value recognized in the Consolidated Statements of Income. Equity investments that
do not have readily determinable fair values 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
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.
20
An ARO represents the fair value of the 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
“Property, plant and equipment” and included in the next depreciation study.
Some of the Company’s transmission and distribution assets may have conditional AROs which are not
recognized in the consolidated financial statements, as the fair value of these obligations could not be
reasonably estimated, given there is 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 fair value in the period in which an amount can
be determined.
Cost of Removal
Tampa Electric, PGS, NMGC and NSPI recognize non-ARO costs of removal (“COR”) as regulatory
liabilities. 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.
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 fair value-based method of accounting for stock-based compensation.
Stock-based compensation cost is measured at the grant date, based on the calculated fair value 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 fair value and re-measured at fair value 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 the unamortized gains
and losses and past service costs in AOCI or regulatory assets. 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 21.
21
2.
CHANGE IN ACCOUNTING POLICY
The new USGAAP accounting policy that is applicable to, and adopted by the Company in 2022, is
described as follows:
Facilitation of the Effects of Reference Rate Reform on Financial Reporting
The Company adopted Accounting Standard Update (“ASU”) 2022-06,
Reference Rate Reform (Topic
848): Deferral of the Sunset Date of Topic 848
preparers can utilize the reference rate reform relief guidance issued under ASU 2020-04, which was
adopted by the Company in Q4 2020. The guidance in ASU 2022-06 was effective as of the date of
issuance and entities may elect to apply the guidance prospectively through to December 31, 2024. The
Company has applied the guidance permitted by ASU 2020-04 to certain debt agreements that were
amended during the current period. The Company’s transition from reference rates will not have a
material impact on the consolidated financial statements.
3. FUTURE ACCOUNTING PRONOUNCEMENTS
The Company considers the applicability and impact of all ASUs issued by the Financial Accounting
Standards Board (“FASB”). ASUs issued by FASB, but which are not yet effective, were assessed and
determined to be either not applicable to the Company or to have an insignificant impact on the
consolidated financial statements.
4.
DISPOSITIONS
On March 31, 2022, Emera completed the sale of its
51.9
approximated its carrying value. Domlec was included in the Company’s Other Electric reportable
segment up to its date of sale. The sale did not have a material impact on earnings.
22
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.
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, 2022
Operating revenues from
external customers (1)
$
3,280
$
1,675
$
1,697
$
518
$
418
$
$
7,588
Inter-segment revenues
(1)
7
-
7
-
22
(36)
3,287
1,675
1,704
518
440
(36)
7,588
Regulated fuel for generation
and purchased power
1,086
803
-
290
-
(8)
2,171
Regulated cost of natural gas
-
-
800
-
-
-
800
OM&G
625
338
365
123
156
(11)
1,596
Provincial, state and municipal
taxes
235
43
83
3
3
-
367
Depreciation and amortization
507
259
118
61
7
-
952
Income from equity investments
-
87
21
4
17
-
129
Other income (expense), net
68
24
13
-
23
17
145
Interest expense, net
(2)
185
136
81
19
288
-
709
Impairment charge
-
-
-
73
-
-
73
Income tax expense (recovery)
121
(8)
70
-
2
-
185
Non-controlling interest in
subsidiaries
-
-
-
1
-
-
1
Preferred stock dividends
-
-
-
-
63
-
63
Net income (loss) attributable to
common shareholders
$
596
$
215
$
221
$
(48)
$
(39)
$
-
$
945
Capital expenditures
$
1,425
$
507
$
574
$
63
$
6
$
-
$
2,575
As at December 31, 2022
Total assets
$
21,053
$
8,223
$
7,737
$
1,337
$
2,835
$
(1,443)
$
39,742
Investments subject to
significant influence
$
-
$
1,241
$
128
$
49
$
-
$
-
$
1,418
Goodwill
$
4,739
$
-
$
1,270
$
-
$
3
$
-
$
6,012
(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 $
13
December 31, 2022, between the Gas Utilities and Infrastructure and Other segments.
23
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, 2021
Operating revenues from
external customers
(1)
$
2,718
$
1,501
$
1,276
$
445
$
(175)
$
$
5,765
Inter-segment revenues
(1)
6
-
4
-
18
(28)
2,724
1,501
1,280
445
(157)
(28)
5,765
Regulated fuel for generation
and purchased power
894
654
-
218
-
(3)
1,763
Regulated cost of natural gas
-
-
472
-
-
-
472
OM&G
536
291
325
140
106
(30)
1,368
Provincial, state and municipal
taxes
212
43
69
4
2
-
330
Depreciation and amortization
469
246
121
58
8
-
902
Income from equity investments
-
103
20
4
16
-
143
Other income (expenses), net
59
12
11
15
1
(5)
93
Interest expense, net
(2)
138
132
64
21
256
-
611
Income tax expense (recovery)
72
9
62
1
(150)
-
(6)
Non-controlling interest in
subsidiaries
-
-
-
1
-
-
1
Preferred stock dividends
-
-
-
-
50
-
50
Net income (loss) attributable to
common shareholders
$
462
$
241
$
198
$
21
$
(412)
$
-
$
510
Capital expenditures
$
1,331
$
366
$
515
$
111
$
5
$
-
$
2,328
As at December 31, 2021
Total assets
$
17,903
$
7,418
$
6,666
$
1,402
$
2,034
$
(1,179)
$
34,244
Investments subject to
significant influence
$
-
$
1,215
$
123
$
44
$
-
$
-
$
1,382
Goodwill
$
4,436
$
-
$
1,189
$
68
$
3
$
-
$
5,696
(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 the 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 $
13
December 31, 2021, between the 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
2022
2021
United States
$
5,346
$
3,754
Canada
1,725
1,566
Barbados
384
292
The Bahamas
122
110
Dominica
11
43
$
7,588
$
5,765
Property Plant and Equipment:
As at
December 31
December 31
millions of dollars
2022
2021
United States
$
17,382
$
14,978
Canada
4,689
4,440
Barbados
583
535
The Bahamas
342
322
Dominica
-
78
$
22,996
$
20,353
24
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, 2022
Regulated Revenue
Residential
$
1,799
$
834
$
184
$
800
$
-
$
-
$
3,617
Commercial
869
427
282
461
-
-
2,039
Industrial
230
353
32
83
-
(7)
691
Other regulatory deferrals
371
28
12
-
-
-
411
Other (1)
18
33
8
283
-
(7)
335
Finance income (2)(3)
-
-
-
61
-
61
$
3,287
$
1,675
$
518
$
1,688
$
-
$
(14)
$
7,154
Non-Regulated Revenue
Marketing and trading margin (4)
-
-
-
-
143
-
143
Other non-regulated operating
revenue
-
-
-
16
16
(10)
22
Mark-to-market (3)
-
-
-
-
281
(12)
269
$
-
$
-
$
-
$
16
$
440
$
(22)
$
434
Total operating revenues
$
3,287
$
1,675
$
518
$
1,704
$
440
$
(36)
$
7,588
For the year ended December 31, 2021
Regulated Revenue
Residential
$
1,449
$
797
$
165
$
642
$
-
$
-
$
3,053
Commercial
754
407
232
379
-
-
1,772
Industrial
215
237
26
65
-
(2)
541
Other regulatory deferrals
289
27
7
-
-
-
323
Other (1)
17
33
15
122
-
(8)
179
Finance income (2)(3)
-
-
-
58
-
-
58
$
2,724
$
1,501
$
445
$
1,266
$
-
$
(10)
5,926
Non-Regulated
Marketing and trading margin (4)
-
-
-
-
102
-
102
Other non-regulated operating
revenue
-
-
-
14
30
(21)
23
Mark-to-market (3)
-
-
-
-
(289)
3
(286)
$
-
$
-
$
-
$
14
$
(157)
$
(18)
(161)
Total operating revenues
$
2,724
$
1,501
$
445
$
1,280
$
(157)
$
(28)
$
5,765
(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, 2022, the
aggregate amount of the transaction price allocated to remaining performance obligations was $
450
million (2021 – $
437
144
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
2042
.
25
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, the 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
2022
2021
Regulatory assets
Deferred income tax regulatory assets
$
1,166
$
1,045
Cost recovery clauses
707
114
Tampa Electric capital cost recovery for early retired assets
674
657
Pension and post-retirement medical plan
369
291
FAM
307
145
Storm reserve
103
-
NMGC winter event gas cost recovery
69
117
Storm restoration
35
35
Deferrals related to derivative instruments
30
23
Environmental remediations
27
27
Stranded cost recovery
27
26
Other
106
86
$
3,620
$
2,566
Current
$
602
$
253
Long-term
3,018
2,313
Total regulatory assets
$
3,620
$
2,566
Regulatory liabilities
Accumulated reserve - cost of remova
l
895
819
Deferred income tax regulatory liabilities
877
863
Deferrals related to derivative instruments
230
241
NMGC gas hedge settlements (note 18)
162
-
Cost recovery clauses
70
35
Self-insurance fund (note 32)
30
28
Storm reserve
-
58
Other
9
11
$
2,273
$
2,055
Current
$
495
$
290
Long-term
1,778
1,765
Total regulatory liabilities
$
2,273
$
2,055
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.
26
Cost Recovery Clauses
These assets and liabilities are related to Tampa Electric, PGS and NMGC clauses and riders. They are
recovered or refunded through cost-recovery mechanisms approved by the FPSC or New Mexico Public
Regulation Commission (“NMPRC”), as applicable, on a dollar-for-dollar basis in a subsequent period.
Tampa Electric Capital Cost Recovery for Early Retired Assets
This regulatory asset is related to the remaining net book value of Big Bend Power Station Units 1
through 3 and smart meter assets that were retired. The balance earns a rate of return as permitted by
the FPSC and will be recovered as a separate line item on customer bills for a period of
15 years
. This
recovery mechanism is authorized by and survives the term of the settlement agreement approved by the
FPSC in 2021. For further information, refer to “Big Bend Modernization Project” in the Tampa Electric
section below.
Pension and Post-Retirement Medical Plan
This asset is primarily related to the deferred costs of pension and post-retirement benefits at Tampa
Electric, PGS and NMGC. It is included in rate base and earns a rate of return as permitted by the FPSC
and NMPRC as applicable. It is amortized over the remaining service life of plan participants.
FAM
This regulated asset is the difference between actual fuel costs and amounts recovered from NSPI
customers through electricity rates in a given year and deferred to a FAM regulatory asset or liability and
recovered from or returned to customers in subsequent periods. For the years 2020 through 2022,
differences between actual fuel costs and fuel revenues recovered from customers will be recovered from
customers in future periods. The Nova Scotia Utility and Review Board’s (“UARB”) decision to approve
the fuel stability plan directed that any annual non-fuel revenues above NSPI’s approved range of ROE
are to be applied to the FAM.
Storm Reserve
The storm reserve is for hurricanes and other named storms that cause significant damage to Tampa
Electric and PGS systems. As allowed by the FPSC, if the charges to the storm reserve exceed the storm
liability, the excess is to be carried as a regulatory asset. Tampa Electric 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. In September 2022, Tampa Electric and PGS were impacted by Hurricane
Ian. For further information, refer to “Storm Reserve – Hurricane Ian” in both Tampa Electric and PGS
sections below.
NMGC Winter Event Gas Cost Recovery
In February 2021, the State of New Mexico experienced an extreme cold weather event that resulted in
an incremental $
108
NMGC normally recovers gas supply and related costs through a purchased gas adjustment clause
(“PGAC”). On April 16, 2021, NMGC filed a Motion for Extraordinary Relief, as permitted by the NMPRC
rules, to extend the terms of the repayment of the incremental gas costs and to recover a carrying charge.
On June 15, 2021, the NMPRC approved the recovery of $
108
over a period of 30 months beginning July 1, 2021.
Storm Restoration
This asset represents storm restoration costs incurred by GBPC. GBPC maintains insurance for its
generation facilities and, as with most utilities, its transmission and distribution networks are not covered
by commercial insurance.
27
In January 2020, the Grand Bahama Port Authority (“GBPA”) approved the recovery of $
15
of costs related to Hurricane Dorian in 2019, over a
five-year
through rates on January 1, 2021.
Restoration costs associated with Hurricane Matthew in 2016 are being recovered through an approved
fuel charge. For further information, refer to “Storm Restoration Costs – Hurricane Matthew” in the GBPC
section below.
Deferrals Related to Derivative Instruments
This asset is primarily related to NSPI deferring changes in fair value 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 its regulator. The realized gain or loss is recognized when the hedged item settles in
regulated fuel for generation and purchased power, inventory, other income, OM&G or PP&E, depending
on the nature of the item being economically hedged.
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 the decommissioning of a GBPC steam turbine in 2012, the GBPA approved the recovery of a $
21
million USD stranded cost through electricity rates; it is included in rate base and is expected to be
included in rates in future years.
Accumulated Reserve – Cost of Removal (“COR”)
This regulatory liability represents the non-ARO COR reserve in Tampa Electric, PGS, NMGC and NSPI.
AROs represent the fair value 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.
NMGC Gas Hedge Settlements
This regulatory liability represents the regulatory deferral of gas options exercised above strike price but
will settle in cash in Q1 2023. The value from the cash settlement of this options will flow through to
customers via the PGAC.
Regulatory Environments and Updates
Florida Electric Utility
Tampa Electric is regulated by the FPSC and is also subject to regulation by the Federal Energy
Regulatory Commission (“FERC”). The FPSC sets rates at a level that allows utilities such as Tampa
Electric 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 Tampa Electric, the FPSC or other interested parties.
28
Tampa Electric’s approved regulated return on equity (“ROE”) range for 2022 and 2021 was
9.25
to
11.25
54
10.20
(2021 -
10.25
Fuel Recovery and Other Cost Recovery Clauses:
Tampa Electric 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 the 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 January 23, 2023, Tampa Electric requested an adjustment to its fuel charges to recover the 2022 fuel
under-recovery of $
518
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
by the FPSC in March 2023, and recovery is expected to begin in April 2023.
The mid-course fuel adjustment requested by Tampa Electric on January 19, 2022, was approved on
March 1, 2022. The rate increase, effective with the first billing cycle in April 2022, covered higher fuel
and capacity costs of $
169
December 2022.
Base Rates:
On October 21, 2021, the FPSC approved a settlement agreement filed by Tampa Electric. The
settlement agreement allows for an increase to rates of $
191
2022. This increase consisted of $
123
68
the costs of retiring assets including, Big Bend coal generation assets Units 1 through 3 and meter
assets. The settlement agreement further includes two subsequent year adjustments of $
90
and $
21
future investments in the Big Bend Modernization project and solar generation. The allowed equity in the
capital structure will continue to be
54
agreement includes an allowed regulated ROE range of
9.0
11.0
9.95
midpoint. It also provides for a
25
10
million USD of additional revenue, if United States Treasury Bond yields exceed a specific threshold set
on the date the FPSC approved the agreement. Under the agreement base rates are frozen from January
1, 2022 to December 31, 2024, unless Tampa Electric’s earned ROE were to fall below the bottom of the
range during that time. The settlement agreement provides for the deferral of income taxes as a result of
changes in tax laws. The changes would be reflected as a regulatory asset or liability and either result in
an increase or a decrease in customer rates through a subsequent regulatory process. The settlement
agreement further creates a mechanism to recover the costs of retiring coal generation units and meter
assets over a period of
15 years
sets new depreciation and dismantlement rates effective January 1, 2022 and contains the provisions that
Tampa Electric will not have to file another depreciation study during the term of the agreement but will
file a new depreciation study no more than
one year
, nor less than
90 days
, before the filing of its next
general base rate proceeding. Tampa Electric agreed not to hedge natural gas through the period ending
on December 31, 2024.
On August 16, 2022, the FPSC approved Tampa Electric’s request to increase revenue and ROE due to
increases in the 30-year United States Treasury bond yield rate. Effective July 1, 2022, the new mid-point
ROE is
10.20
9.25
11.25
29
Storm Reserve – Hurricane Ian:
In September 2022, Tampa Electric was impacted by Hurricane Ian. Total restoration costs were $
126
million USD, with $
119
storm reserve. Total restoration costs charged to the storm reserve have exceeded the reserve balance
and have been deferred as a regulatory asset for future recovery. On January 23, 2023, Tampa Electric
petitioned the FPSC for recovery of the storm reserve regulatory asset and the replenishment of the
balance in the reserve to the previous approved reserve level of $
56
approximately $
131
recovery is expected to begin in April 2023 through March 2024.
Solar Base Rate Adjustments Included in Base Rates:
During 2017 to 2021, Tampa Electric invested $
850
600
photovoltaic projects, which is recoverable through FPSC-approved solar base rate adjustments
(“SoBRAs”). AFUDC was earned on these projects during construction. The FPSC has approved SoBRAs
representing a total of
600
104
service projects.
On October 12, 2021, the FPSC approved the true-up filing for SoBRA tranche 3, included in base rates
as of January 2020. A $
4
SoBRA tranche 4 was required.
Storm Protection Cost Recovery Clause and Settlement Agreement:
On October 3, 2019, the FPSC issued a rule to implement a Storm Protection Plan (“SPP”) Cost
Recovery Clause. This clause provides a process for Florida investor-owned utilities, including Tampa
Electric, 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. A settlement agreement was approved on August 10, 2020,
and Tampa Electric’s cost recovery began in January 2021. The current approved plan addressed the
years 2020 through 2022, and in April 2022 Tampa Electric submitted a new plan to determine cost
recovery in 2023, 2024 and 2025. On October 4, 2022, the FPSC approved Tampa Electric’s SPP.
Big Bend Modernization Project:
Tampa Electric invested $
876
91
2022 to modernize the Big Bend Power Station. The modernization project repowered Big Bend Unit 1
with natural gas combined-cycle technology and eliminated coal as this unit’s fuel. As part of the
modernization project, Tampa Electric retired the Unit 1 components that will not be used in the
modernized plant in 2020 and Big Bend Unit 2 in 2021. Tampa Electric plans to retire Big Bend Unit 3 in
2023 as it is in the best interest of the customers from an economic, environmental risk and operational
perspective.
At December 31, 2021, the balance sheet included $
636
267
million USD in accumulated depreciation related to Unit 1 components and Unit 2 and Unit 3 assets. In
accordance with Tampa Electric’s 2017 settlement agreement approved by the FPSC, Tampa Electric
continued to account for its existing investment in Unit 1, 2 and 3 in electric utility plant and depreciated
the assets using the current depreciation rates until December 31, 2021, at which point they were
reclassified to a regulatory asset on the balance sheet.
30
Tampa Electric’s 2021 settlement agreement provides recovery for the Big Bend Modernization project in
two phases. The first phase was a revenue increase to cover the costs of the assets in service during
2022, among other items. The remainder of the project costs will be recovered as part of the 2023
subsequent year adjustment. The settlement agreement also includes a new charge to recover the
remaining costs of the retiring Big Bend coal generation assets, Units 1 through 3, which will be spread
over
15 years
schedule for all three units was applied beginning January 1, 2022. This recovery mechanism is
authorized by and survives the term of the settlement agreement approved by the FPSC in 2021.
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 2022 and 2021 was
8.75
9.25
quarter average regulated common equity component of up to
40
NSPI has a FAM, approved by the UARB, allowing NSPI to recover fluctuating fuel 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.
For the period of 2020 through 2022, NSPI operated under a
three-year
in an average annual overall rate increase of
1.5
recovery of Maritime Link costs.
General Rate Application (“GRA”):
On November 9, 2022, the Nova Scotia provincial government enacted Bill 212, “Public Utilities Act
(amended)”. The legislation limits non-fuel rate increases in NSPI’s 2022 GRA to the UARB, excluding
increases relating to demand side management (“DSM”) costs, to a total of
1.8
effective date of the UARB’s decision and the end of 2024. The legislation also:
●
requires revenue generated from the non-fuel rate increase to be used only to improve the
reliability of service to ratepayers,
●
limits NSPI’s return on equity to
9.25
40
●
limits the rate used to accrue interest on regulatory deferrals to the Bank of Canada policy
interest rate plus
1.75
31
On November 24, 2022, NSPI filed with the UARB a comprehensive settlement agreement between
NSPI, key customer representatives and participating interest groups (“NSPI Settlement Agreement”) in
relation to its GRA filed in January 2022. The NSPI Settlement Agreement was structured to be
consistent with the amendments to the Public Utilities Act made under Bill 212, including the
1.8
cap on non-fuel rate increases for 2023 and 2024. The NSPI Settlement Agreement also addresses the
recovery of fuel costs over the settlement period and establishes a DSM rider. This will result in a
combined fuel and non-fuel rate increase of
6.9
incremental revenue (fuel and non-fuel) of $
105
115
under or over recovery of fuel costs will be addressed through the UARB’s established FAM process.
NSPI’s ROE range will continue to be
8.75
9.25
average regulated common equity component of up to
40
establishes a storm rider for each of 2023, 2024 and 2025, which gives NSPI the option to apply to the
UARB for recovery of costs if major storm restoration expense exceeds approximately $
10
given year. On February 2, 2023, NSPI received the UARB’s decision, which substantially approved the
Settlement Agreement as filed. Approved rate increases will be effective as of the date of the decision.
Maritime Link:
The Maritime Link is a $
1.8
two
170
-kilometre
sub-sea cables, connecting the island of Newfoundland and Nova Scotia. The Maritime Link entered
service on January 15, 2018 and NSPI started interim assessment payments to NSPML at that time.
As part of a
three-year
164
$
162
stability plan and those approved by the UARB through the NSPML interim assessment application will be
addressed through the FAM.
Nova Scotia Cap-and-Trade (“Cap-and-Trade”) Program:
As at December 31, 2022, the FAM includes a recovery of $
172
38
million) non-cash accrual representing the estimated future cost of acquiring emissions credits for the
2019 through 2022 Cap-and-Trade compliance period. Emissions for the compliance period will not be
finalized until the completion of the environmental audit which begins in March 2023. Emissions are
currently based upon audited actual emissions from 2019 through 2021 and unaudited actuals for 2022.
The total cost of compliance with the Cap-and-Trade program compliance period could change
depending on the price paid for both credits at remaining provincial auctions and reserve credits
purchased from the provincial government, and the results of the 2022 environmental emissions audit.
Lower than forecast Muskrat Falls energy received during the compliance period has resulted in the
increased deployment of higher carbon-emitting generation sources. The Province of Nova Scotia has
agreed to provide approximately $
165
which was equal to the total cost of compliance forecast at the time of the fuel update submitted by NSPI
to the UARB in September 2022 as part of the GRA. Discussions related to the final amount of relief and
how this relief will be provided are ongoing. Further, NSPI’s regulatory framework provides for the
recovery of costs prudently incurred to comply with the Cap-and-Trade Program Regulations pursuant to
NSPI’s FAM.
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
9.25
based on an actual five-quarter average regulated common equity component of up to
30
Nalcor’s Nova Scotia Block (“NS Block”) delivery obligations commenced on August 15, 2021 and
delivery will continue over the next
35 years
32
In February 2022, the UARB issued its decision and Board Order approving NSPML’s requested rate
base of approximately $
1.8
9
7
otherwise been recoverable if incurred by NSPI. NSPML also received approval to collect up to $
168
million (2021 – $
172
2022. This was subject to a holdback of up to $
2
receiving at least
90
In December 2022, NSPML received UARB approval to collect up to $
164
recovery of costs associated with the Maritime Link in 2023. This continues to be subject to a holdback of
up to $
2
direction regarding the holdback and NSPI can now release the holdback to NSPML when
90
NS Block deliveries, including Supplemental Energy deliveries, is achieved. This enabled NSPI to pay
NSPML approximately $
4
14
million in aggregate has been held-back by NSPI. Determination of the allocation of the $
14
between NSPML and NSPI will be subject to a regulatory process that is expected to commence in early
2023 to review the holdback mechanism.
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 2022 and 2021 was
8.9
11.0
9.9
midpoint, based on an allowed equity capital structure of
54.7
Fuel Recovery:
PGS recovers the costs it pays for gas supply and interstate transportation for system supply through its
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.
Storm Reserve – Hurricane Ian:
In September 2022, Hurricane Ian impacted PGS’s operations in Fort Myers and Sarasota. The
restoration costs were approximately $
2
1
approved storm reserve.
33
Base Rates:
On November 19, 2020, the FPSC approved a settlement agreement filed by PGS.
agreement allows for an increase to base rates by $
58
which is a $
34
24
recovered through the cast iron and bare steel replacement rider. It provides PGS the ability to reverse a
total of $
34
14
million USD of the $
34
In addition, the agreement sets new depreciation rates effective January 1, 2021. Under the agreement
base rates are frozen from January 1, 2021 to December 31, 2023, unless its earned ROE were to fall
below
8.9
54.7
investor sources of capital. The settlement agreement provides for the deferral of income taxes as a
result of changes in tax laws. The changes would be reflected as a regulatory asset or liability and either
result in an increase or a decrease in customer rates through a subsequent regulatory process.
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 2022 and 2021 was
9.375
52
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
the 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. In December 2020, NMGC received
approval of its PGAC Continuation Filing for the four-year period ending December 2024.
Base Rates:
On December 13, 2021, NMGC filed a rate case with the NMPRC for new rates to become effective
January 2023. On May 20, 2022, NMGC filed an unopposed settlement agreement with the NMPRC for
an increase of $
19
operating costs and capital investments in pipelines and related infrastructure. The NMPRC approved the
settlement agreement on November 30, 2022.
Weather Normalization Mechanism:
In July 2019, the NMPRC approved changes to the company’s rate design to include a five-year pilot of
Weather Normalization Mechanism. This clause is designed to lower the variability of weather impacts
during the October through April heating seasons. The Weather Normalization Mechanism allows
customer rates and company revenue to be more predictable by partially removing the impact of warmer
than usual or colder than usual weather. Weather-related revenue increases or decreases experienced
from October to April are adjusted annually in October of the following heating season.
34
Integrity Management Programs (“IMP”) Regulatory Asset:
A portion of NMGC’s annual spending on infrastructure is for IMP, or the replacement and update of
legacy systems. These programs are driven both by NMGC integrity management plans and federal and
state mandates. In December 2020, NMGC received approval through its rate case to defer costs through
an IMP regulatory asset for certain of its IMP capital investments occurring between January 1, 2022 and
December 31, 2023 and petitioned recovery of the regulatory asset in its rate case filed on December 13,
2021. On November 30, 2022, the NMPRC issued a Final Order that included approval of recovery of the
IMP regulatory asset.
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 United States. Brunswick
Pipeline entered into a
25
-year firm service agreement commencing in July 2009 with Repsol Energy
North America Canada Partnership. 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”), an independent regulator, 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
Licenses:
The Government of Barbados has granted BLPC a franchise to generate, transmit and distribute
electricity on the island until 2028. In 2019, the Government of Barbados passed legislation amending the
number of licenses required for the supply of electricity from a single integrated license which currently
exists to multiple licenses for Generation, Transmission and Distribution, Storage, Dispatch and Sales. In
March 2021, BLPC reached commercial agreement with the Government of Barbados for each of the
license types, subject to the passage of implementing legislation. The new licenses are expected to take
effect in 2023 on completion of the legislative process. The Dispatch license will have a term of
5 years
with the remaining licenses having terms ranging from
25
-
30 years
. BLPC anticipates that any increased
costs associated with the implementation of the new multi-licensed structure will be recoverable through
BLPC’s regulatory framework. BLPC is awaiting final enactment and will work towards implementation of
the licenses once received.
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.
35
On October 4, 2021 BLPC submitted a general rate review application to the FTC. The application seeks
a rate adjustment and the implementation of a cost reflective rate structure that will facilitate the changes
expected in the newly reformed electricity market and the country’s transition towards 100 per cent
renewable energy generation. The application seeks recovery of capital investment in plant, equipment
and related infrastructure and results in an increase in annual non-fuel revenue of approximately $
23
million USD upon approval. The application includes a request for allowed regulatory ROE of
12.50
cent on an allowed equity capital structure of
65
BLPC interim rate relief, allowing an increase in base rates of approximately $
3
remainder of 2022 and approximately $
1
from September 16, 2022 until the implementation of final rates. The hearing concluded in October 2022.
On February 15, 2023, the FTC issued a decision on the BLPC rate review application which included the
following significant items: an allowed regulatory ROE of
11.75
55
per cent, a directive to update the major components of rate base to September 16, 2022, and a directive
to establish regulatory liabilities of approximately $
70
accumulated depreciation, and taxes. The impacts to BLPC's rate base and final rates are not yet
determinable. BLPC will seek to clarify aspects of the FTC decision in its compliance filing and is also
considering filing a submission to the FTC for a review of the decision. BLPC expects a decision on final
rates from the FTC in 2023.
Fuel Hedging:
On October 21, 2021, the FTC approved BLPC’s application to implement a fuel hedging program which
will be incorporated into the calculation of the fuel clause adjustment. On November 10, 2021, BLPC
requested the FTC review the required
50
/50 cost sharing arrangement between BLPC and customers in
relation to the hedging administrative costs, or any gains and losses associated with the hedging
program. A decision is expected from the FTC in 2023.
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
8.23
8.37
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.
Effective November 1, 2022, GBPC’s fuel pass through charge was increased due to an increase in
global oil prices impacting the unhedged fuel cost. In 2023, the fuel pass through charge will be adjusted
monthly, in-line with actual fuel costs.
Base Rates:
There is a fuel pass-through mechanism and tariff review policy with new rates submitted every three
years. On January 14, 2022, the GBPA issued its decision on GBPC’s application for rate review that was
filed with the GBPA on September 23, 2021. The decision, which became effective April 1, 2022, allows
for an increase in revenues of $
3.5
12.84
cent.
36
Storm Restoration Costs – Hurricane Matthew:
In 2017, as part of the recovery of costs incurred as a result of Hurricane Matthew, the GBPA approved a
fixed per kWh fuel charge and allowed the difference between this and the actual cost of fuel to be
applied to the Hurricane Matthew regulatory asset. As part of its decision on GBPC’s application for rate
review, issued January 14, 2022, and effective April 1, 2022, the GBPA approved the continued
amortization of the remaining regulatory asset over the three year period ending December 31, 2024.
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
2022
2021
2022
2021
2022
LIL
(1)
$
740
$
682
$
58
$
54
31.9
NSPML
501
533
29
49
100.0
M&NP
128
123
21
20
12.9
Lucelec
(2)
49
44
4
4
19.5
Bear Swamp
-
-
17
16
50.0
$
1,418
$
1,382
$
129
$
143
(1) Emera indirectly owns
100
24.5
ownership in LIL is subject to change, based on the balance of capital investments required from Emera and Nalcor Energy to
complete construction of the LIL. Emera’s ultimate percentage investment in LIL will be determined upon final costing of
all transmission projects related to the Muskrat Falls development, including the LIL, Labrador Transmission Assets and Maritime
Link Projects, such that Emera’s total investment in the Maritime Link and LIL will equal
49
transmission developments.
(2) Although Emera’s ownership percentage of these entities is relatively low, it is considered to have significant influence over the
operating and financial decisions of these companies through Board representation. Therefore, Emera records its investment in
these entities using the equity method.
(3) The investment balance in Bear Swamp is in a credit position primarily as a result of a $
179
Bear Swamp's credit investment balance of $
95
104
Consolidated Balance Sheets.
Equity investments include a $
9
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 32).
NSPML's consolidated summarized balance sheets are illustrated as follows:
As at
December 31
millions of dollars
2022
2021
Balance Sheets
Current assets
$
17
$
25
PP&E
1,517
1,587
Regulatory assets
265
247
Non-current assets
29
31
Total assets
$
1,828
$
1,890
Current liabilities
$
48
$
50
Long-term debt
(1)
1,149
1,189
Non-current liabilities
130
118
Equity
501
533
Total liabilities and equity
$
1,828
$
1,890
(1) The project debt has been guaranteed by the Government of Canada.
37
9. OTHER INCOME, NET
For the
Year ended December 31
millions of dollars
2022
2021
TECO Guatemala Holdings award
(1)
$
63
$
-
AFUDC
52
61
Other
30
32
$
145
$
93
(1) Refer to note 27 for further detail related to the TECO Guatemala Holdings award.
10. 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
2022
2021
Income before provision for income taxes
$
1,194
$
555
Statutory income tax rate
29.0%
29.0%
Income taxes, at statutory income tax rate
346
161
Deferred income taxes on regulated income recorded as regulatory assets and
regulatory liabilities
(70)
(62)
Foreign tax rate variance
(44)
(42)
Amortization of deferred income tax regulatory liabilities
(33)
(33)
GBPC impairment charge
21
-
Tax effect of equity earnings
(10)
(16)
Tax credits
(18)
(13)
Other
(7)
(1)
Income tax expense (recovery)
$
185
$
(6)
Effective income tax rate
15%
(1%)
On August 16, 2022, the United States Inflation Reduction Act (“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. During 2022, the Company
recorded a $
9
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
2022
2021
Current income taxes
$
25
$
20
8
11
Deferred income taxes
120
(33)
252
118
-
2
Investment tax credits
(7)
(11)
Operating loss carryforwards
(92)
(64)
(121)
(49)
Income tax expense (recovery)
$
185
$
(6)
38
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
2022
2021
Canada
$
173
$
244
United States
1,063
289
Other
(42)
22
Income before provision for income taxes
$
1,194
$
555
The deferred income tax assets and liabilities presented in the Consolidated Balance Sheets as at
December 31 consisted of the following:
millions of dollars
2022
2021
Deferred income tax assets:
Tax loss carryforwards
$
1,207
$
873
Tax credit carryforwards
415
375
Regulatory liabilities - cost of removal
177
170
Derivative instruments
45
188
Other
428
434
Total deferred income tax assets before valuation allowance
2,272
2,040
Valuation allowance
(312)
(256)
Total deferred income tax assets after valuation allowance
$
1,960
$
1,784
Deferred income tax (liabilities):
PP&E
$
(2,981)
$
(2,622)
Regulatory assets
(219)
(78)
Derivative instruments
(125)
(197)
Other
(594)
(460)
Total deferred income tax liabilities
$
(3,919)
$
(3,357)
Consolidated Balance Sheets presentation:
Long-term deferred income tax assets
$
237
$
295
Long-term deferred income tax liabilities
(2,196)
(1,868)
Net deferred income tax liabilities
$
(1,959)
$
(1,573)
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 $
312
256
related to the loss carryforwards, long-term debt and investments.
The Company intends to indefinitely reinvest earnings from certain foreign operations. Accordingly, as at
December 31, 2022, $
3.8
2.9
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.
39
Emera’s NOL, capital loss and tax credit carryforwards and their expiration periods as at December 31,
2022 consisted of the following:
Subject to
Tax
Valuation
Net Tax
Expiration
millions of dollars
Carryforwards
Allowance
Carryforwards
Period
Canada
$
2,372
$
(977)
$
1,395
2026 - 2042
79
(79)
-
Indefinite
United States
$
2,082
$
-
$
2,082
2032 - Indefinite
1,489
-
1,489
2032 - Indefinite
415
-
415
2025 - 2042
Other
$
73
$
(33)
$
40
2023 - 2029
The following table provides details of the change in unrecognized tax benefits for the years ended
December 31 as follows:
millions of dollars
2022
2021
Balance, January 1
$
28
$
30
Increases due to tax positions related to current year
5
4
Increases due to tax positions related to a prior year
2
1
Decreases due to tax positions related to a prior year
(2)
(1)
Decreases due to settlement with tax authorities
-
(6)
Balance, December 31
$
33
$
28
The total amount of unrecognized tax benefits as at December 31, 2022 was $
33
28
million), which would affect the effective tax rate if recognized. The total amount of accrued interest with
respect to unrecognized tax benefits was $
7
6
1
recognized in the Consolidated Statements of Income (2021 –
nil
).
No
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.
During 2022, the CRA issued notices of reassessment to NSPI for the 2013 through 2016 taxation years.
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
62
55
– $
23
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.
40
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,
2022, the Company’s tax years still open to examination by taxing authorities include 2005 and
subsequent years.
11. COMMON STOCK
Authorized
: Unlimited number of non-par value common shares.
2022
2021
Issued and outstanding:
millions
of shares
dollars
millions of
shares
dollars
Balance, December 31, 2021
261.07
$
7,242
251.43
$
6,705
Issuance of common stock under ATM program
(1)(2)
4.07
248
4.99
284
Issued under the DRIP, net of discounts
4.21
238
3.90
215
Senior management stock options exercised and Employee Share
Purchase Plan
0.60
34
0.75
38
Balance, December 31, 2022
269.95
$
7,762
261.07
$
7,242
(1) As at December 31, 2021, a total of
4,987,123
$
57.63
287
284
(2) For the year ended December 31, 2022,
4,072,469
of $
61.31
250
248
On August 12, 2021, Emera renewed its ATM Program that allows the Company to issue up to $
600
million of common shares from treasury to the public from time to time, at the Company's discretion, at
the prevailing market price. The ATM Program was renewed pursuant to a prospectus supplement to the
Company's short form base shelf prospectus dated August 5, 2021. The ATM program is expected to
remain in effect until September 5, 2023. As at December 31, 2022, an aggregate gross sales limit of
$
207
As at December 31, 2022, the following common shares were reserved for issuance:
6
6.2
million) under the senior management stock option plan,
2.7
3.1
employee common share purchase plan and
10
14.2
The issuance of common shares under the common share compensation arrangements does not allow
the plans to exceed
10
Emera is in compliance with this requirement.
12. 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.
41
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)
2022
2021
Numerator
Net income attributable to common shareholders
$
945.1
$
510.5
Diluted numerator
945.1
510.5
Denominator
Weighted average shares of common stock outstanding
265.5
255.9
Weighted average deferred share units outstanding
-
1.3
Weighted average shares of common stock outstanding – basic
265.5
257.2
Stock-based compensation
0.4
0.4
Weighted average shares of common stock outstanding – diluted
265.9
Earnings per common share
Basic
$
3.56
$
1.98
Diluted
$
3.55
$
1.98
(1) Effective February 10, 2022, deferred share units are no longer able to be settled in shares and are therefore no longer included
in the calculation of earnings per common share.
13. 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 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, 2022
Balance, January 1, 2022
$
10
$
35
$
18
$
(1)
$
(37)
$
25
629
(97)
-
(1)
-
531
-
-
(2)
-
24
22
Net current period other
comprehensive income (loss)
629
(97)
(2)
(1)
24
553
Balance, December 31, 2022
$
639
$
(62)
$
16
$
(2)
$
(13)
$
578
For the year ended December 31, 2021
Balance, January 1, 2021
$
52
$
30
$
1
$
(1)
$
(161)
$
(79)
(42)
5
18
-
-
(19)
-
-
(1)
-
124
123
Net current period other
comprehensive income (loss)
(42)
5
17
-
124
104
Balance, December 31, 2021
$
10
$
35
$
18
$
(1)
$
(37)
$
25
42
The reclassifications out of accumulated other comprehensive income (loss) are as follows:
For the
Year ended December 31
millions of dollars
2022
2021
Affected line item in the Consolidated Financial Statements
Gains on derivatives recognized as cash flow hedges
Interest expense, net
$
(2)
$
(1)
Net change in unrecognized pension and post-retirement benefit costs
Other income, net
$
10
$
24
Pension and post-retirement benefits
15
102
Total before tax
25
126
Income tax expense
(1)
(2)
Total net of tax
$
24
$
124
Total reclassifications out of AOCI, net of tax, for the period
$
22
$
123
14. INVENTORY
As at
December 31
December 31
millions of dollars
2022
2021
Fuel
$
404
$
255
Materials
365
283
Total
$
769
$
538
15. 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
2022
2021
2022
2021
Regulatory deferral:
$
186
$
146
$
42
$
16
18
7
1
8
52
88
-
-
256
241
43
24
HFT derivatives:
89
33
77
32
340
208
1,224
818
429
241
1,301
850
Other derivatives:
-
11
5
-
5
-
23
-
5
11
28
-
Total gross current derivatives
690
493
1,372
874
Impact of master netting agreements:
(18)
(4)
(18)
(4)
(276)
(188)
(276)
(188)
Total impact of master netting agreements
(294)
(192)
(294)
(192)
Total derivatives
$
396
$
301
$
1,078
$
682
Current
(1)
296
195
888
533
Long-term
(1)
100
106
190
149
Total derivatives
$
396
$
301
$
1,078
$
682
(1) Derivative assets and liabilities are classified as current or long-term based upon the maturities of the underlying contracts.
43
Cash Flow Hedges
On May 26, 2021, the treasury lock was settled for a gain of $
19
interest expense over
10 years
unrealized gain in AOCI was $
16
18
December 31, 2022, unrealized gains of $
2
1
into interest expense. The Company expects $
2
reclassified into net income within the next twelve months
.
Regulatory Deferral
The Company has recorded the following changes in realized and unrealized gains (losses) with respect
to derivatives receiving regulatory deferral:
Physical
Commodity
Physical
Commodity
natural gas
swaps and
FX
natural gas
swaps and
FX
millions of dollars
purchases
forwards
forwards
purchases
forwards
forwards
For the year ended December 31
2022
2021
Unrealized gain (loss) in regulatory
assets
$
-
$
(69)
$
1
$
-
$
(7)
$
9
Unrealized gain (loss) in regulatory
liabilities
28
343
16
88
218
(3)
Realized loss in regulatory assets
-
48
-
-
-
-
Realized gain in regulatory liabilities
-
(41)
-
-
(3)
-
Realized (gain) loss in inventory
(1)
-
(121)
1
-
(8)
5
Realized (gain) loss in regulated fuel
for generation and purchased power
(2)
(64)
(146)
-
-
(39)
5
Total change in derivative instruments
$
(36)
$
14
$
18
$
88
$
161
$
16
(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, 2022, the Company had the following notional volumes designated for regulatory
deferral that are expected to settle as outlined below:
millions
2023
2024-2026
Physical natural gas purchases:
Natural gas (Mmbtu)
6
-
Commodity swaps and forwards purchases:
Natural gas (Mmbtu)
18
12
Power (MWh)
1
1
FX swaps and forwards:
FX contracts (millions of USD)
$
206
$
123
Weighted average rate
1.2832
1.3064
% of USD requirements
50%
28%
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
2022
2021
Power swaps and physical contracts in non-regulated operating revenues
$
17
$
4
Natural gas swaps, forwards, futures and physical contracts in non-regulated
operating revenues
47
(142)
Total gains (losses) in net income
$
64
$
(138)
44
As at December 31, 2022, the Company had the following notional volumes of outstanding HFT
derivatives that are expected to settle as outlined below:
2027 and
millions
2023
2024
2025
2026
thereafter
Natural gas purchases (Mmbtu)
319
92
42
36
131
Natural gas sales (Mmbtu)
492
205
105
6
19
Power purchases (MWh)
2
-
-
-
-
Power sales (MWh)
2
-
-
-
-
Other Derivatives
As at December 31, 2022, the Company had equity derivatives in place to manage the 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
2.8
combined notional amount of $
448
The Company has recognized the following realized and unrealized gains (losses) with respect to other
derivatives:
For the
Year ended December 31
millions of dollars
2022
2021
FX
Equity
FX
Equity
Forwards
Derivatives
Forwards
Derivatives
Unrealized gain (loss) in OM&G
$
-
$
(5)
$
-
$
11
Unrealized loss in other income, net
(18)
-
(15)
-
Realized gain (loss) in OM&G
-
(17)
-
15
Realized gain (loss) in other income, net
(6)
-
18
-
Total gains (losses) in net income
$
(24)
$
(22)
$
3
$
26
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, 2022, the maximum exposure the Company had to credit risk was $
1.9
– $
1.3
derivatives.
45
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, 2022 was $
386
341
mitigates 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.
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, 2022, the Company had $
131
114
considered to be past due, which have been outstanding for an average
60
financial assets is $
114
93
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, 2022
December 31, 2021
millions of
dollars
% of total
exposure
millions of
dollars
% of total
exposure
Receivables, net
Regulated utilities:
Residential
$
455
19%
$
384
24%
Commercial
192
8%
167
10%
Industrial
121
5%
54
3%
Other
122
5%
91
6%
890
37%
696
43%
Trading group:
Credit rating of A- or above
125
5%
66
4%
Credit rating of BBB- to BBB+
75
3%
107
7%
Not rated
307
13%
132
8%
507
21%
305
19%
Other accounts receivable
585
25%
329
20%
1,982
83%
1,330
82%
Derivative Instruments
(current and long-term)
Credit rating of A- or above
202
9%
155
9%
Credit rating of BBB- to BBB+
8
0%
22
1%
Not rated
186
8%
124
8%
396
17%
301
18%
$
2,378
100%
$
1,631
100%
46
Cash Collateral
The Company’s cash collateral positions consisted of the following:
As at
December 31
December 31
millions of dollars
2022
2021
Cash collateral provided to others
$
224
$
212
Cash collateral received from others
$
112
$
100
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, 2022, the total fair value of derivatives in a liability position was $
1,078
(December 31, 2021
–
682
grade, the full value of the net liability position could be required to be posted as collateral for these
derivatives.
16. FAIR VALUE MEASUREMENTS
The Company is required to determine the fair value 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 fair value
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:
●
seasonal or monthly shaping and locational basis differentials.
●
accordingly, assumptions were made to extrapolate prices from the last quoted period through the
end of the transaction term.
●
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 fair value measurement.
47
The following tables set out the classification of the methodology used by the Company to fair value its
derivatives
As at
December 31, 2022
millions of dollars
Level 1
Level 2
Level 3
Total
Assets
Regulatory deferral:
$
120
$
48
$
-
$
168
-
18
-
18
-
-
52
52
120
66
52
238
HFT derivatives:
9
31
4
44
3
72
34
109
12
103
38
153
Other derivatives:
-
5
-
5
Total assets
132
174
90
396
Liabilities
Regulatory deferral:
15
9
-
24
-
1
-
1
15
10
-
25
HFT derivatives:
2
28
1
31
51
118
825
994
53
146
826
1,025
Other derivatives:
-
23
-
23
5
-
-
5
5
23
-
28
Total liabilities
73
179
826
1,078
Net assets (liabilities)
$
59
$
(5)
$
(736)
$
(682)
48
As at
December 31, 2021
millions of dollars
Level 1
Level 2
Level 3
Total
Assets
Regulatory deferral:
$
101
$
41
$
-
$
142
-
7
-
7
-
-
88
88
101
48
88
237
HFT derivatives:
4
5
4
13
(1)
29
12
40
3
34
16
53
Other derivatives:
11
-
-
11
Total assets
115
82
104
301
Liabilities
Regulatory deferral:
7
5
-
12
-
8
-
8
7
13
-
20
HFT derivatives:
4
5
3
12
13
122
515
650
17
127
518
662
Total liabilities
24
140
518
682
Net assets (liabilities)
$
91
$
(58)
$
(414)
$
(381)
The change in the fair value of the Level 3 financial assets for the year ended December 31, 2022 was as
follows:
Regulatory Deferral
HFT Derivatives
Physical natural
Natural
millions of dollars
gas purchases
Power
gas
Total
Balance, January 1, 2022
$
88
$
4
$
12
$
104
Realized gains included in fuel for generation and
purchased power
(64)
-
-
(64)
Unrealized gains included in regulatory liabilities
28
-
-
28
Total realized and unrealized gains included in non-
regulated operating revenues
-
-
22
22
Balance, December 31, 2022
$
52
$
4
$
34
$
90
The change in the fair value of the Level 3 financial liabilities for the year ended December 31, 2022 was
as follows:
Natural
millions of dollars
Power
gas
Total
Balance, January 1, 2022
$
3
$
515
$
518
Total realized and unrealized gains (losses) included
in non-regulated operating revenues
(2)
310
308
Balance, December 31, 2022
$
1
$
825
$
826
49
Significant unobservable inputs used in the fair value 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) fair
value 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.
The Company uses a modelled pricing valuation technique for determining the fair value of Level 3
derivative instruments. The following table outlines quantitative information about the significant
unobservable inputs used in the fair value measurements categorized within Level 3 of the fair value
hierarchy:
December 31, 2022
As at
Significant
Weighted
millions of dollars
Fair Value
Unobservable Input
Low
High
average
(1)
Assets
Liabilities
Regulatory deferral –
Physical
$
52
$
-
Third-party pricing
$5.79
$31.85
$12.27
natural gas purchases
HFT derivatives – Power
4
1
Third-party pricing
$43.24
$269.10
$138.79
swaps and physical contracts
HFT derivatives – Natural
34
825
Third-party pricing
$2.45
$33.88
$12.01
gas swaps, futures, forwards
and physical contracts
Total
$
90
$
826
Net liability
$
736
(1) Unobservable inputs were weighted by the relative fair value of the instruments.
December 31, 2021
As at
Significant
Weighted
millions of dollars
Fair Value
Unobservable Input
Low
High
average
(1)
Assets
Liabilities
Regulatory deferral –
Physical
$
88
$
-
Third-party pricing
$4.51
$26.09
$9.74
natural gas purchases
HFT derivatives – Power
4
3
Third-party pricing
$37.05
$213.00
$99.34
swaps and physical contracts
HFT derivatives – Natural
12
515
Third-party pricing
$1.90
$21.53
$8.80
gas swaps, futures, forwards
and physical contracts
Total
$
104
$
518
Net liability
$
414
(1) Unobservable inputs were weighted by the relative fair value of the instruments.
Long-term debt is a financial liability not measured at fair value on the Consolidated Balance Sheets. The
balance consisted of the following:
As at
Carrying
millions of dollars
Amount
Fair Value
Level 1
Level 2
Level 3
Total
December 31, 2022
$
16,318
$
14,670
$
-
$
14,284
$
386
$
14,670
December 31, 2021
$
14,658
$
16,775
$
-
$
16,308
$
467
$
16,775
50
The Company has designated $
1.2
currency exposure of its ne
t investment
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, 2022, the fair value of the Hybrid
Notes was $
1.1
1.7
97
in AOCI for the year ended December 31, 2022 (2021 – $
5
17. 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:
●
Consolidated Statements of Income. NSPI’s expense is reported in Regulated fuel for generation and
purchased power, totalling $
157
149
NSPML is accounted for as an equity investment and therefore, the corresponding earnings related to
this revenue are reflected in Income from equity investments.
●
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 $
9
– $
19
There were no significant receivables or payables between Emera and its associated companies reported
on Emera’s Consolidated Balance Sheets as at December 31, 2022 and at December 31, 2021.
18. RECEIVABLES AND OTHER CURRENT ASSETS
As at
December 31
December 31
millions of dollars
2022
2021
Customer accounts receivable – billed
$
1,096
$
767
Customer accounts receivable – unbilled
424
318
Allowance for credit losses
(17)
(21)
Capitalized transportation capacity
(1)
781
316
NMGC gas hedge settlement receivable
(2)
162
-
Income tax receivable
9
8
Prepaid expenses
82
65
Other
360
280
Total receivables and other current assets
$
2,897
$
1,733
(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.
(2) Related amount is included in regulatory liabilities for NMGC as gas hedges are part of the PGAC. Refer to note 7.
51
19. 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 63 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 that they will be exercised.
As at
December 31
December 31
millions of dollars
Classification
2022
2021
Right-of-use asset
Other long-term assets
$
58
$
58
Lease liabilities
Other current liabilities
3
3
Other long-term liabilities
59
58
Total lease liabilities
$
62
$
61
The Company has recorded lease expense of $
138
– $
150
131
142
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
2023
2024
2025
2026
2027
Thereafter
Total
Minimum lease payments
$
6
$
6
$
5
$
3
$
3
$
116
$
139
Less imputed interest
(77)
Total
$
62
Additional information related to Emera's leases is as follows:
Year ended December 31
For the
2022
2021
Cash paid for amounts included in the measurement of lease liabilities:
$
8
$
7
Right-of-use assets obtained in exchange for lease obligations:
$
1
$
-
Weighted average remaining lease term (years)
44
44
Weighted average discount rate- operating leases
3.98%
3.98%
Lessor
The Company’s net investment in direct finance and sales-type leases primarily relates to Brunswick
Pipeline, Seacoast, compressed natural gas (“CNG”) stations 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.
52
Commencing in January 2022, the Company leased a Seacoast pipeline, a 21-mile, 30-inch lateral that is
classified as a sales-type lease. The term of the pipeline lateral lease is
34
$
100
16
These renewal options have not been included as part of the pipeline lateral lease term as it is not
reasonably certain that they will be exercised.
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
2022
2021
Total minimum lease payment to be received
$
1,393
$
947
Less: amounts representing estimated executory costs
(205)
(165)
Minimum lease payments receivable
$
1,188
$
782
Estimated residual value of leased property (unguaranteed)
183
183
Less: unearned finance lease income
(733)
(443)
Net investment in direct finance and sales-type leases
$
638
$
522
Principal due within one year (included in "Receivables and other
current assets")
34
19
Net Investment in direct finance and sales type leases - long-term
$
604
$
503
As at December 31, 2022, future minimum lease payments to be received for each of the next five years
and in aggregate thereafter are as follows:
millions of dollars
2023
2024
2025
2026
2027
Thereafter
Total
Minimum lease payments to be
received
$
90
$
92
$
95
$
94
$
92
$
930
$
1,393
Less: executory costs
(205)
Total
$
1,188
20. 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
2022
2021
Generation
2
131
$
13,083
$
11,173
Transmission
10
80
2,731
2,532
Distribution
10
65
6,978
6,305
Gas transmission and distribution
13
83
5,061
4,385
General plant and other
2
71
2,723
2,473
Total cost
30,576
26,868
Less: Accumulated depreciation
(1)
(9,574)
(8,739)
21,002
18,129
Construction work in progress
(1)
1,994
2,224
Net book value
$
22,996
$
20,353
(1) 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, 2022, SeaCoast’s share of plant in service was $
27
27
accumulated depreciation of $
1
1
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.
53
21. EMPLOYEE BENEFIT PLANS
Emera maintains a number of contributory defined-benefit and defined-contribution pension plans, which
cover substantially all of its employees. In addition, the Company provides non-pension benefits for its
retirees. These plans cover employees in Nova Scotia, New Brunswick, Newfoundland and Labrador,
Florida, New Mexico, Barbados, and Grand Bahama Island.
Emera’s net periodic benefit cost included the following:
Benefit Obligation and Plan Assets
The changes in benefit obligation and plan assets, and the funded status for all plans were as follows:
For the
Year ended December 31
millions of dollars
2022
2021
Change in Projected Benefit Obligation
("PBO") and Accumulated Post-
retirement Benefit Obligation ("APBO")
Defined benefit
pension plans
Non-pension
benefit plans
Defined benefit
pension plans
Non-pension
benefit plans
Balance, January 1
$
2,624
$
318
$
2,759
$
339
Service cost
41
4
43
5
Plan participant contributions
6
6
6
4
Interest cost
80
9
67
8
Benefits paid
(174)
(31)
(160)
(27)
Actuarial gains
(480)
(79)
(89)
(10)
Settlements and curtailments
(6)
-
-
-
Foreign currency translation adjustment
67
16
(2)
(1)
Balance, December 31
$
2,158
$
243
$
2,624
$
318
Change in plan assets
Balance, January 1
$
2,702
$
51
$
2,605
$
52
Employer contributions
45
24
42
21
Plan participant contributions
6
6
6
4
Benefits paid
(174)
(31)
(160)
(27)
Actual return on assets, net of expenses
(489)
(7)
214
2
Settlements and curtailments
(6)
-
-
-
Foreign currency translation adjustment
79
3
(5)
(1)
Balance, December 31
$
2,163
$
46
$
2,702
$
51
Funded status, end of year
$
5
$
(197)
$
78
$
(267)
The actuarial gains recognized in the period are primarily due to changes in the discount rate and
compensation-related assumption changes. This was partially offset by losses associated with member
experience and indexation.
Plans with PBO/APBO
in Excess of Plan Assets
The aggregate financial position for all pension plans where the PBO or APBO (for post-retirement benefit
plans) exceeds the plan assets for the years ended December 31 is as follows:
millions of dollars
2022
2021
Defined benefit
pension plans
Non-pension
benefit plans
Defined benefit
pension plans
Non-pension
benefit plans
PBO/APBO
$
1,006
$
221
$
140
$
290
Fair value of plan assets
914
-
35
-
Funded status
$
(92)
$
(221)
$
(105)
$
(290)
Plans with Accumulated Benefit Obligation (“ABO”)
in Excess of Plan Assets
The ABO for the defined benefit pension plans was $
2,080
$
2,507
for the years ended December 31 is as follows:
54
millions of dollars
2022
2021
Defined benefit
pension plans
Defined benefit
pension plans
ABO
$
111
$
133
Fair value of plan assets
33
35
Funded status
$
(78)
$
(98)
Balance Sheet
The amounts recognized in the Consolidated Balance Sheets consisted of the following:
As at
December 31
December 31
millions of dollars
2022
2021
Defined benefit
pension plans
Non-pension
benefit plans
Defined benefit
pension plans
Non-pension
benefit plans
Other current liabilities
$
(13)
$
(20)
$
(7)
$
(20)
Long-term liabilities
(80)
(201)
(100)
(270)
Other long-term assets
98
24
185
23
AOCI, net of tax and regulatory assets
358
22
230
90
Less: Deferred income tax (expense)
recovery in AOCI
(7)
(1)
(8)
1
Net amount recognized
$
356
$
(176)
$
300
$
(176)
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
millions of dollars
Defined Benefit Pension Plans
Balance, January 1, 2022
$
192
$
30
Amortized in current period
(21)
(10)
Current year addition to AOCI or regulatory assets
147
(5)
Change in FX rate
18
-
Balance, December 31, 2022
$
336
$
15
Non-pension benefits plans
Balance, January 1, 2022
$
91
$
-
Amortized in current period
(2)
-
Current year addition to AOCI or regulatory assets
(62)
(10)
Change in FX rate
4
-
Balance, December 31, 2022
$
31
$
(10)
As at
December
31
December
31
millions of dollars
2022
2021
Defined benefit
pension plans
Non-pension
benefit plans
Defined benefit
pension plans
Non-pension
benefit plans
Actuarial losses (gains)
$
15
$
(10)
$
30
$
-
Deferred income tax expense (recovery)
7
1
8
(1)
AOCI, net of tax
22
(9)
38
(1)
Regulatory assets
336
31
192
91
AOCI, net of tax and regulatory assets
$
358
$
22
$
230
$
90
Benefit Cost Components
Emera's net periodic benefit cost included the following:
55
As at
Year ended December 31
millions of dollars
2022
2021
Defined benefit
pension plans
Non-pension
benefit plans
Defined benefit
pension plans
Non-pension
benefit plans
Service cost
$
41
$
4
$
43
$
5
Interest cost
80
9
67
8
Expected return on plan assets
(144)
-
(132)
(1)
Current year amortization of:
8
-
21
3
21
2
24
2
Settlement, curtailments
2
-
-
-
Total
$
8
$
15
$
23
$
17
The expected return on plan assets is determined based on the market-related value of plan assets of
$
2,482
2,151
during the year.
The market-related value of assets is based on a
five-year
smoothed asset value. Anyinvestment 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 five-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.
Within each asset class, a further 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:
Canadian Pension Plans
Asset Class
Target Range at Market
Short-term securities
0%
to
5%
Fixed income
35%
to
50%
Equities:
7%
to
17%
36%
to
60%
Non-Canadian Pension Plans
Asset Class
Target Range at Market
Weighted average
Fixed income
30%
to
50%
Equities
50%
to
70%
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 fair value its
investments:
56
millions of dollars
NAV
Level 1
Level 2
Total
Percentage
As at
December 31, 2022
Cash and cash equivalents
$
-
$
70
$
-
$
70
3
%
Net in-transits
-
(70)
-
(70)
(3)
%
Equity securities:
-
87
-
87
4
%
-
233
-
233
11
%
-
186
-
186
8
%
Fixed income securities:
-
-
104
104
5
%
-
-
83
83
4
%
-
3
11
14
1
%
Mutual funds
-
68
-
68
3
%
Other
-
-
(3)
(3)
-
%
Open-ended investments
measured at NAV
790
-
-
790
36
%
Common collective trusts
measured at NAV
(2)
601
-
-
601
28
%
Total
$
1,391
$
577
$
195
$
2,163
100
%
As at
December 31, 2021
Cash and cash equivalents
$
-
$
60
$
-
$
60
2
%
Net in-transits
-
(84)
-
(84)
(3)
%
Equity securities:
-
97
-
97
4
%
-
366
-
366
14
%
-
215
-
215
8
%
Fixed income securities:
-
-
132
132
5
%
-
-
117
117
4
%
-
8
3
11
-
%
Mutual funds
-
86
-
86
3
%
Other
-
1
(1)
-
-
%
Open-ended investments
measured at NAV
952
-
-
952
35
%
Common collective trusts
measured at NAV
(2)
750
-
-
750
28
%
Total
$
1,702
$
749
$
251
$
2,702
100
%
(1) 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 honor 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 honor
subscription and redemption activity regularly.
Refer to note 16 for more information on the fair value hierarchy and inputs used to measure fair value.
Post-Retirement Benefit Plans
There are no assets set aside to pay for most of the Company’s post-retirement benefit plans. As is
common practice, post-retirement health benefits are paid from general accounts as required. The
primary exceptions to this is the NMGC Retiree Medical Plan, which is fully funded.
Investments in Emera
As at December 31, 2022 and 2021, the 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.
57
Cash Flows
The following table shows the expected cash flows for defined benefit pension and other post-retirement
benefit plans:
millions of dollars
Defined benefit
pension plans
Non-pension
benefit plans
Expected employer contributions
2023
$
44
$
20
Expected benefit payments
2023
164
22
2024
161
23
2025
168
23
2026
172
22
2027
178
22
2028 – 2032
919
105
Assumptions
The following table shows the assumptions that have been used in accounting for defined benefit
pension and other post-retirement benefit plans:
2022
2021
(weighted average assumptions)
Defined benefit
pension plans
Non-pension
benefit plans
Defined benefit
pension plans
Non-pension
benefit plans
Benefit obligation – December 31:
Discount rate - past service
5.33
%
5.31
%
3.05
%
2.81
%
Discount rate - future service
5.34
%
5.32
%
3.18
%
2.92
%
Rate of compensation increase
3.62
%
3.61
%
3.31
%
3.29
%
Health care trend - initial (next year)
-
5.40
%
-
5.09
%
-
3.77
%
-
3.77
%
2043
2042
Benefit cost for year ended December 31:
Discount rate - past service
3.05
%
2.81
%
2.49
%
2.48
%
Discount rate - future service
3.18
%
2.92
%
2.64
%
2.51
%
Expected long-term return on plan assets
6.07
%
1.32
%
5.86
%
-
%
Rate of compensation increase
3.31
%
3.29
%
2.89
%
3.04
%
Health care trend - initial (current year)
-
5.09
%
-
5.64
%
-
3.77
%
-
4.35
%
2042
2038
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.
Defined Contribution Plan
Emera also provides a defined contribution pension plan for certain employees. The Company’s
contribution for the year ended December 31, 2022 was $
41
45
58
22. GOODWILL
The change in goodwill for the year ended December 31 is due to the following:
millions of dollars
2022
2021
Balance, January 1
$
5,696
$
5,720
GBPC impairment charge
(1)
(73)
-
Change in FX rate
389
(24)
Balance, December 31
$
6,012
$
5,696
(1) At the beginning of the period, Emera's accumulated impairment charges related to GBPC were $
30
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, 2022, primarily relates to TECO Energy. Emera’s
reporting units with goodwill are Tampa Electric, PGS, NMGC, and GBPC.
In 2022, Emera performed a qualitative impairment assessment for Tampa Electric and PGS, concluding
that the fair value of the reporting units exceeded their respective carrying amounts, and as such, no
quantitative assessments were performed and
no
reporting unit, Emera elected to bypass a qualitative assessment and performed a quantitative
impairment assessment using a combination of the income approach and market approach. This
assessment estimated that the fair value of the NMGC reporting unit exceeded its carrying amount,
including goodwill. As a result of this assessment,
no
In 2022, the Company elected to bypass a qualitative assessment and performed a quantitative
impairment assessment for GBPC, using the income approach, as this reporting unit is sensitive to
changes in assumptions due to limited excess of fair value over carrying amount, including goodwill.
Although the cash flows of GBPC have not changed significantly compared to previous periods, it was
determined that the fair value did not exceed its carrying amount, including goodwill, primarily due to an
increase in discount rates. The discount rate for the reporting unit was negatively impacted by changes in
the macro-economic environment, including the risk-free rate assumption. As a result of this assessment,
a goodwill impairment charge of $
73
to nil as at December 31, 2022. This non-cash charge is included in “Impairment charge” on the
Consolidated Statements of Income.
59
23. 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
2022
Weighted
average
interest rate
2021
Weighted
average
interest rate
Tampa Electric Company ("TEC")
Advances on term, revolving and accounts receivable facilities
$
1,380
5.00
%
$
945
0.58
%
Emera
Non-revolving term facilities
796
5.19
%
400
0.96
%
Bank indebtedness
-
-
%
6
-
%
TECO Finance
Advances on revolving credit and term facilities
481
5.47
%
355
1.20
%
NMGC
Advances on revolving credit facilities
59
5.15
%
25
1.20
%
GBPC
Advances on revolving credit facilities
10
5.25
%
10
5.25
%
NSPI
Bank indebtedness
-
-
%
1
-
%
Short-term debt
$
2,726
$
1,742
The Company’s total short-term revolving and non-revolving credit facilities, outstanding borrowings and
available capacity as at December 31 were as follows:
millions of dollars
Maturity
2022
2021
TEC - Unsecured committed revolving credit facility
2026
$
1,084
$
1,014
TECO Energy/TECO Finance - revolving credit facility
2026
542
507
Emera - non-revolving term facility
2023
400
400
Emera - non-revolving term facility
2023
400
-
TEC - Unsecured non-revolving facility
2023
542
634
NMGC - revolving credit facility
2026
169
158
GBPC - revolving credit facility
on demand
18
16
Total
$
3,155
$
2,729
Less:
Advances under revolving credit and term facilities
2,731
1,735
Letters of credit issued within the credit facilities
4
4
Total advances under available facilities
2,735
1,739
Available capacity under existing agreements
$
420
$
990
The weighted average interest rate on outstanding short-term debt at December 31, 2022 was
5.01
cent (2021 –
0.83
Recent Significant Financing Activity by Segment
Florida Electric Utilities
On December 13, 2022, TEC amended its 364-day non-revolving term credit facility to extend the
maturity date from
December 16, 2022
December 13, 2023
500
million USD to $
400
prior agreement.
60
Other
On December 16, 2022, Emera amended its $
400
maturity from
December 16, 2022
December 16, 2023
. There were no other significant changes in
commercial terms from the prior agreement.
On August 2, 2022, Emera entered into a $
400
August 2, 2023
. The credit agreement contains customary representation and warranties, events of
default and financial and other covenants and bears interest at Bankers’ Acceptances or prime rate
advances, plus a margin.
24. OTHER CURRENT LIABILITIES
As at
December 31
December 31
millions of dollars
2022
2021
Accrued charges
$
174
$
157
Nova Scotia Cap-and-Trade Program provision (note 7)
172
-
Accrued interest on long-term debt
97
75
Pension and post-retirement liabilities (note 21)
33
27
Sales and other taxes payable
14
6
Income tax payable
9
6
Other
80
95
$
579
$
366
61
25. 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
2022
2021
Maturity
2022
2021
Emera
Bankers acceptances, LIBOR loans
Variable
Variable
2027
$
403
$
378
Unsecured fixed rate notes
2.90%
2.90%
2023
500
500
Fixed to floating subordinated notes (USD)
(2)
6.75%
6.75%
2076
1,625
1,521
$
2,528
$
2,399
Emera Finance
Unsecured senior notes (USD)
3.65%
3.65%
2024 - 2046
$
3,725
$
3,487
Tampa Electric
(3)
Fixed rate notes and bonds (USD)
4.15%
4.15%
2024 - 2052
$
4,341
$
3,683
PGS
Fixed rate notes and bonds (USD)
3.78%
3.78%
2024 - 2052
$
772
$
660
NMGC
Fixed rate notes and bonds (USD)
3.11%
3.11%
2026 - 2051
$
521
$
488
Non-revolving term facility, floating rate
Variable
Variable
2024
108
101
$
629
$
589
NMGI
Fixed rate notes and bonds (USD)
3.64%
3.64%
2024
$
203
$
190
NSPI
Discount notes
Variable
Variable
2024 - 2027
$
881
$
376
Medium term fixed rate notes
5.14%
5.14%
2025 - 2097
2,665
2,665
$
3,546
$
3,041
EBP
Senior secured credit facility
Variable
Variable
2026
$
249
$
249
ECI
Secured senior notes (USD)
Variable
Variable
2026
$
86
$
84
Amortizing fixed rate notes (USD)
3.97%
3.97%
2024 - 2026
100
$
104
Non-revolving term facility, floating rate
Variable
Variable
2027
30
$
28
Non-revolving term facility, fixed rate
2.05%
2.36%
2025 - 2026
91
$
101
Secured fixed rate senior notes
(4)
3.06%
4.43%
2023 - 2029
142
$
161
$
449
$
478
Adjustments
Fair market value adjustment - TECO Energy acquisition
(5)
$
2
$
3
Debt issuance costs
(126)
(121)
Amount due within one year
(574)
(462)
$
(698)
$
(580)
Long-Term Debt
$
15,744
$
14,196
(1) Weighted average interest rate of fixed rate long-term debt.
(2) In 2022, the Company recognized $
110
102
subordinated notes.
(3) A substantial part of Tampa Electric’s tangible assets are pledged as collateral to secure its first mortgage bonds. There are
currently no bonds outstanding under Tampa Electric’s first mortgage bond indenture.
(4) Notes are issued and payable in either USD or BBD.
(5) On acquisition of TECO Energy, Emera recorded a fair market value adjustment on the unregulated long-term debt acquired.
The fair market value adjustment is amortized over the remaining term of the debt.
62
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
2022
2021
Emera – revolving credit facility
(1)
June 2027
$
900
$
900
NSPI - revolving credit facility
(1)
December 2027
800
600
NSPI - non-revolving credit facility
July 2024
400
-
NMGC - non-revolving credit facility
March 2024
108
-
ECI – revolving credit facilities
2023-2032
11
27
Total
$
2,219
$
1,527
Less:
Borrowings under credit facilities
1,396
770
Letters of credit issued inside credit facilities
12
124
Use of available facilities
$
1,408
$
894
Available capacity under existing agreements
$
811
$
633
(1) Advances on the revolving credit facility can be made by way of overdraft on accounts up to $
50
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, 2022
Emera
Syndicated credit facilities
Debt to capital ratio
Less than or equal to
0.70
0.57
Recent Significant Financing Activity by Segment
Florida Electric Utilities
On September 15, 2022, TEC repaid a $
250
existing credit facilities.
On July 12, 2022, TEC completed an issuance of $
600
$
300
3.875
July 12,
2024
, and $
300
5
July 15, 2052
.
Canadian Electric Utilities
On December 16, 2022, NSPI amended its revolving operating credit facility to extend the maturity date
from
December 16, 2026
December 16, 2027
600
to $
800
On July 15, 2022, NSPI entered into a $
400
July 15, 2024
. The credit facility contains customary representation and warranties, events of default and
financial and other covenants, and bears interest at Bankers’ Acceptances or prime rate advances, plus a
margin.
Gas Utilities and Infrastructure
On September 23, 2022, NMGC amended its $
80
facility to extend the maturity from
September 23, 2022
, to
March 22, 2024
. There were no other changes
in commercial terms from the prior agreement.
63
On June 30, 2022, Brunswick Pipeline amended its non-revolving credit agreement to extend the maturity
from
June 30, 2025
June 30, 2026
. There were no other changes in commercial terms from the prior
agreement.
Other Electric Utilities
On March 25, 2022, ECI amended its amortizing floating rate notes to extend the maturity from
March 25,
2022
March 25, 2027
. There were no other changes in commercial terms from the prior agreement.
Other
On December 16, 2022, Emera amended its $
900
maturity date from
June 30, 2026
June 30, 2027
. There were no other significant changes in
commercial terms from the prior agreement.
Long-Term Debt Maturities
As at December 31, 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
2023
2024
2025
2026
2027
Thereafter
Total
Emera
$
500
$
-
$
-
$
1,625
$
403
$
-
$
2,528
Emera US Finance LP
-
407
-
1,016
-
2,302
3,725
Tampa Electric
-
356
-
-
-
3,985
4,341
PGS
-
51
-
-
-
721
772
NMGC
-
108
-
95
-
426
629
NMGI
-
203
-
-
-
-
203
NSPI
-
398
125
40
483
2,500
3,546
EBP
-
-
-
249
-
-
249
ECI
74
90
137
85
60
3
449
Total
$
574
$
1,613
$
262
$
3,110
$
946
$
9,937
$
16,442
26. 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 fair value of any related ARO cannot be made.
The change in ARO for the years ended December 31 is as follows:
millions of dollars
2022
2021
Balance, January 1
$
174
$
178
Accretion included in depreciation expense
9
10
Change in FX rate
3
(1)
Additions
1
1
Accretion deferred to regulatory asset (included in PP&E)
1
(2)
Liabilities settled
(1)
(1)
(13)
Revisions in estimated cash flows
(13)
-
Other
-
1
Balance, December 31
$
174
$
174
(1) Tampa Electric produced ash and other by-products, collectively known as CCR's, at its Big Bend and Polk power stations. The
decrease in ARO in 2021 was due to the closure of CCR management facilities.
64
27. COMMITMENTS AND CONTINGENCIES
A.
Commitments
As at December 31, 2022, 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
2023
2024
2025
2026
2027
Thereafter
Total
Transportation
(1)
$
693
$
516
$
423
$
383
$
367
$
2,817
$
5,199
Purchased power
(2)
269
243
237
228
243
2,145
3,365
Fuel, gas supply and storage
1,161
282
138
40
5
1
1,627
Capital projects
264
89
4
1
-
-
358
Equity investment commitments
(3)
240
-
-
-
-
-
240
Other
149
142
132
49
42
189
703
$
2,776
$
1,272
$
934
$
701
$
657
$
5,152
$
11,492
(1) Purchasing commitments for transportation of fuel and transportation capacity on various pipelines. Includes a commitment of
$
144
(2) Annual requirement to purchase electricity production from IPPs or other utilities over varying contract lengths.
(3) Emera has a commitment to make a final equity contribution to the LIL upon its commissioning. Once commissioned, the
commercial agreements between Emera and Nalcor require true ups to finalize the respective investment obligations of the parties in
relation to the Maritime Link and LIL.
NSPI has a contractual obligation to pay NSPML for use of the Maritime Link over approximately
38
from its January 15, 2018 in-service date. In February 2022, the UARB issued its decision and Board
Order approving NSPML’s requested rate base of approximately $
1.8
UARB approved the collection of $
164
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 for Nalcor, if requested, to enable it to transmit
energy which is not otherwise used in Newfoundland and Labrador or Nova Scotia. Nalcor has the right to
transmit this energy from Nova Scotia to New England energy markets effective August 15, 2021, the
date the NS Block delivery obligation commenced, and continuing for
50 years
. As transmission rights are
contracted, the obligations are included within “Other” in the above table.
B.
Legal Proceedings
TECO Guatemala Holdings (“TGH”)
Prior to Emera’s acquisition of TECO Energy in 2016, TGH, a wholly owned subsidiary of TECO Energy,
divested of its indirect investment in the Guatemala electricity sector, but retained certain claims against
the Republic of Guatemala (“Guatemala”). In 2013, TGH asserted an arbitration claim against Guatemala
with the International Centre for the Settlement of Investment Disputes (“ICSID”) under the Dominican
Republic Central America – United States Free Trade Agreement. The arbitration concerned TGH’s
allegation that Guatemala unfairly set the distribution tariff for a local distribution company which harmed
TGH’s investment in that company. A tribunal established by the ICSID ruled in favour of TGH (the “First
Award”) and, in November 2020, Guatemala made a payment of approximately $
38
and final satisfaction of the First Award.
65
On September 23, 2016, TGH had filed a request for resubmission to arbitration seeking damages in
addition to those awarded in the First Award. On May 13, 2020, an ICSID tribunal awarded TGH
additional damages and costs against Guatemala of more than $
35
“Second Award”). TGH subsequently requested a reconsideration of the interest quantum awarded in
connection with the Second Award. On October 16, 2020, the tribunal granted TGH’s request for
additional interest. The additional amount was approximately $
2
Guatemala filed an application with ICSID for annulment of the Second Award. On March 31, 2021, ICSID
constituted an ad hoc Committee to oversee the annulment proceeding. A three-day hearing was held
before the ad hoc Committee beginning on July 27, 2022.
On November 28, 2022, TGH and Guatemala entered into a settlement agreement with respect to the
Second Award. Pursuant to the settlement agreement, on December 15, 2022, Guatemala paid TGH $
46
million USD and the parties agreed to settle all outstanding disputes, concluding this matter. This amount
was recognized in “Other Income, net” on the Consolidated Statements of Income.
Superfund and Former Manufactured Gas Plant Sites
TEC, through its Tampa Electric and PGS divisions, is a potentially responsible party (“PRP”) for certain
superfund sites and, through its PGS division, for certain former manufactured gas plant sites. While the
joint and several liability associated with these sites presents the potential for significant response costs,
as at December 31, 2022, TEC estimated its financial liability to be $
17
13
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 TEC. The estimates
to perform the work are based on TEC’s 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, TEC could be liable for more than TEC’s 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 materially affect the Company in the normal
course of business. Risks associated with derivative instruments and fair value measurements are
discussed in note 15 and note 16.
66
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
an effective, consistent and coherent approach to risk management. The Board of Directors established a
Risk and Sustainability Committee (‘RSC”) in September 2021. The RSC’s mandate includes oversight of
the Company’s Enterprise Risk Management framework, including the identification, assessment,
monitoring and management of enterprise risks. It also includes oversight of the Company’s approach to
sustainability and its performance relative to its sustainability objectives.
Regulatory and Political Risk
The Company’s rate-regulated subsidiaries and certain investments subject to significant influence are
subject to risk of the recovery of costs and investments. Regulatory and political risk can include changes
in regulatory frameworks, shifts in government policy, legislative changes, and regulatory decisions.
As cost-of-service utilities with an obligation to serve customers, Emera’s utilities operate under formal
regulatory frameworks, and must obtain regulatory approval to change or add rates and/or riders. Emera
also holds investments in entities in which it has significant influence, and which are subject to regulatory
and political risk including NSPML, LIL, and M&NP. As a regulated Group II pipeline, the tolls of
Brunswick Pipeline are regulated by the CER on a complaint basis, as opposed to the regulatory approval
process described above. In the absence of a complaint, the CER does not normally undertake a detailed
examination of Brunswick Pipeline’s tolls, which are subject to a firm service agreement expiring in 2034,
with Repsol Energy North America Canada Partnership. The agreement provides for a predetermined toll
increase in the fifth and fifteenth year of the contract.
Regulators administer legislation covering material aspects of the utilities’ businesses, including customer
rates and/or riders, the underlying allowed ROEs, deemed capital structures, capital investment, the
terms and conditions for the provision of service, performance standards, and affiliate transactions. Costs
and investments can be recovered upon approval by the respective regulator as an adjustment to rates
and/or riders, which normally requires a public hearing process or may be mandated by other
governmental bodies. During public hearing processes, consultants and customer representatives
scrutinize the costs, actions and plans of these rate-regulated companies, and their respective regulators
determine whether to allow recovery and to adjust rates based upon the evidence and any contrary
evidence from other parties. In some circumstances, other government bodies may influence the setting
of rates. Regulatory decisions, legislative changes, and prolonged delays in the recovery of costs or
regulatory assets could result in decreased rate affordability for customers and could materially affect
Emera and its utilities.
Emera’s utilities generally manage this risk through transparent regulatory disclosure, ongoing
stakeholder and government consultation and multi-party engagement on aspects such as utility
operations, regulatory audits, rate filings and capital plans. The subsidiaries employ a collaborative
regulatory approach through technical conferences and, where appropriate, negotiated settlements.
Changes in government and shifts in government policy and legislation can impact the commercial and
regulatory frameworks under which Emera and its subsidiaries operate. This includes initiatives regarding
deregulation or restructuring of the energy industry. Deregulation or restructuring of the energy industry
may result in increased competition and unrecovered costs that could adversely affect operations, net
income and cash flows. State and local policies in some United States jurisdictions have sought to
prevent or limit the ability of utilities to provide customers the choice to use natural gas while in other
jurisdictions policies have been adopted to prevent limitations on the use of natural gas. Changes in
applicable state or local laws and regulations, including electrification legislation, could adversely impact
PGS and NMGC.
67
Emera cannot predict future legislative, policy, or regulatory changes, whether caused by economic,
political or other factors, or its ability to respond in an effective and timely manner or the resulting
compliance costs. Government interference in the regulatory process can undermine regulatory stability,
predictability, and independence, and could have a material adverse effect on the Company.
Foreign Exchange Risk
The Company is exposed to foreign currency exchange rate changes. Emera operates internationally,
with an increasing 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.
Consistent with the Company’s risk management policies, Emera manages currency risks through
matching United States denominated debt to finance its United States 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.
Liquidity and Capital Market Risk
Liquidity risk relates to Emera’s ability to ensure sufficient funds are available to meet its financial
obligations. Emera manages this risk by forecasting cash requirements on a continuous basis to
determine whether sufficient funds are available. Liquidity and capital needs could be financed through
internally generated cash flows, asset sales, short-term credit facilities, and ongoing access to capital
markets.
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 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 the 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. Emera
manages these risks by actively monitoring and managing key financial metrics with the objective of
sustaining investment grade credit ratings.
68
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 materially affect Emera and its utilities. 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. Emera seeks to manage interest rate risk
through a portfolio approach that includes the use of fixed and floating rate debt with staggered
maturities. The Company will, from time to time, issue long-term debt or enter interest rate hedging
contracts to limit its exposure to fluctuations in floating interest rate debt.
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 ROE’s 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.
As with most other utilities and other similar yield-returning investments, Emera’s share price may be
affected by changes in interest rates and could underperform the market in an environment of rising
interest rates.
Inflation Risk
The Company may be exposed to changes in inflation that may result in increased operating and
maintenance costs, capital investment, and fuel costs compared to the revenues provided by customer
rates. Emera’s utilities have budgeting and forecasting processes to identify inflationary risk factors and
measure operating performance, as well as collective bargaining agreements that mitigate the short-term
impact of inflation on labour costs.
Commodity Price Risk
The Company’s utility fuel supply is subject to commodity price risk. In addition, Emera Energy is subject
to commodity price risk through its portfolio of commodity contracts and arrangements.
The Company manages this risk through established processes and practices to identify, monitor, report
and mitigate these risks. These include the Company’s commercial arrangements, such as the
combination of supply and purchase agreements, asset management agreements, pipeline transportation
agreements and financial hedging instruments. In addition, its credit policies, counterparty credit
assessments, market and credit position reporting, and other risk management and reporting practices,
are also used to manage and mitigate this risk.
69
Regulated Utilities
The Company’s utility fuel supply is exposed to broader global 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, trade sanctions or embargos. The Company seeks to manage
this risk using financial hedging instruments and physical contracts and through contractual protection
with counterparties, where applicable.
The majority of Emera’s regulated electric and gas utilities have adopted and implemented fuel
adjustment mechanisms and purchased gas adjustment mechanisms respectively, which has further
helped manage commodity price risk, as the regulatory framework for the Company’s rate-regulated
subsidiaries permits the recovery of prudently incurred fuel and gas costs. There is no assurance that
such mechanisms and regulatory frameworks will continue to exist in the future. 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.
Emera Energy Marketing and Trading
Emera Energy has employed further measures to manage commodity risk. 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 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.
To measure commodity price risk exposure, Emera Energy employs a number of controls and processes,
including an estimated VaR analysis of its exposures. The VaR amount represents an estimate of the
potential change in fair value that could occur from changes in Emera Energy’s portfolio or changes in
market factors within a given confidence level, if an instrument or portfolio is held for a specified time
period. The VaR calculation is used to quantify exposure to market risk associated with physical
commodities, primarily natural gas and power positions.
Income Tax Risk
The computation of the Company’s provision for income taxes is impacted by changes in tax legislation in
Canada, the United States and the Caribbean. Any such changes could affect the Company’s future
earnings, cash flows, and financial position. The value of Emera’s existing deferred tax assets and
liabilities are determined by existing tax laws and could be negatively impacted by changes in laws.
Emera monitors the status of existing tax laws to ensure that changes impacting the Company are
appropriately reflected in the Company’s tax compliance filings and financial results.
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 are not included within the Consolidated Balance Sheets as at December
31, 2022
:
70
TECO Energy has issued a guarantee in connection with SeaCoast’s performance of obligations under a
gas transportation precedent agreement. The guarantee is for a maximum potential amount of $
45
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. In
the event that TECO Energy’s and Emera’s long-term senior unsecured credit ratings are downgraded
below investment grade by Moody’s Investor Services (“Moody’s”) or S&P Global Ratings (“S&P”). TECO
Energy would be required to provide its counterparty a letter of credit or cash deposit of $
27
TECO Energy issued a guarantee in connection with SeaCoast’s performance obligations under a firm
service agreement, which expires on 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
In the event that TECO Energy’s long-term senior unsecured credit ratings are downgraded below
investment grade by Moody’s or S&P, TECO Energy would need to provide either a substitute guarantee
from an affiliate with an investment grade credit rating or a letter of credit or cash deposit of $
13
USD.
Emera Inc. has issued a guarantee of up to $
35
relating to outstanding notes of GBPC
. The
guarantee for the notes will
expire in May 2023
.
Emera Inc. has issued a guarantee of $
66
guarantee will automatically terminate on the date upon which the obligations have been repaid in full.
NSPI has issued guarantees on behalf of its subsidiary, NS Power Energy Marketing Incorporated
(“NSPEMI”), in the amount of $
119
118
The Company has standby letters of credit and surety bonds in the amount of $
145
(December 31, 2020 – $
148
subsidiaries. These letters of credit and surety bonds typically have a one-year term and are renewed
annually as required.
Emera Inc., 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 2023. The amount committed
as at December 31, 2022 was $
63
64
Collaborative Arrangements
For the years ended December 31, 2022 and 2021, 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. In
2022, NSPI recognized $
12
18
purchased power” and $
3
3
71
28. CUMULATIVE PREFERRED STOCK
Authorized:
Unlimited number of First Preferred shares, issuable in series.
Unlimited number of Second Preferred shares, issuable in series.
December 31, 2022
December 31, 2021
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
$
1.1802
$
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
$
1.2250
$
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)
Initial Yield
(%)
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)
4.400
0.5456
1.84
August 15, 2025
25.00
Series B
4.100
1.1802
2.65
August 15, 2023
25.00
Series D
4.202
1.0505
2.63
February 15, 2025
25.00
Series G
Minimum rate reset
(3)(4)
2.393
Floating
1.84
August 15, 2025
25.00
Series A
4.900
1.2250
4.90
August 15, 2023
25.00
Series I
4.250
1.0625
4.25
May 15, 2026
25.00
Series K
Perpetual fixed rate
4.500
1.1250
25.00
(6)
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
4.9
0 per cent) and for Series B equals the Government of Treasury Bill Rate on the applicable reset date, plus
1.84
(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
redemption and $
25.50
of redemptions on any other date after August 15, 2023, February 15, 2025 and August 15, 2023, respectively. The reset dividend
yield for Series I equals the Government of Treasury Bill Rate on the applicable reset date, plus
2.54
(5) First Preferred Shares, Series E are redeemable at $
25.00
(6) First Preferred Shares, Series L are redeemable at $
26.00
$
0.25
25.00
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 Equity as a deduction from retained earnings.
72
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.
29. NON-CONTROLLING INTEREST IN SUBSIDIARIES
As at
December 31
December 31
millions of dollars
2022
2021
Preferred shares of GBPC
$
14
$
14
Domlec
(1)
-
20
$
14
$
34
(1) On March 31, 2022, Emera disposed its interest in Domlec. For further details, refer to note 4.
Preferred shares of GBPC:
Authorized:
10,000
2022
2021
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
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
30. SUPPLEMENTARY INFORMATION TO CONSOLIDATED STATEMENTS OF
CASH FLOWS
For the
Year ended December 31
millions of dollars
2022
2021
Changes in non-cash working capital:
$
(214)
$
(84)
(1)
(636)
(364)
423
289
(2)
193
7
Total non-cash working capital
$
(234)
$
(152)
(1) Includes $(
162
) million related to the January 2023 settlement of NMGC gas hedges. Offsetting regulatory liability is included in
operating cash flow before working capital resulting in no impact to net cash provided by operating activities.
(2) Includes $
172
asset (FAM) balance is included in operating cash flow before working capital resulting in no impact to net cash provided by
operating activities.
Supplemental disclosure of cash paid (received):
Interest
$
699
$
603
Income taxes
$
67
$
24
Supplemental disclosure of non-cash activities:
Common share dividends reinvested
$
237
$
214
Reclassification of long-term debt to short-term debt
$
500
$
-
Decrease in accrued capital expenditures
$
(13)
$
(45)
Supplemental disclosure of operating activities:
Net change in short-term regulatory assets and liabilities
$
(157)
$
(108)
31. STOCK-BASED COMPENSATION
Employee Common Share Purchase Plan and Common Shareholders Dividend
Reinvestment and Share Purchase Plan
Eligible employees may participate in Emera’s Employee Common Share Purchase Plan. As of
December 31, 2022, the plan allows employees to make cash contributions of a minimum of $25 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 the reinvestment of dividends for all participants except for where it is 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, 2022, Emera is in compliance with this requirement.
Compensation cost for shares issued under the Employee Common Share Purchase Plan for the year
ended December 31, 2022 was $
3
3
Consolidated Statements of Income.
The Company also has a Common Shareholders Dividend Reinvestment and Share Purchase Plan
(“Dividend Reinvestment Plan”), which provides an opportunity for shareholders 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 in connection with the reinvestment of
cash dividends. The discount was 2 per cent in 2022.
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, 2022, Emera is 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 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
termination without just cause or death, and within
sixty days
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 fair values per stock option along with the assumptions
incorporated into the valuation models for options granted, for the year-ended December 31:
2022
2021
Weighted average fair value per option
$
5.35
$
3.63
Expected term
(1)
5
5
Risk-free interest rate
(2)
1.79
%
0.60
%
Expected dividend yield
(3)
4.55
%
5.00
%
Expected volatility
(4)
18.87
%
19.14
%
(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.
The following table summarizes stock option information for 2022:
75
Total Options
Non-Vested Options
(1)
Number of
Options
average exercise
price per share
Number of
Options
Weighted
average grant
date fair-value
Outstanding as at December 31, 2021
2,590,304
$
48.48
1,452,475
$
3.18
Granted
467,100
58.26
467,100
5.35
Exercised
(203,525)
43.87
N/A
N/A
Vested
N/A
N/A
(571,175)
2.83
Options outstanding December 31, 2022
2,853,879
$
50.41
1,348,400
$
4.08
Options exercisable December 31, 2022
(2)(3)
1,505,479
$
46.59
(1) As at December 31, 2022, there was $
4
expected to be recognized over a weighted average period of approximately
3
3
3
(2) As at December 31, 2022, the weighted average remaining term of vested options was
5
$
10
6
21
(3) As at December 31, 2022, the fair value of options that vested in the year was $
2
1
Compensation cost recognized for stock options for the year ended December 31, 2022 was $
2
(2021 – $
2
As at December 31, 2022, cash received from option exercises was $
9
14
total intrinsic value of options exercised for the year ended December 31, 2022 was $
4
6
million). The range of exercise prices for the options outstanding as at December 31, 2022 was $
32.35
$
60.03
32.35
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.
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. 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.
76
In addition, special DSU awards may be made from time to time by the Management Resources and
Compensation Committee (“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, 2022
is presented in the following table:
Employee
DSU
Weighted
Average
Grant Date
Fair Value
Director
DSU
Weighted
Average
Grant Date
Fair Value
Outstanding as at December 31, 2021
610,601
$
39.22
614,365
$
43.80
Granted including DRIP
76,252
52.42
104,465
57.89
Exercised
(59,630)
31.57
(54,572)
46.04
Outstanding and exercisable as at December 31, 2022
627,223
$
41.55
664,258
$
45.83
Compensation cost recovery recognized for employee and director DSU’s for the year ended December
31, 2022 was $
6
9
recovery for share units realized for the year ended December 31, 2022 was $
2
3
tax recovery). The aggregate intrinsic value of the outstanding shares for the year ended December 31,
2022 for employees was $
33
39
shares for the year ended December 31, 2022 for directors was $
34
39
payments made during the year ended December 31, 2021 associated with the DSU plan was $
8
(2021 – $
11
Performance Share Unit Plan
Under the PSU plan, certain executive and senior employees are eligible for long-term incentives payable
through the PSU plan. PSUs are granted annually for
three
-year overlapping performance cycles,resulting in a cash payment. 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 theMRCC 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.
A summary of the activity related to employee PSUs for the year ended December 31, 2022 is presented
in the following table:
Employee PSU
Weighted Average
Grant Date Fair Value
Aggregate intrinsic value
Outstanding as at December 31, 2021
951,935
$
48.60
$
66
Granted including DRIP
242,462
59.30
Exercised
(357,960)
42.85
Forfeited
(145,991)
44.28
Outstanding as at December 31, 2022
690,446
$
56.24
$
40
Compensation cost recognized for the PSU plan for the year ended December 31, 2022 was $
18
(2021 – $
12
ended December 31, 2022 were $
5
3
ended December 31, 2021 associated with the PSU plan was $
24
29
77
Restricted Share Unit Plan
Under the RSU plan, certain executive and senior employees are eligible for long-term incentives payable
through the RSU plan. RSUs are granted annually for
three
-year overlapping performance cycles,resulting in a cash payment. 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 theMRCC 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.
A summary of the activity related to employee RSUs for the year ended December 31, 2022 is presented
in the following table:
Employee RSU
Weighted Average
Grant Date Fair Value
Aggregate intrinsic value
Outstanding as at December 31, 2021
343,952
$
54.64
$
24
Granted including DRIP
180,426
59.30
Exercised
(134)
54.63
Forfeited
(15,776)
56.08
Outstanding as at December 31, 2022
508,468
$
56.25
$
30
Compensation cost recognized for the RSU plan for the year ended December 31, 2022 was $
9
(2021 – $
8
ended December 31, 2022 were $
2
2
ended December 31, 2022 associated with the RSU plan was
nil
nil
).
32. 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, Nalcor Energy 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.
BLPC has established a Self-Insurance Fund (“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:
78
As at
December 31, 2022
December 31, 2021
Maximum
Maximum
millions of dollars
Total
assets
exposure to
loss
Total
assets
loss
Unconsolidated VIEs in which Emera has variable interests
NSPML (equity accounted)
$
501
$
6
$
533
$
11
33. COMPARATIVE INFORMATION
These financial statements contain certain reclassifications of prior period amounts to be consistent with
the current period presentation, with no effect on net income.
34. SUBSEQUENT EVENTS
These financial statements and notes reflect the Company’s evaluation of events occurring subsequent to
the balance sheet date through February 23, 2023, the date the financial statements were issued.