EMERA INCORPORATED
Consolidated
Financial Statements
December 31, 2021 and 2020
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 14, 2022
“Scott Balfour”
“Gregory Blunden”
President and Chief Executive Officer Chief Financial Officer
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, 2021 and 2020, 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, 2021 and 2020, and the consolidated results of its operations and its consolidated cash
flows for each of the two years in the period ended December 31, 2021, 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.
Accounting for the effects of rate regulation
Description of the
Matter
As disclosed in note 7 of the consolidated financial statements, the
Company has $2.6 billion in regulatory assets and $2.1 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
property, plant and equipment, 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 recovery on costs incurred, of the disallowance of part of the cost of
recently completed property, plant and equipment and construction work in
progress, 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, property, plant and equipment, 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 and disclosure of derivative financial
instruments
Description of the
Matter
Held-for-trading (“HFT”) derivative assets of $241 million and liabilities of
$850 million, disclosed in note 15 to the consolidated financial statements,
are measured at fair value. The Company recognized $138 million in
realized and unrealized losses 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
curves based on illiquid markets, internally developed correlation factors
and basis differentials, the Company’s own credit risk and discount rates.
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, credit metrics and discount rates 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 14, 2022
Emera Incorporated
Consolidated Statements of Income
For the
Year ended December 31
millions of Canadian dollars (except per share amounts)
2021
2020
Operating revenues
$
4,665
$
4,442
1,261
1,034
(161)
30
5,765
5,506
Operating expenses
1,763
1,420
472
293
(1)
4
1,369
1,419
330
317
902
881
0
25
4,835
4,359
Income from operations
930
1,147
Income from equity investments (note 8)
Other income, net (note 9)
93
708
Interest expense, net
611
679
Income before provision for income taxes
555
1,325
Income tax (recovery) expense (note 10)
(6)
341
Net income
561
984
Non-controlling interest in subsidiaries
1
1
Preferred stock dividends
50
45
Net income attributable to common shareholders
$
510
$
938
Weighted average shares of common stock outstanding (in millions) (note 12)
257
248
258
248
Earnings per common share (note 12)
$
1.98
$
3.78
$
1.98
$
3.78
Dividends per common share declared
$
2.5750
$
2.4750
The accompanying notes are an integral part of these consolidated financial statements.
Emera Incorporated
Consolidated Statements of Comprehensive Income
For the
Year ended December 31
millions of Canadian dollars
2021
2020
Net income
$
561
$
984
Other comprehensive income (loss), net of tax
Foreign currency translation adjustment
(1)
(42)
(201)
Unrealized gains on net investment hedges
(2) (3)
5
26
Cash flow hedges
18
0
(1)
2
17
2
Net change in unrecognized pension and post-retirement benefit obligation
(5)
124
(1)
Other comprehensive income (loss)
(6)
104
(174)
Comprehensive income
665
810
Comprehensive income attributable to non-controlling interest
1
1
Comprehensive Income of Emera Incorporated
$
664
$
809
The accompanying notes are an integral part of these consolidated financial statements.
1) Net of tax expense of $
5
1
2) The Company has designated $
1.2
exposure of its net investment in United States dollar denominated operations.
3) Net of tax expense of $
1
4
4) Net of tax expense of $
6
nil
) for the year ended December 31, 2021.
5) Net of tax expense of $
2
1
6) Net of tax expense of $
14
2
Emera Incorporated
Consolidated Balance Sheets
As at
December 31
December 31
millions of Canadian dollars
2021
2020
Assets
Current assets
$
394
$
220
23
34
538
453
195
73
253
165
1,733
1,233
3,136
2,178
Property, plant and equipment,
net of accumulated depreciation
and amortization of $
8,739
8,714
, respectively (note 20)
20,353
19,535
Other assets
295
209
106
25
2,313
1,419
462
475
1,382
1,346
5,696
5,720
501
327
10,755
9,521
Total assets
$
34,244
$
31,234
Emera Incorporated
Consolidated Balance Sheets – Continued
As at
December 31
December 31
millions of Canadian dollars
2021
2020
Liabilities and Equity
Current liabilities
$
1,742
$
1,625
462
1,382
1,485
1,148
533
251
290
129
366
340
4,878
4,875
Long-term liabilities
14,196
12,339
1,868
1,629
149
87
1,765
1,832
370
453
868
781
19,216
17,121
Equity
7,242
6,705
1,422
1,004
79
79
25
(79)
1,348
1,495
10,116
9,204
34
34
10,150
9,238
Total liabilities and equity
$
34,244
$
31,234
Commitments and contingencies
(note 27)
The accompanying notes are an integral part of these consolidated financial statements.
Approved on behalf of the Board of Directors
“M. Jacqueline Sheppard”
“Scott Balfour”
Chair of the Board President and Chief Executive Officer
Emera Incorporated
Consolidated Statements of Cash Flows
For the
Year ended December 31
millions of Canadian dollars
2021
2020
Operating activities
Net income
$
561
$
984
Adjustments to reconcile net income to net cash provided by operating activities:
915
899
(69)
(76)
(61)
(45)
(37)
381
(23)
(23)
(166)
(94)
404
(36)
(176)
(87)
(107)
52
0
25
0
(603)
96
43
Changes in non-cash working capital (note 30)
(152)
217
Net cash provided by operating activities
1,185
1,637
Investing activities
(2,359)
(2,623)
3
1,401
24
(2)
Net cash used in investing activities
(2,332)
(1,224)
Financing activities
(155)
385
640
399
(377)
(688)
2,554
428
(1,660)
(513)
82
(203)
317
285
416
0
(443)
(409)
(50)
(45)
(13)
(11)
Net cash provided by (used in) financing activities
1,311
(372)
Effect of exchange rate changes on cash, cash equivalents, and restricted cash
(1)
(61)
Net increase (decrease) in cash, cash equivalents, restricted cash
163
(20)
Cash, cash equivalents, and restricted cash, beginning of year
254
274
Cash, cash equivalents, and restricted cash, end of year
$
417
$
254
Cash, cash equivalents and restricted cash consists of:
Cash
$
237
$
220
Short-term investments
157
0
Restricted cash
23
34
Cash, cash equivalents and restricted cash
$
417
$
254
Supplementary Information to Consolidated Statements of Cash Flows (note 30)
The accompanying notes are an integral part of these consolidated financial statements.
Emera Incorporated
Consolidated Statements of Changes in Equity
Accumulated
Other
Comprehensive
Non-
Common
Preferred
Contributed
Income
Retained
Controlling
Total
Stock
Surplus
(Loss)
(1)
Earnings
Interest
Equity
millions of Canadian dollars
Balance, December 31, 2020
$
6,705
$
1,004
$
79
$
(79)
$
1,495
$
34
$
9,238
Net income of Emera
incorporated
0
0
0
0
560
1
561
Other comprehensive income,
net of tax expense of $
14
0
0
0
104
0
0
104
Dividends declared on preferred
stock (note 28)
0
0
0
0
(50)
0
(50)
Dividends declared on common
stock ($
2.575
0/share)
0
0
0
0
(657)
0
(657)
Issuance of preferred shares,
net of after-tax issuance costs
(note 28)
0
418
0
0
0
0
418
Common stock issued under
purchase plan
235
0
0
0
0
0
235
Issuance of common stock, net
of after-tax issuance costs
284
0
0
0
0
0
284
Senior management stock
options exercised
14
0
0
0
0
0
14
Other
4
0
0
0
0
(1)
3
Balance, December 31, 2021
$
7,242
$
1,422
$
79
$
25
$
1,348
$
34
$
10,150
Balance, December 31, 2019
$
6,216
$
1,004
$
78
$
95
$
1,173
$
35
$
8,601
Net income of Emera Inc
0
0
0
0
983
1
984
Other comprehensive loss, net of
tax expense of $
2
0
0
0
(174)
0
0
(174)
Dividends declared on preferred
stock (note 28)
0
0
0
0
(45)
0
(45)
Dividends declared on common
stock ($
2.4750
/share)
0
0
0
0
(609)
0
(609)
Common stock issued under
purchase plan
215
0
0
0
0
0
215
Issuance of common stock, net of
after-tax issuance costs
251
0
0
0
0
0
251
Senior management stock
options exercised
20
0
(1)
0
0
0
19
Adoption of credit losses
accounting standard
0
0
0
0
(7)
(7)
Other
3
0
2
0
0
(2)
3
Balance, December 31, 2020
$
6,705
$
1,004
$
79
$
(79)
$
1,495
$
34
$
9,238
(1) Accumulated Other Comprehensive Income (Loss) ("AOCI") ("AOCL")
The accompanying notes are an integral part of these consolidated financial statements.
Emera Incorporated
Notes to the Consolidated Financial Statements
As at December 31, 2021 and 2020
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, 2021, Emera’s reportable segments include the following:
●
utility, serving approximately
810,600
●
●
primary electricity supplier in Nova Scotia, serving approximately
536,000
●
investments related to an
824
Falls on the Lower Churchill River in Labrador being developed by Nalcor Energy. ENL’s two
investments are:
●
100
Maritime Link Project, a $
1.8
two
170
-kilometre sub-sea cables, connecting the island of Newfoundland and Nova
Scotia. This project went in service on January 15, 2018; and
●
37.4
Partnership (“LIL”), a $
3.7
Labrador to enable the transmission of Muskrat Falls energy between Labrador and
the island of Newfoundland. Construction of the LIL has been completed and Nalcor
recognized the first flow of energy from Labrador to Newfoundland in June 2018.
Muskrat Falls generators are completed and available fo r service and Nalcor is
forecasting it will achieve final commissioning of Muskrat Falls and LIL in the first half
of 2022. For further details, refer to note 27.
●
with regulated electric utilities that include:
●
electric utility on the island of Barbados, serving approximately
132,000
●
utility on Grand Bahama Island, serving approximately
19,000
●
51.9
regulated electric utility on the island of Dominica, serving approximately
35,700
and
●
19.5
integrated regulated electric utility on the island of St. Lucia.
On March 24, 2020, Emera completed the sale of Emera Maine which was previously included in the
Other Electric Utilities segment. Refer to note 4.
●
●
445,000
●
approximately
542,000
●
transmission company offering services in Florida;
●
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 Canada,
which expires in 2034; and
●
12.9
1,400
-kilometre
pipeline, that transports natural gas throughout markets in Atlantic Canada and the
northeastern United States.
●
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
633
Massachusetts.
●
reinsurance to Emera and certain affiliates;
●
financing subsidiaries of Emera;
●
deliver renewables and resilient energy to customers;
●
located in the United States; and
●
In 2020, the outbreak of COVID-19, resulted in governments worldwide enacting emergency measures to
combat the spread of the virus. Management considered the impact of COVID-19 in the Company’s
estimates and results and concluded the financial statements as of and for the year ended December 31,
2021 were not materially impacted.
Basis of Presentation
These consolidated financial statements are prepared and presented in accordance with United States
Generally Accepted Accounting Principles (“USGAAP”). In the opinion of management, these
consolidated financial statements 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, unless otherwise indicated.
Principles of Consolidation
The consolidated financial statements of Emera include the accounts of Emera Incorporated, its majority-
owned subsidiaries, and a variable interest entity (“VIE”) in which Emera is the primary beneficiary. For
further details on VIEs, refer to note 32. 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.
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 property, plant and equipment, regulatory assets,
regulated fuel for generation and purchased power, or operating, maintenance and general (“OM&G”),
depending on the nature of the transaction.
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 the 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, 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.
Management has analyzed the impact of the COVID-19 pandemic on its estimates and assumptions and
concluded that no material adjustments were required for the year ended December 31, 2021.
The extent of the future impact of COVID-19 on the Company’s financial results and business operations
cannot be predicted at this time and will depend on future developments, including the duration and
severity of the pandemic, timing and effectiveness of vaccinations, further potential government actions
and future economic activity and energy usage. Actual results may differ significantly from these
estimates.
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 Canadian dollars 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 the 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 United States dollar denominated debt held in Canadian dollar
functional currency companies as hedges of net investments in United States dollar 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 Revenue
Electric 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 is delivered to customers over time as the customer simultaneously receives and consumes the
benefits of the electricity. Electric revenues are recognized on an accrual basis and include billed and
unbilled revenues. Revenues related to the sale of electri city 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 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”) 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.
Regulated Gas Revenue
Gas revenues, including energy charges, demand charges, basic facilities charges and applicable
clauses and riders, are recognized when obligations under the terms of a contract are satisfied, which is
when gas is delivered to customers over time as the customer simultaneously receives and consumes the
benefits of the gas. Gas revenues are recognized on an accrual basis and include billed and unbilled
revenues. Revenues related to the distribution and sale of 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. At the end of each reporting period, the 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 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 usage, weather, and inter-period changes to customer
classes.
Non-regulated Revenue
Marketing and trading margins are comprised of Emera Energy’s corresponding purchases and sales of
natural gas and electricity, pipeline capacity costs and energy asset management revenues. Revenues
are recorded when obligations under terms of a 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 terms of a 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 (“ROU”) 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.
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
Property, plant and equipment are recorded at original cost, including allowance for funds used during
construction (“AFUDC”) or capitalized interest, net of contributions received in aid of construction.
The cost of additions, including betterments and replacements of units of property, plant and equipment,
are included in “Property, plant and equipment”. When units of regulated property, plant and equipment
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 property, plant and equipment occurs, gains and losses are included in income as the
dispositions occur.
The cost of property, plant and equipment represents the original cost of materials, contracted services,
direct labour, AFUDC for regulated property or interest for non-regulated property, asset retirement
obligations (“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 are expensed as incurred. Planned major maintenance projects that do not
increase the overall life of the related assets are expensed. 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 the appropriate 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.
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. For further detail, refer to note 22.
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, BLPC and Domlec 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 information, 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.
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 and PGS have 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 property, plant and equipment, depending on the nature of
the item being economically hedged. Tran sportation 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 is exposed to credit risk with respect to amounts receivable from customers. Credit
assessments may be conducted on new customers. Deposits are requested on accounts in accordance
with the Company’s policy. The Company also maintains provisions for expected credit losses, which are
assessed on a regular basis.
Management estimates credit losses related to accounts receivable after 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.
The economic impact of COVID-19 in the service territories in which Emera operates, has impacted the
aging of customer receivables resulting in higher allowances for credit losses related to customer
receivables, however it has not had a material impact on earnings.
Inventory
Fuel and materials inventories are valued using the weighted -average cost method. These inventories are
carried 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.
Management considered whether the potential impacts of the COVID-19 pandemic on undiscounted
future cash flows could indicate that long-lived assets are not recoverable. As at December 31, 2021,
there are no indications of impairment of Emera’s long-lived assets.
No impairment charges were recognized during the year ended December 31, 2021. In 2020, impairment
charges of $
25
26
“Impairment charges” in the Consolidated Statements of Income.
Goodwill
Goodwill is not amortized but is subject to an annual assessment for impairment at the reporting unit level
with interim impairment tests performed when impairment indicators are present. Reporting units are
generally determined at the operating segment level or one level below the operating segment level.
Reporting units with similar characteristics are grouped for the purpose of determining impairment, if any,
of goodwill. 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 as a reduction to goodwill and a charge to operating
expense. 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, valuation of the reporting units' net
operating loss (“NOL”), utility sector market performance and transactions, projected operating and
capital cash flows and the fair value of debt. Adverse changes in assumptions described above could
result in a future material impairment of the goodwill assigned to Emera’s reporting units with goodwill. As
part of the goodwill impairment assessment management considered the potential impacts of the COVID-
19 pandemic on the future earnings of the reporting units.
As of December 31, 2021, $
5.6
PGS and NMGC reporting units). Qualitative assessments were performed for these reporting units 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.
As of December 31, 2021, $
68
Company performed a quantitative impairment assessment for GBPC as this reporting unit is more
sensitive to changes in assumptions due to limited excess of fair value over the carrying value. The
assessment estimated that the fair value of the reporting unit exceeded its carrying value, including
goodwill, by approximately
12
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, including the impact of COVID-19. 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 impairment of equity
method investments was required in either 2021 or 2020.
Financial Assets
Equity investments, other than those accounted for under the equity method of accounting, 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 impairment of financial assets was required in either 2021 or 2020.
Asset Retirement Obligations
An ARO is recognized if a legal obligation exists in connection with the future disposal or removal costs
resulting from the permanent retirement, abandonment or sale of a long-lived asset. A legal obligation
may exist under an existing or enacted law or statute, written or oral contract, or by legal construction
under the doctrine of promissory estoppel.
An ARO represents the 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 property, plant and equipment 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.
2.
CHANGE IN ACCOUNTING POLICY
The new USGAAP accounting policies that are applicable to, and adopted by the Company in 2021, are
described as follows:
Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity
The Company adopted Accounting Standard Update ("ASU") 2020-06, Debt - Debt with Conversion and
Other Options (Subtopic 470-20) and Derivatives and Hedging - Contracts in Entity’s Own Equity
(Subtopic 815-40) effective January 1, 2021 using the modified retrospective approach. The standard
simplifies the accounting for convertible debenture debt instruments and convertible preferred stock, in
addition to amending disclosure requirements. The standard also updates guidance for the derivative
scope exception for contracts in an entity’s own equity and the related earnings per share guidance.
There was no material impact on the consolidated financial statements as a result of the adoption of this
standard.
Guaranteed Debt Securities Disclosure Requirements
The Company adopted ASU 2020-09, Debt (Topic 470): Amendments to SEC Paragraphs pursuant to
SEC Release No. 33-10762 effective December 31, 2021. The standard aligns with new SEC rules
relating to changes to the disclosure requirements for certain registered debt securities that are
guaranteed. The changes include simplifying and focusing the disclosure models, enhancing certain
narrative disclosures and permitting the disclosures to be made outside of the financial statements. As a
result of adopting this standard, the disclosures related to certain registered debt securities that are
guaranteed were amended and removed from the consolidated financial statements and added to
Management’s Discussion & Analysis.
3. FUTURE ACCOUNTING PRONOUNCEMENTS
The Company considers the applicability and impact of all ASUs issued by the Financial Accounting
Standards Board (“FASB”). The ASUs that have been issued by FASB, but are not yet effective, were
assessed and determined to be either not applicable to the Company or have an insignificant impact on
the consolidated financial statements.
4.
DISPOSITIONS
On March 24, 2020, Emera completed the sale of
Emera Maine
approximately $
2.0
1.4
adjustments. A gain on disposition of $
585
309
recognized in the Other segment and included in “Other income” on the Consolidated Statements of
Income.
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.
5
Utilities, Other Electric Utilities, Gas Utilities and Infrastructure, and Other.
Florida
Canadian
Other
Gas Utilities
Inter-
Electric
Electric
Electric
and
Segment
millions of Canadian dollars
Utility
Utilities
Utilities
Infrastructure
Other
Eliminations
Total
For the year ended December 31, 2021
Operating revenues from
external customers (1)
$
2,718
$
1,501
$
445
$
1,276
$
(175)
$
$
5,765
Inter-segment revenues
(1)
6
0
0
4
18
(28)
2,724
1,501
445
1,280
(157)
(28)
5,765
Regulated fuel for generation
and purchased power
894
654
218
0
0
(3)
1,763
Regulated cost of natural gas
0
0
0
472
0
0
472
OM&G
536
291
140
325
93
(16)
1,369
Depreciation and amortization
469
246
58
121
8
0
902
Income from equity investments
0
103
4
20
16
0
143
AFUDC - debt and equity
77
8
0
7
0
0
92
Interest expense, net
138
132
21
51
269
0
611
Internally allocated interest (2)
0
0
0
13
(13)
0
0
Income tax expense (recovery)
72
9
1
62
(150)
0
(6)
Net income (loss) attributable to
common shareholders
462
241
21
198
(412)
0
510
Capital expenditures
1,331
366
111
515
5
0
2,328
As at December 31, 2021
Total assets
17,903
7,418
1,402
6,666
2,034
(1,179)
34,244
Investments subject to
significant influence
0
1,215
44
123
0
0
1,382
Goodwill
4,436
0
68
1,189
3
0
5,696
(1) All significant inter-company balances and inter-company transactions have been eliminated on consolidation except for certain
transactions between non-regulated and regulated entities that have not been eliminated because management believes the
elimination of these transactions would understate property, plant and equipment, OM&G expenses, 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.
(3) Primarily relates to consolidated deferred tax reclassifications. Deferred tax assets are reclassified and netted with deferred tax
liabilities upon consolidation.
Florida
Canadian
Other
Gas Utilities
Inter-
Electric
Electric
Electric
and
Segment
millions of Canadian dollars
Utility
Utilities
Utilities
Infrastructure
Other
Eliminations
Total
For the year ended December 31, 2020
Operating revenues from
external customers
(1)
$
2,473
$
1,494
$
474
$
1,051
$
14
$
$
5,506
Inter-segment revenues
(1)
7
0
0
7
15
(29)
2,480
1,494
474
1,058
29
(29)
5,506
Regulated fuel for generation
and purchased power
574
659
194
0
0
(7)
1,420
Regulated cost of natural gas
0
0
0
293
0
0
293
OM&G
552
282
151
334
115
(15)
1,419
Depreciation and amortization
455
236
71
111
8
0
881
Income from equity investments
0
96
4
20
29
0
149
AFUDC - debt and equity
54
4
1
9
0
0
68
Interest expense, net
151
139
32
56
301
0
679
Internally allocated interest (2)
0
0
0
13
(13)
0
0
Gain on sale, net of
transactions costs
Impairment charges
0
0
0
0
(25)
0
(25)
Income tax expense (recovery)
89
17
(8)
51
192
0
341
Net income attributable to
common shareholders
501
221
35
162
19
0
938
Capital expenditures
1,361
338
148
749
4
0
2,600
As at December 31, 2020
Total assets
16,889
6,752
1,365
6,067
1,234
(1,073)
31,234
Investments subject to
significant influence
0
1,176
41
129
0
0
1,346
Goodwill
4,455
0
68
1,194
3
0
5,720
(1) All significant inter-company balances and inter-company transactions have been eliminated on consolidation except for certain
transactions between non-regulated and regulated entities that have not been eliminated because management believes the
elimination of these transactions would understate property, plant and equipment, OM&G expenses, 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.
(3) Primarily relates to consolidated deferred tax reclassifications. Deferred tax assets are reclassified and netted with deferred tax
liabilities upon consolidation.
Geographical Information
Revenues
(based on country of origin of the product or service sold)
For the
Year ended December 31
millions of Canadian dollars
2021
2020
United States
$
3,754
$
3,522
Canada
1,566
1,569
Barbados
292
263
The Bahamas
110
112
Dominica
43
40
$
5,765
$
5,506
Property Plant and Equipment:
As at
December 31
December 31
millions of Canadian dollars
2021
2020
United States
$
14,978
$
14,353
Canada
4,440
4,304
Barbados
535
510
The Bahamas
322
289
Dominica
78
79
$
20,353
$
19,535
6. REVENUE
The following disaggregates the Company’s revenue by major source:
Florida
Canadian
Other
Gas Utilities
Inter-
Electric
Electric
Electric
and
Segment
millions of Canadian dollars
Utility
Utilities
Utilities
Infrastructure
Other
Eliminations
Total
For the year ended December 31, 2021
Regulated Electric Revenue
Residential
$
1,449
$
797
$
165
$
0
$
0
$
0
$
2,411
Commercial
754
407
232
0
0
0
1,393
Industrial
215
237
26
0
0
0
478
Other electric and regulatory
deferrals
289
27
7
0
0
0
323
Other (1)
17
33
15
1
0
(6)
60
2,724
1,501
445
1
0
(6)
4,665
Regulated Gas Revenue
Residential
0
0
0
642
0
0
642
Commercial
0
0
0
379
0
0
379
Industrial
0
0
0
65
0
(2)
63
Finance income (2)(3)
0
0
0
58
0
0
58
Other
121
0
(2)
119
0
0
0
1,265
0
(4)
1,261
Non-Regulated
Marketing and trading margin (4)
0
0
0
0
102
0
102
Energy sales
0
0
0
0
21
(21)
0
Other
0
0
0
14
9
0
23
Mark-to-market (3)
0
0
0
0
(289)
3
(286)
0
0
0
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.
Florida
Canadian
Other
Gas Utilities
Inter-
Electric
Electric
Electric
and
Segment
millions of Canadian dollars
Utility
Utilities
Utilities
Infrastructure
Other
Eliminations
Total
For the year ended December 31, 2020
Regulated Electric Revenue
Residential
$
1,365
$
806
$
179
$
0
$
0
$
0
$
2,350
Commercial
678
405
233
0
0
0
1,316
Industrial
178
224
32
0
0
0
434
Other electric and regulatory
deferrals
242
31
8
0
0
0
281
Other (1)
17
28
22
1
0
(7)
61
2,480
1,494
474
1
0
(7)
4,442
Regulated Gas Revenue
Residential
0
0
0
495
0
0
495
Commercial
0
0
0
275
0
0
275
Industrial
0
0
0
54
0
0
54
Finance income (2)(3)
0
0
0
61
0
0
61
Other
156
0
(7)
149
0
0
0
1,041
0
(7)
1,034
Non-Regulated
Marketing and trading margin (4)
0
0
0
0
38
0
38
Energy sales
0
0
0
0
16
(16)
0
Other
0
0
0
16
21
0
37
Mark-to-market (3)
0
0
0
0
(46)
1
(45)
0
0
0
16
29
(15)
30
Total operating revenues
$
2,480
$
1,494
$
474
$
1,058
$
29
$
(29)
$
5,506
(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, 2021, the
aggregate amount of the transaction price allocated to remaining performance obligations was $
437
million (2020 – $
464
142
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
2041
.
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 circumstanc es. 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 Canadian dollars
2021
2020
Regulatory assets
Deferred income tax regulatory assets
$
1,045
$
887
Tampa Electric capital cost recovery for early retired assets
657
0
Pension and post-retirement medical plan
291
394
Regulated fuel adjustment mechanism
145
0
NMGC winter event gas cost recovery
117
0
Cost recovery clauses
114
49
Storm restoration regulatory asset
35
41
Environmental remediations
27
28
Stranded cost recovery
26
26
Deferrals related to derivative instruments
23
65
Demand side management ("DSM") deferral
10
15
Unamortized defeasance costs
10
13
Other
66
66
$
2,566
$
1,584
Current
$
253
$
165
Long-term
2,313
1,419
Total regulatory assets
$
2,566
$
1,584
Regulatory liabilities
Deferred income tax regulatory liabilities
863
933
Accumulated reserve - cost of remova
l
819
865
Deferrals related to derivative instruments
241
15
Storm reserve
58
62
Cost recovery clauses
35
31
Self-insurance fund (note 32)
28
28
Regulated fuel adjustment mechanism
0
21
Other
11
6
$
2,055
$
1,961
Current
$
290
$
129
Long-term
1,765
1,832
Total regulatory liabilities
$
2,055
$
1,961
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.
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. See “Tampa Electric Big Bend Modernization Project” below for further information.
Pension and Post-Retirement Medical Plan
This asset is primarily related to the deferred costs of pension and post-retirement benefits at Tam pa
Electric, PGS and NMGC. It is included in rate base and earns a rate of return as permitted by the FPSC
and New Mexico Public Regulation Commission (“NMPRC”) as applicable. It is amortized over the
remaining service life of plan participants.
Regulated Fuel Adjustment Mechanism
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 fuel adjustment mechanism (“FAM”)
regulatory asset or liability and recovered from or returned to customers in a subsequent year. As
approved on December 6, 2019 as part of NSPI’s three-year fuel stability plan, differences between
actual fuel costs and fuel revenues recovered from customers for the years 2020 to 2022, will be
recovered or returned to customers after 2022. 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.
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. 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
of 30 months beginning July 1, 2021.
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 NMPRC, as
applicable, on a dollar-for-dollar basis in a subsequent period.
Storm Restoration Regulatory Asset
This asset represents storm restoration costs, primarily 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.
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 period. The recovery was implemented
through rates on January 1, 2021.
Restoration costs associated with Hurricane Matthew in 2016 are being recovered through an approved
fuel charge. Additional details on the recovery are included under the GBPC section below. The balance
of the regulatory asset as at December 31, 2021 is $
12
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.
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, operating, maintenance or general or
property, plant and equipment, depending on the nature of the item being economically hedged.
DSM Deferral
The UARB approved implementation of the 2015 DSM deferral set at $35 million in 2015 and recoverable
from customers over an 8-year period beginning in 2016.
The UARB directed EfficiencyOne, a franchisee appointed by the Province of Nova Scotia to provide
NSPI with electricity efficiency and conservation activities under the
Public Utilities Act
, to review
financing options through which EfficiencyOne would borrow the 2015 deferral amount from a commercial
lender in order to repay NSPI the amount it expended on behalf of its customers in 2015. In December
2016, EfficiencyOne secured financing and $
31
deferral. In February 2017, EfficiencyOne advanced an additional $
2
associated amounts from customers over the remaining
three years
, it will repay the balance to
EfficiencyOne. This has been set up as a liability in “Other long-term liabilities” with the current portion of
the liability included in “Other current liabilities” on the Consolidated Balance Sheets.
Unamortized Defeasance Costs
Upon privatization in 1992, NSPI became responsible for managing a portfolio of defeasance securities
held in trust that provide the principal and interest streams to match the related defeased debt, which as
at December 31, 2021, totalled $
200
582
investments over the face value of the related debt is deferred on the balance sheet and amortized over
the life of the defeased debt as permitted by the UARB.
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 property, plant and equipment. Non-ARO COR represent estimated funds received from
customers through depreciation rates to cover future COR of property, plant and equipment 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.
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 2021, 2020 and 2019, Tampa Electric incurred storm restoration
preparation costs for multiple hurricanes of approximately $
10
storm reserve regulatory liability
.
Regulatory Environments
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.
Tampa Electric’s approved regulated return on equity (“ROE”) range for 2021 and 2020 was
9.25
to
11.25
54
10.25
used for the calculation of the return on investments for clauses.
Beginning in 2022, Tampa Electric’s
approved regulated ROE range is
9.00
11.00
structure of
54
9.95
investments for clauses. See below for further detail.
Fuel Recovery
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 a subsequent year.
On January 19, 2022, Tampa Electric requested a mid-course adjustment to its fuel and capacity charges
to recover an additional $
169
fuel commodity and capacity costs. The FPSC is expected to issue its decision in March 2022.
On July 19, 2021, Tampa Electric requested a mid-course adjustment of $
83
capacity charges, effective with September 2021 customer bills, due to an increase in fuel commodity and
capacity costs in 2021. On August 3, 2021, the FPSC approved the request to recover the costs during
the months of September through December 2021.
Base rates
On August 6, 2021, Tampa Electric filed with the FPSC a joint motion for approval of a settlement
agreement (the “Settlement Agreement”) by Tampa Electric and the intervenors in relation to its rate case
filed with the FPSC in April 2021. The Settlement Agreement provides for a projected increase of $
191
million USD in rates annually, effective with January 2022 bills. This increase will consist of $
123
USD in base rate charges and $
68
coal generation assets Units 1 through 3 and meter assets. The Settlement Agreement further includes
two subsequent year adjustments of $
90
21
January 2024, respectively related to the recovery of future investments in the Big Bend Modernization
project and solar generation. The allowed equity in the capital structure will continue to be
54
from investor sources of capital. The Settlement Agreement includes an allowed regulated ROE range of
9.0
11.0
9.95
25
the allowed ROE range and mid-point, and $
10
yields exceed a specific threshold set on the date the FPSC votes to approve the agreement. Under the
agreement, base rates will not further change from January 1, 2022 through December 31, 2024, unless
Tampa Electric’s earned ROE were to fall below the bottom of the range during that time. The Settlement
Agreement contains a provision whereby Tampa Electric agrees to quantify the future impact of a change
in tax rates on net operating income through a reduction or increase in base revenues within 180 days of
when such tax change becomes law or its effective date. 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 which survives the term of that agreement. The Settlement Agreement 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 October 21, 2021, the FPSC approved the Settlement Agreement and the final order, reflecting
such approval, was issued in November 2021.
On April 9, 2019, Tampa Electric reached a settlement agreement with consumer parties regarding
eligible storm costs as a result of Hurricane Irma in 2017, which was approved by the FPSC on May 21,
2019. As a result, Tampa Electric refunded $
12
minimal impact to the Consolidated Statements of Income.
Solar Base Rate Adjustments Included in Base Rates
As of December 31, 2021, Tampa Electric has invested $
850
600
photovoltaic projects, which are recoverable through FPSC-approved solar base rate adjustments
(“SoBRAs”). AFUDC is being earned on these projects during construction. The FPSC has approved
SoBRAs representing a total of
600
104
for in-service projects.
The true-up filing for SoBRAs tranche 1 and 2 revenue requirement estimates that were included in base
rates as of September 2018 and January 2019, respectively, was submitted on April 30, 2020, and the
FPSC approved the amount on August 18, 2020. A $
5
2020. On October 12, 2021, the FPSC approved the true-up filing for SoBRA tranche 3, included in base
rates as of January 2020. An estimated $
4
true-up for SoBRA tranche 4 will be filed in early 2022.
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. Tampa Electric submitted its storm protection plan with the FPSC on April
10, 2020. On April 27, 2020, Tampa Electric submitted a settlement agreement with the FPSC which
specified a $
15
rates beginning January 1, 2021. On June 9, 2020, the FPSC approved this settlement agreement. On
August 3, 2020, Tampa Electric submitted another settlement agreement to the FPSC for approval,
including cost recovery of approximately $
39
2020 and 2021. This cost recovery includes the $
15
settlement agreement was approved on August 10, 2020 and Tampa Electric’s cost recovery began in
January 2021. The current approved plan will apply for the years 2020, 2021 and 2022, and
Tampa
Electric will file a new plan in April 2022 to determine cost recovery in 2023, 2024, and 2025.
The June 9, 2020 settlement agreement approved by the FPSC disclosed above also included approval
of Tampa Electric’s petition to eliminate its $
16
intangible software assets through a credit to amortization expense in 2020.
Big Bend Modernization Project
Tampa Electric expects to invest approximately $
850
the Big Bend Power Station,
of which approximately $
695
December 31, 2021. The modernization project will repower Big Bend Unit 1 with natural gas combined-
cycle technology and eliminate 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 operationa l perspectives.
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 depreciate 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.
Tampa Electric’s Settlement Agreement provides recovery for the Big Bend Modernization project in two
phases. The first phase is 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
will survive the termination of the Settlement Agreement. The special capital recovery schedule for all
three units was applied beginning January 1, 2022.
Canadian Electric Utilities
NSPI
NSPI is a public utility as defined in the
Public Utilities Act of Nova Scotia
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 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 2021 and 2020 was
8.75
9.25
quarter average regulated common equity component of up to
40
NSPI has a FAM, approved by UARB which enables it to seek recovery of its fuel costs from customers
through regularly scheduled fuel rate adjustments. Differences between actual 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 years.
NSPI is currently operating under a
three
-year fuel stability plan which results in an average annual
overall rate increase of
1.5
include recovery of Maritime Link costs.
On January 27, 2022, NSPI filed a General Rate Application (“GRA”) with the UARB. The GRA proposes
a rate stability plan for 2022 through 2024 which includes average base rate increases of
2.9
year and average fuel rate increases pursuant to the FAM of
0.8
January 1, 2023 and January 1, 2024. The proposed rates would result in annualized incremental
revenue (base and fuel rates) increases of $
52
21
through December 31, 2022), $
54
56
expected later this year.
The Maritime Link is a $
1.8
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. The
UARB approved 2021 interim cost assessment recovery payment to NSPML was $
172
$
145
139
135
The
approved interim cost assessment payments are subject to a holdback of up to $10 million pending UARB
agreement that benefits from the Maritime Link are realized for NSPI customers
. For 2021, NSPI has
recorded a $
10
4
collection of $
23
to pay to NSPML approximately $
10
As part of a
three
-year fuel stability plan, electricity rates have been set to include the $
145
approved Maritime Link assessment for 2020 and amounts of $
164
162
2022, respectively. Any difference between the amounts included in the fuel stability plan and those
approved by the UARB through the NSPML interim assessment application will be addressed through the
FAM.
In response to the delayed timing of energy delivery from the Muskrat Falls project, which is being
developed by Nalcor Energy, the approved Maritime Link interim assessment payment in 2019 reflected a
reduction in NSPML’s assessment, related to depreciation and amortization expenses. The UARB’s
decision to approve NSPI’s 2020 through 2022 fuel stability plan outlined the treatment of the reduced
2019 NSPML assessment of $52 million plus interest. NSPI refunded approximately $40 million plus
interest to customers, and the remaining $12 million plus interest will be returned to customers
subsequent to 2022.
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 NS Block delivery obligations commenced on August 15, 2021 and delivery will continue over the
next
35
application with the UARB seeking approval to recover capital costs associated with the Maritime Link
and approval of NSPML’s 2022 assessment. In December 2021, NSPML obtained an interim decision
from the UARB approving interim rates beginning January 1, 2022, until receipt of the UARB’s decision
on the application. On February 9, 2022, the UARB issued its decision relating to the Maritime Link
Project, approving NSPML’s requested rate base of approximately $
1.8
otherwise have been recoverable if incurred by NSPI. The UARB also approved approximately $
168
million of NSPML revenue requirement in 2022 subject to a holdback of $
2
April 1, 2022 and thereafter to the end of the year. This holdback is to be used to fund any replacement
energy costs incurred by NSPI due to a 10 per cent or greater shortfall in contracted NS Block deliveries
each month and will otherwise be released to NSPML. NSPML is required to provide the UARB with a
compliance filing by February 16, 2022 which will confirm the impacts of this decision including the
amount of the unrecoverable items which are not expected to exceed $
10
Other Electric Utilities
The Barbados Light & Power Company Limited
BLPC is regulated by the Fair Trading Commission (“FTC”), an independent regulator, under the Utilities
Regulation (Procedural) Rules 2003. 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. Following a general election called late in 2021 for January 19, 2022, the new licenses are
expected to take effect in 2022 on completion of the legislative process. The Dispatch license will have a
term of
5 years
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 currently assessing the full impact of the new
licenses on its business and working towards the successful implementation of the licenses.
BLPC is regulated under a cost-of-service model, with rates set to recover prudently incurred costs of
providing electricity service to customers and provide an appropriate return to investors. BLPC’s
approved regulated return on rate base was
10
BLPC has a fuel pass-through mechanism which provides the opportunity to recover all prudently
incurred fuel costs from customers in a timely manner. The approved calculation of the fuel charge is
adjusted monthly and reported to the regulator.
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
second half of 2022.
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 the first half of 2022.
In December 2018, the Government of Barbados signed the
Income Tax Amendment Act
legislation, which was effective January 1, 2019, created a new corporate income tax rate schedule and
eliminated certain tax credits. At the date of enactment, BLPC was required to remeasure its deferred
income tax liability at the new lower corporate income tax rate, resulting in recognition of an income tax
recovery of $
10
7
was recognized in earnings in Q1 2020.
Grand Bahama Power Company Limited
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. There is a fuel pass-
through mechanism and tariff review policy with new rates submitted every three years. GBPC’s approved
regulated return on rate base was
8.37
8.34
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 becomes effective April 1, 2022, allows for
an increase in revenues of $
3.5
12.84
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. In September 2021, GBPC filed an application for rate
review with the GBPA. As part of its decision 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.
Dominica Electricity Services Ltd
Domlec is regulated by the Independent Regulatory Commission, Dominica. On October 7, 2013, the
Independent Regulatory Commission, Dominica issued a Transmission, Distribution & Supply License
and a Generation License, both of which came into effect on January 1, 2014, for a period of
25
years. Domlec’s approved allowable regulated return on rate base was
15
Domlec has a fuel pass-through mechanism which provides opportunity to recover substantially all
prudently incurred fuel costs in a timely manner.
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 2021 was
8.9
11.0
9.9
based on an allowed equity capital structure of
54.7
9.25
11.75
54.7
10.75
PGS recovers the costs it pays for gas supply and interstate transportation for system supply through its
purchased gas adjustment clause. 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.
The FPSC annually approves cost-recovery rates for conservation costs and Cast Iron/Bare Steel Pipe
Replacement costs, including a return on capital invested incurred in developing and implementing
energy conservation programs. The Cast Iron/Bare Steel Pipe Replacement clause is to recover the cost
of accelerating the replacement of cast iron and bare steel distribution lines in the PGS system. The
FPSC approved a replacement program of approximately
5
800
system at a cost of approximately $
80
10
-year period beginning in 2013.
In February
2017, the FPSC approved an amendment to the cast iron bare steel rider to include certain plastic
materials and pipe deemed obsolete by Pipeline and Hazardous Materials Safety Administration, totaling
approximately
880
removed from its system by the end of 2022, with the replacement of obsolete plastic pipe continuing until
2028 under the rider.
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
accumulated depreciation to date. 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
capital structure of
54.7
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 2021 was
9.375
52
The approved ROE for 2020 was
9.10
52
NMGC recovers gas supply costs through a purchased gas adjustment clause (“PGAC”). This clause
recovers NMGC’s actual costs for purchased gas, gas storage services, interstate pipeline capacity, and
other related items associated with the purchase, transmi ssion, 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.
In February 2021, the State of New Mexico experienced an extreme cold weather event that resulted in
an incremental $
108
On June 15, 2021, the NMPRC approved the recovery over a period of
30
2021. For more information, refer to the “NMGC Winter Event Gas Cost Recovery” section above.
On December 16, 2020, the NMPRC approved a settlement agreement for new rates that became
effective on January 1, 2021. The new rates reflect the recovery of capital investment in pipelines and
related infrastructure and resulted in an increase in revenue of approximately $
5
On December 13, 2021, NMGC filed a rate case with the NMPRC for new rates to become effective
January 2023. NMGC requested a $
41
increased operating costs and capital investments in pipelines and related infrastructure. A decision from
the NMPRC is expected by the end of 2022.
Brunswick Pipeline
Brunswick Pipeline is a
145
-kilometre pipeline delivering natural gas from the Canaport™ 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
Canada. The agreement provides for a predetermined toll increase in the fifth and fifteenth year of the
contract. The pipeline is considered a Group II pipeline regulated by the Canada Energy Regulator
(“CER”). The CER Gas Transportation Tariff is filed by Brunswick Pipeline in compliance with the
requirements of the
CER Act
Brunswick Pipeline.
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 Canadian dollars
2021
2020
2021
2020
2021
LIL
(1)
$
682
$
629
$
54
$
49
37.4
NSPML
533
547
49
47
100.0
M&NP
123
129
20
20
12.9
Lucelec
(2)
44
41
4
4
19.5
Bear Swamp
0
0
16
29
50.0
$
1,382
$
1,346
$
143
$
149
(1) Emera indirectly owns
100
24.9
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 $
104
118
Consolidated Balance Sheets.
Equity investments include a $
8
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 Canadian dollars
2021
2020
Balance Sheets
Current assets
$
25
$
57
Property, plant and equipment
1,587
1,629
Regulatory assets
247
210
Non-current assets
31
32
Total assets
$
1,890
$
1,928
Current liabilities
$
50
$
56
Long-term debt
(1)
1,189
1,228
Non-current liabilities
118
97
Equity
533
547
Total liabilities and equity
$
1,890
$
1,928
(1) The project debt has been guaranteed by the Government of Canada.
9. OTHER INCOME, NET
Other income, net consisted of the following:
For the
Year ended December 31
millions of Canadian dollars
2021
2020
Allowance for equity funds used during construction
$
61
$
45
Gain on sale of Emera Maine, net of transaction costs
0
585
TECO Guatemala Holdings award
(2)
0
49
Other
32
29
$
93
$
708
(1) Refer to note 4 for further detail related to the gain on sale of Emera Maine.
(2) 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 Canadian dollars
2021
2020
Income before provision for income taxes
$
555
$
1,325
Statutory income tax rate
29.0%
29.5%
Income taxes, at statutory income tax rate
161
391
Additional impact from the sale of Emera Maine
0
102
Deferred income taxes on regulated income recorded as regulatory assets and
regulatory liabilities
(62)
(48)
Foreign tax rate variance
(42)
(45)
Amortization of deferred income tax regulatory liabilities
(33)
(44)
Tax effect of equity earnings
(16)
(15)
Tax credits
(13)
(12)
Revaluation of deferred income taxes due to change in Nova Scotia tax rate
0
12
Other
(1)
0
Income tax (recovery) expense
$
(6)
$
341
Effective income tax rate
(1%)
26%
The change in the effective income tax rate was primarily due to decreased income before provision for
income taxes and the additional impact from the sale of Emera Maine in 2020.
On March 10, 2020, Bill 243 of the Nova Scotia Financial Measures (2020) Act was enacted, which
included a reduction in the Nova Scotia provincial corporate income tax rate. As a result, the Company's
combined Canadian federal and provincial statutory income tax rate was reduced from
31
29.5
per cent for 2020, and further reduced to
29
As a result of the change in tax rate in 2020, the Company recorded a reduction of $
52
deferred income tax liabilities and an offsetting reduction to its net deferred income tax regulatory asset,
as the benefit of lower net deferred income tax liabilities is expected to be returned to customers in future
years. The Company also recognized a $
12
certain net deferred income tax assets.
On March 27, 2020, the United States Coronavirus Aid, Relief, and Economic Security (CARES) Act (“the
CARES Act”) was signed into law. Under the CARES Act, companies can accelerate the refund of
alternative minimum tax (“AMT”) credit carryforwards. As a result, the Company received the balance of
its $
145
material impacts from the CARES Act.
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 Canadian dollars
2021
2020
Current income taxes
$
20
$
18
11
(58)
Deferred income taxes
(33)
20
118
426
2
(9)
Investment tax credits
(11)
(10)
Operating loss carryforwards
(64)
(46)
(49)
0
Income tax (recovery) expense
$
(6)
$
341
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 Canadian dollars
2021
2020
$
244
$
176
289
1,142
22
7
Income before provision for income taxes
$
555
$
1,325
The deferred income tax assets and liabilities presented in the Consolidated Balance Sheets as at
December 31 consisted of the following:
millions of Canadian dollars
2021
2020
Deferred income tax assets:
Tax loss carryforwards
$
873
$
724
Tax credit carryforwards
375
319
Derivative instruments
188
108
Regulatory liabilities - cost of removal
170
184
Other
434
375
Total deferred income tax assets before valuation allowance
2,040
1,710
Valuation allowance
(256)
(202)
Total deferred income tax assets after valuation allowance
$
1,784
$
1,508
Deferred income tax (liabilities):
Property, plant and equipment
$
(2,622)
$
(2,450)
Derivative instruments
(197)
(93)
Other
(538)
(385)
Total deferred income tax liabilities
$
(3,357)
$
(2,928)
Consolidated Balance Sheets presentation:
Long-term deferred income tax assets
$
295
$
209
Long-term deferred income tax liabilities
(1,868)
(1,629)
Net deferred income tax liabilities
$
(1,573)
$
(1,420)
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 investments. A valuation allowance
of $
256
202
carryforwards and investments.
The Company intends to indefinitely reinvest earnings from certain foreign operations. Accordingly, $
2.9
billion as at December 31, 2021 (2020 - $
2.7
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.
Emera’s net operating loss (“NOL”), capital loss and tax credit carryforwards and their expiration periods
as at December 31, 2021 consisted of the following:
Subject to
Tax
Valuation
Net Tax
Expiration
millions of Canadian dollars
Carryforwards
Allowance
Carryforwards
Period
Canada
$
1,776
$
(791)
$
985
2026 - 2041
75
(75)
0
Indefinite
United States
$
1,521
$
0
$
1,521
2032 - Indefinite
817
0
817
2032 - Indefinite
375
0
375
2025 - 2041
Other
$
52
$
(38)
$
14
2022 - 2028
The following table provides details of the change in unrecognized tax benefits for the years ended
December 31 as follows:
millions of Canadian dollars
2021
2020
Balance, January 1
$
30
$
29
Increases due to tax positions related to current year
4
1
Increases due to tax positions related to a prior year
1
2
Decreases due to tax positions related to a prior year
(1)
(2)
Decreases due to settlement with tax authorities
(6)
0
Balance, December 31
$
28
$
30
The total amount of unrecognized tax benefits as at December 31, 2021 was $
28
30
million), which would affect the effective tax rate if recognized. The total amount of accrued interest with
respect to unrecognized tax benefits was $
6
6
recognized in the Consolidated Statements of Income (2020 - $
1
NaN
accrued. The balance of unrecognized tax benefits could change in the next 12 months as a result of
resolving Canada Revenue Agency (“CRA”) and Internal Revenue Service audits. A reasonable estimate
of any change cannot be made at this time.
NSPI and the CRA are currently in a dispute with respect to the timing of certain tax deductions for
NSPI’s 2006 through 2010 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 $
62
million, including interest. NSPI has prepaid $
23
On November 29, 2019, NSPI filed a Notice of Appeal with the Tax Court of Canada with respect to its
dispute. 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 excess, if any, owing to 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 Appeal process is not
determinable at this time.
Emera files a Canadian federal income tax return, which includes its Nova Scotia and New Brunswick
provincial income tax. Emera’s subsidiaries file Canadian, US, Barbados, St. Lucia and Dominica income
tax returns. As at December 31, 2021, 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.
2021
2020
Issued and outstanding:
millions
of shares
Canadian
dollars
millions of
shares
Canadian
dollars
Balance, December 31, 2020
251.43
$
6,705
242.48
$
6,216
Issuance of common stock
(1)(2)
4.99
284
4.54
251
Issued under Purchase Plans at market rate
4.32
239
3.99
219
Discount on shares purchased under Dividend Reinvestment Plan
0
(4)
0
(4)
Options exercised under senior management share option plan
0.33
14
0.42
20
Employee Share Purchase Plan
0
4
0
3
Balance, December 31, 2021
261.07
$
7,242
251.43
$
6,705
(1) As at December 31, 2020, a total of
4,544,025
at an average price of $
56.04
255
251
(2) For the year ended December 31, 2021,
4,987,123
of $
57.63
287
284
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, 2021, an aggregate gross sales limit of
$
457
As at December 31, 2021, the following common shares were reserved for issuance:
6.2
3.5
3.1
3.5
employee common share purchase plan and
14.2
5.1
reinvestment plan (“DRIP”).
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 (“EPS”) is determined by dividing net income attributable to common
shareholders by the weighted average number of common shares and DSUs outstanding during the
period. Diluted EPS is computed by dividing net income attributable to common shareholders by the
weighted average number of common shares and DSUs 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 dividend reinvestment plan.
The following table reconciles the computation of basic and diluted earnings per share:
For the
Year ended December 31
millions of Canadian dollars (except per share amounts)
2021
2020
Numerator
Net income attributable to common shareholders
$
510.5
$
937.6
Diluted numerator
510.5
937.6
Denominator
Weighted average shares of common stock outstanding
255.9
246.5
Weighted average deferred share units outstanding
1.3
1.3
Weighted average shares of common stock outstanding – basic
257.2
247.8
Stock-based compensation
0.4
0.4
Weighted average shares of common stock outstanding – diluted
257.6
248.2
Earnings per common share
Basic
$
1.98
$
3.78
Diluted
$
1.98
$
3.78
13. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
The components of accumulated other comprehensive income are as follows:
millions of Canadian dollars
Unrealized
(loss) gain on
translation of
self-sustaining
foreign
operations
Net change in
net investment
hedges
(Losses)
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, 2021
Balance, January 1, 2021
$
52
$
30
$
1
$
(1)
$
(161)
$
(79)
Other comprehensive
income (loss) before
reclassifications
(42)
5
18
0
0
(19)
Amounts reclassified from
accumulated other
comprehensive income
(loss)
0
0
(1)
0
124
123
Net current period other
comprehensive income
(loss)
(42)
5
17
0
124
104
Balance, December 31,
2021
$
10
$
35
$
18
$
(1)
$
(37)
$
25
For the year ended December 31, 2020
Balance, January 1, 2020
$
253
$
4
$
(1)
$
(1)
$
(160)
$
95
Other comprehensive
income (loss) before
reclassifications
(201)
26
0
0
0
(175)
Amounts reclassified from
accumulated other
comprehensive income
(loss)
0
0
2
0
(1)
1
Net current period other
comprehensive income
(loss)
(201)
26
2
0
(1)
(174)
Balance, December 31,
2020
$
52
$
30
$
1
$
(1)
$
(161)
$
(79)
The reclassifications out of accumulated other comprehensive income (loss) are as follows:
For the
Year ended December 31
millions of Canadian dollars
2021
2020
Affected line item in the Consolidated Financial Statements
(Gains) Losses on derivatives recognized as cash flow hedges
Operating revenue – regulated
$
0
$
2
Interest expense, net
(1)
0
Total
$
(1)
$
2
Net change in unrecognized pension and post-retirement benefit costs
Other income, net
$
24
$
15
Other income, net
0
(1)
Pension and post-retirement benefits
102
(16)
Total before tax
126
(2)
Income tax (expense) recovery
(2)
1
Total net of tax
$
124
$
(1)
Total reclassifications out of AOCI, net of tax, for the period
$
123
$
1
14. INVENTORY
As at
December 31
December 31
millions of Canadian dollars
2021
2020
Fuel
$
255
$
199
Materials
283
254
$
538
$
453
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 Canadian dollars
2021
2020
2021
2020
Cash flow hedges
Interest rate hedge
$
0
$
1
$
0
$
0
Regulatory deferral
Commodity swaps and forwards
22
1
1
6
83
10
8
34
20
4
7
2
21
1
0
5
Foreign exchange forwards
7
0
8
17
Physical natural gas purchases and sales
88
0
0
0
241
16
24
64
HFT derivatives
Power swaps and physical contracts
33
13
32
13
Natural gas swaps, futures, forwards, physical
contracts
208
139
818
346
241
152
850
359
Other derivatives
Equity derivatives
11
0
0
1
Foreign exchange forwards
0
15
0
0
11
15
0
1
Total gross current derivatives
493
184
874
424
Impact of master netting agreements with intent to
settle net or simultaneously
(192)
(86)
(192)
(86)
Total derivatives
$
301
$
98
$
682
$
338
Current
$
195
$
73
$
533
$
251
Long-term
106
25
149
87
Total derivatives
$
301
$
98
$
682
$
338
Derivative assets and liabilities are classified as current or long-term based upon the maturities of the
underlying contracts.
Details of master netting agreements, shown net on the Consolidated Balance Sheets, are summarized in
the following table:
Derivative Assets
Derivative Liabilities
As at
December 31
December 31
December 31
December 31
millions of Canadian dollars
2021
2020
2021
2020
Regulatory deferral
$
4
$
2
$
4
$
2
HFT derivatives
188
84
188
84
Total impact of master netting agreements with
intent to settle net or simultaneously
$
192
$
86
$
192
$
86
Cash Flow Hedges
On May 26, 2021 the treasury lock was settled for a gain of $
18
through interest expense over
10 years
. As of December 31, 2021, there were
0
hedges.
The amounts related to cash flow hedges recorded in income and AOCI consisted of the following:
For the
Year ended December 31
millions of Canadian dollars
2021
2020
Interest
Foreign
rate hedge
exchange forwards
Realized loss in operating revenue – regulated
$
0
$
(2)
Realized gain in interest expense, net
1
0
Total gains (losses) in net income
$
1
$
(2)
As at
December 31
millions of Canadian dollars
2021
2020
Interest
Interest
rate hedge
rate hedge
Total unrealized gain in AOCI – effective portion, net of tax
$
18
$
1
The Company expects $
2
within the next 12 months.
Regulatory Deferral
The Company has recorded the following changes in realized and unrealized gains (losses) with respect
to derivatives receiving regulatory deferral:
For the
Year ended December 31
millions of Canadian dollars
2021
Natural gas
Commodity
swaps and
forwards
Foreign
exchange
forwards
Unrealized gain (loss) in regulatory assets
$
0
$
(7)
$
9
Unrealized gain (loss) in regulatory liabilities
88
218
(3)
Realized (gain) in regulatory liabilities
0
(3)
0
Realized (gain) loss in inventory
(1)
0
(8)
5
Realized (gain) loss in regulated fuel for generation and purchased
power
(2)
0
(39)
5
Total change derivative instruments
$
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.
For the
Year ended December 31
millions of Canadian dollars
2020
Natural gas
Commodity
swaps and
forwards
Foreign
exchange
forwards
Unrealized gain (loss) in regulatory assets
$
0
$
(36)
$
(11)
Unrealized gain (loss) in regulatory liabilities
0
3
3
Realized gain (loss) in regulatory assets
0
2
0
Realized (gain) loss in regulatory liabilities
0
14
0
Realized (gain) loss in inventory
(1)
0
8
(2)
Realized (gain) loss in regulated fuel for generation and purchased
power
(2)
0
24
(3)
Total change derivative instruments
$
0
$
15
$
(13)
(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.
Commodity Swaps and Forwards
As at December 31, 2021, the Company had the following notional volumes of commodity swaps and
forward contracts designated for regulatory deferral that are expected to settle as outlined below:
2022
2023-2024
millions
Purchases
Purchases
Natural Gas (Mmbtu)
17
22
Power (MWh)
1
2
Foreign Exchange Swaps and Forwards
As at December 31, 2021, the Company had the following notional volumes of foreign exchange swaps
and forward contracts designated for regulated deferral that are expected to settle as outlined below:
2022
2023-2024
Foreign exchange contracts (millions of US dollars)
$
170
$
150
Weighted average rate
1.3047
1.2413
% of USD requirements
65%
29%
The Company reassesses foreign exchange forecasted periodically and will enter into additional hedges
or unwind existing hedges, as required.
Held-for-Trading Derivatives
In the ordinary course of its business, Emera enters into physical contracts for the purchase and sale of
natural gas, as well as power and natural gas swaps, forwards and futures, to economically hedge those
physical contracts. These derivatives are all considered HFT.
The Company has recognized the following realized and unrealized gains (losses) with respect to HFT
derivatives:
For the
Year ended December 31
millions of Canadian dollars
2021
2020
Power swaps and physical contracts in non-regulated operating revenues
$
4
$
(1)
Natural gas swaps, forwards, futures and physical contracts in non-regulated
operating revenues
(142)
205
Power swaps, forwards, futures and physical contracts in non-regulated fuel for
generation and purchased power
0
(4)
$
(138)
$
200
As at December 31, 2021, the Company had the following notional volumes of outstanding HFT
derivatives that are expected to settle as outlined below:
millions
2022
2023
2024
2025
2026
Natural gas purchases (Mmbtu)
308
91
56
26
26
Natural gas sales (Mmbtu)
335
103
30
2
2
Power purchases (MWh)
1
0
0
0
0
Power sales (MWh)
2
0
0
0
0
Other Derivatives
As at December 31, 2021, the Company had equity derivatives in place to manage the cash flow risk
associated with forecasted future cash settlements of deferred compensation obligations and foreign
exchange forwards in place to manage cash flow risk associated with forecasted USD cash inflows.
The
equity derivative hedges the return on
2.8
exchange forwards have a combined notional amount of $
52
2023.
For the
Year ended December 31
millions of Canadian dollars
2021
2020
Foreign
Foreign
Exchange
Equity
Exchange
Equity
Forwards
Derivatives
Forwards
Derivatives
Unrealized gain (loss) in operating, maintenance and general
$
0
$
11
$
0
$
(1)
Unrealized gain (loss) in other income (expense), net
(15)
0
15
0
Realized gain (loss) in operating, maintenance and general
0
15
0
(3)
Realized gain (loss) in other income (expense)
18
0
(2)
0
Total gains (losses) in net income
$
3
$
26
$
13
$
(4)
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, 2021, the maximum exposure the Company has to credit risk is $
1.3
$
805
derivatives.
It is possible that volatility in commodity prices could cause the Company to have material credit risk
exposures with one or more counterparties. If such counterparties fail to perform their obligations under
one or more agreements, the Company could suffer a material financial loss. The Company transacts with
counterparties as part of its risk management strategy for managing commodity price, foreign exchange
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, 2021 was $
341
251
which 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 (“ISDA”), North American Energy Standards Board agreements
(“NAESB”) and, or Edison Electric Institute agreements. The Company believes that entering into such
agreements offers protection by creating contractual rights relating to creditworthiness, collateral, non-
performance and default.
As at December 31, 2021, the Company had $
114
123
considered to be past due, which have been outstanding for an average
57
financial assets is $
93
101
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, 2021
December 31, 2020
millions of
Canadian
dollars
% of total
exposure
millions of
Canadian
dollars
% of total
exposure
Receivables, net
Regulated utilities
Residential
$
384
24%
$
341
32%
Commercial
167
10%
143
14%
Industrial
54
3%
49
5%
Other
91
6%
96
9%
696
43%
629
60%
Trading group
Credit rating of A- or above
66
4%
54
5%
Credit rating of BBB- to BBB+
107
7%
41
4%
Not rated
132
8%
75
7%
305
19%
170
16%
Other accounts receivable
329
20%
159
15%
1,330
82%
958
91%
Derivative Instruments
(current and long-term)
Credit rating of A- or above
155
9%
60
6%
Credit rating of BBB- to BBB+
22
1%
13
1%
Not rated
124
8%
25
2%
301
18%
98
9%
$
1,631
100%
$
1,056
100%
Cash Collateral
The Company’s cash collateral positions consisted of the following:
As at
December 31
December 31
millions of Canadian dollars
2021
2020
Cash collateral provided to others
$
212
$
69
Cash collateral received from others
$
100
$
6
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, 2021, the total fair value of derivatives in a liability position was $
682
(December 31, 2020
–
338
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.
The following tables set out the classification of the methodology used by the Company to fair value its
derivatives:
As at
December 31, 2021
millions of Canadian dollars
Level 1
Level 2
Level 3
Total
Assets
Regulatory deferral
Commodity swaps and forwards
$
0
$
22
$
0
$
22
83
0
0
83
15
1
0
16
3
18
0
21
Foreign exchange forwards
0
7
0
7
Physical natural gas purchases and sales
0
0
88
88
101
48
88
237
HFT derivatives
Power swaps and physical contracts
4
5
4
13
Natural gas swaps, futures, forwards, physical
contracts and related transportation
(1)
29
12
40
3
34
16
53
Other derivatives
Equity derivatives
11
0
0
11
Total assets
115
82
104
301
Liabilities
Regulatory deferral
Commodity swaps and forwards
7
0
0
7
0
5
0
5
Foreign exchange forwards
0
8
0
8
7
13
0
20
HFT derivatives
Power swaps and physical contracts
4
5
3
12
Natural gas swaps, futures, forwards and physical
contracts
13
122
515
650
17
127
518
662
Total liabilities
24
140
518
682
Net assets (liabilities)
$
91
$
(58)
$
(414)
$
(381)
As at
December 31, 2020
millions of Canadian dollars
Level 1
Level 2
Level 3
Total
Assets
Cash flow hedges
Interest rate hedge
$
1
$
0
$
0
$
1
1
0
0
1
Regulatory deferral
Commodity swaps and forwards
9
0
0
9
2
1
0
3
0
2
0
2
11
3
0
14
HFT derivatives
Power swaps and physical contracts
3
2
2
7
Natural gas swaps, futures, forwards, physical
contracts and related transportation
1
48
12
61
4
50
14
68
Other derivatives
Foreign exchange forwards
0
15
0
15
0
15
0
15
Total assets
16
68
14
98
Liabilities
Regulatory deferral
Commodity swaps and forwards
0
4
0
4
33
0
0
33
3
3
0
6
0
2
0
2
Foreign exchange forwards
0
17
0
17
36
26
0
62
HFT derivatives
Power swaps and physical contracts
4
2
1
7
Natural gas swaps, futures, forwards and physical
contracts
1
10
257
268
5
12
258
275
Other derivatives
Equity derivatives
1
0
0
1
1
0
0
1
Total liabilities
42
38
258
338
Net assets (liabilities)
$
(26)
$
30
$
(244)
$
(240)
The change in the fair value of the Level 3 financial assets for the year ended December 31, 2021 was as
follows:
Regulatory Deferral
HFT Derivatives
millions of Canadian dollars
Physical natural
gas purchases and
sales
Power
Natural
gas
Total
Balance, January 1, 2021
$
0
$
2
$
12
$
14
Unrealized gains included in regulatory assets or
liabilities
88
0
0
88
Total realized and unrealized gains included in
non-regulated operating revenues
2
0
2
Balance, December 31, 2021
$
88
$
4
$
12
$
104
The change in the fair value of the Level 3 financial liabilities for the year ended December 31, 2021 was
as follows:
millions of Canadian dollars
Power
Natural
gas
Total
Balance, January 1, 2021
$
1
$
257
$
258
Total realized and unrealized losses included in non-regulated
operating revenues
2
258
260
Balance, December 31, 2021
$
3
$
515
$
518
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; 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. Significant increases (decreases) in any of these
inputs in isolation would result in a significantly lower (higher) fair value measurement.
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:
As at
December 31, 2021
millions of Canadian dollars
Fair
Value
Valuation
Technique
Unobservable Input
Range
Weighted
average
(1)
Assets
Regulatory deferral – Physical
$
88
Modelled pricing
Third-party pricing
$
4.51
26.09
$
9.74
natural gas purchases and sales
Probability of default
2.52
% -
4.4
0%
3.31
%
Discount rate
0.01
% -
1.6
0%
0.48
%
HFT derivatives – Power swaps
4
Modelled pricing
Third-party pricing
$
37.05
213.00
$
93.60
and physical contracts
Probability of default
0.01
% -
2.52
%
0.45
%
Discount rate
0.00
% -
1.86
%
0.19
%
HFT derivatives
20
Modelled pricing
Third-party pricing
$
2.18
20.42
$
3.75
Natural gas swaps, futures,
Probability of default
0.01
% -
7.38
%
0.13
%
forwards and physical contracts
Discount rate
0.00
% -
11.98
%
0.37
%
(8)
Modelled pricing
Third-party pricing
$
2.83
20.86
$
10.85
Basis adjustment
$
0.00
-$
0.44
$
0.42
Probability of default
0.01
% -
4.17
%
0.46
%
Discount rate
0.00
% -
1.73
%
0.21
%
Total assets
$
104
Liabilities
HFT derivatives
$
1
Modelled pricing
Third-party pricing
$
37.8
0 - $
145.8
0
$
111.15
Power swaps and
Own credit risk
0.01
% -
1.48
%
0.12
%
physical contracts
Discount rate
0.01
% -
1.86
%
0.31
%
2
Modelled pricing
Third-party pricing
$
37.46
126.75
$
95.02
Correlation factor
100% - 100%
100%
Own credit risk
0.01
% -
11.16
%
0.07
%
Discount rate
0.01
% -
1.86
%
0.21
%
HFT derivatives
458
Modelled pricing
Third-party pricing
$
1.9
0 - $
20.42
$
9.12
Natural gas swaps, futures,
Own credit risk
0.01
% -
7.38
%
0.08
%
forwards and physical contracts
Discount rate
0.00
% -
14.59
%
1.54
%
57
Modelled pricing
Third-party pricing
$
2.83
21.53
$
12.03
Basis adjustment
$
0.00
1.11
$
0.28
Own credit risk
0.01
% -
0.49
%
0.02
%
Discount rate
0.00
% -
1.73
%
0.13
%
Total liabilities
$
518
Net liabilities
$
(414)
(1) Unobservable inputs were weighted by the relative fair value of the instruments
As at
December 31, 2020
millions of Canadian dollars
Fair
Value
Valuation
Technique
Unobservable Input
Range
Weighted
average
(1)
Assets
HFT derivatives
$
1
Modelled pricing
Third-party pricing
$20.50 - $62.45
$
31.14
Power swaps and
Probability of default
0.02
% -
9.74
%
2.52
%
physical contracts
Discount rate
0.01
% -
0.73
%
0.25
%
1
Modelled pricing
Third-party pricing
$25.70 - $36.05
$
29.53
Probability of default
0.36
% -
0.85
%
0.6
0%
Discount rate
0.06
% -
0.41
%
0.28
%
Correlation factor
100
% -
100
%
100
%
HFT derivatives
18
Modelled pricing
Third-party pricing
$1.66 - $6.22
$
2.52
Natural gas swaps, futures,
Probability of default
0.02
% -
2.52
%
0.4
0%
forwards, and physical contracts
Discount rate
0.00
% -
10.36
%
0.75
%
(6)
Modelled pricing
Third-party pricing
$1.82 - $6.44
$
4.66
Basis adjustment
$0.00 - $1.33
$
0.44
Probability of default
0.02
% -
12.58
%
1.95
%
Discount rate
0.00
% -
0.67
%
0.13
%
Total assets
$
14
Liabilities
HFT derivatives
1
Modelled pricing
Third-party pricing
$
1.13
62.45
$
36.90
Power swaps and physical
contracts
Own credit risk
0.02
% -
6.85
%
2.02
%
Discount rate
0.01
% -
0.73
%
0.34
%
1
Modelled pricing
Third-party pricing
$
37.25
62.45
$
55.00
Own credit risk
0.36
% -
1.28
%
0.83
%
Discount rate
0.01
% -
0.40
%
0.31
%
Correlation factor
100
% -
100
%
100%
HFT derivatives
226
Modelled pricing
Third-party pricing
$
1.44
6.57
$
3.68
Natural gas swaps, futures,
Own credit risk
0.02
% -
2.52
%
0.10
%
forwards and physical contracts
Discount rate
0.00
% -
8.79
%
0.43
%
30
Modelled pricing
Third-party pricing
$
1.54
8.44
$
4.69
Basis adjustment
$
0.00
1.33
$
0.87
Own credit risk
0.03
% -
12.58
%
0.10
%
Discount rate
0.00
% -
0.67
%
0.16
%
Total liabilities
$
258
Net assets (liabilities)
$
(244)
'(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 Canadian dollars
Amount
Fair Value
Level 1
Level 2
Level 3
Total
December 31, 2021
$
14,658
$
16,775
$
0
$
16,308
$
467
$
16,775
December 31, 2020
$
13,721
$
16,487
$
0
$
16,020
$
467
$
16,487
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, 2021, the fair value of the Hybrid
Notes was $
1.7
1.8
5
in OCI for the year ended December 31, 2021 (2020 – $
26
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 follow s:
●
Consolidated Statements of Income. NSPI’s expense is reported in Regulated fuel for generation and
purchased power, totalling $
149
139
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 $
19
- $
18
There were no significant receivables or payables between Emera and its associated companies reported
on Emera’s Consolidated Balance Sheets as at December 31, 2021 and at December 31, 2020.
18. RECEIVABLES AND OTHER CURRENT ASSETS
Receivables and other current assets consisted of the following:
As at
December 31
December 31
millions of Canadian dollars
2021
2020
Customer accounts receivable – billed
$
767
$
570
Customer accounts receivable – unbilled
318
286
Allowance for credit losses
(21)
(22)
Capitalized transportation capacity
(1)
316
200
Income tax receivable
8
11
Prepaid expenses
65
50
Other
280
138
$
1,733
$
1,233
(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.
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 64 years, some of which include options to
extend the leases for up to 64 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 Canadian dollars
Classification
2021
2020
Right-of-use asset
Other long-term assets
$
58
$
61
Lease liabilities
Other current liabilities
3
3
Other long-term liabilities
59
60
Total lease liabilities
$
62
$
63
The Company has recorded lease expense of $
150
– $
160
142
149
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 Canadian dollars
2022
2023
2024
2025
2026
Thereafter
Total
Minimum lease payments
$
5
$
6
$
5
$
4
$
3
$
112
$
135
Less imputed interest
(73)
Total
$
62
Additional information related to Emera's leases is as follows:
Year ended December
For the
2021
2020
Cash paid for amounts included in the measurement of lease liabilities:
$
7
$
7
Right-of-use assets obtained in exchange for lease obligations:
$
0
$
7
Weighted average remaining lease term (years)
44
43
Weighted average discount rate- operating leases
3.98%
3.96%
Lessor
The Company’s net investment in direct finance and sales-type leases primarily relates to Brunswick
Pipeline, compressed natural gas (“CNG”) stations and heat pumps.
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 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 at any time after 2021 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.
Net investment in direct finance and sales-type leases consist of the following:
As at
December 31
December 31
millions of Canadian dollars
2021
2020
Total minimum lease payment to be received
$
947
$
1,018
Less: amounts representing estimated executory costs
(165)
(179)
Minimum lease payments receivable
$
782
$
��
839
Estimated residual value of leased property (unguaranteed)
183
183
Less: unearned finance lease income
(443)
(487)
Net investment in direct finance and sales-type leases
$
522
$
535
Principal due within one year (included in "Receivables and other current assets")
19
18
Net investment in sales-type leases - long-term (included in "Other long-term
assets")
41
42
Net Investment in direct finance leases - long-term
$
462
$
475
As at December 31, 2021, future minimum lease payments to be received for each of the next five years
and in aggregate thereafter are as follows:
millions of Canadian dollars
2022
2023
2024
2025
2026
Thereafter
Total
Minimum lease payments to be
received
$
78
$
77
$
79
$
80
$
78
$
555
$
947
Less: executory costs
(165)
Total
$
782
20. PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment consisted of the following regulated and non-regulated assets:
As at
December 31
December 31
millions of Canadian dollars
Estimated useful life
2021
2020
Generation
3
131
$
11,173
$
11,474
Transmission
11
80
2,532
2,414
Distribution
4
80
6,305
5,997
Gas transmission and distribution
7
85
4,385
3,879
General plant and other
2
60
2,473
2,127
Total cost
26,868
25,891
Less: Accumulated depreciation
(1)
(8,739)
(8,714)
18,129
17,177
Construction work in progress
(1)
2,224
2,358
Net book value
$
20,353
$
19,535
(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, 2021, SeaCoast’s share of plant in service was $
27
34
depreciation of $
1
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.
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, Dominica and Grand Bahama Island.
Emera Maine, refer to note 4 for further detail.
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 Canadian dollars
2021
2020
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
$
2,759
$
339
$
2,822
$
353
Service cost
43
5
46
5
Plan participant contributions
6
4
7
5
Interest cost
67
8
84
10
Benefits paid
(160)
(27)
(135)
(27)
Actuarial gains (losses)
(89)
(10)
189
52
Settlements and curtailments
0
0
(229)
(52)
Foreign currency translation adjustment
(2)
(1)
(25)
(7)
Balance, December 31
2,624
318
2,759
339
Change in plan assets
Balance, January 1
2,605
52
2,593
56
Employer contributions
42
21
41
21
Plan participant contributions
6
4
7
5
Benefits paid
(160)
(27)
(135)
(27)
Actual return on assets, net of expenses
214
2
310
5
Settlements and curtailments
0
0
(191)
(7)
Foreign currency translation adjustment
(5)
(1)
(20)
(1)
Balance, December 31
2,702
51
2,605
52
Funded status, end of year
$
78
$
(267)
$
(154)
$
(287)
The actuarial gains recognized in the period are primarily due to gains associated with changes in the
discount rate and demographic assumption changes. This was partially offset by losses associated with
changes in inflation and compensation-related assumptions.
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 Canadian dollars
2021
2020
Defined benefit
pension plans
Non-pension
benefit plans
Defined benefit
pension plans
Non-pension
benefit plans
PBO/APBO
$
140
$
290
$
2,736
$
308
Fair value of plan assets
35
0
2,568
0
Funded status
$
(105)
$
(290)
$
(168)
$
(308)
Plans with Accumulated Benefit Obligation (“ABO”)
in Excess of Plan Assets
The ABO for the defined benefit pension plans was $
2,507
$
2,639
for the years ended December 31 is as follows:
millions of Canadian dollars
2021
2020
Defined benefit
pension plans
Defined benefit
pension plans
ABO
$
133
$
1,519
Fair value of plan assets
35
1,419
Funded status
$
(98)
$
(100)
Balance Sheet
The amounts recognized in the Consolidated Balance Sheets consisted of the following:
As at
December 31
December 31
millions of Canadian dollars
2021
2020
Defined benefit
pension plans
Non-pension
benefit plans
Defined benefit
pension plans
Non-pension
benefit plans
Other current liabilities
$
(7)
$
(20)
$
(4)
$
(19)
Long-term liabilities
(100)
(270)
(163)
(290)
Other long-term assets
185
23
13
20
Amount included in deferred income tax
(8)
1
(4)
(1)
AOCI and regulatory assets, net of tax
230
90
443
107
Net amount recognized
$
300
$
(176)
$
285
$
(183)
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 Canadian dollars
Defined Benefit Pension Plans
Balance, January 1, 2021
$
279
$
160
Amortized in current period
(24)
(21)
Current year addition to AOCI or regulatory assets
(61)
(109)
Change in foreign exchange rate
(2)
0
Balance, December 31, 2021
$
192
$
30
Non-pension benefits plans
Balance, January 1, 2021
$
110
$
(4)
Amortized in current period
(2)
(3)
Current year addition to AOCI or regulatory assets
(16)
7
Change in foreign exchange rate
(1)
0
Balance, December 31, 2021
$
91
$
0
2021
2020
millions of Canadian dollars
Defined benefit
pension plans
Non-pension
benefit plans
Defined benefit
pension plans
Non-pension
benefit plans
Actuarial losses (gains)
$
30
$
0
$
160
$
(4)
Regulatory assets
192
91
279
110
Total AOCI and regulatory assets before
deferred income taxes
222
91
439
106
Amount included in deferred income tax
assets
8
(1)
4
1
Net amount in AOCI and regulatory assets
$
230
$
90
$
443
$
107
Benefit Cost Components
Emera's net periodic benefit cost included the following:
As at
Year ended December 31
millions of Canadian dollars
2021
2020
Defined benefit
pension plans
Non-pension
benefit plans
Defined benefit
pension plans
Non-pension
benefit plans
Service cost
$
43
$
5
$
46
$
5
Interest cost
67
8
84
10
Expected return on plan assets
(132)
(1)
(141)
(1)
Current year amortization of:
21
3
15
0
0
0
(1)
0
24
2
25
0
Total
$
23
$
17
$
28
$
14
The expected return on plan assets is determined based on the market-related value of plan assets of
$
2,151
2,476
during the year.
The market-related value of assets is based on a five-year smoothed asset value. Any
investment gains (or losses) in excess of (or less than) the expected return on plan assets are recognized
on a straight-line basis into the market-related value of assets over a
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:
12%
to
22%
30%
to
55%
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:
millions of Canadian dollars
NAV
Level 1
Level 2
Total
Percentage
December 31, 2021
Cash and cash equivalents
$
0
$
60
$
0
$
60
2
%
Net in-transits
0
(84)
0
(84)
(3)
%
Equity Securities:
0
97
0
97
4
%
0
366
0
366
14
%
0
215
0
215
8
%
Fixed income securities:
0
0
132
132
5
%
0
0
117
117
4
%
0
8
3
11
0
%
Mutual funds
0
86
0
86
3
%
Other
0
1
(1)
0
0
%
Open-ended investments
measured at NAV
952
0
0
952
35
%
Common collective trusts
measured at NAV
(2)
750
0
0
750
28
%
Total
$
1,702
$
749
$
251
$
2,702
100
%
December 31, 2020
Cash and cash equivalents
$
0
$
68
$
0
$
68
3
%
Net in-transits
0
(99)
0
(99)
(4)
%
Equity securities:
0
154
0
154
6
%
0
380
0
380
15
%
0
243
0
243
9
%
Fixed Income securities:
0
0
119
119
5
%
0
0
141
141
5
%
0
10
3
13
0
%
Mutual funds
0
88
0
88
3
%
Other
0
(3)
(4)
(7)
0
%
Open-ended investments
measured at NAV
801
0
0
801
31
%
Common collective trusts
measured at NAV
(2)
704
0
0
704
27
%
Total
$
1,505
$
841
$
259
$
2,605
100
%
(1) NAV investments are open-ended registered and non-registered mutual funds, collective investment trusts, or pooled funds.
NAV’s are calculated daily 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, 2021 and 2020, the assets related to the pension funds and post-retirement benefit
plans do not hold any material investments in Emera or its subsidiaries securities. However, as a
significant portion of assets for the benefit plan are held in pooled assets, there may be indirect
investments in these securities.
Cash Flows
The following table shows the expected cash flows for defined benefit pension and other post-retirement
benefit plans:
millions of Canadian dollars
Defined benefit
pension plans
Non-pension
benefit plans
Expected employer contributions
2022
$
41
$
20
Expected benefit payments
2022
153
21
2023
162
22
2024
162
22
2025
165
22
2026
169
22
2027 – 2031
872
104
Assumptions
The following table shows the assumptions that have been used in accounting for defined benefit
pension and other post-retirement benefit plans:
2021
2020
(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
3.05
%
2.81
%
2.49
%
2.48
%
Discount rate - future service
3.18
%
2.92
%
2.64
%
2.51
%
Rate of compensation increase
3.31
%
3.29
%
2.89
%
3.04
%
Health care trend - initial (next year)
0
5.09
%
0
5.64
%
0
3.77
%
0
4.35
%
2042
2038
Benefit cost for year ended December 31:
Discount rate - past service
2.49
%
2.48
%
3.17
%
3.28
%
Discount rate - future service
2.64
%
2.51
%
3.21
%
3.28
%
Expected long-term return on plan assets
5.86
%
0
%
6.29
%
3.25
%
Rate of compensation increase
2.89
%
3.04
%
3.34
%
3.70
%
Health care trend - initial (current year)
0
5.64
%
0
5.91
%
0
4.35
%
0
4.37
%
2038
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, 2021 was $
45
45
22. GOODWILL
The change in goodwill for the year ended December 31 is due to the following:
millions of Canadian dollars
2021
2020
Balance, January 1
$
5,720
$
5,835
Change in foreign exchange rate
(24)
(115)
Balance, December 31
$
5,696
$
5,720
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, 2021, primarily relates to TECO Energy and
GBPC. Emera’s reporting units with goodwill are Tampa Electric, PGS, NMGC, and GBPC.
In 2021, Emera performed a qualitative impairment assessment for Tampa Electric, PGS and NMGC,
concluding that the fair value of the reporting units exceeded their respective carrying amounts, and as
such, no quantitative assessments were performed and no impairment charges were recognized.
Goodwill on Emera’s Consolidated Balance Sheets at December 31, 2021, included $
68
$
68
using a discounted cash flow analysis. This assessment estimated that the fair value of the reporting unit
exceeded its carrying value, including goodwill, by approximately
12
assumptions used could result in a future impairment.
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 Canadian dollars
2021
Weighted
average
interest rate
2020
Weighted
average
interest rate
Tampa Electric Company ("TEC")
Advances on term, revolving and accounts receivable facilities
$
945
0.58
%
$
987
0.89
%
Emera
Non-revolving term facility
400
0.96
%
400
0.94
%
Bank indebtedness
6
0
%
0
0
%
TECO Finance
Advances on revolving credit and term facilities
355
1.20
%
205
1.46
%
NMGC
Advances on revolving credit facilities
25
1.20
%
21
1.22
%
GBPC
Advances on revolving credit facilities
10
5.25
%
11
5.25
%
NSPI
Bank indebtedness
1
0
%
1
0
%
Short-term debt
$
1,742
$
1,625
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 Canadian dollars
Maturity
2021
2020
Tampa Electric Company - revolving credit facility
2026
$
1,014
$
1,019
TECO Energy/TECO Finance - revolving credit facility
2026
507
509
Emera - non-revolving term facility
2022
400
400
TEC - term loan
2022
634
382
TEC - accounts receivable revolving credit facility
0
191
NMGC - revolving credit facility
2026
158
159
GBPC - revolving credit facility
on demand
16
17
Total
$
2,729
$
2,677
Less:
Advances under revolving credit and term facilities
1,735
1,624
Letters of credit issued within the credit facilities
4
4
Total advances under available facilities
1,739
1,628
Available capacity under existing agreements
$
990
$
1,049
The weighted average interest rate on outstanding short-term debt at December 31, 2021 was
0.83
cent (2020 –
1.01
Recent Significant Financing Activity by Segment
Florida Electric Utility
On December 17, 2021, TEC entered into a $
500
a maturity date of
December 16, 2022
. The credit facility contains customary representations and
warranties, events of default, financial and other covenants and bears interest based on either the
London Inter-Bank Offered Rate (“LIBOR”), prime rate, or the federal funds rate, plus a margin.
On December 17, 2021, TEC amended and restated its $
800
amendment extended the maturity date from
March 22, 2023
December 17, 2026
. There were no other
significant changes in commercial terms from the prior agreement.
On May 25, 2021, TEC established a commercial paper program. Amounts available under the
commercial paper program may be borrowed, repaid and reborrowed with the aggregate amount of the
notes outstanding at any time not to exceed $
800
issued is backed by TEC’s credit facility and results in an equal amount of its credit facility being
considered drawn and unavailable.
As a result of the $
800
repaid its $
300
150
receivable collateralized borrowing facility and the agreement subsequently matured and terminated on
March 22, 2021.
Gas Utilities and Infrastructure
On December 17, 2021, NMGC amended and restated its $
125
amendment extended the maturity date from
March 22, 2023
December 17, 2026
. There were no other
significant changes in commercial terms from the prior agreement.
Other
On December 17, 2021, TECO Finance amended and restated its $
400
facility. The amendment extended the maturity date from
March 22, 2023
December 17, 2026
. There
were no other significant changes in commercial terms from the prior agreement.
On December 3, 2021, Emera extended the maturity date of its $
400
December 16, 2021
December 16, 2022
. There were no other significant changes in commercial terms
from the prior agreement.
24. OTHER CURRENT LIABILITIES
As at
December 31
December 31
millions of Canadian dollars
2021
2020
Accrued charges
$
157
$
141
Accrued interest on long-term debt
75
71
Pension and post-retirement liabilities (note 21)
27
23
Sales and other taxes payable
6
6
Income tax payable
6
1
Other
95
98
$
366
$
340
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 Canadian dollars
2021
2020
Maturity
2021
2020
Emera
Bankers acceptances, LIBOR loans
Variable
Variable
2026
$
378
$
263
Unsecured fixed rate notes
2.90%
2.90%
2023
500
500
Fixed to floating subordinated notes (USD)
(2)
6.75%
6.75%
2076
1,521
1,528
$
2,399
$
2,291
Emera Finance
Unsecured senior notes (USD)
3.65%
3.86%
2024 - 2046
$
3,487
$
3,501
TECO Finance
Tampa Electric
(3)
Fixed rate notes and bonds (USD)
4.15%
4.53%
2022 - 2051
$
3,683
$
3,268
PGS
Fixed rate notes and bonds (USD)
3.78%
4.58%
2022 - 2051
$
660
$
429
NMGC
Fixed rate notes and bonds (USD)
3.11%
4.30%
2026 - 2051
$
488
$
465
Non-revolving term facility, floating rate
Variable
2022
101
$
589
$
465
NMGI
Fixed rate notes and bonds (USD)
3.64%
3.64%
2024
$
190
$
191
NSPI
Discount notes
Variable
Variable
2026
$
376
$
291
Medium term fixed rate notes
5.14%
5.14%
2025 - 2097
2,665
2,665
$
3,041
$
2,956
EBP
Senior secured credit facility
Variable
Variable
2025
$
249
$
249
ECI
Secured senior notes (USD)
Variable
Variable
2026
$
84
$
106
Amortizing fixed rate notes (USD)
3.97%
3.92%
2022 - 2026
104
$
100
Non-revolving term facility, floating rate
Variable
Variable
2025
28
$
28
Non-revolving term facility, fixed rate
2.36%
2.60%
2025 - 2026
101
$
68
Secured fixed rate senior notes
(4)
4.43%
4.39%
2022 - 2035
161
$
174
$
478
$
476
Adjustments
Fair market value adjustment - TECO Energy acquisition
(5)
$
3
$
5
Debt issuance costs
(121)
(110)
Amount due within one year
(462)
(1,382)
$
(580)
$
(1,487)
Long-Term Debt
$
14,196
$
12,339
(1) Weighted average interest rate of fixed rate long-term debt.
(2) In 2021, the company recognized $
102
109
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, BBD or East Caribbean Dollar (XCD).
(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.
The Company’s total long-term revolving credit facilities, outstanding borrowings and available capacity as
at December 31 were as follows:
millions of Canadian dollars
Maturity
2021
2020
Emera – revolving credit facility
(1)
June 2026
$
900
$
900
NSPI - revolving credit facility
(1)
December 2026
600
600
ECI – revolving credit facilities
2022-2032
27
28
Total
1,527
1,528
Less:
Borrowings under credit facilities
770
569
Letters of credit issued inside credit facilities
124
31
Use of available facilities
894
600
Available capacity under existing agreements
$
633
$
928
(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, 2021
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 Utility
On May 15, 2021, TEC repaid its $
278
5.4
repaid using existing credit facilities.
On March 18, 2021, TEC completed an issuance of $
800
included $
400
2.40
March 15, 2031
400
3.45
maturity date of
March 15, 2051
.
Canadian Electric Utilities
On December 3, 2021, NSPI amended its operating credit facility to extend the maturity from
October
2024
December 2026
. There were no other significant changes in commercial terms from the prior
agreement.
Other Electric
On December 16, 2021, GBPC entered into a $
75
4.00
date of
December 31, 2026
. Proceeds from this loan were used to repay existing, non-revolving term
loans totaling $
55
Gas Utilities and Infrastructure
On July 16, 2021, Brunswick Pipeline extended the maturity date of its $
250
May 17, 2023
June 30, 2025
. There were no other significant changes in commercial terms from the
prior agreement.
On March 25, 2021, NMGC entered into a $
100
maturity date of
September 23, 2022
. The credit facility contains customary representations and
warranties, events of default, financial and other covenants and bears interest based on either the LIBOR,
prime rate, or the federal funds rate, plus a margin.
On February 5, 2021, NMGC completed an issuance of $
220
included $
70
2.26
February 5, 2031
, $
65
2.51
maturity date of
February 5, 2036
, and $
85
3.34
per cent with a maturity date of
February 5, 2051
. Proceeds from this issuance were used to repay a
$
200
Other
On July 23, 2021, Emera extended the maturity date of its $
900
credit facility from
June 30, 2024
June 30, 2026
. There were no other significant changes in
commercial terms from the prior agreement.
On June 4, 2021 Emera US Finance LP completed an issuance of $
750
issuance included $
450
2.64
maturity date of
June 15, 2031
300
0.83
cent with a maturity date of
June 15, 2024
. The USD senior notes are guaranteed by Emera and Emera
US Holdings Inc., a wholly owned Emera subsidiary.
From the $
750
Finance LP repaid its previously outstanding $
750
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 Canadian dollars
2022
2023
2024
2025
2026
Thereafter
Total
Emera
$
0
$
500
$
0
$
0
$
1,899
$
0
$
2,399
Emera US Finance LP
0
0
571
0
951
1,965
3,487
Tampa Electric
285
0
0
0
0
3,398
3,683
PGS
32
0
0
0
0
628
660
NMGC
101
0
0
0
89
399
589
NMGI
0
0
190
0
0
0
190
NSPI
0
0
0
125
416
2,500
3,041
EBP
0
0
0
249
0
0
249
ECI
44
90
66
130
124
24
478
Total
$
462
$
590
$
827
$
504
$
3,479
$
8,914
$
14,776
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 Canadian dollars
2021
2020
Balance, January 1
$
178
$
185
Additions
1
10
Liabilities settled
(1)
(13)
(25)
Accretion included in depreciation expense
10
9
Accretion deferred to regulatory asset (included in property, plant and equipment)
(2)
(3)
Other
1
1
Change in foreign exchange rate
(1)
1
Balance, December 31
$
174
$
178
(1) Tampa Electric produces ash and other by-products, collectively known as CCR's, at its Big Bend and Polk power stations. The
decreases in ARO in 2021 and 2020 are due to the closure of CCR management facilities.
27. COMMITMENTS AND CONTINGENCIES
A.
Commitments
As at December 31, 2021, 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 Canadian dollars
2022
2023
2024
2025
2026
Thereafter
Total
Transportation
(1)
$
563
$
437
$
372
$
323
$
297
$
2,627
$
4,619
Purchased power
(2)
231
227
244
242
235
1,967
3,146
Fuel, gas supply and storage
694
104
45
40
25
0
908
Capital Projects
359
93
3
1
1
0
457
Long-term service agreements
(3)
49
66
47
32
26
83
303
Equity investment commitments
(4)
240
0
0
0
0
0
240
Leases and other
(5)
15
14
14
12
4
116
175
Demand side management
44
1
1
0
0
0
46
$
2,195
$
942
$
726
$
650
$
588
$
4,793
$
9,894
(1) Purchasing commitments for transportation of fuel and transportation capacity on various pipelines. Includes a commitment of
$
142
(2) Annual requirement to purchase electricity production from IPPs or other utilities over varying contract lengths.
(3) Maintenance of certain generating equipment, services related to a generation facility and wind operating agreements,
outsourced management of computer and communication infrastructure and vegetation management.
(4) Emera has a commitment to make equity contributions to the LIL.
(5) Includes operating lease agreements for buildings, land, telecommunications services and rail cars, transmission rights and
investment commitments.
NSPI has a contractual obligation to pay NSPML for the use of the Maritime Link over approximately
38
years
rates have been set to include $
164
162
and amounts payable to NSPML for the remainder of the
38
-year commitment period are subject to
UARB approval. Any difference between the amounts included in the NSPI fuel stability plan and those
approved by the UARB through the NSPML interim assessment application will be addressed through the
FAM. On August 9, 2021, NSPML filed a final capital cost application with the UARB seeking approval to
recover capital costs associated with the Maritime Link and approval of NSPML’s 2022 assessment. In
December 2021, NSPML obtained an interim decision from the UARB approving interim rates beginning
January 1, 2022, until receipt of the UARB’s decision on the application. On February 9, 2022, the UARB
issued its decision relating to the Maritime Link Project, approving NSPML’s requested rate base of
approximately $
1.8
For further information on the UARB decision, refer to note
7
.
Once Muskrat Falls and LIL have achieved full power, the commercial agreements between Emera and
Nalcor require true ups to finalize the respective investment obligations of the parties relating to the
Maritime Link and LIL.
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 commenced, and continuing for
50 years
. As transmission rights are contracted, the
obligations are included within “Leases and 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
final satisfaction of the First Award.
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 this Second Award. On October 16, 2020, the tribunal granted TGH’s request for
additional interest. The additional amount is approximately $
2
Guatemala filed an application for annulment of the Second Award with ICSID. On March 31, 2021, ICSID
constituted an ad hoc Committee to oversee the annulment proceeding. On May 17, 2021, the ad hoc
Committee issued (i) a decision continuing the stay of enforcement of the Second Award until the
committee renders its decision on Guatemala’s application for annulment and (ii) an order with dates for
briefings on the annulment and a hearing commencing July 27, 2022. Guatemala filed its Memorial on
Annulment on August 25, 2021. TGH’s Counter-Memorial on Annulment was filed on December 8, 2021.
To date, the total of the Second Award, with interest, is approximately $
62
do not reflect any benefit of the Second Award.
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, 2021, TEC has estimated its financial liability to be $
18
14
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.
Sound risk management is an essential discipline for running the business efficiently and pursuing the
Company’s strategy successfully. Emera has a business-wide risk management process, monitored by
the Board of Directors, to ensure a consistent and coherent approach to risk management. The Board of
Directors established a Risk and Sustainability Committee (‘RSC”) in September 2021. The mandate of
the RSC is to assist the Board in carrying out its risk and sustainability oversight responsibilities and
includes oversight of the Company’s Enterprise Risk Management framework, including the identification,
assessment, monitoring and management of enterprise risks.
Public Health Risk
An outbreak of infectious disease, a pandemic or a similar public health threat, such as the COVID-19
pandemic, or a fear of any of the foregoing, could adversely impact the Company, including causing
operating, supply chain and project development delays and disruptions, labour shortages and shutdowns
(including as a result of government regulation and prevention measures), which could have a negative
impact on the Company’s operations.
Any adverse changes in general economic and market conditions arising as a result of a public health
threat could negatively impact demand for electricity and natural gas, revenue, operating costs, timing
and extent of capital investments, results of financing efforts, or credit risk and counterparty risk; which
could result in a material adverse effect on the Company’s business. The Company maintains pandemic
and business contingency plans in each of its operations to manage and help mitigate the impact of any
such public health threat.
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 Canadian dollar and, particularly, the US dollar,
which could positively or adversely affect results.
Consistent with the Company’s risk management policies, Emera manages currency risks through
matching US denominated debt to finance its US operations and may use foreign currency derivative
instruments to hedge specific transactions and earnings exposure. The Company may enter foreign
exchange forward and swap contracts to limit exposure on certain foreign currency transactions such as
fuel purchases, revenue streams and capital investment s, 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 foreign exchange.
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. The Company reasonably expects liquidity sources to exceed capital needs.
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 property, plant and equipment 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 and
regulatory framework, 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.
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.
Interest Rate Risk
Emera utilizes a combination of fixed and floating rate debt financing for operations and capital
investments, 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.
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. The Company’s commercial arrangements, including the combination of supply
and purchase agreements, asset management agreements, pipeline transportation agreements and
financial hedging instruments are all used to manage and mitigate this risk. 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.
Regulated Utilities
A large portion of the Company’s utility fuel supply comes from international suppliers and therefore may
be exposed to broader global conditions, which may include impacts on delivery reliability and price,
despite contracted terms. The Company seeks to manage this risk using financial hedging instruments
and physical contracts and through contractual protectio n with counterparties, where applicable.
The majority of Emera’s regulated electric and gas utilities have adopted and implemented fuel
adjustment mechanisms and purchased gas adjusted 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.
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.
To measure commodity price risk exposure, Emera Energy employs a number of controls and processes,
including an estimated value-at-risk (“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, 2021:
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 or S&P, TECO Energy would be required to provide its counterparty
a letter of credit or cash deposit of $
27
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
.
In 2021, NSPI issued guarantees in the amount of $
15
Energy Marketing Incorporate (“NSPEMI”), to secure obligations under purchase agreements with third-
party suppliers and $
85
15
-year natural gas transportation commitment. NSPI
has $
118
18
and will be renewed as required.
The Company has standby letters of credit and surety bonds in the amount of $
148
(December 31, 2020 - $
55
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 2022. The amount committed
as at December 31, 2021 was $
64
63
Collaborative Arrangements
For the years ended December 31, 2021 and 2020, 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
expenses. In 2021, NSPI recognized $
18
19
generation and purchased power” and $
3
3
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, 2021
December 31, 2020
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
$
25.25
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
-
$
Series L
$
1.1500
$
25.00
9,000,000
$
222
-
$
Total
58,000,000
$
1,422
41,000,000
$
1,004
First Preferred Shares, Series J
On April 6, 2021, Emera issued
8
4.25
Shares, Series J (“First Preferred Shares, Series J”) at $
25.00
200
million ($
196
First Preferred Shares, Series L
On September 24, 2021, Emera issued
9
4.60
Shares, Series L (“First Preferred Shares, Series L”) at $
25.00
225
million ($
222
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
25.25
(6)
4.600
1.1500
November 15, 2026
25.00
(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
share by the annual fixed or floating dividend rate, which for Series A, C, F and H is the sum of the five-year Government of Canada
Bond Yield on the applicable reset date, plus the applicable reset dividend yield (Series H annual reset rate must be a minimum of
4.90
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 $
25.25
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 is deducted on the
Consolidated Statements of Income before arriving at “Net income attributable to common shareholders”
and is shown on the Consolidated Statement of Equity as a deduction from retained earnings.
The First Preferred Shares of each series rank on a parity with the First Preferred Shares of every other
series and are entitled to a preference over the Second Preferred Shares, the Common Shares, and any
other shares ranking junior to the First Preferred Shares with respect to the payment of dividends and the
distribution of the remaining property and assets or return of capital of the Company in the liquidation,
dissolution or wind-up, whether voluntary or involuntary.
In the event the Company fails to pay, in aggregate, eight quarterly dividends on any series of the First
Preferred Shares, the holders of the First Preferred Shares, for only so long as the dividends remain in
arrears, will be entitled to attend any meeting of shareholders of the Company at which directors are to be
elected and to vote for the election of two directors out of the total number of directors elected at any such
meeting.
29. NON-CONTROLLING INTEREST IN SUBSIDIARIES
As at
December 31
December 31
millions of Canadian dollars
2021
2020
Preferred shares of GBPC
$
14
$
14
Domlec
20
20
$
34
$
34
Preferred shares of GBPC:
Authorized:
10,000 non-voting cumulative redeemable variable perpetual preferred shares.
2021
2020
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
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.
30. SUPPLEMENTARY INFORMATION TO CONSOLIDATED STATEMENTS OF
CASH FLOWS
For the
Year ended December 31
millions of Canadian dollars
2021
2020
Changes in non-cash working capital:
$
(84)
$
6
(364)
187
289
55
7
(31)
Total non-cash working capital
$
(152)
$
217
Supplemental disclosure of cash paid (received):
Interest
$
603
$
679
Income taxes
$
24
$
(148)
Supplemental disclosure of non-cash activities:
Common share dividends reinvested
$
214
$
199
Reclassification of long-term debt from current to non-current
0
256
(Decrease) Increase in accrued capital expenditures
$
(45)
$
17
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, 2021, 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 (2020 –
7
compliance with this requirement.
Compensation cost for shares issued by Emera for the year ended December 31, 2021 under the
Employee Common Share Purchase Plan was $
3
2
the Consolidated Statements of Income.
The Company also has a Common Shareholders Dividend Reinvestment and Share Purchase Plan
(“Dividend Reinvestment Plan”) or (“DRIP”), 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 2021.
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 market price of the stocks
on the day before the option is granted. The maximum aggregate number of shares issuable under this
plan is 14.7 million shares. As at December 31, 2021, Emera is in compliance with this requirement.
Stock options vest in 25 per cent increments on the first, second, third and fourth 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.
Unless a stock option has expired, vested options may be exercised within the
27 months
option holders date of retirement, six months following a termination without just cause or death, and
within
sixty days
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:
2021
2020
Weighted average fair value per option
$
3.63
$
3.58
Expected term
(1)
5
5
Risk-free interest rate
(2)
0.60
%
1.33
%
Expected dividend yield
(3)
5.00
%
4.09
%
Expected volatility
(4)
19.14
%
14.10
%
(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 2021:
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, 2020
2,267,782
$
46.62
1,293,850
$
2.69
Granted
653,600
51.12
653,600
3.63
Exercised
(331,078)
40.97
N/A
N/A
Vested
N/A
N/A
(494,975)
2.49
Options outstanding December 31, 2021
2,590,304
$
48.48
1,452,475
$
3.18
Options exercisable December 31, 2021
(2)(3)
1,137,829
$
44.86
(1) As at December 31, 2021, there was $
3
expected to be recognized over a weighted average period of approximately
3
2
3
(2) As at December 31, 2021, the weighted average remaining term of vested options was
6
$
21
12
6
(3) As at December 31, 2021, the fair value of options that vested in the year was $
1
2
Compensation cost recognized for stock options for the year ended December 31, 2021 was $
2
(2020 – $
1
As at December 31, 2021, cash received from option exercises was $
14
19
total intrinsic value of options exercised for the year ended December 31, 2021 was $
6
6
million). The range of exercise prices for the options outstanding as at December 31, 2021 was $
32.35
$
60.03
32.06
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 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 usually made in cash. At the sole discretion of the Management Resources and
Compensation Committee (“MRCC”), payments may be made in the form of actual shares.
In addition, special DSU awards may be made from time to time by the MRCC to selected executives and
senior management to recognize singular achievements or by achieving certain corporate objectives.
A summary of the activity related to employee and director DSUs for the year ended December 31, 2021
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, 2020
661,998
$
37.17
591,124
$
41.69
Granted including DRIP
93,710
49.64
101,403
51.25
Exercised
(145,107)
36.61
(78,162)
37.57
Outstanding and exercisable as at December 31, 2021
610,601
$
39.22
614,365
$
43.80
Compensation cost recognized for employee and director DSU’s for the year ended December 31, 2021
was $
9
2
for the year ended December 31, 2021 were $
3
1
of the outstanding shares for the year ended December 31, 2021 for employees was $
39
$
36
2021 for directors was $
39
32
December 31, 2021 associated with the DSU plan was $
11
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, 2021 is presented
in the following table:
Employee PSU
Weighted Average
Grant Date Fair Value
Aggregate intrinsic value
Outstanding as at December 31, 2020
1,126,529
$
47.16
$
68
Granted including DRIP
323,610
52.83
Exercised
(464,290)
48.13
Forfeited
(33,914)
47.78
Outstanding as at December 31, 2021
951,935
$
48.60
$
66
Compensation cost recognized for the PSU plan for the year ended December 31, 2021 was $
12
(2020 – $
27
ended December 31, 2021 were $
3
7
ended December 31, 2021 associated with the PSU plan was $
29
29
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, 2021 is presented
in the following table:
Employee RSU
Weighted Average
Grant Date Fair Value
Aggregate intrinsic value
Outstanding as at December 31, 2020
166,275
$
54.62
$
10
Granted including DRIP
184,498
54.66
Exercised
(232)
54.62
Forfeited
(6,589)
54.63
Outstanding as at December 31, 2021
343,952
$
54.64
$
24
Compensation cost recognized for the RSU plan for the year ended December 31, 2021 was $
8
(2020 – $
4
ended December 31, 2021 were $2 million (2020 – $
1
ended December 31, 2021 associated with the RSU plan was nil (2020–
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:
As at
December 31, 2021
December 31, 2020
Maximum
Maximum
millions of Canadian dollars
Total
assets
exposure to
loss
Total
assets
loss
Unconsolidated VIEs in which Emera has variable interests
NSPML (equity accounted)
$
533
$
11
$
547
$
16
33. SUBSEQUENT EVENTS
These financial statements and notes reflect the Company’s evaluation of events occurring subsequent to
the balance sheet date through February 14, 2022, the date the financial statements were issued.