1
Management’s Discussion & Analysis
As at February 23, 2023
Management’s Discussion & Analysis (“MD&A”) provides a review of the results of operations of Emera
Incorporated and its subsidiaries and investments during the fourth quarter of 2022 relative to the same
quarter in 2021; for the full year of 2022 relative to 2021 and selected financial information for 2020; and
its financial position as at December 31, 2022 relative to December 31, 2021. Throughout this discussion,
“Emera” and “Company” refer to Emera Incorporated and all of its consolidated subsidiaries and
investments. The Company’s activities are carried out through five reportable segments: Florida Electric
Utility, Canadian Electric Utilities, Gas Utilities and Infrastructure, Other Electric Utilities, and
Other.
This discussion and analysis should be read in conjunction with the
Emera annual audited consolidated
financial statements and supporting notes as at and for the year ended December 31,
2022. Emera
follows United States Generally Accepted Accounting Principles
(“USGAAP” or “GAAP”).
The accounting policies used by Emera’s rate-regulated entities may differ from
those used by Emera’s
non-rate-regulated businesses with respect to the timing of recognition of certain assets, liabilities,
revenues and expenses. At December 31, 2022, Emera’s rate-regulated subsidiaries and investments
include:
Emera Rate-Regulated Subsidiary or Equity
Investment
Accounting Policies Approved/Examined By
Subsidiary
Tampa Electric –
Electric Division of Tampa Electric
Company (“TEC”)
(1)
Florida Public Service
Commission (“FPSC”) and the
Federal Energy Regulatory Commission (“FERC”)
Nova Scotia Power Inc. ("NSPI")
Nova Scotia
Utility and Review Board (“UARB”)
Peoples Gas System (“PGS”) –
Gas Division of
TEC
FPSC
New Mexico Gas Company, Inc.
(“NMGC”)
New Mexico Public Regulation Commission (“NMPRC”)
SeaCoast Gas Transmission, LLC ("SeaCoast")
FPSC
Emera Brunswick Pipeline Company Limited (“Brunswick
Pipeline”)
Canadian Energy Regulator ("CER")
Barbados
Light & Power Company Limited (“BLPC”)
Fair Trading Commission, Barbados
("FTC")
Grand Bahama Power Company Limited
(“GBPC”)
The Grand Bahama Port Authority (“GBPA”)
Equity Investments
NSP Maritime
Link Inc. (“NSPML”)
UARB
Labrador
Island Link Limited Partnership (“LIL”)
Newfoundland and Labrador Board of Commissioners of
Public Utilities ("NLPUB")
Maritimes &
Northeast Pipeline Limited Partnership and
Maritimes & Northeast Pipeline, LLC (“M&NP”)
CER and FERC
St. Lucia Electricity Services
Limited (“Lucelec”)
National Utility Regulatory Commission (“NURC”)
(1) Effective January 1, 2023, Peoples Gas System ceased to be a division of TEC and the gas utility
was reorganized, resulting in a
separate legal entity called Peoples Gas
System, Inc., a wholly-owned direct subsidiary of TECO Gas Operations, Inc.
All amounts are in Canadian dollars (“CAD”), except for the Florida Electric Utility, Gas Utilities and
Infrastructure, and Other Electric Utilities sections of the MD&A, which are reported in United States dollar
(“USD”) unless otherwise stated.
Additional information related to Emera, including the Company’s Annual Information Form, can be found
on SEDAR at www.sedar.com.
2
TABLE OF CONTENTS
Forward-looking Information……………………...
2
Introduction and Strategic
Overview………….…
3
Non-GAAP Financial Measures and Ratios….…
4
Consolidated Financial
Review……….………….
7
7
7
9
Business Overview and
Outlook…………….……
11
11
12
16
17
19
Consolidated Balance Sheet
Highlights………
20
Other
Developments……………….....................
21
Financial
Highlights……………………………..
22
22
23
26
28
29
Liquidity and Capital
Resources………..………
31
32
33
34
Expenditures………………………………
34
35
37
37
38
Pension
Funding………………………………
39
Off-Balance Sheet Arrangements…….………
39
Dividend Payout
Ratio…………………………
40
Transactions with Related Parties….………….
40
Enterprise Risk and Risk
Management…………
41
Risk Management including
Financial
Instruments……………………………………
54
Disclosure and Internal
Controls……….…….
56
Critical Accounting
Estimates….………………
56
Changes in Accounting Policies and
Practices…
62
62
Summary of Quarterly Results…….....................
62
FORWARD-LOOKING
INFORMATION
This MD&A contains “forward-looking information” and statements which reflect the current view with
respect to the Company’s expectations regarding future growth, results of operations, performance,
carbon dioxide emissions reduction goals, business prospects and
opportunities, and may not be
appropriate for other purposes within the
meaning of applicable Canadian securities laws. All such
information and statements are made pursuant to safe harbour provisions
contained in applicable
securities legislation. The words “anticipates”, “believes”, “budget”,
“could”, “estimates”, “expects”,
“forecast”, “intends”,
“may”, “might”, “plans”, “projects”, “schedule”, “should”, “targets”, “will”, “would” and
similar expressions are often intended to identify forward-looking information, although not all
forward-
looking information contains these identifying words. The forward-looking information reflects
management’s current beliefs and is based on information currently available to Emera’s management
and should not be read as guarantees of future events, performance or results, and will not necessarily
be accurate indications of whether, or the time at which, such events, performance or results will be
achieved.
3
The
forward-looking information is based on reasonable assumptions and is subject to risks, uncertainties
and other factors that could
cause actual results to differ materially from historical results or results
anticipated by the forward-looking information.
Factors that could cause results or events to differ from
current expectations include, without limitation: regulatory and
political risk; operating and maintenance
risks; changes in economic conditions; commodity price and availability risk; liquidity
and capital market
risk; future dividend growth; timing and costs associated with certain capital investments; expected
impacts on Emera of challenges in the global economy; estimated energy consumption rates;
maintenance of adequate insurance coverage; changes in customer energy usage patterns;
developments in technology that could reduce demand for electricity; global climate change; weather;
unanticipated maintenance and other expenditures; system operating and maintenance risk; derivative
financial instruments and hedging; interest rate risk; inflation risk; counterparty risk; disruption of fuel
supply; country risks; environmental risks; foreign exchange (“FX”); regulatory and government decisions,
including changes to environmental, financial reporting and tax legislation; risks associated with pension
plan performance and funding requirements; loss of service area; risk of failure of information technology
(“IT”) infrastructure and cybersecurity risks; uncertainties associated with infectious diseases, pandemics
and similar public health threats, such as the COVID-19 novel coronavirus (“COVID-19”) pandemic;
market energy sales prices; labour relations; and availability of labour and management
resources.
Readers are cautioned not to place undue reliance on
forward-looking information, as actual results could
differ materially from
the plans, expectations, estimates or intentions and statements expressed in the
forward-looking information. All forward-looking
information in this MD&A is qualified in its entirety by the
above cautionary statements and, except as required by law, Emera
undertakes no obligation to revise or
update any forward-looking information as a result of new information, future events or
otherwise.
INTRODUCTION AND
STRATEGIC OVERVIEW
Based in Halifax, Nova Scotia, Emera owns and operates
cost-of-service rate-regulated electric and gas
utilities in Canada, the United States and the Caribbean. Cost-of-service utilities
provide essential electric
and gas services in designated territories under franchises and are overseen by regulatory authorities.
Emera’s strategic focus continues to be safely delivering cleaner, affordable and reliable energy to its
customers.
The majority of Emera’s investment in rate-regulated businesses are located in Florida with other
investments in Nova Scotia, New Mexico and the Caribbean. Emera’s
portfolio of regulated utilities
provides reliable earnings, cash flow and dividends. Earnings opportunities in regulated utilities
are
generally driven by the magnitude of net investment in the utility (known as “rate base”), and the amount
of equity in the capital structure and the return on that equity (“ROE”) as approved through regulation.
Earnings are also affected by sales volumes and operating expenses.
Emera’s capital investment plan is $8 – 9 billion over the 2023-to-2025 period (including a $240 million
equity investment in the LIL in 2023), mainly focused in Florida. This results in a forecasted rate base
growth of approximately 7 per cent to 8 per cent through 2025. The capital investment plan continues to
include significant investments across the portfolio in renewable and cleaner generation, reliability and
integrity investments, infrastructure modernization, and customer-focused technologies. Emera’s capital
investment plan is being funded primarily through internally generated cash flows and debt raised at the
operating company level. Equity requirements in support of the Company’s capital investment plan are
expected to be funded through the issuance of preferred equity and the issuance of common equity
through Emera’s dividend reinvestment plan (“DRIP”) and at-the-market program (“ATM program”).
Maintaining investment-grade credit ratings is a priority of the Company.
Emera has provided annual dividend growth guidance of four to five per cent through 2025. The
Company targets a long-term dividend payout ratio of adjusted net income of 70 to 75 per cent and, while
the payout ratio is likely to exceed that target through and beyond the forecast period, it is expected to
return to that range over time. For further information on the non-GAAP measure “Dividend Payout Ratio
of Adjusted Net Income”, refer to the “Non-GAAP Financial Measures and
Ratios” section.
4
Seasonal
patterns and other weather events affect demand and operating costs. Similarly, mark-to-
market adjustments and foreign currency
exchange can have a material impact on financial results for a
specific period. Emera’s consolidated net income and cash
flows are impacted by movements in the USD
relative to the Canadian dollar. Emera may hedge both transactional and translational
exposure. These
impacts, as well as the timing of capital investments and other factors, mean results in any one quarter
are not necessarily indicative of results in any other quarter, or for the year as a whole.
Energy markets worldwide are facing significant change and Emera is well positioned to respond to
shifting customer demands, digitization, decarbonization, complex regulatory environments, and
decentralized
generation.
Customers are looking for more choice, better control, and
enhanced reliability in a time where costs of
decentralized generation and storage have become more competitive in some regions.
Advancing
technologies are transforming the way utilities interact with their customers and generate and transmit
energy. In addition, climate change and extreme weather are shaping how utilities operate and how they
invest in infrastructure. There is also an overall need to replace aging infrastructure and further enhance
reliability. Emera will play a role in all of these trends. Emera’s strategy is to fund investments in
renewable energy and technology assets which protect the environment and benefit customers through
fuel or operating cost
savings.
For example, significant investments to facilitate the use of
renewable and low-carbon energy include the
Maritime Link in Atlantic Canada, and the ongoing construction of solar generation and
modernization of
the Big Bend Power Station at Tampa Electric. Emera’s
utilities are also investing in reliability projects
and replacing aging infrastructure. All of these projects demonstrate
Emera’s strategy of safely delivering
cleaner, reliable, and affordable energy for its customers.
Building on its decarbonization progress, Emera is continuing its efforts by establishing clear carbon
reduction goals and a vision to achieve net-zero carbon dioxide emissions by 2050.
This vision is inspired by Emera’s strong track record, the Company’s experienced team, and a clear path
to Emera’s interim carbon goals. With existing technologies and
resources, and subject to supportive
government and regulatory decisions,
Emera is working to achieve the following goals compared to
corresponding 2005
levels:
•
A 55 per cent reduction in carbon dioxide emissions by 2025.
• The retirement of Emera’s last existing coal unit no later
than 2040.
• An 80 per cent reduction in carbon dioxide emissions
by 2040.
Achieving the above climate goals on these timelines is subject
to the Company's regulatory obligations
and other external factors beyond Emera's control.
Emera seeks to deliver on its Climate Commitment while maintaining its focus on investing in reliability
and staying focused on the cost impacts for customers. Emera is also committed to identifying emerging
technologies and continuing to work constructively with policymakers, regulators, partners, investors and
customers to achieve these goals and realize its net-zero vision.
Emera is committed to world-class safety, operational excellence, good governance, excellent customer
service, reliability, being an employer of choice, and building constructive relationships.
NON-GAAP FINANCIAL MEASURES AND RATIOS
Emera uses financial measures and ratios that do not have standardized meaning under USGAAP and
may not be comparable to similar measures presented by other entities. Emera calculates the non-GAAP
measures and ratios by adjusting certain GAAP measures for specific items. Management believes
excluding these items better distinguishes the ongoing operations of the business and allows investors to
better understand and evaluate the business. These measures and ratios are discussed and reconciled
below.
5
Adjusted Net Income Attributable to Common Shareholders, Adjusted Earnings (Loss) Per
Common Share (“EPS”) – Basic and Dividend Payout Ratio of Adjusted Net Income
Emera calculates an adjusted net income attributable to common shareholders (“adjusted net income”)
measure by excluding the effect of mark-to-market (“MTM”)
adjustments, impairment charges, the impact
of the NSPML unrecoverable
costs, and the 2020 gain on sale of Emera Maine.
Management believes excluding from net income the effect of these MTM valuations
and changes
thereto, until settlement, better aligns the intent and financial effect of these contracts with the underlying
cash flows, and therefore excludes these MTM adjustments for evaluation of performance and incentive
compensation. The MTM adjustments are related to the following:
● held-for-trading (“HFT”) commodity derivative
instruments, including adjustments related to the
price differential between the point where natural gas is sourced and where it
is delivered, and
the related amortization of transportation capacity recognized as a result of certain Emera Energy
marketing and trading transactions;
● the business activities of Bear Swamp Power Company LLC
(“Bear Swamp”) included in Emera’s
equity income;
● equity securities held in BLPC and a captive reinsurance company
in the Other segment; and
● FX hedges entered into to hedge USD
denominated operating unit earnings exposure.
For further detail on MTM adjustments, refer to the “Consolidated Financial
Review”, “Financial Highlights
– Other Electric Utilities”, and “Financial Highlights –
Other” sections.
In Q4 2022, the Company recognized a $73 million non-cash goodwill impairment charge related to
GBPC due to a decline in the fair value of the reporting unit. The fair value decline was driven by the
effects of macro-economic factors on the discount rate calculation, including the risk-free rate
assumption. Management believes excluding from net income the effect of this charge better
distinguishes ongoing operations of the business and allows investors to better understand and evaluate
the Company. For further details on this GBPC impairment charge, refer to “Significant Items Impacting
Earnings”, and “Financial Highlights – Other” sections.
In February 2022, the UARB issued a decision to disallow the recovery of $9 million in costs ($7 million
after-tax) included in NSPML’s final capital cost application. The after-tax unrecoverable costs were
recognized in “Income from equity investments” in Emera’s Consolidated Statements of Income.
Management believes excluding these unrecoverable costs from the calculation of adjusted net income
better reflects the underlying operations in the period. For further details on the NSPML unrecoverable
costs, refer to the “Business Overview and Outlook – Canadian Electric Utilities” and “Financial Highlights
– Canadian Electric Utilities” sections.
In 2020, the Company recognized a gain on the sale of Emera Maine and certain non-cash impairment
charges. Management believes excluding these from net income better distinguishes ongoing operations
of the business and allows investors to better understand and evaluate the business.
Adjusted EPS – basic and dividend payout ratio of adjusted net income are non-GAAP ratios which are
calculated using adjusted net income, as described above. For further details on dividend payout ratio of
adjusted net income, see the “Dividend Payout Ratio” section.
Emera calculates adjusted net income for the Canadian Electric Utilities, Other Electric Utilities, and Other
segments. Reconciliation to the nearest GAAP measure is included in each segment. Refer to “Financial
Highlights – Canadian Electric Utilities”, “Financial Highlights – Other Electric Utilities” and
“Financial
Highlights – Other” sections.
6
The
following reconciles net income attributable to common shareholders to adjusted net income:
Three months ended
Year ended
For the
December 31
December 31
millions of dollars (except per share amounts)
2022
2021
2022
2021
2020
Net income attributable to common
shareholders
$
$
$
$
$
MTM gain (loss), after-tax
(1)
Impairment charges, after-tax
(2)
NSPML unrecoverable costs
(3)
Gain on sale, after tax and transaction costs
(4)
Adjusted net income attributable to common shareholders
$
$
$
$
$
EPS – basic
$
$
$
$
$
Adjusted EPS – basic
$
$
$
$
$
(1) Net of income tax expense of $124 million for the three months ended December 31, 2022 (2021 – $63 million
expense) and $73
million expense for the year ended December 31, 2022
(2021 – $86 million recovery) (2020 - $8 million recovery).
(2) Net of income tax expense of nil for the three months and
year ended December 31, 2022 (2021 – nil) (2020 – $1 million
expense).
(3) Emera accounts for NSPML as an equity investment and therefore the after-tax unrecoverable costs were
recorded in “Income
from equity investments” on Emera’s
Consolidated Statements of Income.
(4) Net of income tax expense of $276 million for the year ended December 31, 2020.
EBITDA and Adjusted EBITDA
Earnings before interest, income taxes, depreciation and amortization (“EBITDA”) and adjusted EBITDA
are non-GAAP financial measures used by Emera. These financial measures are used by numerous
investors and lenders to better understand cash flows and credit quality. EBITDA is useful to assess
Emera’s operating performance and indicates the Company’s ability to service or incur debt, invest in
capital, and finance working capital requirements.
Similar to adjusted net income calculations described above, adjusted EBITDA represents EBITDA
absent the income effect of MTM adjustments, impairment charges, the NSPML unrecoverable costs, and
the 2020 gain on sale of Emera
Maine.
The following is a reconciliation of net income to EBITDA and
Adjusted EBITDA:
Three months ended
Year
ended
For the
December 31
December 31
millions of dollars
2022
2021
2022
2021
2020
Net income
(1)
$
$
$
$
$
Interest expense, net
Income tax expense (recovery)
Depreciation and amortization
EBITDA
$
$
$
$
$
MTM gain (loss), excluding income tax
Impairment charges, excluding income tax
NSPML unrecoverable costs
(2)
Gain on sale, net of transaction costs (excluding income tax)
Adjusted EBITDA
$
$
$
$
$
(1) Net income is before Non-controlling interest in subsidiaries and Preferred stock dividends.
(2) Emera accounts for NSPML as an equity investment and therefore the after-tax unrecoverable costs were
recorded in “Income
from equity investments” on Emera’s
Consolidated Statements of Income.
7
CONSOLIDATED FINANCIAL REVIEW
Significant Items Affecting Earnings
GBPC Impairment Charge
In Q4 2022, Emera recognized a goodwill impairment charge of $73 million ($0.27 per common share) for
GBPC due to a decline in the fair value of the reporting unit. Although the cash flows of GBPC have not
changed significantly compared to previous periods, the decline in the fair value was driven by the effects
of macro-economic factors on discount rate calculations, including the risk-free rate assumption. This
non-cash charge was recorded in “Impairment charge” on the Consolidated Statements of Income and
reduced the GBPC goodwill balance to nil. For further details, refer to note 22 in the consolidated financial
statements.
TECO Guatemala Holdings (“TGH”) International Arbitration and Award
On December 15, 2022, a payment of $63 million ($45 million after tax and legal costs, or $0.17 per
common share), was made by the Republic of Guatemala to TECO Energy in satisfaction of the second
and final award issued by the International Centre of the Settlement of Investment Disputes tribunal
regarding a dispute over an investment of TGH, a wholly owned subsidiary of TECO Energy. The dispute
related to the 2007 intervention by the government of Guatemala in an ongoing independent rate-setting
process to unilaterally set a new and lower tariff. The payment was recognized in ‘Other income, net” on
the Consolidated Statements of Income. For further details, refer to note 27 in the consolidated financial
statements.
Earnings Impact of MTM Gain (Loss), After-Tax
MTM gain, after-tax increased $151 million to $307 million in Q4 2022, compared to $156 million in Q4
2021, and for the year ended December 31, increased $388 million to $175 million compared to a MTM
loss, after-tax of $213 million for the same period in 2021. These increases were due to changes in
existing positions and reversal of losses in 2022, partially offset by higher amortization in 2022 of gas
transportation assets at Emera Energy.
Consolidated Financial Highlights
For the
Three months ended
Year ended
millions of
dollars
December 31
December 31
Adjusted net income
2022
2021
2022
2021
2020
Florida Electric Utility
$
$
$
$
$
Canadian Electric Utilities
Gas Utilities and Infrastructure
Other Electric Utilities
Other
Adjusted net income
$
$
$
$
$
MTM gain (loss), after-tax
Impairment charges, after-tax
NSPML unrecoverable costs
Gain on sale, after tax and transaction costs
Net income attributable to common shareholders
$
$
$
$
$
8
The following
table highlights the significant changes in adjusted net income from 2021 to 2022:
For the
Three months ended
Year ended
millions of dollars
December 31
December 31
Adjusted net
income – 2021
$
$
Operating Unit Performance
Increased earnings at Tampa Electric due to higher revenues as a result
of rate increases effective January 2022, customer growth, and the
impact of a weakening CAD. These were partially offset by higher
operating, maintenance and general expenses (OM&G"), increased
interest expense, and higher depreciation. Year-over-year also
increased due to favourable weather
Increased earnings at Emera Energy Services ("EES") due to favourable
market conditions
Increased earnings at PGS due to higher off-system sales and customer
growth, partially offset by higher OM&G. Year-over-year also increased
due to reversal of accumulated depreciation as a result of the rate case
settlement
Increased earnings at Seacoast due to commencement of a 34-year
pipeline lateral lease in 2022
Increased earnings at NMGC were primarily due to higher asset
optimization revenues. Year-over-year increased earnings were partially
offset by higher OM&G and increased depreciation
Decreased earnings at NSPI due to higher OM&G primarily due to
increased costs for storm restoration, IT, power generation, regulatory
affairs, and higher depreciation. This was partially offset by higher sales
volumes. Quarter-over-quarter also decreased due to unfavourable
weather
Corporate
TGH award, after tax
and legal costs, in Q4 2022. Refer to the
"Significant Items Affecting Earnings" section
Increased income tax recovery primarily due to increased losses before
provision for income taxes
Increased OM&G, pre-tax, due to the timing of long-term compensation
and related hedges
Increased FX loss, pre-tax, primarily due to realized gains in 2021 on FX
hedges entered into to hedge USD denominated operating unit earnings
exposure
Increased interest expense, pre-tax, due to higher interest rates and
increased total debt
Increased preferred stock dividends due to issuance of preferred shares
in 2021
Other Variances
Adjusted net income – 2022
$
$
For further details of reportable segments contributions, refer to the "Financial Highlights" section.
9
For the
Year ended December 31
millions of dollars
2022
2021
2020
Operating cash flow before changes in working capital
$
$
$
Change in working capital
Operating cash flow
$
$
$
Investing cash flow
$
$
$
Financing cash flow
$
$
$
For further discussion of cash flow, refer to the "Consolidated Cash Flow Highlights" section.
As
at
December 31
millions of dollars
2022
2021
2020
Total assets
$
$
$
Total long-term debt (including current portion)
$
$
$
Consolidated Income Statement Highlights
For
the
Three months ended
Year ended
Year ended
millions of dollars
December 31
December 31
December 31
(except per share amounts)
2022
2021
Variance
2022
2021
Variance
2020
Operating revenues
$
$
$
$
$
$
$
Operating expenses
Income from operations
$
$
$
$
$
$
$
Net income attributable to
common shareholders
$
$
$
$
$
$
$
Adjusted net income
$
$
$
$
$
$
$
Weighted average shares of
common stock
outstanding (in
millions)
(1)
EPS – basic
$
$
$
$
$
$
$
EPS – diluted
$
$
$
$
$
$
$
Adjusted EPS – basic
$
$
$
$
$
$
$
Adjusted EBITDA
$
$
$
$
$
$
$
Dividends per common share
declared
$
$
$
$
$
$
$
Dividends per first preferred shares declared:
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
(1) Effective February 10, 2022, deferred share units are no longer able to be settled in shares and
are therefore excluded from
weighted average shares of common stock
outstanding.
Operating
Revenues
For Q4 2022, operating revenues increased $490 million compared to Q4 2021 and, absent increased
MTM gains of $195 million, increased $295 million. For the year ended December 31, 2022, operating
revenues increased $1,823 million compared to 2021 and, absent increased MTM gains of $555 million,
increased by $1,268 million. The increases in both periods were due to: higher fuel revenues at NMGC,
Tampa Electric PGS and BLPC; new rates effective January 2022 and
customer growth at Tampa
Electric; the impact of a weaker CAD; higher off-system sales and customer growth at PGS; and
increased marketing and trading margin due to favourable market conditions at EES. Year-over-year also
increased due to increased sales volumes at NSPI and favourable weather at Tampa Electric.
10
Operating
Expenses
For Q4 2022, operating expenses increased $286 million compared to Q4 2021 and, absent the GBPC
impairment charge of $73 million, increased by $213 million. For the year ended December 31, 2022,
operating expenses increased $1,124 million compared to 2021 and, absent the GBPC impairment
charge of $73 million, increased by $1,051 million. The increases in both periods were due to: higher
natural gas prices at NMGC and PGS; the impact of a weaker CAD; and increased OM&G at Tampa
Electric, Corporate, NSPI, NMGC and PGS. Year-over-year also increased due to higher natural gas and
fuel prices at Tampa Electric and BLPC.
Other Income,
Net
Other income, net increased for Q4 2022 and the year ended December 31, 2022, compared to the same
periods in 2021, primarily due to the TGH award in Q4
2022.
Net Income and Adjusted Net Income
Net income attributable to common shareholders for Q4 2022, as compared to Q4 2021, was favourably
impacted by the $151 million increase in MTM gains, after-tax and unfavourably impacted by the $73
million GBPC impairment charge. Absent these changes, adjusted net income increased $81 million. The
increase was primarily due to: the TGH award in Q4 2022; higher earnings contribution from Tampa
Electric, Emera Energy and NMGC; and the impact of a weaker CAD. These were partially offset by lower
earnings contribution from NSPI and increased corporate OM&G due to the timing of long-term
compensation and related hedges, and higher corporate interest expense.
Net income attributable to common shareholders for the year ended 2022, as compared to the same
period in 2021, was favourably impacted by the $388 million increase in MTM gains, after-tax and
unfavourably impacted by the $73 million GBPC impairment charge as well as the $7 million in NSPML
unrecoverable costs. Absent these changes, adjusted net income increased $127 million. The increase
was primarily due to: higher earnings contributions from Tampa Electric, Emera
Energy, PGS and
Seacoast; the TGH award in Q4 2022; and the impact of a
weaker CAD. These were partially offset by
increased corporate OM&G due to the timing of long-term compensation and related
hedges, higher
corporate interest expense, realized gains on corporate FX hedges in 2021, increased preferred stock
dividends and lower earnings contribution from NSPI.
EPS and Adjusted EPS – Basic
EPS and Adjusted EPS – basic were higher for
Q4
2022, and for the year ended December 31, 2022,
due to the impact of higher earnings as discussed above, partially offset by the impact of the increase in
weighted average shares of common stock
outstanding.
Effect of Foreign Currency Translation
Emera operates in Canada, the United States and various Caribbean countries and, as such, generates
revenues and incurs expenses denominated in local currencies which are translated into CAD for
financial reporting. Changes in translation rates, particularly in the value of the USD against the CAD, can
positively or adversely affect
results.
In general, Emera’s earnings benefit from a weakening CAD
and are adversely impacted by a
strengthening CAD. The impact in any period is driven by rate changes, the timing and percentage
of
earnings from foreign operations, and the impact of FX hedges entered into to hedge USD denominated
operating unit earnings exposure.
11
Results of foreign operations are translated at the weighted average rate of exchange, and assets and
liabilities of foreign operations are translated at period end rates. The relevant CAD/USD exchange rates
for 2022 and 2021 are as follows:
Three months
ended
Year ended
December 31
December 31
2022
2021
2022
2021
Weighted average
CAD/USD
$
1.37
$
1.26
$
1.34
$
1.26
Period end CAD/USD exchange rate
$
1.35
$
1.27
$
1.35
$
1.27
The table below includes Emera’s significant segments whose contributions to adjusted net income are
recorded in USD currency.
Three months ended
Year ended
For
the
December 31
December 31
millions of USD
2022
2021
2022
2021
Florida Electric Utility
$
91
$
67
$
458
$
369
Other Electric Utilities
7
4
23
16
Gas Utilities and
Infrastructure
45
37
143
130
Other segment
(2)
30
(20)
(50)
(98)
Total
(3)
$
173
$
88
$
574
$
417
(1) Includes USD net income from PGS, NMGC, SeaCoast and M&NP.
(2) Includes Emera Energy's USD adjusted net income from EES, Bear Swamp and interest expense on Emera Inc.'s USD
denominated debt.
(3) Excludes $222 million USD in MTM gain, after-tax, for the three months ended December 31, 2022 (2021 – $122
million USD
MTM gain, after-tax) and MTM gain, after-tax of $130 million
USD for the year ended December 31, 2022 (2021 – $164 million USD
MTM loss, after-tax) and the GBPC impairment charge of $54 million USD for the three months and year ended
December 31, 2022
(2021 - nil).
The impact of the weakening CAD, partially offset
by
the unrealized losses on FX hedges increased net
income by $42 million in Q4 2022 and $30 million for the year ended December 31, 2022, compared to
the same periods in 2021. Weakening of the CAD increased adjusted net income by $14 million in Q4
2022 and $28 million for the year ended December 31, 2022, compared to the same periods in 2021.
Impacts of the weakening CAD include the impacts of corporate FX hedges in the Other segment.
BUSINESS OVERVIEW AND OUTLOOK
Florida Electric
Utility
Florida Electric Utility consists of Tampa Electric, a vertically integrated regulated electric utility engaged
in the generation, transmission and distribution of electricity, serving customers in West Central Florida.
Tampa Electric has $12.1 billion USD of assets and approximately 827,000
customers at December 31,
2022. Tampa Electric owns 6,549 megawatts
(“MW”) of generating capacity, of which 78 per cent is
natural gas-fired, 15 per cent is solar and 7 per cent is coal.
Tampa Electric owns 2,171 kilometres of
transmission facilities and 19,916 kilometres of distribution facilities. Tampa Electric
meets the planning
criteria for reserve capacity established by the FPSC, which is a 20 per cent reserve margin over firm
peak
demand.
Tampa Electric’s approved regulated ROE range is 9.25 per
cent to 11.25 per cent, based on an allowed
equity capital structure of 54 per cent. An ROE of 10.20 per cent will be used for the
calculation of the
return on investments for clauses.
Tampa Electric anticipates earning within its ROE range in 2023. New base
rates effective January 1,
2023, as a result of the 2021 settlement agreement, will result in higher 2023 USD earnings than in
2022.
Normalizing 2022 for weather, Tampa Electric sales volumes in 2023
are projected to be higher than in
2022 due to customer growth. Tampa Electric expects customer growth rates in 2023 to be
comparable to
2022, reflective of the current expected economic growth in Florida.
12
On January
23, 2023, Tampa Electric requested an adjustment to its fuel charges to recover the 2022 fuel
under-recovery of $518 million USD over a period of 21 months. The request also included an adjustment
to 2023 projected fuel costs to reflect the reduction in natural gas prices since September 2022 for a
projected reduction of $170 million USD for the balance of 2023. The proposed changes will be decided
by the FPSC in March 2023, and recovery is expected to begin in April
2023.
On September 28, 2022, Hurricane Ian made landfall in Southwest
Florida as a Category 4 hurricane
and, as a result, approximately 291,000 customers lost power. The majority of Hurricane Ian
restoration
costs were charged against Tampa Electric’s FPSC
approved storm reserve, resulting in minimal impact
to earnings for 2022. The total cost of restoration was $126 million USD, with
approximately $119 million
USD charged to the storm reserve. Total restoration costs charged to the storm reserve have exceeded
the reserve balance and have been deferred as a regulatory asset for future recovery. On January 23,
2023, Tampa Electric petitioned the FPSC for recovery of the storm reserve
regulatory asset and the
replenishment of the balance in the reserve to the previous approved reserve level of $56 million USD,
for
a total of approximately $131 million
USD.
The proposed changes will be decided by the FPSC in March
2023, and recovery is expected to begin in April 2023 through March 2024.
The mid-course fuel adjustment requested by Tampa Electric on January 19, 2022, was approved on
March 1, 2022. The rate increase, effective with the first billing cycle in April 2022, covered higher fuel
and capacity costs of $169 million USD and was spread over customer bills from April 1, 2022 through
December 2022.
In 2023, capital investment in the Florida Electric Utility segment is expected to be $1.3 billion USD (2022
– $1.1 billion USD), including allowance for funds used during construction (“AFUDC”). Capital projects
include solar investments, grid modernization and storm hardening
investments.
Canadian Electric
Utilities
Canadian Electric Utilities includes NSPI and ENL. NSPI is a vertically integrated regulated electric utility
engaged in the generation, transmission and distribution of electricity and the primary electricity supplier
to customers in Nova Scotia. ENL is a holding company with equity investments in NSPML and LIL: two
transmission investments related to the development of an 824 MW hydroelectric generating facility at
Muskrat Falls on the Lower Churchill River in
Labrador.
NSPI
With $6.8 billion of assets and approximately 541,000 customers, NSPI owns 2,420 MW of generating
capacity, of which approximately 44 per cent is coal-fired; 28 per cent is natural gas and/or oil; 19 per
cent is hydro and wind; 7 per cent is petcoke and 2 per cent is biomass-fueled generation. In addition,
NSPI has contracts to purchase renewable energy from independent power producers (“IPPs”), which
own 546 MW of capacity. NSPI also has rights to 153 MW of Maritime Link
capacity, representing Nalcor
Energy’s (“Nalcor”) Nova
Scotia Block (“NS Block”) delivery obligations, as discussed below. NSPI owns
approximately 5,000 kilometres of transmission facilities and 28,000 kilometres of distribution facilities.
NSPI’s approved regulated ROE range is 8.75 per cent to 9.25 per cent, based on an actual five-quarter
average regulated common equity component of up to 40 per cent of approved rate
base.
NSPI anticipates earning near the low end of its allowed ROE range in
2023, and below the allowed
range in 2024. NSPI expects earnings and sales volumes to be higher in 2023 than
2022.
NSPI operated under a three-year fuel stability plan which resulted
in an average annual overall rate
increase of 1.5 per cent to recover fuel costs for the period of 2020 through 2022. These rates
include
recovery of Maritime Link costs (discussed below in the “ENL, NSPML” section).
13
On November
9, 2022, the Nova Scotia provincial government enacted Bill 212, “Public Utilities Act
(amended)”. The legislation
limits non-fuel rate increases in NSPI’s 2022 General Rate Application
(“GRA”) to the UARB, excluding increases
relating to demand side management (“DSM”) costs, to a total
of 1.8 per cent between the effective date of the
UARB’s decision and the end of 2024. The legislation
also:
●
reliability of service to ratepayers,
●
●
interest rate plus 1.75 per cent, unless otherwise directed by the UARB.
Actions required to address the impact of Bill 212, “Public Utilities Act (amended)”, include a material
reduction in NSPI’s planned capital investments and operating costs over the 2023 through 2024 period.
Such deferral of capital investment and operating costs may result in higher customer costs in future
periods. The legislation will have a direct and negative impact on the financial performance of NSPI and
has had a negative impact on NSPI’s credit quality. For more information on this risk, refer to the “Risk
Management and Financial Instruments – Regulatory and Political Risk” section.
On November 24, 2022, NSPI filed with the UARB a comprehensive settlement agreement between
NSPI, key customer representatives and participating interest groups (“NSPI Settlement Agreement”) in
relation to its GRA filed in January 2022. The NSPI Settlement Agreement was structured to be
consistent with the amendments to the Public Utilities Act made under Bill 212, which included a 1.8 per
cent cap on non-fuel rate increases for 2023 and 2024. Bill 212, “Public Utilities Act (amended),” is
described further above. The NSPI Settlement Agreement also addresses the recovery of fuel costs over
the settlement period and establishes a DSM rider. This will result in a combined fuel and non-fuel rate
increase of 6.9 per cent each year for 2023 and 2024 and annualized incremental revenue (fuel and
non-
fuel) of $105 million in 2023 and $115 million in 2024. In addition, any under or over recovery of fuel costs
will be addressed through the UARB’s established FAM process. NSPI’s ROE range will continue to be
8.75 per cent to 9.25 per cent, based on an actual five-quarter average regulated common equity
component of up to 40 per cent. The NSPI Settlement Agreement also establishes a storm rider for each
of 2023, 2024 and 2025, which gives NSPI the option to apply to the UARB for recovery of costs if major
storm restoration expense exceeds approximately $10 million in a given year. On February 2, 2023, NSPI
received the UARB’s decision, which substantially approved the NSPI Settlement Agreement as filed.
Approved rate increases will be effective as of the date of the decision.
On September 24, 2022, Nova Scotia was struck by Hurricane Fiona, which made landfall as a
post-
tropical storm equivalent to a Category 2 hurricane. The storm had sustained winds of over 100
kilometres per hour and peak gusts of approximately 180 kilometres per hour. This historic storm for Nova
Scotia caused significant and widespread damage to NSPI’s transmission and distribution system and at
the height of the storm approximately 415,000 customers lost power. The total cost of the restoration was
approximately $115 million, of which $91 million was capitalized to
Property, plant and equipment
(“PP&E”) and $24 million
deferred to Other long-term assets for future amortization, subject to UARB
approval. NSPI intends to submit an application to the
UARB requesting to defer the recognition of
incremental operating costs related to storm restoration. If the deferral is approved,
this balance will be
reclassified to “Regulatory assets” and amortized over the UARB approved recognition
period.
14
Energy from
renewable sources has increased with Nalcor’s NS Block delivery obligations from the
Muskrat Falls hydroelectric project
(“Muskrat Falls”) commencing in 2021. Nalcor is obligated to provide
NSPI with approximately 900 GWh of energy
annually over 35 years. In addition, for the first five years of
the NS Block, Nalcor is obligated to provide approximately 240
GWh of additional energy from the
Supplemental Energy Block transmitted through the Maritime Link. Nalcor’s final
commissioning of the LIL
has experienced delays and it’s expected that final commissioning of the LIL will be completed in
2023.
During these final stages of commissioning, there will be interruptions in supply, with any resultant
delivery shortfalls being delivered on a timely basis in accordance with the Energy and Capacity
Agreement. NSPI has the option of purchasing additional market-priced energy from Nalcor through the
Energy Access Agreement. The Energy Access Agreement enables NSPI to access a market-priced bid
from Nalcor for up to 1.8 Terawatt hours (“TWh”) of energy in any given year and, on average, 1.2 TWh of
energy per year through August 31, 2041.
Capital investment for 2023, including AFUDC, is expected to be approximately $375 million (2022 –
$540 million). NSPI is primarily investing in capital projects required to support power system reliability
and reliable service for
customers.
Environmental Legislation
and Regulations
NSPI is subject to environmental laws and regulations set by both the Government of Canada and the
Province of Nova Scotia. NSPI continues to work with both levels of government to comply with these
laws and regulations to maximize efficiency of emission control measures and minimize customer cost.
NSPI anticipates that costs prudently incurred to achieve legislated compliance will be recoverable under
NSPI’s regulatory framework. NSPI faces risks associated with achieving climate-related and
environmental legislative requirements, including the risk of non-compliance, which could adversely affect
NSPI’s operations and financial performance. For further discussion on these risks and environmental
legislation and regulations, refer to the “Enterprise Risk and Risk Management” section. Recent
developments related to provincial and federal environmental laws and regulations are outlined below.
Nova Scotia Cap-and-Trade Program Regulations:
NSPI is a participant in the Nova Scotia Cap-and-Trade Program (“Cap-and-Trade Program”) and is
subject to the 2019 through 2022 compliance period. NSPI received granted emissions allowances under
the Cap-and-Trade Program and is permitted to purchase up to five per cent of the credits available at
provincial auctions. Any remaining allowance shortfall requires the purchase of reserve credits directly
from the provincial government, which are anticipated to be priced at a premium to provincial auction
pricing. Compliance is forecast to be achieved through granted emissions allowances and credit
purchases under the Cap-and-Trade Program, including reserve credits. Lower than forecast Muskrat
Falls energy received during the compliance period has resulted in the increased deployment of higher
carbon-emitting generation sources. The Province of Nova Scotia has agreed to provide approximately
$165 million of relief from the 2019 through 2022 compliance costs, which was equal to the total cost of
compliance forecast at the time of the fuel update submitted by NSPI to the UARB in September 2022 as
part of the GRA. Discussions related to the final amount of relief and how this relief will be provided are
ongoing. Further, NSPI’s regulatory framework provides for the recovery of costs prudently incurred to
comply with the Cap-and-Trade Program Regulations pursuant to NSPI’s FAM.
15
Carbon Pricing Regulations:
On November 9, 2022, the Nova Scotia provincial government enacted Bill 208, “Environment Act
(amended)”. The legislation provides the framework for Nova Scotia’s system to comply with the federal
government’s 2023 through 2030 carbon pollution pricing regulations laid out in the Pan-Canadian
Framework on Clean Growth and Climate Change. Nova Scotia’s proposed system utilizes an
output-
based pricing system that will implement performance standards for large industrial greenhouse gas
emitters to achieve emission reduction goals. Subsequent regulations will be required to detail how the
pricing system will operate. The Province of Nova Scotia’s proposed output-based pricing system is
subject to the approval of the federal government. If an agreement is not reached between the federal
and provincial governments on a Nova Scotia system that meets the federal compliance criteria, Nova
Scotia will be subject to the federal carbon pollution pricing backstop which uses emissions performances
standards that vary by fuel type, and a carbon price that will start at $65 per tonne in 2023 and increase
by $15 per tonne annually, reaching $170 per tonne by 2030. NSPI’s regulatory framework provides for
the recovery of costs prudently incurred to comply with carbon pricing programs pursuant to NSPI’s FAM.
Nova Scotia Renewable Energy Regulations:
Under the provincially legislated Renewable Energy Regulations, 40 per cent of electric sales must be
generated from renewable sources. This standard was predicated on receipt of the full NS Block. Due to
the delay of the NS Block, the provincial government provided NSPI with an alternative compliance plan
that requires NSPI to achieve 40 per cent of electric sales generated from renewable sources over the
2020 through 2022 period. With delivery of the NS Block commencing later than anticipated, as well as
further interruptions in supply due to delays in the LIL, NSPI did not achieve the requirements of the
alternative compliance plan. The Renewable Energy Regulations require NSPI to have acted in a duly
diligent manner. If NSPI is found not to have acted in a duly diligent manner, it could be subject to a
maximum penalty of $10
million.
ENL
Total equity earnings from NSPML and LIL are expected to be higher in
2023, compared to 2022. Both
the NSPML and LIL investments are recorded as “Investments subject to significant
influence” on
Emera’s Consolidated Balance Sheets.
NSPML
Equity earnings from the Maritime Link are dependent on the approved ROE and operational
performance of NSPML. NSPML’s approved regulated ROE range is 8.75 per cent to 9.25 per cent,
based on an actual five-quarter average regulated common equity component of up to 30 per cent.
The Maritime Link assets entered service on January 15, 2018, enabling the transmission of energy
between Newfoundland and Nova Scotia, improved reliability and ancillary benefits, supporting the
efficiency and reliability of energy in both provinces. Nalcor continues to advance towards completion of
the LIL, and it’s expected final commissioning will be achieved in 2023. Nalcor’s NS Block delivery
obligations commenced on August 15, 2021, and the NS Block will be delivered over the next 35 years
pursuant to the project agreements. As Nalcor is in the final stages of commissioning the LIL, there will be
commissioning related interruptions in supply with any resultant delivery shortfalls being delivered on a
timely basis in accordance with the Energy and Capacity Agreement.
In February 2022, the UARB issued its decision and Board Order approving NSPML’s requested rate
base of approximately $1.8 billion less $9 million of costs ($7 million after-tax) that would not have
otherwise been recoverable if incurred by NSPI. NSPML also received approval to collect up to $168
million (2021 – $172 million) from NSPI for the recovery of costs associated with the Maritime Link in
2022. This was subject to a holdback of up to $2 million per month, beginning April 2022, contingent on
receiving at least 90 per cent of NS Block deliveries, including Supplemental Energy
deliveries.
16
In December
2022, NSPML received UARB approval to collect up to $164 million from NSPI for the
recovery of costs associated with the Maritime
Link in 2023. This continues to be subject to a holdback of
up to $2 million a month, as discussed above. On December 22, 2022,
the UARB clarified its earlier
direction regarding the holdback and NSPI can now release the holdback to NSPML when 90 per cent of
NS Block deliveries, including Supplemental Energy deliveries, is
achieved. This enabled NSPI to pay
NSPML approximately $4 million of the 2022 holdback. As of December 31, 2022, an additional $14
million in aggregate has been held back by NSPI. Determination of allocation of the $14 million between
NSPML and NSPI will be subject to a regulatory process that is expected to commence in early 2023 to
review the holdback
mechanism.
NSPML does not anticipate any significant capital investment in 2023.
LIL
ENL is a limited partner with Nalcor in LIL. Construction of the LIL is complete and Nalcor is forecasting it
will achieve final commissioning in
2023.
Equity earnings from the LIL investment are based upon the book value of the equity investment and the
approved ROE. Emera’s current equity investment is $740 million, comprised of $410 million in equity
contribution and $330 million of accumulated equity earnings. Emera’s total equity contribution in the LIL,
excluding accumulated equity earnings, is estimated to be approximately $650 million after the Lower
Churchill projects are completed.
Cash earnings and return of equity will begin after commissioning of the LIL by Nalcor, which is
anticipated in 2023, and until that point Emera will continue to record AFUDC earnings.
Gas Utilities and Infrastructure
Gas Utilities and Infrastructure includes PGS, NMGC, SeaCoast, Brunswick Pipeline and Emera’s
non-
consolidated investment in M&NP. PGS is a regulated gas
distribution utility engaged in the purchase,
distribution and sale of natural gas serving customers in Florida. NMGC is an
intrastate regulated gas
distribution utility engaged in the purchase, transmission, distribution and sale of natural gas serving
customers in New Mexico. SeaCoast is a regulated intrastate natural gas transmission company offering
services in Florida. Brunswick Pipeline is a regulated 145-kilometre pipeline delivering re-gasified
liquefied natural gas from Saint John, New Brunswick, to markets in the northeastern United States.
Peoples Gas System
With $2.5 billion USD of assets and approximately 468,000 customers, the PGS system includes 24,300
kilometres of natural gas mains and 13,500 kilometres of service lines. Natural gas throughput (the
amount of gas delivered to its customers, including transportation-only service) was 2 billion therms in
2022.
The approved ROE range for PGS is 8.9 per cent to 11.0 per cent, based on an allowed equity capital
structure of 54.7 per cent. An ROE of 9.9 per cent is used for the calculation of return on investments for
clauses.
New Mexico Gas Company, Inc.
With $2.0 billion USD of assets and approximately 545,000 customers, NMGC’s system includes
approximately 2,426 kilometres of transmission pipelines and 17,781 kilometres of distribution pipelines.
Annual natural gas throughput was approximately 926 million therms in 2022.
The approved ROE for NMGC is 9.375 per cent, on an allowed equity capital structure of 52 per
cent.
17
Gas Utilities and Infrastructure Outlook
Gas Utilities and Infrastructure USD earnings are anticipated to be higher in 2023 than 2022, primarily
due to a base rate increase at NMGC, effective January
2023.
PGS expects 2023 rate base growth and USD earnings to be consistent
with 2022 as higher revenues
from customer growth offset increased interest expenses and the effect of inflation. Increased
residential
and commercial sales volumes and customer growth are anticipated in 2023. PGS anticipates earning
below its allowed ROE range in 2023 primarily due to rate base growth. As a
result, on February 3, 2023,
PGS notified the FPSC that it is planning to file a base rate proceeding in April 2023 for new rates
effective January
2024.
The PGS rate case settlement, which was approved in November 2020,
provides the ability to reverse a
total of $34 million USD of accumulated depreciation through 2023. Through December 31, 2022,
PGS
reversed $14 million USD accumulated depreciation. The reversal of the remaining accumulated
depreciation is expected to occur over 2023.
NMGC expects 2023 rate base and USD earnings to be higher in 2023 than 2022 due to base rate
increases effective January 2023, as discussed below, and rate base growth to expand the distribution
system and to continue to reliably serve customers. NMGC anticipates earning near its authorized ROE
in 2023 and expects customer growth rates to be consistent with historical trends. NMGC’s asset
optimization revenues for 2022 were well above the historical average, and may not recur in 2023.
On December 13, 2021, NMGC filed a rate case with the NMPRC for new rates to become effective
January 2023. On May 20, 2022, NMGC filed an unopposed settlement agreement with the NMPRC for
an increase of $19 million USD in annual base revenues. The rates reflect the recovery of increased
operating costs and capital investments in pipelines and related infrastructure. The NMPRC approved the
settlement agreement on November 30, 2022.
In 2018, SeaCoast executed a 34-year agreement to provide long-term firm gas transportation service via
a 21-mile, 30-inch pipeline lateral. The lease of the pipeline lateral commenced January 1, 2022.
In 2023, capital investment in the Gas Utilities and Infrastructure segment is expected to be
approximately $475 million USD (2022 – $436 million USD), including AFUDC. PGS will make
investments to expand its system and support customer growth. NMGC will continue to make investments
to maintain the reliability of its system and support customer
growth.
Other Electric
Utilities
Other Electric Utilities includes Emera (Caribbean) Incorporated (“ECI”), a holding company with
regulated electric utilities. ECI’s regulated utilities include vertically integrated regulated electric utilities of
BLPC on the island of Barbados, GBPC on Grand Bahama Island, and a 19.5 per cent interest in Lucelec
on the island of St. Lucia, which is accounted for on the equity basis.
On March 31, 2022, Emera completed the sale of its 51.9 per cent interest in Dominica Electricity
Services Ltd. (“Domlec”) for proceeds which approximated carrying value. Domlec was included in the
Other Electric Utilities segment in Q1 2022. The sale did not have a material impact on earnings.
BLPC
With $505 million USD of assets and approximately 133,000 customers, BLPC owns 276 MW of
generating capacity, of which 96 per cent is oil-fired and four per cent is
solar. BLPC owns approximately
188 kilometres of transmission facilities
and 3,789 kilometres of distribution facilities. BLPC’s approved
regulated return on rate base for 2022 was 10 per
cent.
18
GBPC
With
$338 million USD of assets and approximately 19,000 customers, GBPC owns 98 MW of oil-fired
generation, approximately 90
kilometres of transmission facilities and 670 kilometres of distribution
facilities. GBPC’s approved regulatory return on
rate base for 2023 is 8.32 per cent (2022 – 8.23 per
cent).
Other Electric Utilities Outlook
Absent the impact of the GBPC impairment charge in Q4 2022, Other Electric Utilities’ USD earnings in
2023 are expected to increase over the prior year primarily as a result of higher earnings due to higher
base rates at BLPC.
BLPC currently operates pursuant to a franchise to generate, transmit and distribute electricity on the
island of Barbados until 2028. In 2019, the Government of Barbados passed legislation amending the
number of licenses required for the supply of electricity from a single integrated license which currently
exists, to multiple licenses for Generation, Transmission and Distribution, Storage, Dispatch and Sales. In
March 2021, BLPC reached commercial agreement with the Government of Barbados for each of the
license types, subject to the passage of implementing legislation. The new licenses are expected to take
effect in 2023 on completion of the legislative process. The Dispatch license will have a term of five years
with the remaining licenses having terms ranging from 25-30 years. BLPC anticipates that any increased
costs associated with the implementation of the new multi-licensed structure will be recoverable through
BLPC’s regulatory framework. BLPC is awaiting final enactment and will work towards implementation of
the licenses once received.
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 toward 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 an allowed regulatory ROE of 12.50
per cent on an allowed equity capital structure of 65 per cent. On September
16,
2022, the FTC granted
BLPC interim rate relief, allowing an increase in base rates of approximately $3 million USD for the
remainder of 2022 and approximately $1 million USD per month for 2023. Interim rate relief is effective
from September 16, 2022 until the implementation of final rates. The hearing concluded in October 2022.
On February 15, 2023, the FTC issued a decision on the BLPC rate review application which included the
following significant items: an allowed regulatory ROE of 11.75 per cent, an equity capital structure of 55
per cent, a directive to update the major components of rate base to September 16, 2022, and a directive
to establish regulatory liabilities of approximately $70 million USD related to the self-insurance fund,
accumulated depreciation, and taxes. The impacts to BLPC's rate base and final rates are not yet
determinable but management does not expect the decision to have a material impact on Emera’s
adjusted net income. BLPC will seek to clarify aspects of the FTC decision in its compliance filing and is
also considering filing a submission to the FTC for a review of the decision. BLPC expects a decision on
final rates from the FTC in 2023.
On January 14, 2022, the GBPA issued its decision on GBPC’s rate application. The decision, which
became effective April 1, 2022, allows for an increase in revenues of $3.5 million USD. The new rates
include a regulatory ROE of 12.84 per cent.
Effective November 1, 2022, GBPC’s fuel pass through charge was increased due to an increase in
global oil prices impacting the unhedged fuel cost. In 2023, the fuel pass through charge will be adjusted
monthly, in-line with actual fuel costs.
19
In 2023,
capital investment in the Other Electric Utilities segment is expected to be approximately $65
million USD (2022 – $48
million USD), primarily in more efficient and cleaner sources of generation,
including renewables and battery
storage.
Other
The Other segment includes those business operations that in a normal year are below the required
threshold for reporting as separate segments; and corporate expense and revenue items that are not
directly allocated to the operations of Emera’s subsidiaries and investments.
Business operations in the Other segment include Emera Energy and Emera Technologies LLC (“ETL”).
Emera Energy consists of EES, a wholly owned physical energy marketing and trading business and an
equity investment in a 50 per cent joint venture ownership of Bear Swamp, a 660 MW pumped storage
hydroelectric facility in northwestern Massachusetts. ETL is a wholly owned technology company focused
on finding ways to deliver renewable and resilient energy to
customers.
Corporate items included in the Other segment are certain corporate-wide functions including executive
management, strategic planning, treasury services, legal, financial reporting, tax planning, corporate
business development, corporate governance, investor relations, risk management, insurance, acquisition
and disposition related costs, gains or losses on select assets sales, and corporate human resource
activities. It includes interest revenue on intercompany financings and interest expense on corporate debt
in both Canada and the United States. It also includes costs associated with corporate activities that are
not directly allocated to the operations of Emera’s subsidiaries and investments.
Earnings from EES are generally dependent on market conditions. In particular, volatility in natural gas
and electricity markets, which can be influenced by weather, local supply constraints and other supply
and demand factors, can provide higher levels of margin opportunity. The business is seasonal, with Q1
and Q4 usually providing the greatest opportunity for earnings. EES is generally expected to deliver
annual adjusted net income within its guidance range of $15 to $30 million USD ($45 to $70 million USD
of margin).
Absent the TGH award in Q4 2022, the adjusted net loss from the Other segment is expected to be
higher in 2023, based on EES returning to its normal earnings range in 2023 and increased interest
expense. The increase is expected to be partially offset by decreased taxes due to a higher net
loss.
The Other segment does not anticipate any significant capital
investment in 2023.
20
CONSOLIDATED BALANCE SHEET HIGHLIGHTS
Significant changes in the Consolidated Balance Sheets between December 31, 2021 and December 31,
2022 include:
millions of
dollars
Increase
(Decrease)
Explanation
Assets
Cash and cash
equivalents
$
Decreased due to increased investment in PP&E at regulated
utilities and dividends on common stock. These were partially
offset by proceeds from short-term debt issuance at Emera and
Tampa Electric, increased proceeds under committed credit
facilities at NSPI and Emera, cash from operations, and issuance
of common stock
Inventory
Increased due to higher commodity prices at Emera Energy and
NSPI, increased materials inventory at Tampa Electric and the
effect of the FX translation of Emera's foreign affiliates
Derivative instruments (current and
long-term)
Increased due to reversal of 2021 contracts at Emera Energy
Regulatory assets (current and long-
term)
Increased due to higher fuel cost recovery clauses at Tampa
Electric, increased FAM deferrals, driven mainly by increased
Cap-and Trade emissions compliance charges, and increased
deferred income tax regulatory assets at NSPI, the effect of the
FX translation of Emera's foreign affiliates, recognition of storm
reserve asset at Tampa Electric due to restoration costs from
Hurricane Ian in excess of the storm reserve liability, and
increased pension and post-retirement plan deferrals at Tampa
and NSPI. These were partially offset by recovery of gas costs
from the NMGC 2021 winter event
Receivables
and other assets
(current and long-term)
Increased due to higher gas transportation assets and higher
trade receivables due to higher commodity prices at Emera
Energy, fuel option receivable at NMGC and the effect of the FX
translation of Emera's foreign affiliates
PP&E, net of accumulated
depreciation and
amortization
Increased due to the effect of the FX translation of Emera's
foreign affiliates, and capital additions. These were partially offset
by reclassification of Seacoast's pipeline lateral on
commencement of the lease in 2022
Net
investment in direct finance and
sales type leases
Increased due to commencement of the pipeline lease at
Seacoast in 2022
Goodwill
Increased due to the effect of the FX translation of Emera's
foreign affiliates, partially offset by the GBPC impairment
21
millions of dollars
Increase
(Decrease)
Explanation
Liabilities and Equity
Short-term debt and long-term debt
(including
current portion)
$
Increased due to the effect of the FX translation of Emera's
foreign affiliates, issuance of short-term debt at Emera and
Tampa Electric, and net borrowings under the committed credit
facility at NSPI and
Emera
Accounts payable
Increased due to increased commodity prices at Emera Energy,
Tampa Electric and NMGC, the effect of the FX translation of
Emera's foreign affiliates, higher cash collateral position on
derivative instruments at NSPI, and timing of payments at Tampa
Electric and NSPI
Deferred income tax
liabilities, net of
deferred income tax
assets
Increased due to tax deductions in excess of accounting
depreciation related to PP&E, increase in net regulatory assets,
decrease in net derivative liabilities, and the effect of the FX
translation of Emera's foreign affiliates, partially offset by net
increase in tax loss carryforwards
Derivative
instruments (current and
long-term)
Increased due to new contracts in 2022, partially offset by
reversal of 2021 contracts and changes in existing positions at
Emera Energy
Regulatory liabilities (current
and
long-term)
Increased due to NMGC gas hedge settlements and the effect of
the FX translation of Emera's foreign affiliates, partially offset by
decreased storm reserve at Tampa Electric due to restoration
costs incurred from Hurricane Ian
Pension and
post-retirement
liabilities
Decreased due to favourable changes in actuarial assumptions,
partially offset by lower investment returns
Other liabilities (current and long-
term)
Increased due to accrued emissions compliance charges at NSPI
and the effect of the FX translation of Emera's foreign affiliates
Common stock
Increased due to Emera's ATM equity program and shares issued
under the DRIP
Accumulated other comprehensive
income
Increased due to the effect of the FX translation of Emera's
foreign affiliates
Retained earnings
Increased due to net income in excess of dividends paid.
OTHER
DEVELOPMENTS
USGAAP Reporting Extension
Emera was granted exemptive relief by Canadian securities regulators on September 13, 2022, and
under the Companies Act (Nova Scotia) on October 12, 2022, each allowing Emera to continue to report
its financial results in accordance with USGAAP (collectively the “Exemptive Relief”). The Exemptive
Relief will terminate on the earliest of: (i) January 1, 2027; (ii) if the Company ceases to have
rate-
regulated activities, the first day of the Company’s financial year that commences after the Company
ceases to have rate-regulated activities; and (iii) the first day of the Company’s financial year that
commences on or following the later of: (a) the effective date prescribed by the International Accounting
Standards Board (“IASB”) for the mandatory application of a standard within IFRS specific to entities with
rate-regulated activities (“Mandatory Rate-regulated Standard”); and (b) two years after the IASB
publishes the final version of a Mandatory Rate-regulated Standard. The Exemptive Relief replaces
similar relief that had been granted to Emera in 2018 and would have expired by no later than January 1,
2024.
Increase in Common Dividends
On September 22, 2022, the Emera Board of Directors approved an increase in the annual common
share dividend rate to $2.76 from $2.65. The first payment was effective November 15, 2022. Emera also
extended its dividend growth rate target of four to five per cent through 2025.
22
Appointments
Effective July 1, 2022, Michael Barrett was appointed Executive Vice President and General Counsel for
Emera. Mr. Barrett was most recently the General Counsel for Emera.
Effective June 30, 2022, Bruce Marchand was appointed Chief Risk and Sustainability Officer for Emera.
Mr. Marchand was most recently the Chief Legal and Compliance Officer for Emera.
FINANCIAL
HIGHLIGHTS
Florida Electric Utility
All amounts are reported in USD, unless otherwise stated.
Three months ended
Year ended
For the
December 31
December 31
millions of USD (except as
indicated)
2022
2021
2022
2021
Operating revenues – regulated electric
$
$
$
$
Regulated fuel for generation and purchased power
$
$
$
$
Contribution to consolidated net
income
$
$
$
$
Contribution to consolidated net income – CAD
$
$
$
$
Average fuel costs in dollars per MWh
$
$
$
$
The impact of the change in the FX rate increased CAD earnings for the three months and year ended
December 31, 2022, by $10 million and $23 million,
respectively.
Net Income
Highlights of the net income changes are summarized in the following table:
For the
Three months ended
Year ended
millions of USD
December 31
December 31
Contribution to consolidated net income – 2021
$
67
$
Increased operating revenues due to higher rates effective January
2022, higher fuel recovery clause revenue as a result of increased fuel
costs, and customer growth. Year-over-year also increased due to
favourable weather
Fuel for generation and purchased power decreased in Q4 due to
lower natural gas prices quarter-over-quarter. Year -over-year, fuel
increased due to higher natural gas prices
Increased OM&G due to timing of deferred clause recoveries.
Year-
over-year the increase is also due to higher transmission and
distribution costs, higher benefit costs and higher insurance costs
Increased depreciation and amortization due to additions to facilities
and the in-service of generation projects
Increased interest expense due to higher interest rates and higher
borrowings to support Tampa Electric’s ongoing operations, including
fuel under-recoveries, and capital investments
Decreased AFUDC earnings due to timing of Big Bend modernization
and solar projects
Increased income tax expense year-over-year primarily due to
increased income before provision for income taxes
Other
Contribution to consolidated net income – 2022
$
$
23
Operating Revenues – Regulated
Electric
Annual electric revenues and sales volumes are summarized in the following table by customer
class:
Electric Revenues
Electric Sales Volumes
(Gigawatt hours ("GWh"))
2022
2021
2022
2021
Residential
$
$
Commercial
Industrial
Other
(1)
Total
$
$
(1) Other includes sales to public authorities, off-system sales to other utilities and regulatory deferrals
related to clauses.
Regulated Fuel for Generation and
Purchased Power
Annual production volumes are summarized in the following
table:
Production Volumes (GWh)
2022
2021
Natural
gas
Purchased
power
Solar
Coal
Total
Tampa Electric’s fuel costs are affected by commodity prices and
generation mix that is largely
dependent on economic dispatch of the generating fleet, bringing the lowest cost options on first
(renewable energy from solar), such that the incremental cost of production increases as sales volumes
increase. Generation mix may also be affected by plant outages, plant performance, availability of lower
priced short-term purchased power, availability of renewable solar generation, and compliance with
environmental standards and regulations.
Regulatory Environment
Tampa Electric is regulated by the FPSC and is also subject to regulation
by the FERC. The FPSC sets
rates at a level that allows utilities such as Tampa Electric to collect total revenues or revenue
requirements equal to their cost of providing service, plus an appropriate return on invested capital. Base
rates are determined in FPSC rate setting hearings which can occur at the initiative of Tampa Electric, the
FPSC or other interested parties. For further details on Tampa
Electric’s regulatory environment, base
rates and recovery
mechanisms, refer to note 7 in the consolidated financial statements.
Canadian Electric Utilities
Three months ended
Year ended
For the
December 31
December 31
millions of dollars (except as
indicated)
2022
2021
2022
2021
Operating revenues – regulated electric
$
$
$
$
Regulated fuel for generation and purchased power
(1)
$
$
$
$
Contribution to consolidated adjusted net income
$
$
$
$
NSPML unrecoverable costs
$
$
$
$
Contribution to consolidated net income
$
$
$
$
Average fuel costs in dollars per MWh
$
$
$
$
(1) Regulated fuel for generation and purchased power includes NSPI's
FAM and fixed cost deferrals on the Consolidated
Statements of Income,
however it is excluded in the segment overview.
24
Canadian Electric Utilities' contribution to consolidated adjusted net income is summarized in the following
table:
Three months
ended
Year ended
For the
December 31
December 31
millions of dollars
2022
2021
2022
2021
NSPI
$
$
$
$
Equity investment in LIL
Equity investment in NSPML
(1)
Contribution to consolidated adjusted net
income
$
$
$
$
(1) Excludes $7 million in NSPML unrecoverable costs, after-tax, for the year ended December 31, 2022 (2021 – nil).
Net Income
Highlights of the net income changes are summarized in the following table:
For the
Three months ended
Year ended
millions of dollars
December 31
December 31
Contribution to consolidated net income – 2021
$
$
Increased operating revenues due to increased electric revenues related
to recovery of fuel costs from an industrial customer, increased
residential and commercial class sales volumes, and increased
electricity pricing effective January 1, 2022. Quarter-over-quarter
increase partially offset by unfavourable weather
Decreased regulated fuel for generation and purchased power
quarter-
over-quarter due to lower Cap-and-Trade Program provision and lower
Maritime Link assessment costs. Increased regulated fuel for generation
and purchased power year-over year due to increased Nova Scotia
Cap-and-Trade program provision, increased commodity prices and
higher sales volume, partially offset by a favourable change in
generation mix
Decreased FAM and fixed cost deferrals year-over-year due to
increased recovery of fuel costs, partially offset by increased
Cap-and-
Trade provision. Quarter-over-quarter decreased due to increased
recovery of fuel costs and decreased Cap-and-Trade provision
Increased OM&G due to higher costs for storm restoration, IT, power
generation, and regulatory affairs
Increased depreciation and amortization due to increased PP&E
in-
service
Decreased income tax expense primarily due to increased tax
deductions in excess of accounting depreciation and amortization
related to PP&E and deferrals and decreased income before provision
for income taxes. This was partially offset by the benefit of tax loss
carryforwards recognized as a deferred income tax regulatory liability
Year-over-year decrease in net income from equity investment in
NSPML primarily due to the Maritime Link holdback
NSPML unrecoverable costs
Other
Contribution to consolidated net income – 2022
$
$
25
NSPI
Operating Revenues – Regulated
Electric
Annual electric revenues and sales volumes are summarized in the following tables by customer class:
Electric Revenues
Electric Sales Volumes
(millions of dollars)
(GWh)
2022
2021
2022
2021
Residential
$
$
Commercial
Industrial
Other
Total
$
$
Regulated Fuel for Generation and Purchased Power
Annual production volumes are summarized in the following
table:
Production Volumes (GWh)
2022
2021
Coal
Natural gas
Purchased power – other
Petcoke
Oil
Total non-renewables
Purchased power
Wind and
hydro
Biomass
Total renewables
Total production volumes
NSPI’s fuel costs are affected by commodity prices and generation mix, which is largely dependent on
economic dispatch of the generating fleet. NSPI brings the lowest cost options on stream first after
renewable energy from IPPs, including Community Feed-in Tariff (“COMFIT”) participants, for which NSPI
has power purchase agreements in place, and the NS Block of energy, including the Supplemental
Energy Block. NSPI pays annual assessments approved by the UARB to NSPML for use of the Maritime
Link, and therefore utilizes all transmitted NS Block and Supplemental Energy Block energy received
which carries no additional fuel cost.
NSPI-owned hydro and wind have no fuel cost component. After hydro and wind, historically, petcoke and
coal have the lowest per-unit fuel cost, followed by natural gas. Oil, biomass and purchased power have
the next lowest fuel cost, depending on the relative pricing of each. Generation mix may also be affected
by plant outages, availability of renewable generation, availability of energy from the NS Block, plant
performance, and compliance with environmental standards including the Cap-and-Trade
Program.
The generation mix has undergone significant transformation with
the addition of non-dispatchable
renewable energy sources such as wind, including from IPPs and COMFIT, which typically have a
higher
cost per MWh than NSPI-owned generation or other purchased power sources.
The provision for the Cap-and-Trade program was an $18 million recovery for the three months ended
December 31, 2022 (2021 - $35 million expense) and a $134 million expense for the year ended
December 31, 2022 (2021 - $38 million expense). For further information on this non-cash accrual, the
estimated costs and the FAM regulatory balance, refer to note 7 in the consolidated financial statements.
26
Regulatory Environment -
NSPI
NSPI is a public utility as defined in the Public Utilities Act and is subject to regulation under the Public
Utilities Act by the UARB. The Public Utilities Act gives the UARB supervisory powers over NSPI’s
operations and expenditures. Electricity rates for NSPI’s customers are subject to UARB approval. NSPI
is not subject to a general annual rate review process, but rather participates in hearings held from time to
time at NSPI’s or the UARB’s request. For further details on NSPI’s regulatory environment and recovery
mechanisms, refer to note 7 in the consolidated financial statements.
Gas Utilities and Infrastructure
All amounts are reported in USD, unless otherwise
stated.
Three months ended
Year ended
For the
December 31
December 31
millions of USD (except as
indicated)
2022
2021
2022
2021
Operating revenues – regulated gas
(1)
$
$
$
$
Operating revenues – non-regulated
Total operating revenue
$
$
$
$
Regulated cost of natural gas
$
$
$
$
Contribution to consolidated net
income
$
$
$
$
Contribution to consolidated net income – CAD
$
$
$
$
three months ended December 31, 2022 and $47 million (2021 – $46 million) for the year ended December 31
2022; however, it is
excluded from the gas revenues and cost of natural
gas analysis below.
Gas Utilities and Infrastructure's contribution to consolidated net income is summarized in the following
table:
Three months
ended
Year ended
For the
December 31
December 31
millions of USD
2022
2021
2022
2021
PGS
$
$
$
$
NMGC
Other
Contribution to consolidated net
income
$
$
$
$
The impact of the change in the FX rate increased CAD earnings for the three months and year ended
December 31, 2022, by $4 million and $6 million, respectively.
27
Net Income
Highlights of the net income changes are summarized in the following table:
For the
Three months ended
Year ended
millions of USD
December 31
December 31
Contribution to consolidated net income – 2021
$
$
Increased gas revenues due to higher purchased gas adjustment
clause revenues at NMGC and PGS as a result of higher gas prices,
higher off-system sales, and customer growth at PGS
Increased asset optimization revenues at NMGC. In 2022, NMGC’s 30
per cent share of asset optimization revenues were well above the
historical average, and may not reoccur in 2023
Increased cost of natural gas sold due to higher gas prices at NMGC
and PGS, and higher off-system sales at PGS
Increased OM&G primarily due to higher labour and benefits costs at
NMGC and PGS, and higher contractor costs at PGS
Increased depreciation and amortization due to asset growth at PGS
and NMGC. Year-over-year, the increase was more than offset by the
reversal of accumulated depreciation as a result of the rate case
settlement at
PGS
Increased interest expense due to higher interest rates
Increased income tax expense primarily due to increased income
before provision for income taxes
Other
Contribution to consolidated net income – 2022
$
$
Operating Revenues – Regulated
Gas
Annual gas revenues and sales volumes are summarized in the following tables by customer
class:
Gas Revenues
Gas Volumes
(millions of USD)
(Therms)
2022
2021
2022
2021
Residential
$
$
Commercial
Industrial
(1)
Other
(2)
Total
(3)
$
$
(1) Industrial gas revenue includes sales to power generation customers.
(2) Other gas revenue includes off-system sales to other utilities and various other items.
(3) Total gas revenue excludes $47 million of finance income from
Brunswick Pipeline (2021 – $46 million).
Regulated Cost of Natural Gas
PGS and NMGC purchase gas from various suppliers depending on the needs of their customers. In
Florida, gas is delivered to the PGS distribution system through interstate pipelines on which PGS has
firm transportation capacity for delivery by PGS to its customers. NMGC’s natural gas is transported on
major interstate pipelines and NMGC’s intrastate transmission and distribution system for delivery to
customers.
In Florida, natural gas service is unbundled for non-residential customers and residential customers who
use more than 1,999 therms annually and elect the option. In New Mexico, NMGC is required, if
requested, to provide transportation-only services for all customer classes. The commodity portion of
bundled sales is included in operating revenues, at the cost of the gas on a pass-through basis, therefore
no net earnings effect when a customer shifts to transportation-only sales.
28
Annual gas sales by type are summarized in the following table:
Gas Volumes by Type (millions of Therms)
2022
2021
Transportation
System supply
Total
Regulatory Environments
PGS is regulated by the FPSC. The FPSC sets rates at a level that allows utilities such as PGS to collect
total revenues or revenue requirements equal to their cost of providing service, plus an appropriate return
on invested capital.
NMGC is subject to regulation by the NMPRC. The NMPRC sets rates at a level that allows NMGC to
collect total revenues equal to its cost of providing service, plus an appropriate return on invested
capital.
For further information on PGS and NMGC’s regulatory
environment and recovery mechanisms, refer to
note 7 in the consolidated financial statements.
Other Electric
Utilities
All amounts are reported in USD, unless otherwise
stated.
Three months ended
Year ended
For the
December 31
December 31
millions of USD (except as indicated)
2022
2021
2022
2021
Operating revenues – regulated electric
$
$
$
$
Regulated fuel for generation and purchased power
$
$
$
$
Contribution to consolidated adjusted net income
$
$
$
$
Contribution to consolidated adjusted net income – CAD
$
$
$
$
GBPC Impairment charge
$
$
$
$
Equity securities MTM gain (loss)
$
$
$
$
Contribution to consolidated net
income
$
$
$
$
Contribution to consolidated net income – CAD
$
$
$
$
Electric sales volumes (GWh)
Electric production volumes (GWh)
Average fuel cost in dollars per MWh
$
$
$
$
The impact of the change in the FX rate increased net loss by $3 million for the three months and year
ended December 31, 2022 and had a minimal impact on adjusted net income for the same periods.
Other Electric Utilities' contribution to consolidated adjusted net income is summarized in the following
table:
Three months
ended
Year ended
For the
December 31
December 31
millions of USD
2022
2021
2022
2021
BLPC
$
$
$
$
GBPC
Other
Contribution to consolidated adjusted net
income
$
$
$
$
29
Net Income
Highlights of the net income changes are summarized in the following table:
For the
Three months ended
Year ended
millions of USD
December 31
December 31
Contribution to consolidated net income – 2021
$
$
Increased operating revenues - regulated electric year-over-year due to
higher fuel revenue at BLPC as a result of higher fuel prices, partially
offset by the sale of Domlec in Q1 2022
Increased fuel for generation and purchased power as a result of
higher fuel prices at BLPC
Decreased OM&G due to the sale of Domlec in Q1 2022 and lower
generation costs at GBPC, partially offset by the recognition of
Hurricane Dorian insurance proceeds at GBPC in 2021
Goodwill impairment charge at GBPC
Decreased MTM gain on equity securities held in
BLPC
Other
Contribution to consolidated net income – 2022
$
$
Regulatory
Environments
BLPC is regulated by the FTC, an independent regulator. Rates are set to recover prudently incurred
costs of providing electricity service to customers plus an appropriate return on capital
invested.
GBPC is regulated by the GBPA. Rates are set to recover
prudently incurred costs of providing electricity
service to customers plus an appropriate return on rate
base.
For further details on BLPC and GBPC’s regulatory
environments and recovery mechanisms, refer to note
7 in the consolidated financial statements.
Other
Three
months ended
Year ended
For the
December 31
December 31
millions of dollars
2022
2021
2022
2021
Marketing and trading margin
(1)
(2)
$
$
$
$
Other non-regulated operating revenue
Total operating revenues – non-regulated
$
$
$
$
Contribution to consolidated adjusted net income (loss)
$
$
$
$
MTM gain (loss), after-tax
(3)
Contribution to consolidated net income (loss)
$
$
$
$
(1) Marketing and trading margin represents EES's purchases and sales of natural gas and
electricity, pipeline and storage capacity
costs and energy asset
management services’ revenues.
(2) Marketing and trading margin excludes a MTM gain, pre-tax of $430 million in Q4 2022
(2021 – $212 million gain) and a gain of
$281 million for the year
ended December 31, 2022 (2021 – $289 million loss).
(3) Net of income
tax expense of $124 million for the three months ended December 31, 2022 (2021 – $63 million expense) and $73
million expense for the year ended December 31, 2022 (2021 – $86 million recovery).
Other's contribution to consolidated adjusted net income is summarized in the following table:
Three months
ended
Year ended
For the
December 31
December 31
millions of dollars
2022
2021
2022
2021
Emera Energy
$
$
$
$
Corporate – see breakdown of adjusted contribution below
Emera Technologies
Other
Contribution to consolidated adjusted net income (loss)
$
$
$
$
30
MTM
Adjustments
Emera Energy’s “Marketing and trading margin”, “Non-regulated fuel for generation and purchased
power”, “Income from equity investments” and “Income tax expense (recovery)” are affected by MTM
adjustments. Management believes excluding the effect of MTM valuations, and changes thereto, from
income until settlement better matches the financial effect of these contracts with the underlying cash
flows. Variance explanations of the MTM changes for this quarter and for the year are explained in the
chart
below.
Emera Energy has a number of asset management agreements
(“AMA”) with counterparties, including
local gas distribution utilities, power utilities and natural gas producers in
North America. The AMAs
involve Emera Energy buying or selling gas for a specific term, and the corresponding release of the
counterparties’ gas transportation/storage capacity to Emera Energy. MTM adjustments on these AMAs
arise on the price differential between the point where gas is sourced and where it is delivered. At
inception, the MTM adjustment is offset fully by the value of the corresponding gas transportation asset,
which is amortized over the term of the AMA
contract.
Subsequent changes in gas price differentials, to the extent
they are not offset by the accounting
amortization of the gas transportation asset, will result in MTM gains or losses recorded in
income. MTM
adjustments may be substantial during the term of the contract, especially in the winter months of a
contract when delivered volumes and market pricing are usually at peak levels. As a contract is realized,
and volumes reduce, MTM volatility is expected to decrease. Ultimately, the gas transportation asset and
the MTM adjustment reduce to zero at the end of the contract term. As the business grows, and AMA
volumes increase, MTM volatility resulting in gains and losses may also increase.
Emera Corporate has FX forwards to manage the cash flow risk of forecasted USD cash inflows.
Fluctuations in the FX rate result in MTM gains or losses recorded in income.
Net Income
Highlights of the net income changes are summarized in the following table:
For the
Three months
ended
Year ended
millions of dollars
December 31
December 31
Contribution to
consolidated net income (loss) – 2021
$
$
Increased marketing and trading margin due to weather driven market
conditions that increased pricing and volatility, which created profitable
opportunities for Emera Energy. Year -over-year increase also reflected
sustained higher pricing and volatility
Increased OM&G, pre-tax, primarily due to the timing of long-term
compensation and related hedges
Increased interest expense, pre-tax, due to increased interest rates
and increased total debt
Increased FX loss, pre-tax, primarily due to realized gains in 2021 on
FX hedges entered into to hedge USD denominated operating unit
earnings exposure
Increased income tax recovery primarily due to increased losses before
provision for income taxes
Increased preferred stock dividends due to issuance of preferred
shares in
2021
TGH award, after tax and legal costs
Increased MTM gain, after-tax, due to change in existing positions and
larger reversal of MTM losses in 2022, partially offset by higher
amortization of gas transportation assets in 2022 at Emera Energy
Other
Contribution to consolidated net income (loss) – 2022
$
$
31
Emera
Energy
EES derives revenue and earnings from the wholesale marketing and
trading of natural gas and
electricity within the Company’s risk tolerances, including those related to value-at-risk
(“VaR”) and credit
exposure. EES purchases and sells physical natural gas and electricity, the related transportation
and
transmission capacity rights, and provides energy asset management services. The primary market area
for the natural gas and power marketing and trading business is northeastern North America, including
the Marcellus and Utica shale supply areas. EES also participates in the Florida, United States Gulf Coast
and Midwest/Central Canadian natural gas markets. Its counterparties include electric and gas utilities,
natural gas producers, electricity generators and other marketing and trading entities. EES operates in a
competitive environment, and the business relies on knowledge of the region’s energy markets,
understanding of pipeline and transmission infrastructure, a network of counterparty relationships and a
focus on customer service. EES manages its commodity risk by limiting open positions, utilizing financial
products to hedge purchases and sales, and investing in transportation capacity rights to enable
movement across its
portfolio.
Corporate
Corporate's adjusted loss is summarized in the following
table:
Three months
ended
Year ended
For the
December 31
December 31
millions of dollars
2022
2021
2022
2021
Operating
expenses
$
$
$
$
Interest expense
Income tax
recovery
Preferred dividends
TGH award, after tax and legal costs
Other
Corporate adjusted net
loss
$
$
$
$
(1) Operating expenses include OM&G and depreciation. In Q4 2021, OM&G and depreciation were offset
by a decrease in long-
term incentive compensation. The value of long-term
incentive compensation and related hedges are impacted by changes in
Emera's period end share
price.
(2) Other includes realized FX gains and losses on FX hedges
entered into to hedge USD denominated operating unit earnings
exposure.
(3) Includes a realized, pre-tax net loss of $5 million (2021 – $5 million gain) quarter-to-date and a $6
million loss for the year ended
December 31, 2022 (2021 – $18
million gain) on FX hedges, as discussed above.
(4) Excludes a MTM gain, after-tax of $9 million for the three months ended
December 31, 2022 (2021 – $3 million loss) and a MTM
loss, after-tax of $12 million for the year ended December 31, 2023
(2021 – $14 million loss)
LIQUIDITY AND CAPITAL RESOURCES
The Company generates internally sourced cash from its various regulated and non-regulated energy
investments. Utility customer bases are diversified by both sales volumes and revenues among customer
classes. Emera’s non-regulated businesses provide diverse revenue streams and counterparties to the
business. Circumstances that could affect the Company’s ability to generate cash include changes to
global macro-economic conditions, downturns in markets served by Emera, impact of fuel commodity
price changes on collateral requirements and timely recoveries of fuel costs from customers, the loss of
one or more large customers, regulatory decisions affecting customer rates and the recovery of regulatory
assets, and changes in environmental legislation. Emera’s subsidiaries are generally in a financial
position to contribute cash dividends to Emera provided they do not breach their debt covenants, where
applicable, after giving effect to the dividend payment, and maintain their credit metrics.
32
Emera’s future liquidity and capital needs will be predominately for working capital requirements, ongoing
rate base investment, business acquisitions, greenfield development, dividends and debt servicing.
Emera has an $8 – 9 billion capital investment plan over the 2023-to-2025 period (including a $240 million
equity investment in the LIL in 2023), mainly focused in Florida. This plan includes significant rate base
investments across the portfolio in renewable and cleaner generation, infrastructure modernization and
customer-focused technologies. Capital investments at the regulated utilities are subject to regulatory
approval.
Emera plans to use cash from operations and debt raised at the utilities to support normal operations,
repayment of existing debt, and capital requirements. Debt raised at certain of the Company’s utilities is
subject to applicable regulatory approvals. Equity requirements in support of the Company’s capital
investment plan are expected to be funded through the issuance of preferred equity and the issuance of
common equity through Emera’s DRIP and ATM
program.
Emera has credit facilities with varying maturities that
cumulatively provide $4.7 billion of credit, with
approximately $1.1 billion undrawn and available at December 31, 2022. The
Company was holding a
cash balance of $332 million at December 31, 2022. For further discussion, refer to the “Debt
Management” section below. For additional information regarding the credit facilities, refer to notes 23
and 25 in the consolidated financial statements.
Consolidated Cash Flow Highlights
Significant changes in the Consolidated Statements of Cash Flows between the years ended December
31, 2022 and 2021 include:
millions of dollars
2022
2021
$ Change
Cash, cash equivalents and restricted cash, beginning of period
$
$
$
Provided by (used in):
Operating activities
$
$
$
Investing activities
Financing activities
Effect of exchange rate changes on cash, cash equivalents and restricted cash
Cash, cash equivalents, and restricted cash, end of period
$
$
$
Cash Flow from Operating Activities
Net cash provided by operating activities
decreased
$272 million to $913 million for the year ended
December 31, 2022, compared to $1,185 million in 2021.
Cash from operations before changes in working capital
decreased
$190 million for the year ended
December 31, 2022. This decrease was due to under-recovery of clause-related costs primarily due to
higher natural gas prices at Tampa Electric, unfavourable changes in
Tampa Electric’s storm reserve
balance as a result of Hurricane
Ian, increased fuel for generation and purchased power at NSPI, and
decreased long-term payables due to the Nova Scotia
Cap-and-Trade accrued emissions compliance
charges being reclassified to other current liabilities as the liability is anticipated
to be settled in 2023.
This was partially offset by the 2021 deferral of gas costs at NMGC resulting from the extreme cold
weather event, increased revenues at Tampa Electric and NSPI, favourable changes in regulatory
liabilities due to the NMGC gas hedge settlement, TGH award, and increased marketing and trading
margin at Emera Energy.
33
Changes in
working capital decreased operating cash flows by $82 million for the year ended December
31, 2022. This decrease was due to
unfavourable changes in accounts receivable at NMGC due to the
gas hedge settlement, unfavourable changes in accounts receivable
at NSPI, unfavourable changes in
cash collateral positions on derivative instruments at NSPI, and the required prepayment of
income taxes
and related interest at NSPI. This was partially offset by the Nova Scotia Cap-and-Trade accrued
emissions compliance charges, favourable changes in cash collateral positions at Emera Energy, and
favourable changes in accounts payable at Tampa Electric and NMGC.
Cash Flow used in Investing Activities
Net cash used in investing activities increased $237 million to $2,569 million for the year ended
December 31, 2022, compared to $2,332 million in 2021. The increase was due to higher capital
investment in 2022.
Capital expenditures for the year ended December 31, 2022, including AFUDC, were $2,646 million
compared to $2,420 million in 2021. Details of 2022 capital spending by segment are shown
below:
●
●
●
●
●
Cash Flow from Financing Activities
Net cash provided by financing activities increased $244 million to $1,555 million for the year ended
December 31, 2022, compared to $1,311 million in 2021. This increase was due to higher proceeds of
short-term debt at Tampa Electric, proceeds from committed credit facilities at NSPI, and term loan
issuance at Emera in 2022. These were partially offset by the issuance of preferred shares in 2021, lower
proceeds of long-term debt at Tampa Electric, and net proceeds of long-term debt at NMGC in 2021.
Working Capital
As at December 31, 2022, Emera’s cash and cash equivalents were $310 million (2021 – $394 million)
and Emera’s investment in non-cash working capital was $1,173 million (2021 – $491 million). Of the
cash and cash equivalents held at December 31, 2022, $250 million was held by Emera’s foreign
subsidiaries (2021 – $194 million). A portion of these funds are invested in countries that have certain
exchange controls, approvals, and processes for repatriation. Such funds are available to fund local
operating and capital requirements unless repatriated.
34
Contractual Obligations
As at December 31, 2022, contractual commitments for each of the next five years and in aggregate
thereafter consisted of the following:
millions of dollars
2023
2024
2025
2026
2027
Thereafter
Total
Long-term debt
principal
$
$
$
$
$
$
$
Interest payment obligations
(1)
Transportation
(2)
Purchased power
(3)
Fuel, gas supply and storage
Capital
projects
Asset retirement obligations
Pension and post-retirement
obligations
(4)
Equity investment commitments
(5)
Other
$
$
$
$
$
$
$
(1) Future interest payments are calculated based on the assumption that all debt is outstanding until
maturity. For debt instruments
with variable rates, interest is calculated
for all future periods using the rates in effect at December 31, 2022, including any expected
required payment under associated swap agreements.
(2) Purchasing commitments for transportation of fuel and transportation capacity on various
pipelines. Includes a commitment of
$144 million related to a gas
transportation contract between PGS and SeaCoast through 2040.
(3) Annual requirement to purchase electricity production from IPPs
or other utilities over varying contract lengths.
(4) The estimated contractual obligation is calculated as the current
legislatively required contributions to the registered funded
pension
plans (excluding the possibility of wind-up), plus the estimated costs of further benefit accruals contracted under NSPI's
Collective Bargaining Agreement and estimated benefit payments related to other unfunded benefit plans.
(5) Emera has a commitment to make a final equity contribution to the LIL upon its commissioning. Once commissioned, the
commercial agreements between Emera and Nalcor require true ups to finalize the respective investment
obligations of the parties
in relation to the Maritime Link and LIL.
NSPI has a contractual obligation to pay NSPML for use of the Maritime Link over approximately 38 years
from its January 15, 2018 in-service date. In February 2022, the UARB issued its decision and Board
Order approving NSPML’s requested rate base of approximately $1.8 billion. In December 2022, the
UARB approved the collection of $164 million from NSPI for the recovery of Maritime Link costs in 2023.
The timing and amounts payable to NSPML for the remainder of the 38-year commitment period are
subject to UARB
approval.
Emera has committed to obtain certain transmission rights for
Nalcor, if requested, to enable it to transmit
energy which is not otherwise used in Newfoundland and Labrador or Nova Scotia.
Nalcor has the right to
transmit this energy from Nova Scotia to New England energy markets effective August 15, 2021, the
date the NS Block delivery obligation commenced, and continuing for 50 years. As transmission rights are
contracted, the obligations are included within “Other” in the above table.
Forecasted Gross Consolidated Capital Expenditures
The 2023 forecasted gross consolidated capital expenditures are as follows:
millions of dollars
Florida
Electric
Utility
Canadian
Electric
Utilities
Gas Utilities
and
Infrastructure
Other
Electric
Utilities
Other
Total
Generation
$
$
$
$
$
$
New renewable generation
Transmission
Distribution
Gas transmission and distribution
Facilities, equipment, vehicles, and other
$
$
$
$
$
$
35
Debt Management
In addition to funds generated from operations, Emera and its subsidiaries have, in aggregate, access to
committed syndicated revolving and non-revolving bank lines of credit in either CAD or USD per the table
below.
Undrawn
Credit
and
millions of dollars
Maturity
Facilities
Utilized
Available
Emera –
Unsecured committed revolving credit facility
June 2027
$
$
$
TEC (in USD) – Unsecured committed revolving credit facility
(1)
December 2026
NSPI – Unsecured committed revolving credit facility
December 2027
Emera – Unsecured non-revolving
facility
December 2023
Emera – Unsecured non-revolving facility
August 2023
TEC (in USD) – Unsecured non-revolving facility
(2)
December 2023
TECO Finance (in USD) – Unsecured committed revolving credit
facility
December 2026
NSPI – Unsecured non-revolving facility
July 2024
NMGC (in USD) – Unsecured revolving credit facility
December 2026
NMGC (in USD) – Unsecured non-revolving facility
March 2024
Other (in USD) – Unsecured committed revolving credit facilities
Various
(1) This facility is available for use by Tampa Electric and PGS. At
December 31, 2022, $554 million USD was used by Tampa
Electric and $66 million USD was used by PGS.
(2) This facility is available for use by Tampa Electric and PGS. At
December 31, 2022, $300 million USD was used by Tampa
Electric and $100 million USD was used by PGS.
Emera and its subsidiaries have certain financial and other covenants associated with their debt and
credit facilities. Covenants are tested regularly, and the Company is in compliance with covenant
requirements as at December 31, 2022. Emera’s significant covenant
is listed below:
As at
Financial Covenant
Requirement
December 31, 2022
Emera
Syndicated credit
facilities
Debt to capital ratio
Less
than or equal to 0.70 to 1
0.57 : 1
Recent significant financing activity for Emera and its subsidiaries are discussed below by segment:
Florida Electric Utilities
On December 13, 2022, TEC amended its 364-day non-revolving credit facility to extend the maturity date
from December 16, 2022 to December 13, 2023 and reduced the facility amount from $500 million USD
to $400 million USD. There were no other significant changes in commercial terms from the prior
agreement.
On September 15, 2022, TEC repaid a $250 million USD note upon maturity. The note was repaid using
existing credit
facilities.
On July 12, 2022, TEC completed an issuance of $600 million
USD senior notes. The issuance included
$300 million USD senior notes that bear an interest rate of 3.875 per cent with a
maturity date of July 12,
2024, and $300 million USD senior notes that bear an interest rate of 5 per cent with a maturity date
of
July 15, 2052. Proceeds from the issuance were used to repay TEC’s $470 million USD commercial
paper, due in 2022, and for general corporate purposes.
36
Canadian Electric Utilities
On December 16, 2022, NSPI amended its revolving operating credit facility to extend the maturity date
from December 16, 2026 to December 16, 2027 and increase the amount of the facility from $600 million
to $800 million. There were no other significant changes in commercial terms from the prior
agreement.
On July 15, 2022, NSPI entered into a $400 million
non-revolving term credit facility which matures on
July 15, 2024. The credit facility contains customary representation and
warranties, events of default and
financial and other covenants, and bears interest at Bankers’ Acceptances or prime rate
advances, plus a
margin. Proceeds from this facility were used for general corporate
purposes.
Gas Utilities and Infrastructure
On September 23, 2022, NMGC amended its $80 million USD, unsecured, non-revolving term credit
facility to extend the maturity from September 23, 2022, to March 22, 2024. There were no other changes
in commercial terms from the prior
agreement.
On June 30, 2022, Brunswick Pipeline amended its
non-revolving credit agreement to extend the maturity
from June 30, 2025 to June 30, 2026. There were no other changes in
commercial terms from the prior
agreement.
Other Electric
Utilities
On March 25, 2022, ECI amended its amortizing floating rate
notes to extend the maturity from March 25,
2022 to March 25, 2027. There were no other changes in commercial terms from the
prior agreement.
Other
On December 16, 2022, Emera amended its $900 million revolving operating credit facility to extend the
maturity date from June 30, 2026 to June 30, 2027. There were no other significant changes in
commercial terms from the prior
agreement.
On December 16, 2022, Emera amended its $400 million
non-revolving term credit facility to extend the
maturity from December 16, 2022 to December 16, 2023. There were no other
significant changes in
commercial terms from the prior
agreement.
On August 2, 2022, Emera entered into a $400 million
non-revolving term facility which matures on
August 2, 2023. The credit agreement contains customary representation and
warranties, events of
default and financial and other covenants and bears interest at Bankers’ Acceptances or prime rate
advances, plus a margin. Proceeds from this facility were used for general corporate purposes.
37
Credit Ratings
Emera and its subsidiaries have been assigned the following senior unsecured debt ratings:
Fitch
S&P
(2)(3)
Moody's
DBRS
Emera Inc.
BBB (Negative)
BBB- (Negative)
Baa3 (Negative)
N/A
TECO Energy/TECO Finance
N/A
N/A
N/A
N/A
TEC
A (Negative)
BBB+ (Negative)
A3 (Negative)
N/A
NMGC
BBB+ (Negative)
N/A
N/A
N/A
NSPI
N/A
BBB- (Negative)
N/A
BBB (high)(stable)
(1) On November 21, 2022, Fitch Ratings ("Fitch") affirmed its BBB issuer rating for Emera Inc. Fitch
also affirmed the A- issuer and
A unsecured debt ratings for TEC and BBB+
for NMGC. Emera and subsidiaries’ outlook was changed to negative from stable.
(2) On November 21, 2022, S&P Global
Ratings (“S&P”) affirmed its BBB issuer rating for Emera Inc. and TECO Energy, while
affirming the BBB+ issuer credit ratings for TEC. S&P downgraded NSPI's issue-level and senior
unsecured debt ratings to BBB-.
Emera and subsidiaries’ outlook
remained at negative.
(3) On October 24, 2022, S&P affirmed its BBB issuer rating for Emera Inc. S&P also
affirmed ratings on NSPI, TECO Energy, and
TEC affirming the BBB+ issuer
credit ratings for NSPI and TEC. Emera and subsidiaries’ outlook was changed to negative from
stable.
(4) On November 2, 2022, Moody’s Investor Services (“Moody’s”)
affirmed its Baa3 issuer rating for Emera Inc. Moody’s also
affirmed ratings on TECO Finance and TEC, affirming the TECO Finance Baa1
issuer rating and A3 issuer rating for TEC. Emera
and
subsidiaries’ outlook was changed to negative from stable.
(5) On June 2, 2022, Moody’s affirmed its Baa1 issuer
rating for TECO Finance. Moody’s also affirmed TEC’s A3 issuer rating and
changed the outlook to stable from positive.
(6) On December 20, 2022, DBRS (“Dominion Bond Rating Service”) downgraded its issuer credit and senior unsecured
rating for
NSPI to BBB (high). NSPI’s outlook remained unchanged
at stable.
The downgrades from both S&P and DBRS of NSPI were
attributed to their view of the enactment of Bill
212, “Public Utilities Act (amended)”, as a political intervention
in the regulatory process that resulted in
an increase in political risk and a reduction in the stability and predictability of
NSPI’s regulatory
environment.
Guaranteed Debt
As of December 31, 2022, the Company had $2.75 billion USD senior unsecured notes ("U.S. Notes”)
outstanding.
The U.S. Notes are fully and unconditionally guaranteed, on a joint and several basis, by Emera and
Emera US Holdings Inc. (in such capacity, the “Guarantor Subsidiaries”). Emera owns, directly or
indirectly, all of the limited and general partnership interests in Emera US Finance
LP. Other subsidiaries
of the Company do not guarantee the U.S. Notes
(such subsidiaries are referred to as the "Non-
Guarantor Subsidiaries") however, Emera has unrestricted access to the assets of
consolidated entities.
In compliance with Rule 13-01 of Regulation S-X,
the Company is including summarized financial
information for Emera, Emera US Holdings Inc., and Emera US Finance LP (together,
the "Obligor
Group"), on a combined basis after transactions and balances between the combined entities have been
eliminated. Investments in and equity earnings of the Non-Guarantor Subsidiaries have been excluded
from the summarized financial
information.
The Obligor Group was not determined using geographic,
service line or other similar criteria and, as a
result the summarized financial information includes portions of Emera’s
domestic and international
operations. Accordingly, this basis of presentation is not intended to present Emera’s financial
condition
or results of operations for any purpose other than to comply with the specific requirements for guarantor
reporting.
38
Summarized Statement of Income
(loss)
The Company recognized income related to guaranteed debt under
the following categories:
For the
Year ended December 31
millions of dollars
2022
2021
Loss from operations
$
$
Net losses
(1)
$
$
(1) Includes $262 million in interest and dividend income, net, from non-guarantor subsidiaries.
Summarized Balance Sheet
The Company has the following categories on the balance sheet related to guaranteed debt:
As at
December 31
millions of dollars
2022
2021
Current
assets
$
$
Goodwill
Other assets
(2)
Total
assets
$
$
Current liabilities
(4)
$
$
Long-term liabilities
(5)
Total liabilities
$
$
(1) Includes $144 million (2021 – $140 million) in amounts due from non-guarantor subsidiaries.
(2) Includes $6,058 million (2021 – $5,749 million) in amounts due from non-guarantor subsidiaries.
(3) Excludes investments in non-guarantor subsidiaries. Consolidated Emera total assets are $39,742
million (2021 – $34,244
million).
(4) Includes $392 million (2021 – $346 million) due to non-guarantor subsidiaries.
(5) Includes $769 million (2021 – $776 million) due to non-guarantor subsidiaries.
Outstanding Stock Data
Common Stock
millions of
millions of
Issued and outstanding:
shares
dollars
Balance, December 31, 2021
261.07
$
7,242
Issuance of common stock under ATM program
(1)
4.07
248
Issued under the
DRIP, net of discounts
4.21
238
Senior management stock options
exercised and Employee Share Purchase Plan
0.60
34
Balance, December 31,
2022
269.95
$
7,762
(1) In Q4 2022, 278,545 common shares were issued under Emera's
ATM program at an average price of $54.06 per share for
gross proceeds
of $15 million ($15 million net of after-tax issuance costs). For the year ended December 31, 2022, 4,072,469
common shares were
issued under Emera's ATM program at an average price of $61.31 per share for gross proceeds of $250
million ($248 million net of after-tax issuance costs). As at December 31, 2022, an aggregate gross sales
limit of $207 million
remained available for issuance under the ATM
program.
As at February 16, 2023, the amount of issued and outstanding common shares was 271.4 million.
If all outstanding stock options were converted as at February 16, 2023, an additional 2.9 million common
shares would be issued and outstanding.
Preferred Stock
As at February 16, 2023, Emera had the following preferred shares issued and outstanding: Series A –
4.9 million; Series B – 1.1 million; Series C – 10.0 million; Series E – 5.0 million; Series F – 8.0
million;
Series H – 12.0 million; Series J – 8.0 million, and Series L – 9.0 million. Emera’s preferred
shares do not
have voting rights unless the Company fails to pay, in aggregate, eight quarterly dividends.
39
PENSION FUNDING
For funding purposes, Emera determines required contributions to its largest defined benefit pension
plans based on smoothed asset values. This reduces volatility in the cash funding requirement as the
impact of investment gains and losses are recognized over a three-year period. The cash required in
2023 for defined benefit pension plans is expected to be $44 million (2022 – $45 million). All pension plan
contributions are tax deductible and will be funded with cash from operations.
Emera’s defined benefit pension plans employ a long-term strategic approach with respect to asset
allocation, real return and risk. The underlying objective is to earn an appropriate return, given the
Company’s goal of preserving capital with an acceptable level of risk for the pension fund
investments.
To
achieve the overall long-term asset allocation, pension assets are managed by external investment
managers per the pension
plan’s investment policy and governance framework. The asset allocation
includes investments in the assets of Canadian and
global equities, domestic and global bonds and short-
term investments. Emera reviews investment manager performance on a regular
basis and adjusts the
plans’ asset mixes as needed in accordance with the pension plans’ investment policy.
Emera’s projected contributions to defined contribution pension plans are $44 million for 2023 (2022 –
$41
million).
Defined Benefit Pension Plan Summary
in millions of dollars
Plans
by region
TECO Energy
NSPI
Caribbean
Total
Assets as at
December 31, 2022
$
$
$
$
Accounting obligation at December 31, 2022
$
$
$
$
Accounting expense during fiscal 2022
$
$
$
$
Off-Balance Sheet Arrangements
Defeasance
Upon privatization in 1992, NSPI became responsible for managing a portfolio of defeasance securities
that provide principal and interest streams to match the related defeased debt, which at December 31,
2022 totalled $200 million (2021 – $200 million). The securities are held in trust for an affiliate of the
Province of Nova Scotia. Approximately 66 per cent of the defeasance portfolio consists of investments in
the related debt, eliminating all risk associated with this portion of the portfolio; the remaining defeasance
portfolio has a market value higher than the related debt, reducing the future risk of this portion of the
portfolio.
Guarantees and Letters of Credit
Emera has guarantees and letters of credit on behalf of third parties outstanding. The following significant
guarantees and letters of credit are not included within the Consolidated Balance Sheets as at December
31, 2022:
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 million
USD if SeaCoast fails to pay or perform under the contract. The guarantee expires five years after the
gas transportation precedent agreement termination date, which was terminated on January 1, 2022. 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 million USD.
40
TECO
Energy issued a guarantee in connection with SeaCoast’s performance obligations under a firm
service agreement, which
expires on December 31, 2055, subject to two extension terms at the option of
the counterparty with a final expiration date of
December 31, 2071. The guarantee is for a maximum
potential amount of $13 million USD if SeaCoast fails to pay or perform under
the firm service agreement.
In the event that TECO Energy’s long-term senior unsecured credit ratings are downgraded below
investment grade by Moody’s or S&P, TECO Energy would need to
provide either a substitute guarantee
from an affiliate with an investment grade credit rating or a letter of credit or cash
deposit of $13 million
USD.
Emera Inc. has issued a guarantee of up to $35 million USD relating to outstanding notes of GBPC. The
guarantee for the notes will expire in May 2023.
Emera Inc. has issued a guarantee of $66 million USD relating to outstanding notes of ECI. This
guarantee will automatically terminate on the date upon which the obligations have been repaid in full.
NSPI has issued guarantees on behalf of its subsidiary, NS Power Energy Marketing Incorporated
(“NSPEMI”), in the amount of $119 million USD (2021 –
$118 million USD) with terms of varying lengths.
The Company has standby
letters of credit and surety bonds in the amount of $145 million USD
(December 31, 2021 – $148 million USD) to third
parties that have extended credit to Emera and its
subsidiaries. These letters of credit and surety bonds typically have a
one-year term and are renewed
annually as required.
Emera Inc., on behalf of NSPI, has a standby letter of credit to secure obligations under a supplementary
retirement plan. The expiry date of this letter of credit was extended to June 2023. The amount committed
as at December 31, 2022 was $63 million (December 31, 2021 – $64 million).
DIVIDEND PAYOUT RATIO
Emera has provided annual dividend growth guidance of four to five per cent through 2025. The
Company targets a long-term dividend payout ratio of adjusted net income of 70 to 75 per cent, and while
the payout ratio is likely to exceed that target through and beyond the forecast period, it is expected to
return to that range over time. Emera’s common share dividends paid in 2022 were $2.6775 ($0.6625 in
Q1, Q2, and Q3 and $0.6900 in Q4) per common share and $2.5750 ($0.6375 in Q1, Q2, and Q3 and
$0.6625 in Q4) per common share for 2021, representing a dividend payout ratio of 75 per cent in 2022
(2021 – 129 per cent) and a dividend payout ratio of adjusted net income of 83 per cent in 2022 (2021 –
91 per
cent).
On September 22, 2022, the Emera Board of Directors approved an
increase in the annual common
share dividend rate to $2.76 from $2.65. The first quarterly dividend payment at the increased rate
was
paid on November 15,
2022.
TRANSACTIONS WITH
RELATED PARTIES
In the ordinary course of business, Emera provides
energy and other services and enters into
transactions with its subsidiaries, associates and other related companies on terms
similar to those
offered to non-related parties. Intercompany balances and intercompany transactions have been
eliminated on consolidation, except for the net profit on certain transactions between non-regulated and
regulated entities in accordance with accounting standards for rate-regulated entities. All material
amounts are under normal interest and credit terms.
41
Significant transactions between Emera and its associated companies are as follows:
●
Consolidated Statements of Income. NSPI’s expense is reported in Regulated fuel for generation and
purchased power, totalling $157 million for the year ended December 31, 2022 (2021 – $149 million).
NSPML is accounted for as an equity investment and therefore, the corresponding earnings related to
this revenue are reflected in Income from equity investments. For further details, refer to the
“Business Overview and Outlook - Canadian Electric Utilities – ENL” and “Contractual Obligations”
sections.
●
Natural
gas transportation capacity purchases from M&NP are reported in the Consolidated
Statements of Income. Purchases from
M&NP reported net in Operating revenues, Non-regulated,
totalled $9 million for the year ended December 31, 2022
(2021
– $19 million).
There were no significant receivables or payables between Emera and its associated companies reported
on Emera’s Consolidated Balance Sheets as at December 31, 2022 and at December 31, 2021.
ENTERPRISE RISK AND RISK
MANAGEMENT
Emera has an enterprise-wide risk management process, overseen by its Enterprise Risk Management
Committee (“ERMC”) and monitored by the Board of Directors, to ensure an effective, consistent and
coherent approach to risk management. Certain risk management activities for Emera are overseen by
the ERMC to ensure such risks are appropriately identified, assessed, monitored and subject to
appropriate
controls.
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. The RSC’s mandate includes oversight of the Company’s Enterprise Risk
Management
framework, including the identification, assessment, monitoring and management of enterprise risks. It
also includes oversight of the Company’s approach to sustainability and its performance relative to its
sustainability objectives.
The Company’s financial risk management activities are focused on those areas that most significantly
impact profitability, quality and consistency of income, and cash flow.
Emera’s risk management focus
extends to key operational risks
including safety and environment, which represent core values of Emera.
In this section, Emera describes the principal risks that
management believes could materially affect its
business, revenues, operating income, net income, net assets, liquidity or
capital resources. The nature
of risk is such that no list is comprehensive, and other risks may arise or risks not currently
considered
material may become material in the future.
Regulatory and Political Risk
The Company’s rate-regulated subsidiaries and certain investments subject to significant influence are
subject to risk of the recovery of costs and investments. Regulatory and political risk can include changes
in regulatory frameworks, shifts in government policy, legislative changes, and regulatory decisions.
As cost-of-service utilities with an obligation to serve customers, Emera’s utilities operate under formal
regulatory frameworks, and must obtain regulatory approval to change or add rates and/or riders. Emera
also holds investments in entities in which it has significant influence, and which are subject to regulatory
and political risk including NSPML, LIL, and M&NP. As a regulated
Group II pipeline, the tolls of
Brunswick Pipeline are regulated by the CER on a complaint basis, as opposed to the regulatory
approval
process described above. In the absence of a complaint, the CER does not normally undertake a detailed
examination of Brunswick Pipeline’s tolls, which are subject to a firm service agreement, expiring in 2034,
with Repsol Energy North America Canada Partnership. The agreement provides for a predetermined toll
increase in the fifth and fifteenth year of the contract.
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Regulators administer legislation covering material aspects of the utilities’ businesses, including customer
rates and/or riders, the underlying allowed ROEs, deemed capital structures, capital investment, the
terms and conditions for the provision of service, performance standards, and affiliate transactions. Costs
and investments can be recovered upon approval by the respective regulator as an adjustment to rates
and/or riders, which normally require a public hearing process or may be mandated by other
governmental bodies. During public hearing processes, consultants and
customer representatives
scrutinize the costs, actions and plans of these rate-regulated companies, and their respective
regulators
determine whether to allow recovery and to adjust rates based upon the evidence and any contrary
evidence from other parties. In some circumstances, other government bodies may influence the setting
of rates. Regulatory decisions, legislative changes, and prolonged delays in the recovery of costs or
regulatory assets could result in decreased rate affordability for customers and could materially affect
Emera and its
utilities.
Emera’s utilities generally manage this risk through
transparent regulatory disclosure, ongoing
stakeholder and government consultation, and multi-party engagement on aspects such as
utility
operations, regulatory audits, rate filings and capital plans. The subsidiaries employ a collaborative
regulatory approach through technical conferences and, where appropriate, negotiated
settlements.
Changes in government and shifts in government policy and
legislation can impact the commercial and
regulatory frameworks under which Emera and its subsidiaries operate. This includes
initiatives regarding
deregulation or restructuring of the energy industry. Deregulation or restructuring of the energy industry
may result in increased competition and unrecovered costs that could adversely affect operations, net
income and cash flows. State and local policies in some United States jurisdictions have sought to
prevent or limit the ability of utilities to provide customers the choice to use natural gas while in other
jurisdictions policies have been adopted to prevent limitations on the use of natural gas. Changes in
applicable state or local laws and regulations, including electrification legislation, could adversely impact
PGS and NMGC.
Emera cannot predict future legislative, policy, or regulatory changes, whether caused by economic,
political or other factors, or its ability to respond in an effective and timely manner or the resulting
compliance costs. Government interference in the regulatory process can undermine regulatory stability,
predictability, and independence, and could have a material adverse effect on the Company.
Global Climate Change Risk
The Company is subject to risks that may arise from the impacts of climate change. There is increasing
public concern about climate change and growing support for reducing carbon dioxide emissions.
Municipal, state, provincial and federal governments have been setting policies and enacting laws and
regulations to deal with climate change impacts in a variety of ways, including decarbonization initiatives
and promotion of cleaner energy and renewable energy generation of electricity. Refer to “Changes in
Environmental Legislation” risk below. Insurance companies have begun to limit their exposure to
coal-
fired electricity generation and are evaluating the medium and long-term impacts of climate change which
may result in fewer insurers, more restrictive coverage and increased premiums. Refer to the “Markets”
section below and “Uninsured Risk”.
Climate change may lead to increased frequency and intensity of weather events and related impacts
such as storms, ice storms, hurricanes, cyclones, heavy rainfall, extreme winds, wildfires, flooding and
storm surge. The potential impacts of climate change, such as rising sea levels and larger storm surges
from more intense hurricanes, can combine to produce even greater damage to coastal generation and
other facilities. Climate change is also characterized by rising global temperatures. Increased air
temperatures may bring increased frequency and severity of wildfires within the Company’s service
territories. Refer to “Weather Risk” and “System Operating and Maintenance Risks”.
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The
Company has made significant investments to facilitate the use of renewable and lower-carbon
energy including wind generation,
the Maritime Link in Atlantic Canada, and in Florida, solar generation
and modernization of the Big Bend Power Station. Tampa
Electric has taken significant steps to reduce
overall emissions at its facilities as a result of its capital investment plan
which has and will continue to
reduce carbon dioxide
emissions.
In 2022, NSPI achieved reductions of carbon dioxide emissions of
approximately 45 per cent from 2005 levels. NSPI expects to exceed the Canadian target of 40-45 per
cent reduction by 2030, as set out in the Canadian Net-Zero Emissions Accountability Act. Both the
Government of Nova Scotia and the Government of Canada have enacted or introduced legislation that
includes goals of net-zero GHG emissions by 2050. The Province of Nova Scotia has established targets
with respect to the percentage of renewable energy in NSPI’s generation mix, reductions in GHG
emissions, as well as the goal to phase out coal-fired electricity generation by 2030. Failure to meet such
goals by 2030 could result in material fines, penalties, other sanctions and adverse reputational impacts.
NSPI continues to work with both the provincial and federal governments on measures to seek to address
their carbon reduction goals. Future compliance with provincial and federal GHG emission caps, coal
phase out requirements and targets, and renewable standards has been challenged as a result of the
constraints imposed by the enactment of Bill 212, “Public Utilities Act (amended)”. Within Emera’s natural
gas utilities, there are ongoing efforts to reduce methane and carbon dioxide emissions through
replacement of aging infrastructure, more efficient operations, operational and supply chain optimization,
and support of public policy initiatives that address the effects of climate change.
The Company’s long-term capital investment plan includes significant investment across the portfolio in
renewable and cleaner generation, infrastructure modernization, storm hardening, energy storage and
customer-focused technologies. All these initiatives contribute toward mitigating the potential impacts of
climate change. The Company continues to engage with government, regulators, industry partners and
stakeholders to share information and participate in the development of climate change related policies
and
initiatives.
Physical Impacts
The Company is subject to physical risks that arise, or may arise, from global climate change, including
damage to operating assets from more frequent and intense weather events and from wildfires due to
warming air temperatures and increasing drought conditions. Substantially all of the Company’s fossil
fueled generation assets are located at or near coastal sites and, as such, are exposed to the separate
and combined effects of rising sea levels and increasing storm intensity, including storm surges and
flooding. Refer to “Weather Risk” for further information.
These risks are mitigated to an extent through features such as flood walls at certain plants and through
the location of plants on higher ground. Planned investments in under-grounding parts of the electricity
infrastructure contribute to risk mitigation, as does insurance coverage (for assets other than electricity
transmission and distribution assets). In addition, implementation of regulatory mechanisms for recovery
of costs, such as storm reserves and regulatory deferral accounts, help smooth out the recovery of storm
restoration costs over
time.
Reputation
Failure to address issues related to climate change could affect Emera’s reputation with stakeholders, its
ability to operate and grow, and the Company’s access to, and cost of, capital. Refer to “Liquidity and
Capital Market Risk”. The Company seeks to mitigate this in part by moving away from higher-carbon
generation in favour of lower-carbon generation and non-emitting renewable generation.
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Markets
Changing carbon-related costs, policy and regulatory changes and shifts in supply and demand factors
could lead to more expensive or more scarce products and services that are required by the Company in
its operations. This could lead to supply shortages, delivery delays and the need to source alternate
products and services. The Company seeks to mitigate these risks through close monitoring of such
developments and adaptive changes to supply chain procurement strategies.
Given concerns regarding carbon-emitting generation, those assets and businesses may, over time,
become difficult (or uneconomic) to insure in commercial insurance markets. In the short term, this may
be mitigated through increased investment in engineered protection or alternative risk financing (such as
funded self-insurance or regulatory structures, including storm reserves). Longer-term mitigation may be
achieved through infrastructure siting decisions and further engineered protections. This risk may also be
mitigated through the continued transition away from high-carbon generation sources to sources with low
or zero carbon dioxide emissions.
Policy
Government and regulatory initiatives, including greenhouse gas emissions standards, air emissions
standards and generation mix standards, are being proposed and adopted in many jurisdictions in
response to concerns regarding the effects of climate change. In some jurisdictions, government policy
has included timelines for mandated shutdowns of coal generating facilities, percentage of electricity
generation from renewables, carbon pricing, emissions limits and cap and trade mechanisms. Over the
medium and longer terms, this could potentially lead to a significant portion of hydrocarbon infrastructure
assets being subject to additional regulation and limitations in respect of GHG emissions and
operations.
The Company is subject to climate-related and environmental
legislative and regulatory requirements.
Such legislative and regulatory initiatives could adversely affect Emera’s
operations and financial
performance. Refer to “Regulatory and Political Risk” and “Changes in Environmental
Legislation” risk.
The Company seeks to mitigate these risks through active engagement with governments and regulators
to pursue transition strategies that meet the needs of customers, stakeholders and the Company. This
has included NSPI’s participation in negotiated equivalency agreements in Nova Scotia to provide for an
affordable transition to lower-carbon generation. Equivalency agreements allow NSPI to achieve
compliance with federal GHG emissions regulations by meeting provincial legislative and regulatory
requirements as they are deemed to be equivalent. There is no guarantee that such equivalency
agreements will be renewed or remain in force in the future.
Regulatory
Depending on the regulatory response to government legislation and regulations, the Company may be
exposed to the risk of reduced recovery through rates in respect of the affected assets. Valuation
impairments could result from such regulatory outcomes. Mitigation efforts in respect of these risks
include active engagement with policy makers and regulators to find mechanisms to avoid such impacts
while being responsive to customers’ and stakeholders’ objectives.
Legal
The Company could face litigation or regulatory action related to environmental harms from carbon
dioxide emissions or climate change public disclosure issues. The Company addresses these risks
through compliance with all relevant laws, emissions reduction strategies, and public disclosure of climate
change risks.
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Water Resources
For thermal plants requiring cooling water, reduced availability of water resulting from climate change
could adversely impact operations or the costs of operations. The Company seeks ways to reduce and
recycle water as it does in its Polk power plant in Florida, where recovered and treated wastewater is
used in operations to reduce reliance on fresh water supplies in an area where water is not as abundant
as in other markets.
The Company operates hydroelectric generation in certain of its markets. Such generation depends on
availability of water and the hydrological profile of water sources. Changes in precipitation patterns, water
temperatures and air temperatures could adversely affect the availability of water and consequently the
amount of electricity that may be produced from such facilities. The Company is reinvesting in the
efficiency of certain hydroelectric generation facilities to increase generation capacity and continues to
monitor changing hydrology patterns. Such issues may also affect the availability of third-party owned
hydroelectricity purchased power sources.
Weather Risk
The Company is subject to risks that arise or may arise from weather including seasonal variations
impacting energy sales, more frequent and intense weather events, changing air temperatures, wildfires
and extreme weather conditions associated with climate change. Refer to “Global Climate Change Risk”.
Fluctuations in the amount of electricity or natural gas used by customers can vary significantly in
response to seasonal changes in weather and could impact the operations, results of operations, financial
condition, and cash flows of the Company’s utilities. For example, Tampa Electric could see lower
demand in summer months if temperatures are cooler than expected. Further, extreme weather
conditions such as hurricanes and other severe weather conditions which may be associated with climate
change could cause these seasonal fluctuations to be more pronounced. In the absence of a regulatory
recovery mechanism for unanticipated costs, such events could influence the Company’s results of
operations, financial conditions or cash flows.
Extreme weather events create a risk of physical damage to the Company’s assets. High winds can
impact structures and cause widespread damage to transmission and distribution infrastructure, solar
generation, and wind powered generation. Increased frequency and severity of weather events increases
the likelihood that the duration of power outages and fuel supply disruptions could increase. Increased
frequency and intensity of flooding and storm surge could adversely affect the operations of utilities and in
particular generation assets. The impact of extreme weather events would be amplified if the same
events affect multiple utilities.
Each of Emera’s regulated electric utilities have programs for storm hardening of transmission and
distribution facilities to minimize damage, but there can be no assurance that these measures will fully
mitigate the risk. This risk to transmission and distribution facilities is typically not insured, and as such
the restoration cost is generally recovered through regulatory processes, either in advance through
reserves or designated self-insurance funds, or after the fact through the establishment of regulatory
assets. Recovery is not assured and is subject to prudency review. The risk to generation assets is, in
part, mitigated through the design, siting, construction and maintenance of such facilities, regular risk
assessments, engineered mitigation, emergency storm response plans, and
insurance.
The risk of wildfires is addressed primarily through asset
management programs for natural gas
transmission and distribution operations, and vegetation management programs for electric
transmission
and distribution facilities. If it is found to be responsible for such a fire, the Company could suffer costs,
losses and damages, all or some of which may not be recoverable through insurance, legal, regulatory
cost recovery or other processes. If not recovered through these means, they could materially affect
Emera’s business and financial results including its reputation with customers, regulators, governments
and financial markets. Resulting costs could include fire suppression costs, regeneration, timber value,
increased insurance costs and costs arising from damages and losses incurred by third
parties.
46
Changes in Environmental
Legislation
Emera is subject to regulation by federal, provincial,
state, regional and local authorities regarding
environmental matters, primarily related to its utility operations. This includes
laws setting GHG emissions
standards and air emissions standards. Emera is also subject to laws regarding waste management,
wastewater discharges and aquatic and terrestrial habitats.
Changes to GHG emissions standards and air emissions standards could adversely affect Emera’s
operations and financial performance. Legislative or regulatory changes could influence decisions
regarding early retirement of generation facilities and may result in stranded costs if the Company is not
able to fully recover the costs and investment in the affected generation assets. Recovery is not assured
and is subject to prudency review. Legislative or regulatory changes may curtail sales of natural gas to
new customers, which could reduce future customer growth in Emera’s natural gas businesses. Stricter
environmental laws and enforcement of such laws in the future could increase Emera’s exposure to
additional liabilities and costs. These changes could also affect earnings and strategy by changing the
nature and timing of capital investments.
In addition to imposing continuing compliance obligations, there are permit requirements, laws and
regulations authorizing the imposition of penalties for non-compliance, including fines, injunctive relief,
and other sanctions. The cost of complying with current and future environmental requirements is, and
may be, material to Emera. Failure to comply with environmental requirements or to recover
environmental costs in a timely manner through rates, could have a material adverse effect on Emera. In
addition, Emera’s business could be materially affected by changes in government policy, utility
regulation, and environmental and other legislation that could occur in response to environmental and
climate change
concerns.
Emera manages its environmental risk by operating in a manner
that is respectful and protective of the
environment and in compliance with applicable legal requirements and Company policy.
Emera has
implemented this policy through the development and application of environmental management systems
in its operating subsidiaries. Comprehensive audit programs are in place to regularly test
compliance.
Cybersecurity Risk
Emera is exposed to potential risks related to cyberattacks and unauthorized access. The Company
increasingly relies on IT systems network, and cloud infrastructure to manage its business and safely
operate its assets, including controls for interconnected systems of generation, distribution and
transmission as well as financial, billing and other business systems. Emera also relies on third-party
service providers to conduct business. As the Company operates critical infrastructure, it may be at
greater risk of cyberattacks by third parties, which could include nation-state-controlled parties. This risk
may be further elevated by geo-political risks such as the ongoing conflict between Russia and Ukraine.
Cyberattacks can reach the Company’s assets and information via their interfaces with third parties or the
public internet and gain access to critical infrastructures. Cyberattacks can also occur via personnel with
direct access to critical assets or trusted networks. Methods used to attack critical assets could include
general purpose or energy-sector-specific malware delivered via network transfer, removable media,
viruses, attachments, or links in e-mails. The methods used by attackers are continuously evolving and
can be difficult to predict and detect.
Despite security measures in place, that are described below, the Company’s systems, assets and
information could experience security breaches that could cause system failures, disrupt operations, or
adversely affect safety. Such breaches could compromise customer, employee-related or other
information systems and could result in loss of service to customers, unavailability of critical assets, safety
issues, or the release, destruction, or misuse of critical, sensitive or confidential information. These
breaches could also delay delivery or result in contamination or degradation of hydrocarbon products the
Company transports, stores or distributes.
47
Cyberattacks or unauthorized accesses may cause costs, losses and damages all, or some of which, may
not be recoverable (through insurance, legal, regulatory cost recovery or other processes). This could
materially adversely affect Emera’s business and financial results including its reputation with customers,
regulators, governments and financial markets. Resulting costs could include, amongst others, response,
recovery and remediation costs, increased protection or insurance costs and costs arising from damages
and losses incurred by third parties. If any such security breaches occur, there is no assurance they can
be adequately addressed in a timely manner.
The Company seeks to manage these risks by aligning to a common set of cybersecurity standards and
policies derived, in part, on the National Institute of Standards and Technology’s Cyber Security
Framework, periodic security testing, program maturity objectives, cybersecurity incident readiness
program, and employee communication and training. With respect to certain of its assets, the Company is
required to comply with rules and standards relating to cybersecurity and IT including, but not limited to,
those mandated by bodies such as the North American Electric Reliability
Corporation, Northeast Power
Coordinating Council, and the United States
Department of Homeland Security. The status of key
elements of the Company’s cybersecurity program is reported to the RSC.
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 expenditures, 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.
Energy Consumption Risk
Emera’s rate-regulated utilities are affected by demand for energy based on changing customer patterns
due to fluctuations in a number of factors including general economic conditions, weather events,
customers’ focus on energy efficiency, changes in rates, and advancements in new technologies such as
rooftop solar, electric vehicles and battery storage. Government policies promoting distributed generation,
and new technology developments that enable those policies, have the potential to impact how electricity
enters the system and how it is bought and sold. In addition, increases in distributed generation may
impact demand resulting in lower load and revenues. These changes could negatively impact Emera’s
operations, rate base, net earnings, and cash flows. The Company’s rate-regulated utilities are focused
on understanding customer demand, energy efficiency, and government policy to ensure that the impact
of these activities benefit customers, that they do not negatively impact the reliability of the energy service
and that they are addressed through regulations.
Foreign Exchange
Risk
The Company is exposed to foreign currency exchange rate changes.
Emera operates internationally,
with an increasing amount of the Company’s net income earned outside of Canada. As such,
Emera is
exposed to movements in exchange rates between the CAD and, particularly, the USD, which could
positively or adversely affect results.
48
Consistent
with the Company’s risk management policies, Emera manages currency risks through
matching United States denominated debt
to finance its Unites States operations and may use foreign
currency derivative instruments to hedge specific transactions and
earnings exposure. The Company may
enter FX forward and swap contracts to limit exposure on certain foreign currency transactions
such as
fuel purchases, revenue streams and capital expenditures, and on net income earned outside of Canada.
The regulatory framework for the Company’s rate-regulated subsidiaries permits the recovery of prudently
incurred costs, including FX.
The Company does not utilize derivative financial instruments for foreign currency trading or speculative
purposes or to hedge the value of its investments in foreign subsidiaries. Exchange gains and losses on
net investments in foreign subsidiaries do not impact net income as they are reported in Accumulated
Other Comprehensive Income (Loss) ("AOCI”) (“AOCL”).
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 PP&E and the risk associated with changes in interest rates could have an adverse effect
on the cost of financing. The Company’s future access to capital and cost of borrowing may be impacted
by various market disruptions. The inability to access cost-effective capital could have a material impact
on Emera’s ability to fund its growth
plan.
Emera is subject to financial risk associated with changes in its
credit ratings. There are a number of
factors that rating agencies evaluate to determine credit ratings, including the
Company’s business, its
regulatory framework and legislative environment, political interference in the regulatory process,
the
ability to recover costs and earn returns, diversification, leverage, liquidity and increased exposure to
climate change-related impacts, including increased frequency and severity of hurricanes and other
severe weather events. A decrease in a credit rating could result in higher interest rates in future
financings, increased borrowing costs under certain existing credit facilities, limit access to the
commercial paper market, or limit the availability of adequate credit support for subsidiary operations. For
certain derivative instruments, if the credit ratings of the Company were reduced below investment grade,
the full value of the net liability of these positions could be required to be posted as collateral. 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.
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General Economic Risk
The Company has exposure to the macro-economic conditions in North America and in other geographic
regions in which Emera operates. Like most utilities, economic factors such as consumer income,
employment and housing affect demand for electricity and natural gas and, in turn, the Company’s
financial results. Adverse changes in general economic conditions and inflation may impact the ability of
customers to afford rate increases arising from increases to fuel, operating, capital, environmental
compliance, and other costs, and therefore could materially affect Emera and its utilities. This may also
result in higher credit and counterparty risk, adverse shifts in government policy and legislation, and/or
increased risk to full and timely recovery of costs and regulatory assets.
Interest Rate Risk
Emera utilizes a combination of fixed and floating rate debt financing for operations and capital
expenditures, resulting in an exposure to interest rate risk. Emera seeks to manage interest rate risk
through a portfolio approach that includes the use of fixed and floating rate debt with staggered
maturities. The Company will, from time to time, issue long-term debt or enter interest rate hedging
contracts to limit its exposure to fluctuations in floating interest rate debt.
For Emera’s regulated subsidiaries, the cost of debt is a component of rates and prudently incurred debt
costs are recovered from customers. Regulatory ROE will generally follow the direction of interest rates,
such that regulatory ROEs are likely to fall in times of reducing interest rates and rise in times of
increasing interest rates, albeit not directly and generally with a lag period reflecting the regulatory
process. Rising interest rates may also negatively affect the economic viability of project development
and acquisition initiatives.
As with most other utilities and other similar yield-returning investments, Emera’s share price may be
affected by changes in interest rates and could underperform the market in an environment of rising
interest rates.
Inflation
Risk
The Company may be exposed to changes in inflation that may result
in increased operating and
maintenance costs, capital investment, and fuel costs compared to the revenues provided by customer
rates. Emera’s utilities have budgeting and forecasting processes to identify inflationary risk factors and
measure operating performance, as well as collective bargaining agreements that mitigate the short-term
impact of inflation on labour costs.
Project Development and Land Use Rights Risk
The Company’s capital plan includes significant investment in generation, infrastructure modernization,
and customer-focused technologies. Any projects planned or currently in construction, particularly
significant capital projects, may be subject to risks including, but not limited to, impact on costs from
schedule delays, risk of cost overruns, ensuring compliance with operating and environmental
requirements and other events within or beyond the Company’s control. The Company’s projects may
also require approvals and permits at the federal, provincial, state, regional and local levels. There is no
assurance that Emera will be able to obtain the necessary project approvals or applicable permits or
receive regulatory approval to recover the costs in rates.
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Some of
the Company’s assets are located on land owned by third parties, including Indigenous Peoples,
and may be subject to land
claims. Present or future assets may be located on lands that have been used
for traditional purposes and therefore subject to
specific consultations, consents, or conditions for
development or operation. If the Company’s rights to locate and operate
its assets on any such lands are
subject to expiry or become invalid, it may incur material costs to renew rights or obtain such
rights. If
reasonable terms for land-use rights cannot be negotiated, the Company may incur significant costs to
remove and relocate its assets and restore the land. Additional costs incurred could cause projects to be
uneconomical to proceed with.
Emera manages these project development and land use rights risks by deploying robust project and risk
management approaches, led by teams with extensive experience in large projects. The Company
consults with Indigenous Peoples in obtaining approvals, constructing, maintaining and operating such
facilities, consistent with laws and public policy frameworks. Emera maintains relationships through
on-
going communications with stakeholders, including Indigenous Peoples, landowners and governments.
Counterparty Risk
Emera is exposed to risk related to its reliance on certain key partners, suppliers, and customers, any of
which may endure financial challenges resulting from commodity price and market volatility, economic
instability or adversity, adverse political or regulatory changes and other causes which may cause or
contribute to such parties’ insolvency, bankruptcy, restructuring
or default on their contractual obligations
to Emera. Emera is also
exposed to potential losses related to amounts receivable from customers,
energy marketing collateral deposits and derivative
assets due to a counterparty’s non-performance
under an agreement.
Emera manages this counterparty risk through due diligence and third-party risk assessment processes
prior to signing contracts, contractual rights and remedies, regulatory frameworks, and by monitoring
significant developments with its customers, partners and suppliers. The Company also manages credit
risk with policies and procedures for counterparty analysis, exposure measurement, and exposure
monitoring and mitigation. Credit assessments may be conducted on new customers and counterparties,
and deposits or collateral may be requested on certain accounts. There is no assurance that
management strategies will be effective, and significant counterparty
defaults could have a material effect
on the Company.
Country Risk
The majority of Emera’s earnings are from outside of Canada, mostly concentrated in the United States.
Emera’s investments are currently in regions where political and economic risks are considered by the
Company to be acceptable. For more information, refer to the “Regulatory and Political Risk” and
“General Economic Risk” sections above. Emera’s operations in some countries may be subject to
changes in economic growth, restrictions on the repatriation of income or capital exchange controls,
inflation, the effect of global health, safety and environmental matters, including climate change, or
economic conditions and market conditions, and change in financial policy and availability of credit. The
Company mitigates this risk through a rigorous approval process for investment, and by forecasting cash
requirements on a continuous basis to determine whether sufficient funds are available in all
affiliates.
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.
51
The
Company manages this risk through established processes and practices to identify, monitor, report
and mitigate these risks.
These include the Company’s commercial arrangements, such as the
combination of supply and purchase agreements, asset
management agreements, pipeline transportation
agreements, and financial hedging instruments. In addition, its credit policies,
counterparty credit
assessments, market and credit position reporting, and other risk management and reporting practices,
are also used to manage and mitigate this risk.
Regulated Utilities
The Company’s utility fuel supply is exposed to broader global conditions, which may include impacts on
delivery reliability and price, despite contracted terms. Supply and demand dynamics in fuel markets can
be affected by a wide range of factors which are difficult to predict and may change rapidly, including but
not limited to, currency fluctuations, changes in global economic conditions, natural disasters,
transportation or production disruptions, and geo-political risks, such as political instability, conflicts,
changes to international trade agreements, trade sanctions or embargos. The Company seeks to manage
this risk using financial hedging instruments and physical contracts and through contractual protection
with counterparties, where
applicable.
The majority of Emera’s regulated electric and gas
utilities have adopted and implemented fuel
adjustment mechanisms and purchased gas adjustment mechanisms respectively, which
further helps
manage commodity price risk, as the regulatory framework for the Company’s rate-regulated subsidiaries
permits the recovery of prudently incurred fuel and gas costs. There is no assurance that such
mechanisms and regulatory frameworks will continue to exist in the future. Prolonged and substantial
increases in fuel prices could result in decreased rate affordability, increased risk of recovery of costs or
regulatory assets, and/or negative impacts on customer consumption patterns and sales.
Emera Energy Marketing and Trading
Emera Energy has employed further measures to manage commodity risk. The majority of Emera
Energy’s portfolio of electricity and gas marketing and trading contracts and, in particular, its natural gas
asset management arrangements, are contracted on a back-to-back basis, avoiding any material long or
short commodity positions. However, the portfolio is subject to commodity price risk, particularly with
respect to basis point differentials between relevant markets in the event of an operational issue or
counterparty default. Changes in commodity prices can also result in increased collateral requirements
associated with physical contracts and financial hedges, resulting in higher liquidity requirements and
increased costs to the business.
To measure commodity price risk exposure, Emera Energy employs a number
of controls and processes,
including an estimated VaR analysis of its exposures. The
VaR amount represents an estimate of the
potential change in fair value
that could occur from changes in Emera Energy’s portfolio or changes in
market factors within a given confidence level, if
an instrument or portfolio is held for a specified time
period. The VaR calculation is used to quantify exposure to market risk
associated with physical
commodities, primarily natural gas and power positions.
52
Future Employee Benefit Plan Performance and Funding Risk
Emera subsidiaries have both defined benefit and defined contribution employee pension plans that cover
their employees and retirees. All defined benefit plans are closed to new entrants, except for the TECO
Energy Group Retirement Plan. The cost of providing these benefit plans varies depending on plan
provisions, interest rates, inflation, investment performance and actuarial assumptions concerning the
future. Actuarial assumptions include earnings on plan assets, discount rates (interest rates used to
determine funding levels, contributions to the plans and the pension and post-retirement liabilities) and
expectations around future salary growth, inflation and mortality. Three of the largest drivers of cost are
investment performance, interest rates and inflation, which are affected by global financial and capital
markets. Depending on future interest rates and future inflation and actual versus expected investment
performance, Emera could be required to make larger contributions in the future to fund these plans,
which could adversely affect Emera’s cash flows, financial condition and operations.
Each of Emera’s employee defined benefit pension plans are managed according to an approved
investment policy and governance framework. Emera employs a long-term approach with respect to asset
allocation and each investment policy outlines the level of risk which the Company is prepared to accept
with respect to the investment of the pension funds in achieving both the Company’s fiduciary and
financial objectives. Studies are routinely undertaken approximately every five years with the objective
that the plans’ asset allocations are appropriate for meeting Emera’s long-term pension objectives.
Labour Risk
Emera’s ability to deliver service to its customers and to execute its growth plan depends on attracting,
developing and retaining a skilled workforce. Utilities are faced with demographic challenges related to
trades, technical staff and engineers with an increasing number of employees expected to retire over the
next several years. Failure to attract, develop and retain an appropriately qualified workforce could
adversely affect the Company’s operations and financial results. Emera seeks to manage this risk through
maintaining competitive compensation programs, a dedicated talent acquisition team, human resources
programs and practices, including ethics and diversity training, employee engagement surveys,
succession planning for key positions and apprenticeship programs.
Approximately 32 per cent of Emera’s labour force is represented by unions and subject to collective
labour agreements. The inability to maintain or negotiate future agreements on acceptable terms could
result in higher labour costs and work disruptions, which could adversely affect service to customers and
have an adverse effect on the Company’s earnings, cash flow and financial position. Emera seeks to
manage this risk through ongoing discussions and working to maintain positive relationships with local
unions. The Company maintains contingency plans in each of its operations to manage and reduce the
effect of any potential labour disruption.
IT Risk
Emera relies on various IT systems to manage operations. This subjects Emera to inherent costs and
risks associated with maintaining, upgrading, replacing and changing these systems. This includes
impairment of its IT, potential disruption of internal control systems, substantial capital expenditures,
demands on management time and other risks of delays, difficulties in upgrading existing systems,
transitioning to new systems or integrating new systems into its current systems. Emera’s digital
transformation strategy, including investment in infrastructure modernization and customer focused
technologies, is driving increased investment in IT solutions, resulting in increased project risks
associated with the implementation of these solutions.
53
Emera
manages these risks through IT asset lifecycle planning and management, governance, internal
auditing and testing of systems, and
executive oversight. Employees with extensive subject matter
expertise assist in risk identification and mitigation, project
management, implementation, change
management and training. System resiliency, formal disaster recovery and backup processes,
combined
with critical incident response practices, table-top exercises, and simulations, help mitigate operational
disruptions.
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.
System Operating and Maintenance Risks
The safe and reliable operation of electric generation and electric and natural gas transmission and
distribution systems is critical to Emera’s operations. There are a variety of hazards and operational risks
inherent in operating electric utilities and natural gas transmission and distribution pipelines. Electric
generation, transmission and distribution operations can be impacted by risks such as mechanical
failures, supply chain issues impacting timely access to critical equipment, activities of third parties,
terrorism, cyberattacks, damage to facilities, solar panels and infrastructure caused by hurricanes,
storms, falling trees, lightning strikes, floods, fires and other natural disasters. Natural gas pipeline
operations can also be impacted by risks such as leaks, explosions, mechanical failures, activities of third
parties, terrorism, cyberattacks, and damage to the pipeline facilities and equipment caused by
hurricanes, storms, floods, fires and other natural disasters. Refer to “Global Climate Change Risk” and
“Weather Risk”. Electric utility and natural gas transmission and distribution pipeline operation interruption
could negatively affect revenue, earnings, and cash flows as well as customer and public confidence, and
public safety.
Emera manages these risks by investing in a highly skilled workforce, operating prudently, preventative
maintenance, safety and operations management systems, third-party risk program, and making effective
capital investments. Insurance, warranties, or recovery through regulatory mechanisms may not cover
any or all these losses, which could adversely affect the Company’s results of operations and cash
flows.
Fuel Supply Disruptions
Emera’s electric and natural gas utilities are also exposed to the risk of fuel supply chain disruptions, both
within and outside their service territories, which may be caused by severe weather or natural disasters.
This may also be caused by damage to, operational issues with, terrorist or cyberattacks on, third party
fuel production, storage, pipeline, and distribution facilities. The risk of fuel supply disruptions is managed
through contractual protections, maintaining a diversity of fuel suppliers and transportation contracts, and
contracting for access to third-party storage facilities. Significant unanticipated fuel supply disruptions,
such as those which arose from Winter Storm Uri in February 2021, could result in increased exposure to
commodity price risk for Emera’s regulated electric and gas utilities and Emera Energy, and these could
have adverse effects on service to utility customers and on the Company’s reputation, earnings, cash flow
and financial position.
54
Uninsured Risk
Emera and its subsidiaries maintain insurance to cover accidental loss suffered to its facilities and to
provide indemnity in the event of liability to third parties. This is consistent with Emera’s risk management
policies. Certain facilities, in particular coal and other thermal generation, may, over time, become more
difficult (or uneconomic) to insure as a result of the impact of global climate change. Refer to “Global
Climate Change Risk – Markets”. There are certain elements of Emera’s operations which are not
insured. These include a significant portion of its electric utilities’ transmission and distribution assets, as
is customary in the industry. The cost of this coverage is not economically viable. In addition, Emera
accepts deductibles and self-insured retentions under its various insurance policies. Insurance is subject
to coverage limits as well as time sensitive claims discovery and reporting provisions and there can be no
assurance that the types of liabilities or losses that may be incurred by the Company and its subsidiaries
will be covered by insurance.
The occurrence of significant uninsured claims, claims in excess of the insurance coverage limits
maintained by Emera and its subsidiaries, or claims that fall within a significant self-insured retention
could have a material adverse effect on Emera’s results of operations, cash flows and financial position, if
regulatory recovery is not available.
The Company mitigates its uninsured risk by ensuring insurance limits align with risk exposures, and for
uninsured assets and operations, that appropriate risk assessments and mitigation measures are in
place. The regulatory framework for the Company’s rate-regulated subsidiaries permits the recovery of
prudently incurred costs, including uninsured
losses.
RISK MANAGEMENT INCLUDING FINANCIAL
INSTRUMENTS
Emera’s risk management policies and procedures provide a framework through which management
monitors various risk exposures. The risk management policies and practices are overseen by the Board
of Directors. The Company has established a number of processes and practices to identify, monitor,
report on and mitigate material risks to the Company. This includes establishment of the ERMC, whose
responsibilities include preparing an updated risk dashboard and heat map presented at regular meetings
of the Board’s Risk and Sustainability Committee. Furthermore, a corporate team independent from
operations is responsible for tracking and reporting on market and credit risks.
The Company manages its exposure to normal operating and market risks relating to commodity prices,
FX, interest rates and share prices through contractual protections with counterparties where practicable,
and by using financial instruments consisting mainly of FX forwards and swaps, interest rate options and
swaps, equity derivatives, and coal, oil and gas futures, options, forwards and swaps. In addition, the
Company has contracts for the physical purchase and sale of natural gas. These physical and financial
contracts are classified as 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.
55
Derivatives qualify for hedge accounting if they meet stringent documentation requirements and can be
proven to effectively hedge the identified risk both at the inception and over the term of the instrument.
Specifically, for cash flow hedges, the change in the fair value of derivatives is deferred to AOCI and
recognized in income in the same period the related hedged item is realized. Where the documentation or
effectiveness requirements are not met, the derivatives are recognized at fair value with any changes in
fair value recognized in net income in the reporting period, unless deferred as a result of regulatory
accounting.
Derivatives entered into by NSPI, NMGC and GBPC that are documented as economic hedges or for
which the NPNS exception has not been taken, are subject to regulatory accounting treatment. The
change in fair value of the derivatives is deferred to a regulatory asset or liability. The gain or loss is
recognized in the hedged item when the hedged item is settled. Management believes any gains or
losses resulting from settlement of these derivatives related to fuel for generation and purchased power
will be refunded to or collected from customers in future rates. Tampa Electric has no derivatives related
to hedging as a result of a FPSC approved five-year moratorium on hedging of natural gas purchases
which ended 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.
Derivative Assets and Liabilities Recognized on the Balance Sheet
As at
December 31
December 31
millions of dollars
2022
2021
Regulatory Deferral:
Derivative instrument assets
(1)
$
$
Derivative instrument liabilities
(2)
Regulatory assets
(1)
Regulatory
liabilities
Net asset (liability)
$
$
HFT
Derivatives:
Derivative instrument
assets
$
$
Derivatives instruments liabilities
(2)
Net liability
$
$
Other Derivatives:
Derivative instrument assets
(1)
$
$
Derivatives instruments
liabilities
Net asset (liability)
$
$
(1) Current and other assets.
(2) Current and long-term liabilities.
56
Realized and Unrealized Gains (Losses) Recognized in Net Income
For the
Year ended December 31
millions of dollars
2022
2021
Regulatory
Deferral:
Regulated fuel for generation and purchased power
(1)
$
$
HFT Derivatives:
Non-regulated operating revenues
$
$
Other Derivatives:
OM&G
$
$
Other income, net
Net gains (losses)
$
$
Total net gains (losses)
$
$
(1) Realized gains (losses) on derivative instruments settled and
consumed in the period, hedging relationships that have been
terminated
or the hedged transaction is no longer probable. Realized gains (losses) recorded in inventory will be recognized in
“Regulated fuel for generation and purchased power” when the hedged item is consumed.
As of December 31, 2022, the unrealized gain in AOCI was $16 million, net of tax (2021 – $18 million, net
of tax). For the year ended December 31, 2022, unrealized gains of $2 million (2021 – $1 million), have
been reclassified into interest
expense.
DISCLOSURE AND INTERNAL
CONTROLS
Management is responsible for establishing and maintaining adequate disclosure controls and
procedures (“DC&P”) and internal control over financial reporting (“ICFR”), as defined in National
Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings (“NI 52-109”). The
Company’s internal control framework is based on the criteria published in the Internal Control -
Integrated Framework (2013), a report issued by the Committee of Sponsoring Organizations (“COSO”) of
the Treadway Commission. Management, including the Chief Executive Officer and Chief Financial
Officer, evaluated the design and effectiveness of the Company’s DC&P and ICFR as at December 31,
2022 to provide reasonable assurance regarding the reliability of financial reporting in accordance with
USGAAP.
Management recognizes the inherent limitations in internal control systems, no matter how well designed.
Control systems determined to be appropriately designed can only provide reasonable assurance with
respect to the reliability of financial reporting and may not prevent or detect all misstatements.
There were no changes in the Company’s ICFR, during the year ended December 31, 2022, that have
materially affected, or are reasonably likely to materially affect, the Company’s internal control over
financial reporting.
CRITICAL ACCOUNTING ESTIMATES
The preparation of consolidated financial statements in accordance with USGAAP requires management
to make estimates and assumptions. These may affect the reported amounts of assets and liabilities at
the date of the financial statements and reported amounts of revenues and expenses during the reporting
periods. Significant areas requiring use of management estimates relate to rate-regulated assets and
liabilities, accumulated reserve for cost of removal, pension and post-retirement benefits, unbilled
revenue, useful lives for depreciable assets, goodwill and long-lived assets impairment assessments,
income taxes, asset retirement obligations (“ARO”), and valuation of financial instruments. Management
evaluates the Company’s estimates on an ongoing basis based upon historical experience, current and
expected conditions and assumptions believed to be reasonable at the time the assumption is made, with
any adjustments recognized in income in the year they arise.
57
Rate
Regulation
The rate-regulated accounting policies of Emera’s rate-regulated subsidiaries and regulated equity
investments are subject to examination and approval by their respective regulators and may differ from
the accounting policies of non-rate-regulated companies. Differences occur when regulators render their
decisions on rate applications or other matters, and generally involve a difference in the timing of revenue
and expense recognition. The accounting for these items is based on expectations of the future actions of
the regulators. Assumptions and judgments used by regulatory authorities continue to have an impact on
the recovery of costs, the rate earned on invested capital, and the timing and amount of assets to be
recovered. The application of regulatory accounting guidance is a critical accounting policy as a change in
these assumptions may result in a material impact on reported assets, liabilities and the results of
operations.
As at December 31, 2022, the Company has recorded $3,620 million (2021 – $2,566 million) of regulatory
assets and $2,273 million (2021 – $2,055 million) of regulatory liabilities.
Accumulated Reserve – Cost of Removal
Tampa Electric, PGS, NMGC and NSPI recognize non-ARO costs of removal
(“COR”) as regulatory
liabilities. The non-ARO COR represent estimated funds received from customers through
depreciation
rates to cover future COR of PP&E upon retirement that are not legally required. The companies accrue
for COR over the life of the related assets based on depreciation studies approved by their respective
regulators. The costs are estimated based on historical experience and future expectations, including
expected timing and estimated future cash outlays. As at December 31, 2022, the balance of the
Accumulated reserve – COR within regulatory liabilities was $895 million (2021 – $819 million).
Pension and Other Post-Retirement Employee Benefits
The Company provides post-retirement benefits to employees, including defined benefit pension plans.
The cost of providing these benefits is dependent upon many factors that result from actual plan
experience and assumptions of future expectations.
The accounting related to employee post-retirement benefits is a critical accounting estimate. Changes in
the estimated benefit obligation, affected by employee demographics, including age, compensation
levels, employment periods, contribution levels and earnings, could have a material impact on reported
assets, liabilities, accumulated other comprehensive income and results of operations. Changes in key
actuarial assumptions, including anticipated rates of return on plan assets and discount rates used in
determining the accrued benefit obligation and benefit costs, could change annual funding requirements.
This could have a significant impact on the Company’s annual earnings and cash requirements.
The pension plan assets are comprised primarily of equity and fixed income investments. Fluctuations in
actual equity market returns and changes in interest rates may result in changes to pension costs in
future periods.
The Company’s accounting policy is to amortize the net actuarial gain or loss that exceeds 10 per cent of
the greater of the projected benefit obligation / accumulated post-retirement benefit obligation (“PBO”)
and the market-related value of assets, over active plan members’ average remaining service period. For
the largest plans this is currently 8.3 years (8.7 years for 2022 benefit cost) for the Canadian plans and a
weighted average of 11.4 years for the United States plans). The Company’s use of smoothed asset
values reduces volatility related to the amortization of actuarial investment experience. As a result, the
main cause of volatility in reported pension cost is the discount rate used to determine the
PBO.
58
The discount rate used to determine benefit costs is based on the yield of high quality long-term corporate
bonds in each operating entity’s country and is determined with reference to bonds which have the same
duration as the PBO as at January 1 of the fiscal year. The following table shows the discount rate for
benefit cost purposes and the expected return on plan assets for each plan:
2022
2021
Discount
rate for
benefit cost
purposes
Expected
return
on
plan assets
Discount rate for
benefit cost purposes
Expected
return on
plan assets
TECO Energy Group Retirement
Plan
2.78%
6.50%
2.38%
6.70%
TECO Energy Group Supplemental
Executive Retirement Plan
(1)
2.35/5.33%
N/A
1.84%
N/A
TECO Energy Group Benefit
Restoration Plan (1)
2.27/4.19/5.48%
N/A
1.71%
N/A
TECO Energy Post-retirement
Health and Welfare Plan
2.84%
N/A
2.47%
N/A
New Mexico Gas Company Retiree
Medical Plan
2.85%
1.50%
2.49%
4.00%
NSPI
3.25%, 3.48%
5.75%
2.59%, 2.85%
5.25%
GBPC Salaried
5.75%
6.00%
4.25%
6.00%
GBPC Union
5.75%
5.35%
5.65%
5.65%
(1) The discount
rate and expected return on assets for benefit cost purposes is updated throughout the year as special events
occur, such as
settlements and curtailments.
Based on management’s estimate, the reported benefit cost for defined benefit and defined
contribution
plans was $64 million in 2022 (2021 – $85 million). The reported benefit cost is impacted by numerous
assumptions, including the discount rate and asset return assumptions. A 0.25 per cent change in the
discount rate and asset return assumptions would have had +/- impact on the 2022 benefit cost of $0.5
million and $1 million respectively (2021 – $1 million and $3
million).
Unbilled Revenue
Electric and gas revenues are billed on a systematic basis over a one or two-month period for NSPI and a
one-month period for other Emera utilities. At the end of each month, the Company must make an
estimate of energy delivered to customers since the date their meter was last read and determine related
revenues earned but not yet billed. The unbilled revenue is estimated based on several factors, including
current month’s generation, estimated customer usage by class, weather, line losses, inter-period
changes to customer classes and applicable customer rates. Based on the extent of estimates included in
the determination of unbilled revenue, actual results may differ from the estimate. At December 31, 2022,
unbilled revenues totalled $424 million (2021 – $318 million) on total regulated operating revenues of
$7,154 million (2021 – $5,926 million).
Property, Plant and
Equipment
PP&E represents 58 per cent of total assets on the Company’s balance sheet and include the generation,
transmission and distribution, and other assets of the Company.
Depreciation is determined by the straight-line method, based on the estimated remaining service lives of
the depreciable assets in each category. The service lives of regulated PP&E are determined based on
depreciation studies and require appropriate regulatory approval. Due to the magnitude of the Company’s
PP&E, changes in estimated depreciation rates can have a material impact on depreciation expense and
accumulated depreciation.
Depreciation expense was $927 million for the year ended December 31, 2022 (2021 – $877 million).
59
Goodwill Impairment
Assessments
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. Application of the goodwill impairment test requires
management judgment on significant assumptions and estimates. When assessing goodwill for
impairment, the Company has the option of first performing a qualitative assessment to determine
whether a quantitative assessment is necessary. In performing a qualitative assessment management
considers, among other factors, macroeconomic conditions, industry and market considerations and
overall financial performance.
If the Company performs 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. Significant assumptions used in estimating the fair
value include discount and growth rates, rate case assumptions including future cost of capital, valuation
of the reporting units' net operating loss (“NOL”) and projected operating and capital cash flows. Adverse
changes in these assumptions could result in a future material impairment of the goodwill assigned to
Emera’s reporting units.
As of December 31, 2022, $6,009 million of Emera’s goodwill represents the excess of the acquisition
purchase price for TECO Energy (Tampa Electric, PGS and NMGC reporting units) over the fair values
assigned to identifiable assets acquired and liabilities assumed. In Q4 2022, qualitative assessments
were performed for Tampa Electric and PGS given the significant excess of fair value over carrying
amounts calculated during the last quantitative test in Q4 2019. Management concluded it was more likely
than not that the fair value of these reporting units exceeded their respective carrying amounts, including
goodwill. As such, no quantitative testing was required. For the NMGC reporting unit, Emera elected to
bypass a qualitative assessment and performed a quantitative impairment assessment using a
combination of the income and market approach. This assessment estimated that the fair value of the
NMGC reporting unit exceeded its carrying amount, including goodwill. As a result of this assessment, no
impairment charges were recognized.
In Q4 2022, the Company elected to bypass a qualitative assessment and performed a quantitative
impairment assessment for GBPC, using the income approach, as this reporting unit is sensitive to
changes in assumptions due to limited excess of fair value over the carrying value, including goodwill.
Although the cash flows of GBPC have not changed significantly compared to previous periods, it was
determined that the carrying value, including goodwill, exceeded the fair value, due to an increase in
discount rates. The discount rate for the reporting unit was negatively impacted by changes in the
macro-
economic environment, including the risk-free rate assumption. As a result of this assessment, a goodwill
impairment charge of $73 million was recorded in 2022, reducing the GBPC goodwill balance to nil as at
December 31, 2022. No impairment was recorded in 2021. For further detail, refer to note 22.
As of December 31, 2022, the Company had goodwill with a total carrying amount of $6,012 million
(December 31, 2021 – $5,696 million). The change in the carrying value of goodwill from 2021 to 2022
was a result of the effect of the FX translation of Emera’s foreign affiliates, partially offset by the GBPC
impairment.
60
Long-Lived Assets Impairment Assessments
In accordance with accounting guidance for long-lived assets, the Company assesses whether there has
been an impairment of long-lived assets and intangibles when a triggering event occurs, such as a
significant market disruption or the sale of a business. The assessment involves comparing 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 believes accounting estimates related to asset impairments are critical estimates, as they
are highly susceptible to change and the impact of an impairment on reported assets and earnings could
be material. Management is required to make assumptions based on expectations regarding the results
of operations for significant/indefinite future periods and the current and expected market conditions in
such periods. Markets can experience significant uncertainties. Estimates based on the Company’s
assumptions relating to future results of operations or other recoverable amounts are based on a
combination of historical experience, fundamental economic analysis, observable market activity and
independent market studies. The Company’s expectations regarding uses and holding periods of assets
are based on internal long-term budgets and projections, which consider external factors and market
forces, as of the end of each reporting period. Assumptions made by management are consistent with
generally accepted industry approaches and assumptions used for valuation and pricing activities.
As at December 31, 2022, there were no indications of impairment of Emera’s long-lived assets. No
impairment charges were recognized in either 2022 or 2021.
Income
Taxes
Income taxes are determined based on the expected tax treatment of transactions recorded in the
consolidated financial statements. In determining income taxes, tax legislation is interpreted in a variety of
jurisdictions, the likelihood that deferred tax assets will be realized is assessed and assumptions about
the expected timing of the reversal of deferred tax assets and liabilities are made. Uncertainty associated
with application of tax statutes and regulations and the outcomes of tax audits and appeals, requires that
judgments and estimates be made in the accrual process and in the calculation of effective tax rates.
Only income tax benefits that meet the “more likely than not” threshold may be recognized or continue to
be recognized. Unrecognized tax benefits are evaluated quarterly and changes are recorded based on
new information, including issuance of relevant guidance by the courts or tax authorities and
developments in examinations of the Company’s tax returns.
The Company believes the accounting estimates related to income taxes are critical estimates. The
realization of deferred tax assets is dependent upon the generation of sufficient taxable income, both
operating and capital, in future periods. A change in the estimated valuation allowance could have a
material impact on reported assets and results of operations. Administrative actions of the tax authorities,
changes in tax law or regulation, and the uncertainty associated with the application of tax statutes and
regulations, could change the Company’s estimate of income taxes, including the potential for elimination
or reduction of the Company’s ability to realize tax benefits and to utilize deferred tax assets.
Asset Retirement Obligations
Measurement of the fair value of AROs requires the Company to make reasonable estimates concerning
the method and timing of settlement associated with the legally obligated costs. There are uncertainties in
estimating future asset-retirement costs due to potential events, such as changing legislation or
regulations, and advances in remediation technologies. Emera has AROs associated with the remediation
of generation, transmission, distribution and pipeline
assets.
61
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. Accretion expense is included
as part of “Depreciation and amortization expense”. Any accretion expense not yet approved by the
regulator is recorded in “PP&E” and included in the next depreciation study.
Accordingly, changes to the
ARO or cost recognition attributable to
changes in the factors discussed above, should not impact the
results of operations of the Company.
Some of the Company’s transmission and distribution assets may have conditional AROs 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 when an amount can be determined.
As at December 31, 2022, AROs recorded on the balance sheet were $174 million (2021 – $174 million).
The Company estimates the undiscounted amount of cash flow required to settle the obligations is
approximately $429 million (2021 – $422 million), which will be incurred between 2023 and 2061. The
majority of these costs will be incurred between 2028 and 2050.
Financial Instruments
The Company is required to determine the fair value of all derivatives except those which qualify for the
normal purchase, normal sale exception. Fair value is the price that would be received for the sale of an
asset or paid to transfer a liability in an orderly arms-length transaction between market participants at the
measurement date. Fair value measurements are required to reflect assumptions that market participants
would use in pricing an asset or liability based on the best available information, including the risks
inherent in a particular valuation technique, such as a pricing model, and the risks inherent in the inputs to
the model.
Level Determinations and Classifications
The Company uses Level 1, 2, and 3 classifications in the fair value hierarchy. The fair value
measurement of a financial instrument is included in only one of the three levels and is based on the
lowest level input significant to the derivation of the fair value. Fair values are determined, directly or
indirectly, using inputs that are observable for the asset or
liability. Only in limited circumstances does the
Company enter into
commodity transactions involving non-standard features where market observable
data is not available or have contract terms that
extend beyond five years.
62
CHANGES IN ACCOUNTING POLICIES AND
PRACTICES
The new USGAAP accounting policy that is applicable to, and adopted by the Company in 2022, is
described as
follows:
Facilitation of the Effects of Reference Rate
Reform on Financial Reporting
The Company adopted Accounting Standard Update (“ASU”) 2022-06,
Reference Rate Reform (Topic
848): Deferral of the Sunset Date of Topic
848
preparers can utilize the reference rate reform relief guidance issued under ASU 2020-04, which was
adopted by the Company in Q4 2020. The guidance in ASU 2022-06 was effective as of the date of
issuance and entities may elect to apply the guidance prospectively through to December 31, 2024. The
Company has applied the guidance permitted by ASU 2020-04 to certain debt agreements that were
amended during the current period. The Company’s transition from reference rates will not have a
material impact on the consolidated financial statements.
Future Accounting
Pronouncements
The Company considers the applicability and impact of all ASUs issued by the Financial Accounting
Standards Board (“FASB”). ASUs issued by FASB, but which are not yet effective, were assessed and
determined to be either not applicable to the Company or to have an insignificant impact on the
consolidated financial
statements.
SUMMARY OF QUARTERLY RESULTS
For the quarter ended
millions of
dollars
Q4
Q3
Q2
Q1
Q4
Q3
Q2
Q1
(except per share amounts)
2022
2022
2022
2022
2021
2021
2021
2021
Operating revenues
$
$
$
$
$
$
$
$
Net income (loss) attributable to
common
shareholders
$
$
$
$
$
$
$
$
Adjusted net income
$
$
$
$
$
$
$
$
EPS – basic
$
1.80
$
$
$
$
$
$
$
EPS – diluted
$
1.80
$
$
$
$
$
$
$
Adjusted EPS – basic
$
0.93
$
$
$
$
$
$
$
Quarterly operating revenues and adjusted net income are affected by seasonality. The first quarter
provides strong earnings contributions due to a significant portion of the Company’s operations being in
northeastern North America, where winter is the peak electricity usage season. The third quarter provides
strong earnings contributions due to summer being the heaviest electric consumption season in Florida.
Seasonal and other weather patterns, as well as the number and severity of storms, can affect demand
for energy and the cost of service. Quarterly results could also be affected by items outlined in the
“Significant Items Affecting Earnings” section.