Exhibit 99.2
1
Management’s Discussion & Analysis
As at February 26, 2024
Management’s Discussion & Analysis (“MD&A”) provides a review of the results of operations of Emera
Incorporated and its consolidated subsidiaries and investments (collectively referred to as “Emera” or the
“Company”) during the fourth quarter of, and for the full year of, 2023 relative to the same periods in 2022
and selected financial information for 2021; and its financial position as at December 31, 2023 relative to
December 31, 2022. The Company’s activities are carried out through five reportable segments: Florida
Electric Utility, Canadian Electric Utilities, Gas Utilities and Infrastructure, Other Electric Utilities, and
Other.
This MD&A should be read in conjunction with the Emera annual audited consolidated financial
statements and supporting notes as at and for the year ended December 31,
2023. Emera follows United
States Generally Accepted Accounting
Principles (“USGAAP” or “GAAP”). Additional information related
to Emera, including the Company’s
Annual Information Form can be found on Sedar+ at
www.sedarplus.ca.
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, 2023, Emera’s rate-regulated subsidiaries and investments
include:
Emera Rate-Regulated Subsidiary or Equity
Investment
Accounting Policies Approved/Examined By
Subsidiary
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, Inc. (“PGS”)
(1)
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
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
(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
dollars (“USD”) unless otherwise stated.
Exhibit 99.2
2
TABLE OF CONTENTS
Forward-looking Information……………………......
2
Introduction and Strategic
Overview………….……
3
Non-GAAP Financial Measures and Ratios….…...
5
Consolidated Financial
Review……….………….…
7
7
7
9
Business Overview and
Outlook…………….……..
11
12
13
17
18
19
Consolidated Balance Sheet
Highlights…………..
20
Other
Developments…………………………………
21
Financial Highlights……………………………..…..
21
21
22
25
27
28
Liquidity and Capital
Resources………..…………..
31
32
33
33
34
34
36
37
38
Pension Funding……………………………………..
38
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……….…………..
55
Critical Accounting
Estimates….……………………
56
Changes in Accounting Policies and
Practices…...
61
61
Summary of Quarterly Results……........................
62
FORWARD
-LOOKING INFORMATION
This MD&A contains “forward-looking information” (“FLI”) 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 FLI, although not all FLI contains these identifying
words. The FLI reflects management’s current beliefs and is based on information currently available to
Emera’s management and should not be read as guarantees of future events, performance or results,
and will not necessarily be accurate indications of whether, or the time at which, such events,
performance or results will be
achieved.
Exhibit 99.2
3
The
FLI is based on reasonable assumptions and is subject to risks, uncertainties and other factors that
could cause actual results to
differ materially from historical results or results anticipated by the FLI.
Factors that could cause results or events to differ
from current expectations include, without limitation:
regulatory and political risk; operating and maintenance risks; changes in
economic conditions;
commodity price and availability risk; liquidity and capital market risk; changes in credit ratings; 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 risk, including higher frequency
and severity of weather events; risk of wildfires; 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; supply chain risk; environmental
risks; foreign exchange (“FX”); regulatory and government decisions, including changes to environmental
legislation, financial reporting and tax legislation; risks associated with pension plan performance and
funding requirements; loss of service area; risk of failure of information technology (“IT”) infrastructure and
cybersecurity risks; uncertainties associated with infectious diseases, pandemics and similar public health
threats; market energy sales prices; labour relations; and availability of labour and management
resources.
Readers are cautioned not to place undue reliance on FLI, as actual results could differ materially from
the plans, expectations, estimates or intentions and statements expressed in the FLI. All FLI in this MD&A
is qualified in its entirety by the above cautionary statements and, except as required by law, Emera
undertakes no obligation to revise or update any FLI as a result of new information, future events or
otherwise.
INTRODUCTION AND
STRATEGIC OVERVIEW
Based in Halifax, Nova Scotia, Emera owns and operates
cost-of-service rate-regulated electric and gas
utilities in Canada, the United States (“US”) 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 investments 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 approximately $9 billion over the 2024 through 2026 period with
approximately $2 billion of additional potential capital investments over the same period. The capital
investment plan and additional potential capital result in an anticipated compound annual rate base
growth in the range of approximately 7 per cent to 8 per cent through 2026. The capital investment plan
includes significant investments across the portfolio in renewable and cleaner generation, reliability and
system integrity investments, infrastructure
modernization, infrastructure expansion to meet the needs of
new and
existing customers, and technologies to better support the business and customer experiences.
It is anticipated that approximately
75 per cent of Emera’s $9 billion capital investment plan over the 2024
through 2026 period will be made in
Florida.
Emera’s capital investment plan is being funded primarily
through internally generated cash flows, debt
raised at the operating company level consistent with regulated capital structures,
equity, and select asset
sales. Generally, 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.
Exhibit 99.2
4
Emera
has provided annual dividend growth guidance of four to five per cent through 2026. 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.
Seasonal patterns and other weather events affect
demand and operating costs. Similarly, mark-to-
market (“MTM”) 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 CAD. 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 experiencing significant change and Emera is well-positioned to continue
to respond to shifting customer demands and meet the challenges of digitization, decarbonization and
decentralized generation, within complex regulatory environments.
Customers depend on energy and are looking for more choice, better control, and greater reliability. The
costs of decentralized generation and storage have become more competitive and advancing
technologies are transforming how utilities operate and interact with customers. Concurrently, climate
change and the increased frequency of extreme weather events are shaping government energy policy.
This is also creating a need to replace aging infrastructure and make investments to protect and harden
energy systems to deliver energy reliability and system resiliency. These factors combined with inflation,
higher interest rates and higher cost of capital place increased pressure on energy costs, and thus
customer rates, at a time when affordability is a challenge.
Emera’s strategy is centered on delivering value for customers, and in doing so creating value for
shareholders. This includes:
•
energy storage needed to support intermittent renewables;
•
•
systems to service new customers; and
•
customer
experiences.
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 visible
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:
•
•
•
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.
Exhibit 99.2
5
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. The non-GAAP measures and
ratios are calculated by adjusting certain GAAP measures for specific items. Management believes
excluding these items better distinguishes ongoing operations of the business and allows investors to
better understand and evaluate the business. These measures and ratios are discussed and reconciled
below.
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 MTM adjustments, the GBPC impairment charge in 2022, and the
impact of the 2022 NSPML unrecoverable costs.
Management believes excluding from net income the effect of MTM valuations and changes thereto, until
settlement, better aligns the intent and financial effect of these contracts with the underlying cash flows,
and therefore excludes MTM adjustments for evaluation of performance and incentive compensation. The
MTM adjustments are related to the following:
●
price differential between the point where natural gas is sourced and where it is delivered, and
the related amortization of transportation capacity recognized as a result of certain Emera Energy
marketing and trading transactions;
●
equity income;
●
●
For further detail on these 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 (“FV”) of the reporting unit driven by the effects of
macro-
economic factors on the discount rate calculation. 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 the GBPC impairment charge, refer to
“Significant Items Impacting Earnings”, and “Financial Highlights – Other Electric Utilities”
sections.
In February 2022, the UARB issued a decision to disallow 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 2022 NSPML unrecoverable costs, refer
to the “Financial Highlights – Canadian Electric Utilities” section.
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.
Exhibit 99.2
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)
2023
2022
2023
2022
2021
Net income attributable to common
shareholders
$
$
$
$
$
MTM gain (loss), after-tax
(1)
GBPC impairment
charge
NSPML unrecoverable costs
(2)
Adjusted net income
$
$
$
$
$
EPS – basic
$
$
$
$
$
Adjusted EPS – basic
$
$
$
$
$
(1) Net of income tax expense of $44 million for the three months ended December 31, 2023 (2022 – $124 million
expense) and $68
million expense for the year ended December 31, 2023
(2022 – $73 million expense) (2021 – $86 million recovery).
(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.
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, the 2022 GBPC impairment charge and the 2022 NSPML
unrecoverable costs.
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
2023
2022
2023
2022
2021
Net income
(1)
$
$
$
$
$
Interest expense, net
Income tax expense (recovery)
Depreciation and amortization
EBITDA
$
$
$
$
$
MTM gain (loss), before-tax
GBPC impairment charge
NSPML unrecoverable costs
(2)
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.
Exhibit 99.2
7
CONSOLIDATED FINANCIAL REVIEW
Significant Items Affecting Earnings
2023
Earnings Impact of MTM Gain, After-Tax
MTM gain, after-tax decreased $193 million to $114 million in Q4 2023, compared to $307 million in Q4
2022 primarily due to unfavourable changes in existing positions, partially offset by higher amortization of
gas transportation assets in 2022 at Emera Energy Services (“EES”). For the year ended December 31,
2023, MTM gain, after-tax decreased $6 million to $169 million compared to $175 million for the same
period in 2022 primarily due to higher amortization of gas transportation assets at EES, partially offset by
favourable changes in existing positions at EES and gains on Corporate FX
hedges.
2022
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 FV of the reporting unit driven by the effects of macro-economic factors on
discount rate calculations. This non-cash charge was recorded in “GBPC 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
In Q4 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 payment was recognized in
‘Other income, net” on the Consolidated Statements of Income. For further details, refer to note 8 in the
consolidated financial statements.
Consolidated Financial Highlights
For the
Three months ended
Year ended
millions of
dollars
December 31
December 31
Adjusted net
income
2023
2022
2023
2022
2021
Florida Electric Utility
$
$
$
$
$
Canadian Electric Utilities
Gas Utilities and Infrastructure
Other Electric Utilities
Other
Adjusted net income
$
$
$
$
$
MTM gain (loss), after-tax
GBPC impairment charge
NSPML unrecoverable costs
Net income attributable to common shareholders
$
$
$
$
$
Exhibit
99.2
8
The following table highlights the significant changes in adjusted net income from 2022 to 2023:
For the
Three months ended
Year ended
millions of dollars
December 31
December 31
Adjusted net income – 2022
$
$
Operating Unit Performance
Increased earnings at NSPI due to new base rates and increased sales
volumes, partially offset by higher operating, maintenance and general
expenses ("OM&G"), interest expense and depreciation
Increased income from equity investments at NSPML
quarter-over-
quarter primarily due to the Maritime Link holdback (the "holdback")
recognized in Q4 2022. Year-over-year also due to the partial reversal in
Q3 2023 of the holdback recognized in 2022
Decreased earnings quarter-over-quarter at TEC due to increased
interest expense, depreciation, state and municipal taxes, unfavourable
weather, and higher OM&G, partially offset by new base rates and
customer growth driving higher sales volumes. Increased earnings
year-
over-year due to new base rates, the impact of a weaker CAD and
customer growth, partially offset by higher interest expense,
depreciation, state and municipal taxes, and OM&G, and unfavourable
weather
Decreased earnings quarter-over-quarter at NMGC primarily due to
lower asset optimization revenues and higher OM&G, partially offset by
new base rates. Increased earnings year-over-year due to new base
rates, partially offset by higher OM&G and interest expense
Decreased earnings at EES due to more favourable market conditions in
2022
Corporate
Decreased
OM&G, pre-tax, due to timing of long-term compensation
and related hedges
Increased interest expense, pre-tax, due to higher interest rates and
higher debt levels
Decreased income tax recovery quarter-over-quarter primarily due to the
impact of effective state tax rates
TGH award, after tax and legal costs, in Q4 2022. Refer to the
"Significant Items Affecting Earnings" section
Other Variances
Adjusted net income – 2023
$
$
For further details of reportable segments contributions, refer to the "Financial Highlights" section.
For the
Year ended December 31
millions of dollars
2023
2022
2021
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
2023
2022
2021
Total assets
$
$
$
Total long-term debt (including current portion)
$
$
$
Exhibit
99.2
9
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)
2023
2022
Variance
2023
2022
Variance
2021
Operating revenues
$
$
$
$
$
$
$
Operating expenses
Income from operations
$
$
$
$
$
$
$
Other income, net
$
$
$
$
$
$
$
Interest expense, net
$
$
$
$
$
$
$
Net income attributable to
common
shareholders
$
$
$
$
$
$
$
Adjusted net income
$
$
$
$
$
$
$
Weighted average shares of
common stock
outstanding
(in millions)
(1)
EPS – basic
$
$
$
(0.76)
$
$
$
0.01
$
EPS – diluted
$
$
$
(0.76)
$
$
$
0.02
$
Adjusted EPS – basic
$
$
$
(0.30)
$
$
$
(0.24)
$
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 2023, operating revenues decreased $386 million compared to Q4 2022 and, excluding
decreased MTM gains of $286 million, decreased $100 million. The decrease was due to lower fuel
revenues at NMGC, TEC, and NSPI; decreased marketing and trading margin at EES; lower asset
optimization revenue at NMGC; and unfavourable weather at TEC. These decreases were partially offset
by new base rates at TEC, NSPI and NMGC; storm cost recovery surcharge revenue at TEC; customer
growth at TEC and NSPI; and favourable weather at NSPI.
For the year ended December 31, 2023, operating revenues decreased $25 million compared to 2022
and, excluding decreased MTM gains of $62 million, increased $37 million. The increase was due to new
base rates at TEC, NSPI and NMGC; the impact of a weaker CAD; storm cost recovery surcharge
revenue at TEC; and customer growth at TEC and NSPI. These increases were partially offset by lower
fuel revenues at NMGC, TEC, NSPI, PGS and BLPC; lower off-system sales at PGS; a change in fuel
cost recovery methodology for an industrial customer at NSPI; and decreased marketing and trading
margin at EES.
Exhibit 99.2
10
Operating
Expenses
For Q4 2023, operating expenses decreased $171 million compared to Q4 2022 and excluding the 2022
GBPC impairment charge of $73 million, decreased $98 million. For the year ended December 31, 2023,
operating expenses decreased $190 million compared to 2022 and excluding the 2022 GBPC impairment
charge of $73 million, decreased $117 million. The decreases in both periods were due to lower fuel
expenses at TEC, NMGC, and PGS; partially offset by higher OM&G at TEC due to storm restoration
costs recognized related to the storm cost recovery surcharge revenue, and at NSPI due to higher power
generation and transmission and distribution field services cost. Year-over-year the decrease was also
due to a change in fuel cost recovery for an industrial customer at NSPI, partially offset by the impact of a
weaker CAD and the recognition of the Nova Scotia Renewable Electricity Regulations (“RER”) penalty at
NSPI.
Other Income,
net
For Q4 2023, other income, net decreased $51 million compared to Q4 2022, primarily due to the TGH
award in Q4 2022. For the year ended December 31, 2023, other income, net increased $13 million
compared to 2022, primarily due to increased FX gains in 2023; higher interest income primarily at TEC;
and higher pension non-current service cost recovery, partially offset by the TGH award in
2022.
Interest Expense, net
Interest expense, net for Q4 2023 increased $35 million, and for the year ended December 31, 2023
increased $216 million compared to the same periods in 2022. The increases in both periods were due to
higher interest rates; higher borrowings to support capital investments and ongoing operations; and the
impact of a weaker
CAD.
Net Income and Adjusted Net Income
Net income attributable to common shareholders for Q4 2023, compared to Q4 2022, was unfavourably
impacted by the $193 million decrease in MTM gains, after-tax, and favourably impacted by the $73
million GBPC impairment charge from 2022. Excluding these changes, adjusted net income decreased
$74 million. This was primarily due to the TGH award in Q4 2022; decreased earnings at EES, NMGC
and TEC; lower Corporate income tax recovery; and increased Corporate interest expense. These were
partially offset by increased earnings at NSPI and NSPML; and decreased Corporate OM&G due to the
timing of long-term compensation and related hedges.
Net income attributable to common shareholders for the year ended 2023, as compared to the same
period in 2022, was unfavourably impacted by the $6 million decrease in MTM gains, after-tax, and
favourably impacted by the $73 million GBPC impairment charge and the $7 million in NSPML
unrecoverable costs from 2022. Excluding these changes, adjusted net income decreased $41 million.
The decrease was primarily due to increased Corporate interest expense due to higher interest rates and
increased total debt; the TGH award in Q4 2022; and decreased earnings at EES. These were partially
offset by increased earnings at TEC, NMGC, NSPI and NSPML.
EPS and Adjusted EPS – Basic
EPS and Adjusted EPS – basic were lower for
Q4
2023 due to the increase in weighted average shares
of common stock outstanding and decreased earnings as discussed above.
EPS – basic was higher for the year ended December 31, 2023, due to the impact of higher earnings as
discussed above. Adjusted EPS – basic was lower for the year ended December 31, 2023 due to the
increase in weighted average shares of common stock outstanding and decreased adjusted earnings, as
discussed above.
Exhibit
99.2
11
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.
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 2023 and 2022 are as follows:
Three months
ended
Year ended
December 31
December 31
2023
2022
2023
2022
Weighted average
CAD/USD
$
1.36
$
1.37
$
1.35
$
1.34
Period end CAD/USD exchange rate
$
1.32
$
1.35
$
1.32
$
1.35
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
2023
2022
2023
2022
Florida Electric Utility
$
85
$
91
$
466
$
458
Gas Utilities and
Infrastructure
41
45
142
143
Other Electric Utilities
3
7
26
23
Other segment
(2)
(18)
30
(95)
(50)
Total
(3)
$
111
$
173
$
539
$
574
(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 $73 million USD in MTM gain, after-tax, for the three months ended December 31, 2023 (2022 – $222 million USD
MTM gain, after-tax) and MTM gain, after-tax of $116 million USD for
the year ended December 31, 2023 (2022 – $130 million USD
MTM gain, after-tax) and the GBPC impairment charge of nil for
the three months and year ended December 31, 2023 (2022 – $54
million USD).
The translation impact of the change in FX rates on foreign denominated earnings increased net income
by $13 million in Q4 2023 and $46 million for the year ended December 31, 2023, compared to the same
periods in 2022. The translation impact of the change in FX rates on foreign denominated earnings
decreased adjusted net income by $3 million in Q4 2023 and increased adjusted net income by $20
million for the year ended December 31, 2023 compared to the same periods in 2022. Impacts of the
changes in the translation of the CAD include the impacts of Corporate FX hedges used to mitigate
translation risk of USD earnings in the Other
segment.
BUSINESS OVERVIEW AND OUTLOOK
Emera’s 2023 results were impacted by macroeconomic conditions, specifically higher interest rates as
well as other impacts of inflation. These macroeconomic conditions are likely to continue for the near
term. For information on general economic risk, including interest rate and inflation risk, refer to the
“Enterprise Risk and Risk Management – General Economic Risk” section.
Exhibit 99.2
12
Florida Electric
Utility
Florida Electric Utility consists of TEC, a vertically integrated regulated electric utility engaged in the
generation, transmission and distribution of electricity, serving customers in West Central Florida. TEC
has $12 billion USD of assets and approximately 840,000 customers at December 31, 2023. TEC owns
6,433 megawatts (“MW”) of generating capacity, of which 74 per cent is natural gas fired, 19 per cent is
solar and 7 per cent is coal. TEC owns 2,192 kilometres of transmission facilities and 20,299 kilometres of
distribution facilities. TEC meets the planning criteria for reserve capacity established by the FPSC, which
is a 20 per cent reserve margin over firm peak
demand.
TEC’s approved regulated ROE range is 9.25 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 is used for the calculation of the return on
investments for clauses.
TEC anticipates earning towards the lower end of the ROE range in 2024 but expects earnings to be
higher than 2023. Normalizing 2023 for weather, TEC sales volumes in 2024 are projected to be higher
than 2023 due to customer growth. TEC expects customer growth rates in 2024 to be comparable to
2023, reflective of the expected economic growth in
Florida.
On February 1, 2024, TEC notified the FPSC of its intent to
seek a base rate increase effective January
2025, reflecting a revenue requirement increase of approximately $290 to $320 million
USD and
additional adjustments of approximately $100 million USD and $70 million USD for 2026 and 2027,
respectively. TEC’s proposed rates include recovery of solar generation projects, energy storage
capacity, a more resilient and modernized energy control center, and numerous other resiliency and
reliability projects. The filing range amounts are estimates until TEC files its detailed case in April 2024.
The FPSC is scheduled to hear the case in Q3 2024 with a decision expected by the end of 2024.
On August 16, 2023, TEC filed a petition to implement the 2024 Generation Base Rate Adjustment
provisions pursuant to the 2021 rate case settlement agreement. Inclusive of TEC’s ROE adjustment, the
increase of $22 million USD was approved by the FPSC on November 17, 2023.
On January 23, 2023, TEC petitioned the FPSC for recovery of the storm reserve regulatory asset and
the replenishment of the balance in the storm reserve to the approved storm reserve level of $56 million
USD, for a total of $131 million
USD.
The storm cost recovery surcharge was approved by the FPSC on
March 7, 2023, and TEC began applying the surcharge in April 2023. Subsequently, on November 9,
2023, the FPSC approved TEC’s petition, filed on August 16, 2023, to update the total storm cost
collection to $134 million USD. It also changed the collection of the expected remaining balance of $29
million USD as of December 31, 2023, from over the first three months of 2024 to over the 12 months of
2024. The storm recovery is subject to review of the underlying costs for prudency and accuracy by the
FPSC and issuance of an order by the FPSC is expected by Q3 2024.
In Q3 2023, TEC was impacted by Hurricane Idalia. The related storm restoration costs were
approximately $35 million USD, which were charged to the storm reserve regulatory asset, resulting in
minimal impact to earnings. TEC will determine the timing of the request for recovery of Hurricane Idalia
costs at a future time.
On January 23, 2023, TEC requested an adjustment to its fuel charges to recover the 2022 fuel
under-
recovery of $518 million USD over a period of 21 months. The request also included an adjustment to
2023 projected fuel costs to reflect the reduction in natural gas prices since September 2022 for a
projected reduction of $170 million USD for the balance of 2023. The changes were approved by the
FPSC on March 7, 2023, and were effective beginning on April 1,
2023.
In 2024, capital investment in the Florida Electric Utility
segment is expected to be $1.3 billion USD (2023
– $1.3 billion USD), including allowance for funds used during
construction (“AFUDC”). Capital projects
include solar
investments, grid modernization, storm hardening investments and building resilience.
Exhibit 99.2
13
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 $7.2 billion of assets and approximately 549,000 customers, NSPI owns 2,422 MW of generating
capacity, of which 44 per cent is coal and/or oil-fired; 28 per cent is natural gas and/or oil; 19 per cent is
hydro, wind, or solar; 7 per cent is petroleum coke (“petcoke”) and 2 per cent is biomass-fueled
generation. In addition, NSPI has contracts to purchase renewable energy from independent power
producers (“IPPs”) and community feed-in tariff (“COMFIT") participants, which own 532 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.
Nalcor is obligated to provide NSPI with approximately 900 Gigawatt hours (“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. 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.
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 expects earnings and sales volumes to be higher in 2024 than
2023 but anticipates earning below
its allowed ROE range in
2024.
On January 29, 2024, NSPI applied to the UARB for approval of a
structure that would begin to recover
the outstanding Fuel Adjustment Mechanism (“FAM”) balance. As part of the
application, NSPI requested
approval for the sale of $117 million of the
FAM regulatory asset to Invest Nova Scotia, a provincial
Crown
corporation, with the proceeds paid to NSPI upon approval. NSPI has requested approval to
collect from customers the amortization
and financing costs of $117 million on behalf of Invest Nova
Scotia over a 10-year period, and remit those amounts to Invest Nova
Scotia as collected, reducing short-
term customer rate increases relative to the currently established FAM process. If approved,
this portion
of the FAM regulatory asset would be removed from the Consolidated Balance Sheets and NSPI would
collect the balance on behalf of Invest Nova Scotia in NSPI rates beginning in 2024. A decision is
expected in the first half of 2024. It is anticipated that NSPI will apply to the UARB later in 2024 to collect
additional under-recovered fuel amounts in 2025 or future periods, subject to the approval of the UARB.
On October 31, 2023, NSPI submitted an application to the UARB to defer $24 million in incremental
operating costs incurred during Hurricane Fiona storm restoration efforts in September 2022. NSPI is
seeking amortization of the costs over a period to be approved by the UARB during a future rate setting
process. At December 31, 2023, the $24 million is deferred to “Other long-term assets”, pending UARB
approval. A decision is expected from the UARB in 2024.
Exhibit 99.2
14
On
September 16, 2023, Nova Scotia was struck by post-tropical storm Lee and as a result,
approximately 280,000 customers lost
power. The total cost of storm restoration was $19 million, with $9
million charged to “OM&G”, $5 million
capitalized to property, plant and equipment (“PP&E) and $5 million
deferred to the UARB approved storm rider. The
storm rider, for each of 2023, 2024, and 2025, allows
NSPI to apply to the UARB for deferral and recovery of expenses if major
storm restoration expenses
exceed approximately $10 million in any given year. The application for deferral of the storm rider is
made
in the year following the year of the incurred costs, with recovery beginning in the year after the
application.
On February 2, 2023, the UARB approved the General Rate Application settlement agreement between
NSPI, key customer representatives and participating interest groups. This resulted in average customer
rate increases of 6.9 per cent effective on February 2, 2023, and a further average increase of 6.5 per
cent on January 1, 2024, with any under or over-recovery of fuel costs addressed through the UARB’s
established FAM process. It also established a storm rider, described above, and a demand-side
management rider. On March 27, 2023, the UARB issued a final order approving the electricity rates
effective on February 2, 2023.
In 2024, capital investment, including AFUDC, is expected to be $435 million (2023 – $451 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 (the “Province”). NSPI continues to work with both levels of government to
comply with these laws and regulations to maximize efficiency of emission control measures and
minimize customer cost. NSPI anticipates that costs prudently incurred to achieve legislated compliance
will be recoverable under NSPI’s regulatory framework. NSPI faces risks associated with achieving
climate-related and environmental legislative requirements, including the risk of non-compliance, which
could adversely affect NSPI’s operations and financial performance. For further discussion on these risks
and environmental legislation and regulations, refer to the “Enterprise Risk and Risk Management”
section. Recent developments related to provincial and federal environmental laws and regulations are
outlined below.
Clean Electricity Solutions Task
Force:
The Clean Electricity Solutions Task Force (the
“Task Force”) was created by the Province in April 2023
to
advise the provincial government on Nova Scotia’s transition away from coal to more renewable
sources of energy. On
February 23, 2024, the Task Force released its report and recommendations,
based on engagement with stakeholders, including NSPI. The Task Force report focuses on findings
related to system operations, regulatory oversight, reliability, transmission and
affordability. The Task
Force announced a number of recommendations,
including a strengthening of the authority and
independence of the regulator and the establishment of an independent system
operator, in order to
support the continuing transition to clean energy and the achievement of federal and provincial clean
energy goals and legislation. The Province announced they intend to accept these recommendations and
will table enabling legislation in its upcoming session which starts February 27, 2024.
RER:
On April 6, 2023, the Province levied a $10 million penalty on NSPI for non-compliance with the RER
compliance period ending in 2022. The penalty was recorded in “OM&G” on the Consolidated Statements
of Income. On May 26, 2023, NSPI initiated an appeal of the penalty through a proceeding with the
UARB, as permitted under the RER. On October 12, 2023, the UARB decided that it will hear the appeal
by giving due deference to the Province’s decision but permitting the filing of new evidence to support the
parties’ positions. The hearing for the matter is scheduled for June 2024 and a decision is expected
before the end of 2024.
Exhibit 99.2
15
Carbon Pricing Regulations:
In November 2022, the Province enacted amendments to the Environment Act which provided the
framework for Nova Scotia to implement an output-based pricing system (“OBPS”) to comply with the
Government of Canada’s 2023 through 2030 carbon pollution pricing regulations effective January 1,
2023. The Government of Canada approved the Province’s proposed system, however the OBPS will be
subject to an interim review by the Government of Canada of the standards effective for 2026. The final
Output-Based Pricing System Reporting and Compliance Regulations were prescribed by Order in
Council dated January 30, 2024. The OBPS implements greenhouse gas (“GHG”) emissions
performance standards for large industrial GHG emitters that vary by fuel type. GHG emissions in excess
of the prescribed intensity standards will be subject to a carbon price that starts at $65 per tonne in 2023
and will 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 Cap-and-Trade Program Regulations:
NSPI was a participant in the Nova Scotia Cap-and-Trade Program and was subject to the 2019 through
2022 compliance period. On March 16, 2023, the Province provided NSPI with emissions allowances
sufficient to achieve compliance for the 2019 through 2022 compliance period. As such, compliance costs
accrued of $166 million were reversed in Q1 2023. The credits NSPI purchased from provincial auctions
in the amount of $6 million were not refunded and no further costs were incurred to achieve compliance
with the Nova Scotia Cap-and-Trade Program.
Other Legislation
Electricity Act Amendment:
On November 9, 2023, the Province enacted amendments in the Electricity Act which permit the
Governor in Council to approve energy storage projects proposed by a public utility and owned wholly or
in majority by the public utility if the project is in the best interest of ratepayers. Further, the amendments
to the Electricity Act expand the ability of the Province to require NSPI to enter into power purchase
agreements with renewable generation facilities by further empowering the Province to require NSPI to
enter into an agreement for the sale of the electricity to specified customers. This allows specified
customers to buy renewable electricity from specified producers, with NSPI managing the transmission
and sale of the energy. On December 21, 2023, the Governor in Council enacted regulations which
directed NSPI to install three 50 MW four-hour duration grid-scale batteries as part of the regulated
assets of NSPI.
Performance Standards Penalty Amendment:
On April 12, 2023, the Province enacted amendments to the Public Utilities Act which increased the
cumulative total of administrative penalties that could be levied by the UARB against NSPI for
non-
compliance with current and future performance standards in a calendar year from $1 million to $25
million. Any administrative penalties levied against NSPI must be credited to customers and NSPI cannot
recover administrative penalties imposed through rates.
Exhibit 99.2
16
ENL
Total equity earnings from NSPML and LIL are expected to be higher in
2024, compared to 2023 resulting
from an increased investment in LIL planned for 2024. 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’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.
On December 21, 2023, NSPML received approval to collect up to $164 million from NSPI for the
recovery of costs associated with the Maritime Link in 2024; subject to a holdback of $4 million per month,
as discussed
below.
On October 4, 2023 and January 31, 2024, the UARB issued
decisions providing clarification on
remaining aspects of the Maritime Link holdback mechanism primarily relating to release of
past and
future holdback amounts and requirements to end the holdback mechanism. In these decisions, the
UARB agreed with the Company’s submission that $12 million ($8 million related to 2022 and $4 million
relating to 2023) of the previously recorded holdback remain credited to NSPI’s FAM, with the remainder
released to NSPML and recorded in Emera’s “Income from equity investments. NSPML did not record
any additional holdback in Q4 2023. The UARB also confirmed that the holdback mechanism will cease
once 90 per cent of NS Block deliveries are achieved for 12 consecutive months (subject to potential
relief for planned outages or exceptional circumstances) and the net outstanding balance of previously
underdelivered NS Block energy is less than 10 per cent of the contracted annual amount. In addition, the
UARB increased the monthly holdback amount from $2 million to $4 million beginning December 1, 2023.
NSPML expects to file an application to terminate the holdback mechanism in
2024.
NSPML does not anticipate any significant capital investment in
2024.
LIL
ENL is a limited partner with Nalcor in LIL. Construction of the LIL is complete and the Newfoundland
Electrical System Operator confirmed the asset to be operating suitably to support reliable system
operation and full functionality at 700MW, which was validated by the Government of Canada’s
Independent Engineer issuing its Commissioning Certificate on April 13, 2023.
Upon issuance of the Commissioning Certificate, AFUDC equity earnings ceased and cash equity
earnings and return of equity to Emera commenced. The first distribution was received from the LIL
partnership in Q4
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 $747 million, comprised of $410 million in equity
contribution and $337 million of accumulated equity earnings. Emera’s total equity contribution in the LIL,
excluding accumulated equity earnings, is estimated to be approximately $650 million once the final
costing has been confirmed by Nalcor to determine the amount of the remaining investment.
Exhibit 99.2
17
Gas Utilities and Infrastructure
Gas Utilities and Infrastructure includes PGS, NMGC, SeaCoast, Brunswick Pipeline and Emera’s equity
investment in M&NP. PGS is a regulated gas distribution utility
engaged in the purchase, distribution and
sale of natural gas serving customers in Florida. NMGC is an intrastate regulated gas
distribution utility
engaged in the purchase, transmission, distribution and sale of natural gas serving customers in New
Mexico. SeaCoast is a regulated intrastate natural gas transmission company offering services in Florida.
Brunswick Pipeline is a regulated 145-kilometre pipeline delivering re-gasified liquefied natural gas from
Saint John, New Brunswick, to markets in the northeastern United States.
Peoples Gas System
With $2.8 billion USD of assets and approximately 490,000 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
2023.
Beginning in 2024, the approved ROE range for PGS is 9.15 per cent to 11.15 per cent (2023 – 8.9 per
cent to 11.0 per cent), based on an allowed equity capital structure of 54.7 per cent (2023 – 54.7 per
cent). An ROE of 10.15 per cent (2023 – 9.9 per cent) is used for the calculation of return on investments
for clauses.
New Mexico Gas Company, Inc.
With $1.8 billion USD of assets and approximately 540,000 customers, NMGC’s system includes
approximately 2,408 kilometres of transmission pipelines and 17,657 kilometres of distribution pipelines.
Annual natural gas throughput was approximately 1 billion therms in 2023.
The approved ROE for NMGC is 9.375 per cent, on an allowed equity capital structure of 52 per
cent.
Gas Utilities and Infrastructure Outlook
Gas Utilities and Infrastructure USD earnings are anticipated to be higher in 2024 than 2023, primarily
due to a base rate increase effective January 2024 at PGS and an expected base rate increase effective
Q4 2024 at NMGC, partially offset by lower asset optimization revenues expected at
NMGC.
PGS expects rate base to be higher than in 2023 and anticipates
earning within its allowed ROE range in
2024. USD earnings for 2024 are expected to be to be significantly higher than in 2023
primarily due to
higher revenue from new base rates in support of significant ongoing system investment and continued
customer growth in 2024, which is expected to be consistent with Florida’s population growth rates.
On April 4, 2023, PGS filed a rate case with the FPSC and a hearing for the matter was held in
September 2023. On November 9, 2023, the FPSC approved a $118 million USD increase to base
revenues which includes $11 million USD transferred from the cast iron and bare steel replacement rider,
for a net incremental increase to base revenues of $107 million USD. This reflects a 10.15 per cent
midpoint ROE with an allowed equity capital structure of 54.7 per cent. A final order was issued on
December 27, 2023, with the new rates effective January
2024.
The 2020 PGS rate case settlement provided the ability to reverse
a total of $34 million USD of
accumulated depreciation through 2023. PGS reversed $20 million USD of accumulated depreciation in
2023 and $14 million USD in 2022.
Exhibit 99.2
18
NMGC expects 2024 rate base growth to be consistent with 2023, with slightly lower USD earnings as a
result of lower asset optimization revenues, partially offset by higher revenue from expected new base
rates, effective Q4 2024. NMGC anticipates earning near its authorized ROE in 2024. Customer growth
rates are expected to be consistent with historical
trends.
On September 14, 2023, NMGC filed a rate case with the NMPRC
for new base rates to become effective
Q4 2024. NMGC requested a $49 million USD increase in annual base revenues primarily as a
result of
increased operating costs and capital investments in pipeline projects and related infrastructure. The rate
case includes a requested ROE of 10.5 per cent. A final order from the
NMPRC is expected in Q3 2024.
In 2024, capital investment in the Gas Utilities and Infrastructure segment is expected to be
approximately $465 million USD (2023 – $495 million USD), including AFUDC. PGS and NMGC will make
investments to maintain the reliability of their systems 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 an equity investment in Lucelec
on the island of St. Lucia.
BLPC
With $517 million USD of assets and approximately 134,000 customers, BLPC owns 243 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 3,839 kilometres of distribution facilities. BLPC’s approved
regulated return on rate base for 2023 was 10
per
cent.
GBPC
With
$334 million USD of assets and approximately 19,000 customers, GBPC owns 98 MW of oil-fired
generation, approximately 90
kilometres of transmission facilities and 994 kilometres of distribution
facilities. GBPC’s approved regulatory return on
rate base for 2024 is 8.52 per cent (2023 – 8.32 per
cent).
Other Electric Utilities Outlook
Other Electric Utilities’ USD earnings in 2024 are expected to increase over the prior year.
BLPC currently operates pursuant to a single integrated license to generate, transmit and distribute
electricity on the island of Barbados until 2028. In 2019, the Government of Barbados passed legislation
requiring multiple licenses for the supply of electricity. In 2021, BLPC reached commercial agreement with
the Government of Barbados for each of the license types, subject to the passage of implementing
legislation. The timing of the final enactment is unknown at this time, but BLPC will work towards the
implementation of the licenses once enacted.
Exhibit 99.2
19
In
2021, BLPC submitted a general rate review application to the FTC. In September 2022, the FTC
granted BLPC interim rate relief,
allowing an increase in base rates of approximately $1 million USD per
month. On February 15, 2023, the FTC issued a decision on
the application which included the following
significant items: an allowed regulatory ROE of 11.75 per cent, an equity capital
structure of 55 per cent,
a directive to update the major components of rate base to September 16, 2022, and a directive to
establish regulatory liabilities related to the self-insurance fund of $50 million USD, prior year benefits
recognized on remeasurement of deferred income taxes of $5 million USD, and accumulated depreciation
of $16 million USD. On March 7, 2023, BLPC filed a Motion for Review and Variation (the “Motion”) and
applied for a stay of the FTC’s decision, which was subsequently granted. On November 20, 2023, the
FTC issued their decision dismissing the Motion. Interim rates continue to be in effect through to a date to
be determined in a final decision and order.
On December 1, 2023, BLPC appealed certain aspects of the FTC’s February 15 and November 20,
2023, decisions to the Supreme Court of Barbados in the High Court of Justice (the “Court”) and
requested that they be stayed. On December 11, 2023, the Court granted the
stay. BLPC’s position is
that the FTC made errors of law and
jurisdiction in their decisions and believes the success of the appeal
is probable, and as a result, the adjustments to
BLPC’s final rates and rate base, including any
adjustments to regulatory assets and liabilities, have not been recorded at
this time. Management does
not expect the final decision and order to have a material impact on adjusted net income.
In 2024, capital investment in the Other Electric Utilities segment is expected to be approximately $80
million USD (2023 – $47 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 Block Energy LLC (“Block Energy”).
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. Block Energy 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.
The adjusted net loss from the Other segment is expected to be higher in 2024 due to increased interest
expense and lower contribution to net income from Emera Energy primarily as a result of one-time
investment tax credits at Bear Swamp in
2023.
The Other segment does not anticipate any significant capital
investment in 2024.
Exhibit
99.2
20
CONSOLIDATED BALANCE SHEET HIGHLIGHTS
Significant changes in the Consolidated Balance Sheets between December 31, 2022 and December 31,
2023 include:
millions of
dollars
Increase
(Decrease)
Explanation
Assets
Cash and cash
equivalents
$
Increased due to cash from operations, proceeds from long-term
debt issuances at PGS and NSPI, and issuance of Emera
common stock. These were partially offset by investment in PP&E
at the regulated utilities, net repayments of debt at TEC, and
dividends paid on Emera common stock
Derivative instruments (current and
long-term)
Decreased due to settlements of derivative instruments and
decreased pricing on power derivative instruments at NSPI,
partially offset by reversal of 2022 contracts at EES
Regulatory assets (current and long-
term)
Decreased due to higher fuel clause and storm cost recoveries at
TEC, and reversal of accrued Cap-and-Trade emission
compliance charges at NSPI. These were partially offset by
increased FAM deferrals at NSPI due to an under-recovery of fuel
costs and a change in fuel cost recovery methodology for an
industrial customer, and increased deferred income tax regulatory
assets at NSPI
Receivables and other
assets
(current and long-term)
Decreased due to lower gas transportation assets, decreased
cash collateral and lower trade receivables as a result of lower
commodity prices at EES, and settlement of the gas hedge
receivable at NMGC
PP&E, net of
accumulated
depreciation and amortization
Increased due to capital additions in excess of depreciation and
amortization, partially offset by the effect of FX translation of
Emera's non-Canadian affiliates
Goodwill
Decreased due to the effect of the FX translation of non-Canadian
affiliates
Liabilities
and Equity
Short-term debt and long-term debt
(including current portion)
$
Issuance of long-term debt at PGS and NSPI and proceeds from
committed credit facilities at Emera, partially offset by net
repayments under committed credit facilities at NSPI and TEC,
repayment of debt at NMGC, and the effect of the FX translation
of non-Canadian affiliates
Accounts
payable
Decreased due to lower commodity prices at EES, NMGC and
TEC, decreased cash collateral position on derivative instruments
and lower fuel related payables at 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, partially offset by changes in
derivative instruments and increased tax credits related to solar
projects at TEC and Bear Swamp facility upgrades
Derivative instruments (current and
long-term)
Decreased due to changes in existing positions and reversal of
2022 contracts, partially offset by new contracts in 2023 at EES
Regulatory liabilities (current and
long-term)
Decreased due to lower deferrals related to derivative instruments
at NSPI and settlement of NMGC gas hedges
Other liabilities (current and long-
term)
Decreased due to reversal of accrued Cap-and-Trade emissions
compliance charges at NSPI
Common stock
Increased due to shares issued
Accumulated other comprehensive
income
Decreased due to the effect of the FX translation of non-Canadian
affiliates
Retained earnings
Increased due to net income in excess of dividends paid
Exhibit 99.2
21
OTHER
DEVELOPMENTS
Increase in Common
Dividend
On September 20, 2023, the Emera Board of Directors (the “Board”) approved an increase in the annual
common share dividend rate to $2.87 from $2.76 per common share. The first payment was effective
November 15, 2023. Emera also extended its dividend growth rate target of four to five per cent through
2026.
FINANCIAL
HIGHLIGHTS
Florida Electric Utility
Three months ended
Year ended
For the
December 31
December 31
millions of USD (except as
indicated)
2023
2022
2023
2022
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, 2023, by $1 million and $22 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 – 2022
$
91
$
Increased operating revenues due to storm cost recovery surcharge
revenue (offset in OM&G), new base rates and customer growth driving
higher sales volumes, partially offset by changes in fuel recovery
clause revenue and unfavourable weather
Decreased fuel for generation and purchased power due to lower
natural gas prices
Increased OM&G primarily due to storm cost recovery recognition
related to the storm surcharge (offset in revenue) and timing of
deferred clause recoveries
Increased depreciation and amortization due to additions to facilities
and generation projects placed in service
Increased interest expense due to higher interest rates and higher
borrowings to support capital investments and ongoing operations
Increased state, and municipal taxes due to higher retail sales and
higher taxable property placed in service
(Increased) decreased income tax expense primarily due to production
tax credits related to solar facilities
Other
Contribution to consolidated net income – 2023
$
$
Exhibit
99.2
22
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"))
2023
2022
2023
2022
Residential
$
$
Commercial
Industrial
Other
(1)
Total
$
$
(1) Other includes regulatory deferrals related to clauses, sales to public authorities, off-system sales
to other utilities.
Regulated Fuel for Generation and
Purchased Power
Annual production volumes are summarized in the following
table:
Production Volumes (GWh)
2023
2022
Natural
gas
Solar
Purchased
power
Coal
Total
TEC’s fuel costs are affected by commodity prices and generation mix that is largely dependent on
economic dispatch of the generating fleet, bringing the lowest cost options on first (renewable energy
from solar or battery storage), such that the 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
TEC is regulated by the FPSC and is also subject to regulation by the FERC. The FPSC sets rates at a
level that allows utilities such as TEC to collect total revenues or revenue requirements equal to their cost
of providing service, plus an appropriate return on invested capital. Base rates are determined in FPSC
rate setting hearings which can occur at the initiative of TEC, the FPSC or other interested parties. For
further details on TEC’s regulatory environment, base rates and recovery mechanisms, refer to note 6 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)
2023
2022
2023
2022
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
(2)
$
$
$
$
(1) Regulated fuel for generation and purchased power includes NSPI's
FAM deferral on the Consolidated Statements of Income,
however, it is
excluded in the segment overview.
(2) Average fuel costs for the year
ended December 31, 2023 include reversal of the $166 million of the Nova Scotia Cap-and-Trade
Program provision (2022 – $134 million expense).
Exhibit
99.2
23
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
2023
2022
2023
2022
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.
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 – 2022
$
$
Increased operating revenues quarter-over-quarter due to new rates,
increased residential, commercial and other class sales volumes, and
favourable weather, partially offset by decreased industrial sales
volume. Year-over-year decrease primarily due to changes in fuel cost
recovery methodology for an industrial customer
(1)
, partially
offset by
quarter-over-quarter impacts noted above
Increased fuel for generation and purchased power quarter-over-quarter
due to increased commodity prices and partial reversal of Nova Scotia
Cap-and-Trade Program costs accrued in 2022, partially offset by a
change in generation mix. Year-over-year decreased due to reversal of
the Nova Scotia Cap-and-Trade Program provision in 2023, compared
to an expense in 2022, partially offset by increased commodity prices
and the Nova Scotia OBPS carbon tax accrual
Increased FAM deferral quarter-over-quarter due to under-recovery of
fuel costs. Year-over-year decreased due to reversal of the Nova Scotia
Cap-and-Trade provision in 2023, partially offset by increased
under-
recovery of fuel costs and changes in the fuel recovery methodology for
an industrial customer
(1)
Increased OM&G due to higher costs for power generation and
transmission and distribution field services. Year-over-year also
increased due to the recognition of the RER penalty and higher
vegetation management costs
Increased depreciation and amortization due to increased PP&E in
service
Increased interest expense due to increased interest rates and higher
debt levels
Increased income from equity investments at NSPML
quarter-over-
quarter primarily due to the holdback recognized in Q4 2022.
Year-over-
year also increased due to partial reversal in Q3 2023 of the holdback
recognized in 2022, and higher equity earnings from LIL
NSPML unrecoverable costs in 2022
Other
Contribution to consolidated net income – 2023
$
$
(1) For more information on the changes in fuel cost recovery methodology for an industrial
customer, refer to note 6 in the 2023
consolidated financial statements
Exhibit 99.2
24
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)
2023
2022
2023
2022
Residential
$
$
Commercial
Industrial
Other
Total
$
$
Regulated Fuel for Generation and Purchased Power
Annual production volumes are summarized in the following
table:
Production Volumes (GWh)
2023
2022
Coal
Natural gas
Purchased power
Petcoke
Oil
Total non-renewables
Purchased power - IPP, COMFIT and imports
Wind, hydro and solar
Biomass
Total renewables
Total production volumes
NSPI’s fuel costs are affected by commodity prices and generation mix, which is largely dependent on
economic dispatch of the generating fleet. NSPI brings the lowest cost options on stream first after
renewable energy from IPPs including COMFIT participants, for which NSPI has power purchase
agreements in place, and the NS Block of energy, including the Supplemental Energy Block, which
carries no additional fuel cost outside of the UARB approved annual assessments paid to NSPML for the
use of the Maritime
Link.
Generation mix may also be affected by plant outages, carbon
pricing programs, including the Nova
Scotia OBPS, availability of renewable generation, availability of energy from the NS Block,
plant
performance, and compliance with environmental
regulations.
The Nova Scotia Cap-and-Trade Program provision related to
the accrued cost of acquiring emissions
credits for the 2019 through 2022 compliance period. As of December 31, 2022, NSPI had
recognized a
cumulative $166 million accrual in fuel costs related to anticipated purchase of emissions credits and $6
million related to credits purchased from provincial auction. Accrued compliance costs of $166 million
were reversed in Q1 2023 and NSPI does not anticipate further costs related to the Nova Scotia
Cap-and-
Trade Program. For further information on the reversal of this non-cash accrual and the FAM regulatory
balance, refer to the “Business Overview and Outlook – Canadian Electric Utilities – NSPI” section and
note 6 in the consolidated financial statements.
Exhibit 99.2
25
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 6 in the consolidated financial statements.
Gas Utilities and Infrastructure
Three months ended
Year ended
For the
December 31
December 31
millions of USD (except as
indicated)
2023
2022
2023
2022
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, 2023 and $46 million (2022 – $47 million) for the year ended December 31
2023; 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
2023
2022
2023
2022
PGS
$
$
$
$
NMGC
Other
Contribution to consolidated net
income
$
$
$
$
Impact of the change in the FX rate on CAD earnings was minimal for the three months ended and
increased CAD earnings for the year ended December 31, 2023, by $8 million.
Exhibit
99.2
26
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 – 2022
$
$
Decreased operating revenues due to lower fuel revenues at PGS and
NMGC, and lower off-system sales at PGS, partially offset by new base
rates at NMGC and customer growth at PGS
Decreased asset optimization revenue quarter-over-quarter at NMGC
Decreased cost of natural gas sold due to lower natural gas prices at
PGS and NMGC
Increased OM&G primarily due to higher labour and benefit costs
Decreased depreciation and amortization expense quarter-over-quarter
due to a higher reversal of accumulated depreciation in 2023 as a
result of the 2021 rate case settlement at PGS. Year-over-year
increase due to asset growth at PGS and NMGC, partially offset by a
higher reversal of accumulated depreciation in 2023 at PGS
Increased interest expense due to higher interest rates and increased
borrowings to support ongoing operations and capital investments
Other
Contribution to consolidated net income – 2023
$
$
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)
2023
2022
2023
2022
Residential
$
$
Commercial
Industrial
(1)
Other
(2)
Total
(3)
$
$
(1) Industrial gas revenue includes sales to power generation customers.
(2) Other gas revenue includes off-system sales to other utilities and various other items.
(3) Total gas revenue excludes $46 million of finance income from
Brunswick Pipeline (2022 – $47 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.
Exhibit
99.2
27
Annual gas sales by type are summarized in the following table:
Gas Volumes by Type (millions of Therms)
2023
2022
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 6 in the consolidated financial statements.
Other Electric
Utilities
.
Three
months ended
Year ended
For the
December 31
December 31
millions of USD (except as indicated)
2023
2022
2023
2022
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 (loss)
$
$
$
$
Contribution to consolidated net income (loss) – CAD
$
$
$
$
Electric sales volumes (GWh)
Electric production volumes (GWh)
Average fuel cost in dollars per MWh
$
$
$
$
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. The sale did not have a
material impact on earnings.
The impact of the change in the FX rate on CAD earnings for the three months and year ended
December 31, 2023 was minimal.
Other Electric Utilities' contribution to consolidated adjusted net income is summarized in the following
table:
Three months
ended
Year ended
For the
December 31
December 31
millions of USD
2023
2022
2023
2022
BLPC
$
$
$
$
GBPC
Other
Contribution to consolidated adjusted net
income
$
$
$
$
Exhibit
99.2
28
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 – 2022
$
$
Increased operating revenues quarter-over-quarter due to higher fuel
revenue at BLPC and GBPC as a result of higher fuel prices and higher
sales volumes at BLPC. Year-over-year decreased due to lower fuel
revenue at BLPC reflecting lower fuel prices, and the sale of Domlec in
Q1 2022, partially offset by interim rates at BLPC and increased sales
volumes at BLPC and GBPC
Increased fuel for generation and purchased power
quarter-over-
quarter due to higher fuel costs at BLPC and GBPC. Decreased
year-
over-year due to lower fuel prices and change in generation mix at
BLPC
GBPC impairment charge in 2022
Other
Contribution to consolidated net income – 2023
$
$
Regulatory
Environments
BLPC is regulated by the FTC. Rates are set to recover prudently incurred costs of providing electricity
service to customers plus an appropriate return on capital
invested.
GBPC is regulated by the GBPA. Rates are set to recover
prudently incurred costs of providing electricity
service to customers plus an appropriate return on rate
base.
For further details on BLPC and GBPC’s regulatory
environments and recovery mechanisms, refer to note
6 in the consolidated financial statements.
Other
Three months ended
Year ended
For the
December 31
December 31
millions of dollars
2023
2022
2023
2022
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, 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 $131 million in Q4 2023
(2022 – $430 million gain) and a gain of
$216 million for the
year ended December 31, 2023 (2022 – $281 million gain).
(3) Net
of income tax expense of $44 million for the three months ended December 31, 2023 (2022 – $124 million expense) and $68
million expense for the year ended December 31, 2023 (2022 – $73 million expense).
Exhibit
99.2
29
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
2023
2022
2023
2022
Emera Energy:
$
$
$
$
Corporate – see breakdown of adjusted contribution below
Block Energy LLC
(1)
Other
Contribution to consolidated adjusted net income (loss)
$
$
$
$
(1) Previously Emera Technologies LLC
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) – 2022
$
$
Decreased marketing and trading margin quarter-over-quarter primarily
due to weather driven market conditions in Q4 2022 that increased
pricing and volatility. Year -over-year decrease reflects less favourable
market conditions, specifically lower natural gas prices and volatility
and higher cost commitments for gas transportation in 2023 compared
to 2022
Decreased 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 income tax recovery primarily due to increased losses before
provision for income taxes and the recognition of investment tax credits
related to Bear Swamp facility upgrades, partially offset by the impact
of effective state tax rates
TGH award in 2022, after tax and legal costs
Decreased MTM gain, after-tax, quarter-over-quarter due to
unfavourable changes in existing positions, partially offset by higher
amortization of gas transportation assets in 2022 at EES. Decreased
MTM gain after-tax, year-over-year primarily due to higher amortization
of gas transportation assets partially offset by favourable changes in
existing positions at EES and gains on Corporate FX hedges
Other
Contribution to consolidated net income (loss) – 2023
$
$
Exhibit 99.2
30
Emera
Energy
EES derives revenue and earnings from wholesale marketing and
trading of natural gas and electricity
within the Company’s risk tolerances, including those related to value-at-risk
(“VaR”) and credit exposure.
EES purchases and sells physical natural gas and electricity, the related transportation
and transmission
capacity rights, and provides energy asset management services. The primary market area for the natural
gas and power marketing and trading business is northeastern North America, including the Marcellus
and Utica shale supply areas. EES also participates in the 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.
EES’ contribution to consolidated adjusted net income was $19 million in Q4 2023, compared to $40
million in Q4 2022; and $46 million ($33 million USD) for the year ended December 31, 2023, compared
to $68 million ($50 million USD) for the same period in 2022. The 2023 and 2022 EES contribution to
consolidated adjusted net income was above the expected EES annual adjusted net income guidance
range of $15 to $30 million USD. Market conditions in 2022 were very favourable, due to high natural gas
pricing and volatility, which reflected weather patterns and geopolitical conditions.
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
table
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 are recorded in “Other income, net” on the
Consolidated Statements of Income.
Exhibit
99.2
31
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
2023
2022
2023
2022
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.
(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 net loss, pre-tax of $4 million ($3 million after-tax) for the three months ended December 31,
2023 (2022 – $5
million net loss, pre-tax and $4 million loss,
after-tax) and a $11 million net loss, pre-tax ($8 million after-tax) for the year ended
December 31, 2023 (2022 – $6 million net loss, pre-tax and $5 million loss after-tax) on FX hedges, as
discussed above.
(4) Excludes a MTM gain, after-tax of $15 million for
the three months ended December 31, 2023 (2022 – $9 million gain, after-tax)
and a MTM gain, after-tax of $20 million for
the year ended December 31, 2023 (2022 – $12 million loss, after-tax).
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.
Emera’s future liquidity and capital needs will be predominately for working capital requirements, ongoing
rate base investment, business acquisitions, greenfield development, dividends and debt servicing.
Emera has an approximate $9 billion capital investment plan over the 2024 through 2026 period with
approximately $2 billion of additional potential capital investments over the same period. Capital
investments at Emera’s regulated utilities are subject to regulatory approval.
Emera plans to use cash from operations, debt raised at the utilities, equity, and select asset sales to
support normal operations, repayment of existing debt, and capital requirements. Debt raised at certain of
the Company’s utilities is subject to applicable regulatory approvals. Generally, equity requirements in
support of the Company’s capital investment plan are expected to be funded through issuance of
preferred equity and issuance of common equity through Emera’s DRIP and ATM
programs.
Emera has credit facilities with varying maturities that
cumulatively provide $5.3 billion of credit, with
approximately $2.3 billion undrawn and available at December 31, 2023. The
Company was holding a
cash balance of $588 million at December 31, 2023. 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.
Exhibit 99.2
32
Consolidated Cash Flow Highlights
Significant changes in the Consolidated Statements of Cash Flows between the years ended December
31, 2023 and 2022 include:
millions of dollars
2023
2022
$ 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
increased
$1,328 million to $2,241 million for the year ended
December 31, 2023, compared to $913 million in 2022.
Cash from operations before changes in working capital
increased
$1,189 million for the year ended
December 31, 2023. This increase was due to higher fuel clause recoveries and favourable changes in
the storm reserve balance at TEC, decreased fuel for generation and purchased power expense at NSPI
driven by the decreased Nova Scotia Cap-and-Trade Program provision and a distribution received from
the LIL partnership. This was partially offset by a decrease in regulatory liabilities due to 2022 gas hedge
settlements at NMGC, and receipt of the TGH award in 2022.
Changes in working capital increased operating cash flows by $139 million for the year ended December
31, 2023. This increase was due to favourable changes in accounts receivable at NMGC due to receipt of
its 2022 gas hedge settlement, favourable changes in cash collateral positions at Emera Energy,
favourable changes in natural gas inventory at EES in 2023, and the required prepayment of income
taxes and related interest in 2022 at NSPI. These increases were offset by the timing of accounts payable
payments at NSPI, TEC and NMGC, unfavourable changes in cash collateral positions at NSPI, and
decreased accrual for the Nova Scotia Cap-and-Trade emissions compliance charges at NSPI.
Cash Flow used in Investing Activities
Net cash used in investing activities increased $348 million to $2,917 million for the year ended
December 31, 2023, compared to $2,569 million in 2022. The increase was due to higher capital
investment in 2023.
Capital expenditures for the year ended December 31, 2023, including AFUDC, were $2,976 million
compared to $2,646 million in 2022. Details of 2023 capital spending by segment are shown
below:
●
●
●
●
●
Exhibit
99.2
33
Cash Flow from Financing Activities
Net cash provided by financing activities decreased $616 million to $939 million for the year ended
December 31, 2023, compared to $1,555 million in 2022. This decrease was due to lower proceeds from
long-term debt at TEC, higher repayment of short-term debt at TEC, lower proceeds from short-term debt
at TECO Finance and Emera, and higher repayments of committed credit facilities at NSPI. This was
partially offset by proceeds from long-term debt at PGS and NSPI, retirement of long-term debt at TEC in
2022, and higher issuance of common stock.
Working Capital
As at December 31, 2023, Emera’s cash and cash equivalents were $567 million (2022 – $310 million)
and Emera’s investment in non-cash working capital was $831 million (2022 – $1,173 million). Of the
cash and cash equivalents held at December 31, 2023, $482 million was held by Emera’s foreign
subsidiaries (2022 – $250 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.
Contractual Obligations
As at December 31, 2023, contractual commitments for each of the next five years and in aggregate
thereafter consisted of the following:
millions of dollars
2024
2025
2026
2027
2028
Thereafter
Total
Long-term debt
principal
$
$
$
$
$
$
$
Interest payment obligations
(1)
Transportation
(2)
Purchased power
(3)
Fuel, gas supply and storage
Capital
projects
111
70
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, 2023, 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
$134 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 equity contributions to the LIL related to an investment true up in 2024 and
sustaining capital
contributions over the life of the
partnership. The commercial agreements between Emera and Nalcor require true ups to finalize the
respective investment obligations of the parties in relation the Maritime Link and LIL which is expected to be
approximately $240
million in 2024. In addition, Emera has future
commitments to provide sustaining capital to the LIL for routine capital and major
maintenance.
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 2023, the
UARB approved collection of up to $164 million from NSPI for recovery of Maritime Link costs in 2024.
The timing and amounts payable to NSPML for the remainder of the 38-year commitment period are
subject to UARB approval.
Exhibit
99.2
34
Construction of the LIL is complete and the Newfoundland Electrical System Operator confirmed the
asset to be operating suitably to support reliable system operation and full functionality at 700MW, which
was validated by the Government of Canada’s Independent Engineer issuing its Commissioning
Certificate on April 13, 2023.
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 and
continuing for 50 years. As transmission rights are contracted, the obligations are included within “Other”
in the above table.
Forecasted Consolidated Capital Investments
The 2024 forecasted consolidated capital investments are as follows:
millions of dollars
Florida
Electric
Utility
Canadian
Electric
Utilities
Gas Utilities
and
Infrastructure
Other
Electric
Utilities
Other
Total
Generation
$
$
$
$
$
$
New renewable generation
Electric transmission
Electric distribution
Gas transmission and distribution
Facilities, equipment, vehicles, and other
$
$
$
$
$
$
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 Canadian
dollars (unless otherwise indicated)
Maturity
Facilities
Utilized
Available
Emera –
Unsecured committed revolving credit facility
June 2027
$
$
$
TEC (in USD) – Unsecured committed revolving credit facility
December 2026
NSPI – Unsecured committed revolving credit facility
December 2027
Emera – Unsecured non-revolving
facility
December 2024
Emera – Unsecured non-revolving
facility
February 2024
Emera – Unsecured non-revolving facility
August 2024
TECO Finance (in USD) – Unsecured committed revolving credit
facility
December 2026
NSPI – Unsecured non-revolving facility
July 2024
PGS (in USD) – Unsecured revolving facility
December 2028
TEC (in USD) - Unsecured revolving facility
February 2024
TEC (in USD) - Unsecured revolving facility
April 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
Exhibit 99.2
35
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, 2023. Emera’s significant
covenant is listed below:
As at
Financial Covenant
Requirement
December 31, 2023
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 January 30, 2024, TEC issued $500 million USD of senior unsecured bonds that bear interest at 4.90
per cent with a maturity date of March 1, 2029. Proceeds from the issuance were primarily used for the
repayment of short-term borrowings outstanding under the 5-year credit facility. Therefore, $497 million
USD of short-term borrowings that was repaid was classified as long-term debt at December 31, 2023.
On November 24, 2023, TEC repaid its $400 million USD unsecured non-revolving facility, which expired
on December 13, 2023.
On April 3, 2023, TEC entered into a 364-day, $200 million USD senior unsecured revolving credit facility
which matures on April 1, 2024. The credit agreement contains customary representations and
warranties, events of default and financial and other covenants, and bears interest at a variable interest
rate, based on either the term secured overnight financing rate (“SOFR”), Wells Fargo’s prime rate, the
federal funds rate or the one-month SOFR, plus a margin. Proceeds from this facility will be used for
general corporate purposes.
On March 1, 2023, TEC entered into a 364-day, $200 million USD senior unsecured revolving credit
facility which matures on February 28, 2024. The credit facility contains customary representations and
warranties, events of default and financial and other covenants, and bears interest at a variable interest
rate, based on either the term SOFR, the Bank of Nova Scotia’s prime rate, the federal funds rate or the
one-month SOFR, plus a margin. Proceeds from this facility will be used for general corporate
purposes.
Canadian Electric Utilities
On March 24, 2023, NSPI issued $500 million in unsecured notes. The issuance included $300 million
unsecured notes that bear interest at 4.95 per cent with a maturity date of November 15, 2032, and $200
million unsecured notes that bear interest at 5.36 per cent with a maturity date of March 24, 2053.
Proceeds from these issuances were added to the general funds of the Company and applied primarily to
refinance existing indebtedness, to finance capital investment and for general corporate
purposes.
Gas Utilities and Infrastructure
On December 19, 2023, PGS completed an issuance of $925 million USD in senior notes. The issuance
included $350 million USD senior notes that bear interest at 5.42 per cent with a maturity date of
December 19, 2028, $350 million USD senior notes that bear interest at 5.63 per cent with a maturity date
of December 19, 2033 and $225 million USD senior notes that bear interest at 5.94 per cent with a
maturity date of December 19, 2053. Proceeds from these issuances were used to settle intercompany
loan agreements with TEC for the assets and liabilities transferred to PGS as part of the reorganization of
the gas division of Tampa Electric, effective on January 1, 2023.
Exhibit
99.2
36
On December 1, 2023, PGS entered into a $250 million USD senior unsecured revolving credit facility
with a group of banks, maturing on December 1, 2028. PGS has the ability to request the lenders to
increase their commitments under the credit facility by up to $100 million USD in the aggregate subject to
agreement from participating lenders. The credit agreement contains customary representations 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 these facilities will be used for
general corporate purposes.
On October 19, 2023, NMGC issued $100 million USD in senior unsecured notes that bear interest at
6.36 per cent with a maturity date of October 19, 2033. Proceeds from the issuance were used to repay
short-term borrowings.
Other Electric
Utilities
On May 24, 2023, GBPC issued a $28 million USD non-revolving
term loan that bears interest at 4.00 per
cent with a maturity date of May 24, 2028. Proceeds from this issuance were used to
repay GBPC’s $28
million USD bond, which matured in May 2023.
Other
On December 16, 2023, Emera amended its $400 million unsecured non-revolving facility to extend the
maturity date from December 16, 2023 to December 16, 2024. There were no other changes in
commercial terms from the prior agreement.
On August 18, 2023, Emera entered into a $400 million non-revolving term facility which matures on
February 19, 2024. The credit agreement contains customary representations 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 will be used for general corporate purposes. On
February 16, 2024, Emera extended the term of this agreement to a maturity date of February 19, 2025.
On June 30, 2023, Emera amended its $400 million unsecured non-revolving facility to extend the
maturity date from August 2, 2023 to August 2, 2024. There were no other changes in commercial terms
from the prior
agreement.
On May 2, 2023, Emera issued $500 million in senior
unsecured notes that bear interest at 4.84 per cent
with a maturity date of May 2, 2030. The proceeds were used to repay
Emera’s $500 million unsecured
fixed rate notes, which matured in June
2023.
Credit Ratings
Emera and its subsidiaries have been assigned the following senior unsecured debt ratings:
Fitch
S&P
Moody's
DBRS
Emera Inc.
BBB (Negative)
BBB- (Negative)
Baa3 (Negative)
N/A
TEC
A (Negative)
BBB+ (Negative)
A3 (Negative)
N/A
PGS (1)
A (Negative)
N/A
N/A
N/A
NMGC
BBB+ (Negative)
N/A
N/A
N/A
NSPI
N/A
BBB- (Negative)
N/A
BBB (high)(stable)
(1) On November 10, 2023 Fitch Ratings ("Fitch") assigned first-time long-term issuer default rating of 'A-'
to PGS and an instrument
rating of 'A' for its private placements of
senior unsecured bonds.
Exhibit 99.2
37
Guaranteed Debt
As of December 31, 2023, the Company had $2.75 billion USD (2022 – $2.75 billion USD) senior
unsecured notes ("US Notes”)
outstanding.
The US 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 US Notes
(such subsidiaries are referred to as the "Non-Guarantor
Subsidiaries"); however, Emera has unrestricted access to the assets of
consolidated entities.
In compliance with Rule 13-01 of Regulation
S-X, the Company is including summarized financial
information for Emera, 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.
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
2023
2022
Loss from
operations
$
$
Net gains (losses)
(1)
$
$
(1) Includes $750 million (2022 – $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
2023
2022
Current
assets
$
$
Goodwill
Other assets
(2)
Total
assets
$
$
Current liabilities
(4)
$
$
Long-term liabilities
(5)
Total liabilities
$
$
(1) Includes $179 million (2022 – $144 million) in amounts due from non-guarantor subsidiaries.
(2) Includes $5,941 million (2022 – $6,058 million) in amounts due from non-guarantor subsidiaries.
(3) Excludes investments in non-guarantor subsidiaries. Consolidated Emera total assets are $39,480
million (2022 – $39,742 million).
(4) Includes $411 million
(2022 – $392 million) due to non-guarantor subsidiaries.
(5)
Includes $619 million (2022 – $769 million) due to non-guarantor subsidiaries.
Exhibit 99.2
38
Outstanding Stock Data
Common Stock
millions of
millions of
Issued and outstanding:
shares
dollars
Balance, December 31, 2022
269.95
$
7,762
Issuance of common stock under ATM program
(1)
8.29
397
Issued under the
DRIP, net of discounts
5.26
272
Senior management stock options
exercised and Employee Share Purchase Plan
0.62
31
Balance, December
31, 2023
284.12
$
8,462
(1) For the year ended December 31,2023, 8,287,037 common shares were issued under Emera's
ATM program at an average
price of $48.27 per share for gross proceeds
of $400 million ($397 million net of after-tax issuance costs). As at December
31,2023, an aggregate gross sales limit of $200
million remained available for issuance under the ATM program.
As at
February 20, 2024, the amount of issued and outstanding common shares was 285.8 million.
If all outstanding stock options were
converted as at February 20, 2024, an additional 3.1 million common
shares would be issued and outstanding.
ATM Equity Program
On October 3, 2023, Emera filed a short form base shelf prospectus, primarily in support of the renewal of
its ATM Program in Q4 2023 that will allow the Company to issue up to $600 million of common shares
from treasury to the public from time to time, at the Company’s discretion, at the prevailing market price.
This ATM Program is expected to remain in effect until November 4, 2025.
Preferred Stock
As at February 20, 2024, 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.
On July 6, 2023, Emera announced it would not redeem the 10 million outstanding Cumulative Rate
Reset Preferred Shares, Series C (“Series C Shares”) or the 12 million outstanding Cumulative Minimum
Rate Reset First Preferred Shares, Series H (“Series H Shares”) on August 15,
2023.
On August 4, 2023, Emera announced after having taken into
account all conversion notices received
from holders, no Series C Shares were converted into Cumulative Floating Rate First
Preferred Shares,
Series D Shares and no Series H shares were converted into Cumulative Floating Rate First Preferred
Shares, Series I shares. The holders of the Series C Shares are entitled to receive a dividend of 6.434
per cent per annum on the Series C Shares during the five-year period commencing on August 15, 2023,
and ending on (and inclusive of) August 14, 2028 ($0.40213 per Series C Share per quarter). The holders
of the Series H Shares are entitled to receive a dividend of 6.324 per cent per annum on the Series H
Shares during the five-year period commencing on August 15, 2023, and ending on (and inclusive of)
August 14, 2028 ($0.39525 per Series H Share per quarter).
PENSION FUNDING
For funding purposes, Emera determines required contributions to its largest defined benefit (“DB”)
pension plans based on smoothed asset values. This reduces volatility in the cash funding requirement
as the impact of investment gains and losses are recognized over a three-year period. Expected cash
flow for DB pension plans is $34 million in 2024 (2023 – $42 million). All pension plan contributions are
tax deductible and will be funded with cash from operations.
Exhibit
99.2
39
Emera’s DB pension plans employ a long-term strategic approach with respect to asset allocation, real
return and risk. The underlying objective is to earn an appropriate return, given the Company’s goal of
preserving capital with an acceptable level of risk for the pension fund
investments.
To
achieve the overall long-term asset allocation, pension assets are managed by external investment
managers per each pension
plan’s investment policy and governance framework. The asset allocation
includes investments in the assets of domestic and
global equities, domestic and global bonds and short-
term investments. The Company reviews investment manager performance on a
regular basis and
adjusts the plans’ asset mixes as needed in accordance with the pension plans’ investment policy.
Emera’s projected contributions to defined contribution pension plans are $46 million for 2024 (2023 –
$45
million).
Defined Benefit Pension Plan Summary
in millions of dollars
Plans by region
TECO Energy
NSPI
Caribbean
Total
Assets as
at December 31, 2023
$
$
$
$
Accounting obligation at December 31, 2023
$
$
$
$
Accounting expense (income) during fiscal 2023
$
$
$
$
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,
2023 totalled $200 million (2022 – $200 million). The securities are held in trust for an affiliate of the
Province of Nova Scotia. Approximately 66 per cent of the defeasance portfolio consists of investments in
the related debt, eliminating all risk associated with this portion of the portfolio.
Guarantees and Letters of Credit
Emera has guarantees and letters of credit on behalf of third parties outstanding. The following significant
guarantees and letters of credit are not included within the Consolidated Balance Sheets as at December
31, 2023:
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 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.
TECO Energy issued a guarantee in connection with SeaCoast’s performance obligations under a firm
service agreement, which expires December 31, 2055, subject to two extension terms at the option of the
counterparty with a final expiration date of December 31, 2071. The guarantee is for a maximum potential
amount of $13 million USD if SeaCoast fails to pay or perform under the firm service agreement. 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 $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.
Exhibit 99.2
40
NSPI has issued guarantees on behalf of its subsidiary, NS Power Energy Marketing Incorporated, in the
amount of $104 million USD (2022 – $119 million USD) with terms of varying lengths.
The Company has standby letters of credit and surety bonds in the amount of $103 million USD
(December 31, 2022 – $145 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 2024. The amount committed
as at December 31, 2023 was $56 million (December 31, 2022 – $63 million).
DIVIDEND PAYOUT RATIO
Emera has provided annual dividend growth guidance of four to five per cent through 2026. 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 2023 were $2.7875 ($0.6900 in
Q1, Q2, and Q3 and $0.7175 in Q4) per common share and $2.6775 ($0.6625 in Q1, Q2, and Q3 and
$0.6900 in Q4) per common share for 2022, representing a dividend payout ratio of 78 per cent in 2023
(2022 – 75 per cent) and a dividend payout ratio of adjusted net income of 94 per cent in 2023 (2022 – 83
per
cent).
On September 20, 2023, the Board approved an increase in the
annual common share dividend rate to
$2.87 from $2.76 per common share. The first quarterly dividend payment at the increased
rate was paid
on November 15, 2023.
TRANSACTIONS WITH RELATED PARTIES
In the ordinary course of business, Emera provides energy and other services and enters into
transactions with its subsidiaries, associates and other related companies on terms similar to those
offered to non-related parties. Intercompany balances and intercompany transactions have been
eliminated on consolidation, except for the net profit on certain transactions between non-regulated and
regulated entities in accordance with accounting standards for rate-regulated entities. All material
amounts are under normal interest and credit
terms.
Significant transactions between Emera and its associated
companies are as follows:
●
Consolidated Statements of Income. NSPI’s expense is reported in Regulated fuel for generation and
purchased power, totalling $163 million for the year ended December 31, 2023 (2022 – $157 million).
NSPML is accounted for as an equity investment, and therefore 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 $14 million for the year ended December 31, 2023
(2022
– $9 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, 2023 and at December 31, 2022.
Exhibit 99.2
41
ENTERPRISE RISK AND RISK
MANAGEMENT
Emera has an enterprise-wide risk management process, overseen by its Enterprise Risk Management
Committee (“ERMC”) and monitored by the Board, to ensure 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 has a Risk and Sustainability Committee
(“RSC”) with a mandate 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.
Regulators administer the regulatory frameworks covering
material aspects of the utilities’ businesses,
including applying market-based tests to determine the appropriate 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. Regulators also review the
prudency of costs and other decisions that impact customer rates and reliability of service and work to
ensure the financial health of the utility for the benefit of customers. 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.
Exhibit 99.2
42
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 work to establish
collaborative relationships with regulatory stakeholders, including customer representatives, both through
its approach to filings and additional efforts with 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 the Company’s
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 “Insurance”
section below and “Uninsured Risk”.
Climate change may lead to increased frequency and intensity of events and related impacts such as
hurricanes, ice and other storms, heavy rainfall, cyclones, extreme winds, wildfires, flooding and
droughts. 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”.
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.
Exhibit 99.2
43
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.
Supply Chain:
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. Refer to “Supply Chain
Risk” and “Uninsured Risk”.
Insurance:
Given concerns regarding carbon-emitting generation, 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.
Exhibit 99.2
44
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.
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 purchased power
from third-party owned hydroelectricity 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, TEC 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. Higher frequency and severity of weather events increase the
likelihood of longer power outages and more fuel supply disruptions. 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.
Exhibit 99.2
45
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.
High winds and lack of precipitation increase the risk of
wildfires resulting from the Company’s
infrastructure or for which the Company may otherwise have responsibility. The risk
of wildfires is
addressed primarily through asset management programs for natural gas transmission and distribution
operations, and asset management, storm hardening, and vegetation management programs for electric
utilities, but there can be no assurance that these measures will fully mitigate the risk. If it is found to be
responsible for such a fire, the Company could suffer material costs, losses and damages, all or some of
which may not be recoverable through insurance, legal, regulatory cost recovery or other processes. If
not recovered through these means, they could materially affect Emera’s business, access to capital,
financial condition and results of operations 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.
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.
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. 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, renewable natural gas
projects, and support of public policy initiatives that address the effects of climate change.
In 2023, the United States Environmental Protection Agency proposed new carbon emission standards
for fossil fuel-fired power plants and the Government of Canada released draft Clean Electricity
Regulations which propose limitations on the use of natural gas generation. Until final rules are issued, it
is not certain what the impact will be on the Company and its
operations.
These and other legislative or regulatory changes could
influence decisions regarding capital investment,
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.
Exhibit 99.2
46
Per- and polyfluoroalkyl substances (“PFAS”) are man-made chemicals that are widely used in consumer
products and can persist and bio-accumulate in the environment. The Company does not manufacture
PFAS but because these emerging contaminants of concern are so ubiquitous in products and the
environment, it may impact Emera’s operations. Changes in environmental laws and regulations related
to PFAS could result in new costs or obligations for investigation and cleanup and change the Company’s
strategy for land acquisition for projects such as solar generation.
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 assess
compliance.
Cybersecurity Risk
Emera is exposed to potential risks related to cyberattacks and unauthorized access. The Company relies
on IT systems, cloud infrastructure, third-party service providers and the diligence of its team members to
effectively manage and safely operate its assets. This includes controls for interconnected systems of
generation, distribution and transmission as well as financial, billing and other enterprise systems. As the
Company operates critical assets, it may be at greater risk of cyberattacks, which could include those
from nation-state cyber threat actors. Major emerging and ongoing global conflicts may also elevate this
risk.
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
access to critical assets or trusted networks. Methods used to attack critical assets could include generic
or energy-sector-specific malware delivered via network transfer, removable media, attachments, 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.
Cyberattacks or unauthorized accesses may cause lost
revenues, 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.
Exhibit 99.2
47
The Company seeks to manage these risks by aligning to a common set of cybersecurity standards and
policies derived, in part, on the National Institute of Standards and Technology’s Cyber Security
Framework, 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. The Board oversees risk and
mitigation plans in relation to cybersecurity risks and receives a quarterly update in a
risk dashboard at
each regularly scheduled Board
meeting.
Public Health Risk
An outbreak of infectious disease, a pandemic or a similar public health threat, 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.
Consistent with the Company’s risk management policies, Emera manages currency risks through
matching United States denominated debt to finance its United States operations and may use foreign
currency derivative instruments to hedge specific transactions and earnings exposure. The Company may
enter FX forward and swap contracts to limit exposure on certain foreign currency transactions such as
fuel purchases, revenue streams and capital expenditures, and on net income earned outside of Canada.
The regulatory framework for the Company’s rate-regulated subsidiaries permits the recovery of prudently
incurred costs, including FX.
Exhibit 99.2
48
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 meet 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 various market analysts, including credit
rating agencies. Disruptions in capital markets could prevent Emera from issuing new securities or cause
the Company to issue securities with less than preferred terms and conditions. Emera’s growth plan
requires significant capital investments in PP&E and the risk associated with changes in interest rates
could have an adverse effect on the cost of financing. The Company’s future access to capital and cost of
borrowing may be impacted by various market disruptions. The inability to access cost-effective capital
could have a material impact on Emera’s ability to fund its growth
plan.
Emera is subject to financial risk associated with changes in
its credit ratings. There are a number of
factors that rating agencies evaluate to determine credit ratings, including the
Company’s business, its
regulatory framework and legislative environment, political interference in the regulatory
process, the
ability to recover costs and earn returns, diversification, leverage, liquidity and increased exposure to
climate change-related impacts, including increased frequency and severity of hurricanes and other
severe weather events. A decrease in a credit rating could result in higher interest rates in future
financings, increased borrowing costs under certain existing credit facilities, limit access to the
commercial paper market, or limit the availability of adequate credit support for subsidiary operations. For
more information on interest rate risk, refer to “General Economic Risk – Interest Rate Risk”. 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.
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.
Exhibit 99.2
49
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.
Interest rates could also be impacted by changes in credit ratings. For more information, refer to “Liquidity
and Capital Market
Risk”.
As with most other utilities and other similar
yield-returning investments, Emera’s share price may be
affected by changes in interest rates and could underperform the
market in an environment of rising
interest rates.
Inflation Risk:
The Company may be exposed to changes in inflation that may result in increased operating and
maintenance costs, capital investment, and fuel costs compared to the revenues provided by customer
rates. 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 of unionized employees.
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, increased demand for renewable energy inputs, risk of cost overruns, ensuring
compliance with operating and environmental requirements and other events within or beyond the
Company’s control. The Company’s projects may also require approvals and permits at the federal,
provincial, state, regional and local levels. There is no assurance that Emera will be able to obtain the
necessary project approvals or applicable permits or receive regulatory approval to recover the costs in
rates.
Some of the Company’s assets are located on land owned by third parties, including Indigenous Peoples,
and may be subject to land claims. Present or future assets may be located on lands that have been used
for traditional purposes and therefore subject to specific consultations, consents, or conditions for
development or operation. If the Company’s rights to locate and operate its assets on any such lands are
subject to expiry or become invalid, it may incur material costs to renew rights or obtain such rights. If
reasonable terms for land-use rights cannot be negotiated, the Company may incur significant costs to
remove and relocate its assets and restore the land. Additional costs incurred could cause projects to be
uneconomical to proceed 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.
Exhibit 99.2
50
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.
Supply Chain Risk
Emera’s ability to meet customer energy requirements, respond to storm-related disruptions and execute
on our capital program in a cost-effective and timely manner are dependent on maintaining an efficient
supply chain. Domestic and global supply chain issues may delay the delivery or result in shortages of
certain materials, equipment and other resources that are critical to the Company’s operations. These
disruptions may be further exacerbated by inflationary pressures, labour shortages, government
incentives increasing demand for clean energy projects, and the impact of international conflicts, tariffs, or
other trade restrictions. Failure to eliminate or manage supply chain constraints may impact the
availability and cost of items and labour that are necessary to support operations and capital investment.
Emera continues to monitor the situation and seeks to mitigate the impacts of supply chain risk by
securing alternative suppliers, third party risk management, modifying design standards, and adjusting
the timing of work.
Commodity Price Risk
The Company’s utility fuel supply and purchase of other commodities is subject to commodity price risk.
In addition, Emera Energy is subject to commodity price risk through its portfolio of commodity contracts
and arrangements.
Exhibit 99.2
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 FV 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.
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 and the Grand Bahama Power Company Limited Union Employees’
Pension Plan. The cost of providing these benefit plans varies depending on plan provisions, interest
rates, inflation, investment performance and actuarial assumptions concerning the future. Actuarial
assumptions include earnings on plan assets, discount rates (interest rates used to determine funding
levels, contributions to the plans and the pension and post-retirement liabilities) and expectations around
future salary growth, inflation and mortality. 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.
Exhibit 99.2
52
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 30 per cent of Emera’s labour force is represented by unions and subject to collective
labour agreements. The inability to maintain or negotiate future agreements on acceptable terms could
result in higher labour costs and work disruptions, which could adversely affect service to customers and
have 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.
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 income 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.
Exhibit 99.2
53
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
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.
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 and
its gas utilities’ 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 manages its insured risk by aligning insurance limits 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.
Exhibit 99.2
54
RISK MANAGEMENT INCLUDING FINANCIAL
INSTRUMENTS
Emera’s risk management policies and procedures provide a framework through which management
monitors various risk exposures. Risk management policies and practices are overseen by the Board.
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 exposure to normal operating and market risks relating to commodity prices, FX,
interest rates and share prices through contractual protections with counterparties where practicable, and
by using financial instruments consisting mainly of FX forwards and swaps, interest rate options and
swaps, equity derivatives, and coal, oil and gas futures, options, forwards and swaps. In addition, the
Company has contracts for the physical purchase and sale of natural gas. These physical and financial
contracts are classified as HFT. Collectively, these contracts and
financial instruments are considered
derivatives.
The Company recognizes the FV of all its derivatives on its balance sheet, except for non-financial
derivatives that meet the normal purchases and normal sales (“NPNS”) exception. Physical contracts that
meet the NPNS exception are not recognized on the balance sheet; these contracts are recognized in
income when they settle. A physical contract generally qualifies for the NPNS exception if the transaction
is reasonable in relation to the Company’s business needs, the counterparty owns or controls resources
within the proximity to allow for physical delivery, the Company intends to receive physical delivery of the
commodity, and the Company deems the counterparty creditworthy. The
Company continually assesses
contracts designated under the NPNS exception and will discontinue the treatment of these contracts
under this exemption if the criteria are no longer
met.
Derivatives qualify for hedge accounting if they meet stringent
documentation requirements and can be
proven to effectively hedge identified risk both at the inception and over the term of the
instrument.
Specifically, for cash flow hedges, change in the FV of derivatives is deferred to AOCI and recognized in
income in the same period the related hedged item is realized. Where documentation or effectiveness
requirements are not met, the derivatives are recognized at FV with any changes in FV 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 FV of the derivatives is deferred to a regulatory asset or liability. The gain or loss is recognized
in the hedged item when the hedged item is settled. Management believes any gains or losses resulting
from settlement of these derivatives related to fuel for generation and purchased power will be refunded
to or collected from customers in future rates. TEC has no derivatives related to hedging as a result of a
FPSC approved five-year moratorium on hedging of natural gas purchases that ended on December 31,
2022 and was extended through December 31, 2024 as a result of TEC’s 2021 rate case settlement
agreement.
Derivatives that do not meet any of the above criteria are designated as HFT, with changes in FV
normally recorded in net income of the period. The Company has not elected to designate any derivatives
to be included in the HFT category where another accounting treatment would apply.
Exhibit
99.2
55
Derivative Assets and Liabilities Recognized on the Balance Sheet
As at
December 31
December 31
millions of dollars
2023
2022
Regulatory Deferral:
Derivative instrument assets
(1)
$
$
Derivative instrument liabilities
(2)
Regulatory assets
(1)
Regulatory
liabilities
Net asset
$
$
HFT
Derivatives:
Derivative instrument
assets
$
$
Derivatives instruments liabilities
(2)
Net liability
$
$
Other Derivatives:
Derivative instrument assets
(1)
$
$
Derivatives instruments
liabilities
Net asset (liability)
$
$
(1) Current and other assets.
(2) Current and long-term
liabilities.
Realized and Unrealized Gains (Losses)
Recognized in Net Income
For the
Year
ended December 31
millions of dollars
2023
2022
Regulatory Deferral:
Regulated fuel for generation and purchased power
(1)
$
$
HFT Derivatives:
Non-regulated operating revenues
$
$
Other Derivatives:
OM&G
$
$
Other income, net
Net gains (losses)
$
$
Total net gains
$
$
(1) Realized gains (losses) on derivative instruments settled and
consumed in the period, hedging relationships that have been
terminated
or the hedged transaction is no longer probable. Realized gains (losses) recorded in inventory will be recognized in
“Regulated fuel for generation and purchased power” when the hedged item is consumed.
For the year ended December 31, 2023, unrealized gains of $2 million (2022 – $2 million), have been
reclassified out of AOCI into interest
expense.
As at
December 31, 2023
December 31, 2022
Interest rate
Interest rate
millions of dollars
hedge
hedge
Total unrealized gain in AOCI – net of tax
$
14
$
DISCLOSURE AND INTERNAL
CONTROLS
Management is responsible for establishing and maintaining adequate disclosure controls and
procedures (“DC&P”) and internal control over financial reporting (“ICFR”), as defined in National
Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings (“NI 52-109”). The
Company’s internal control framework is based on criteria published in the Internal Control Integrated
Framework (2013), a report issued by the Committee of Sponsoring Organizations (“COSO”) of the
Treadway Commission. Management, including the Chief Executive Officer and Chief Financial Officer,
evaluated the design and effectiveness of the Company’s DC&P and ICFR as at December 31, 2023 to
provide reasonable assurance regarding the reliability of financial reporting in accordance with USGAAP.
Exhibit 99.2
56
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, 2023, that have
materially affected, or are reasonably likely to materially affect, the Company’s internal control over
financial reporting.
CRITICAL ACCOUNTING ESTIMATES
The preparation of consolidated financial statements in accordance with USGAAP requires management
to make estimates and assumptions. These may affect reported amounts of assets and liabilities at the
date of the financial statements and reported amounts of revenues and expenses during the reporting
periods. Significant areas requiring use of management estimates relate to rate-regulated assets and
liabilities, accumulated reserve for cost of removal, pension and post-retirement benefits, unbilled
revenue, useful lives for depreciable assets, goodwill and long-lived assets impairment assessments,
income taxes, asset retirement obligations (“ARO”), and valuation of financial instruments. Management
evaluates the Company’s estimates on an ongoing basis based upon historical experience, current and
expected conditions and assumptions believed to be reasonable at the time the assumption is made, with
any adjustments recognized in income in the year they
arise.
Rate
Regulation
The rate-regulated accounting policies of Emera’s rate-regulated subsidiaries and regulated equity
investments are subject to examination and approval by their respective regulators and may differ from
the accounting policies of non-rate-regulated companies. Differences occur when regulators render their
decisions on rate applications or other matters, and generally involve a difference in the timing of revenue
and expense recognition. The accounting for these items is based on expectations of the future actions of
the regulators. Assumptions and judgments used by regulatory authorities continue to have an impact on
recovery of costs, rates earned on invested capital, and the timing and amount of assets to be recovered.
Application of regulatory accounting guidance is a critical accounting policy as a change in these
assumptions may result in a material impact on reported assets, liabilities and the results of operations.
As at December 31, 2023, the Company had recorded $3,105 million (2022 – $3,620 million) of regulatory
assets and $1,772 million (2022 – $2,273 million) of regulatory liabilities.
Accumulated Reserve – Cost of Removal
TEC, PGS, NMGC and NSPI recognize non-ARO costs of removal (“COR”) as regulatory liabilities. The
non-ARO COR 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. Costs
are estimated based on historical experience and future expectations, including expected timing and
estimated future cash outlays. As at December 31, 2023, the balance of the Accumulated reserve – COR
within regulatory liabilities was $849 million (2022 – $895 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.
Exhibit
99.2
57
The accounting related to employee post-retirement benefits is a critical accounting estimate. Changes in
the estimated benefit obligation, affected by employee demographics - including age, compensation
levels, employment periods, contribution levels and earnings - could have a material impact on reported
assets, liabilities, accumulated other comprehensive income and results of operations. Changes in key
actuarial assumptions, including anticipated rates of return on plan assets and discount rates used in
determining the accrued benefit obligation and benefit costs, could change annual funding requirements.
This could have a significant impact on the Company’s annual earnings and cash requirements.
Pension plan assets are comprised primarily of equity and fixed income investments. Fluctuations in
actual equity market returns and changes in interest rates may result in changes to pension costs in
future periods.
The Company’s accounting policy is to amortize the net actuarial gain or loss that exceeds 10 per cent of
the greater of the projected benefit obligation / accumulated post-retirement benefit obligation (“PBO”)
and the market-related value of assets, over active plan members’ average remaining service period. For
the largest plans this is currently 8.0 years (8.4 years for 2023 benefit cost) for Canadian plans and a
weighted average of 11.5 years for United States plans. The Company’s use of smoothed asset values
reduces volatility related to amortization of actuarial investment experience. As a result, the main cause of
volatility in reported pension cost is the discount rate used to determine the
PBO.
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:
2023
2022
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
5.55%
7.05%
2.78%
6.50%
TECO Energy Group Supplemental
Executive Retirement Plan
(1)
5.45%/5.31%
N/A
2.35/5.33%
N/A
TECO Energy Group Benefit
Restoration Plan (1)
5.48/5.30/5.49%
N/A
2.27/4.19/5.48%
N/A
TECO Energy Post-retirement Health
and Welfare Plan
5.53%/6.14%
N/A
2.84%
N/A
New Mexico Gas Company Retiree
Medical Plan
5.55%
2.50%
2.85%
1.50%
NSPI
5.17%, 5.19%
6.25%
3.25%, 3.48%
5.75%
GBPC Salaried
5.75%
5.75%
6.00%
GBPC Union
5.75%
5.75%
5.35%
(1) The discount rate for benefit cost purposes is updated throughout the year as special events
occur, such as settlements and
curtailments
Based on management’s estimate, the reported benefit cost for defined benefit and defined contribution
plans was $43 million in 2023 (2022 – $64 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 2023 benefit cost of $0.5
million and $2.5 million, respectively (2022 – $0.5 million and $1
million).
Exhibit 99.2
58
Unbilled Revenue
Electric and gas revenues are billed on a systematic basis over a one or two-month period for NSPI and a
one-month period for other Emera utilities. At the end of each month, the Company must make an
estimate of energy delivered to customers since the date their meter was last read and determine related
revenues earned but not yet billed. The unbilled revenue is estimated based on several factors, including
current month’s generation, estimated customer usage by class, weather, line losses, inter-period
changes to customer classes and applicable customer rates. Based on the extent of estimates included in
determination of unbilled revenue, actual results may differ from the estimate. At December 31, 2023,
unbilled revenues totalled $363 million (2022 – $424 million) on total regulated operating revenues of
$7,235 million (2022 – $7,154 million).
PP&E
PP&E
represents 62 per cent of total assets on the Company’s balance sheet and includes generation,
transmission and
distribution, and other assets of the Company.
Depreciation is determined by the straight-line method, based on the estimated
remaining service lives of
depreciable assets in each category. The service lives of regulated PP&E are determined based on
depreciation studies and require appropriate regulatory approval. Due to the magnitude of the Company’s
PP&E, changes in estimated depreciation rates can have a material impact on depreciation expense and
accumulated depreciation.
Depreciation expense was $1,019 million for the year ended December 31, 2023 (2022 – $927 million).
Goodwill Impairment
Assessments
Goodwill is calculated as the excess of the purchase price of an acquired entity over the estimated FV of
identifiable assets acquired, and liabilities assumed at the acquisition
date.
Goodwill is subject to assessment for impairment at the
reporting unit level annually, or if an event or
change in circumstances indicates that the FV of a reporting unit may be below
its carrying value.
Application of the goodwill impairment test requires management judgment on significant assumptions
and estimates. When assessing goodwill for impairment, the Company has the option of first performing a
qualitative assessment to determine whether a quantitative assessment is necessary. In performing a
qualitative assessment, management considers, among other factors, macroeconomic conditions,
industry and market considerations and overall financial performance.
If the Company performs a qualitative assessment and determines it is more likely than not that its FV is
less than its carrying amount, or if the Company chooses to bypass the qualitative assessment, a
quantitative test is performed. The quantitative test compares the FV of the reporting unit to its carrying
amount, including goodwill. If the carrying amount of the reporting unit exceeds its FV, an impairment loss
is recorded. Significant assumptions used in estimating the FV of a reporting unit include discount and
growth rates, rate case assumptions including future cost of capital, valuation of the reporting units' net
operating loss (“NOL”), and projected operating and capital cash flows. Adverse changes in these
assumptions could result in a future material impairment of the goodwill assigned to Emera’s reporting
units.
Exhibit 99.2
59
As of December 31, 2023, $5,868 million (2022 – $6,009 million) of Emera’s goodwill represents the
excess of the acquisition purchase price for TECO Energy (TEC, PGS and NMGC reporting units) over
the FV assigned to identifiable assets acquired and liabilities assumed. In Q4 2023, qualitative
assessments were performed for NMGC and PGS, given the significant excess of FV over carrying
amounts calculated during the last quantitative tests in Q4 2022 and Q4 2019, respectively. Management
concluded it was more likely than not that the FV of these reporting units exceeded their respective
carrying amounts, including goodwill. As such, no quantitative testing was required. Given the length of
time passed since the last quantitative impairment test for the TEC reporting unit, Emera elected to
bypass a qualitative assessment and performed a quantitative impairment assessment in Q4 2023 using
a combination of the income and market approach. This assessment estimated that the FV of the TEC
reporting unit exceeded its carrying amount, including goodwill, and as a result no impairment charges
were recognized.
As of December 31, 2023, the Company had goodwill with a total carrying amount of $5,871 million
(December 31, 2022 – $6,012 million). The change in the carrying value of goodwill from 2022 to 2023
was a result of the effect of the FX translation of Emera’s foreign affiliates.
In Q4 2022, as a result of a quantitative assessment, the Company recorded a goodwill impairment
charge of $73 million, reducing the GBPC goodwill balance to nil as at December 31, 2022. For further
detail, refer to note 22 in the consolidated financial statements.
Long-Lived Assets Impairment Assessments
The Company assesses whether there has been an impairment of long-lived assets and intangibles when
a triggering event occurs, such as a significant market disruption or the sale of a business. The
assessment involves comparing undiscounted expected future cash flows, to the carrying value of the
asset. When the undiscounted cash flow analysis indicates a long-lived asset is not recoverable, the
amount of the impairment loss is determined by measuring the excess of the carrying amount of the
long-
lived asset over its estimated FV.
The Company believes accounting estimates related to asset impairments are critical estimates, as they
are highly susceptible to change and the impact of an impairment on reported assets and earnings could
be material. Management is required to make assumptions based on expectations regarding results of
operations for significant/indefinite future periods and current and expected market conditions in such
periods. Markets can experience significant uncertainties. Estimates based on the Company’s
assumptions relating to future results of operations or other recoverable amounts are based on a
combination of historical experience, fundamental economic analysis, observable market activity and
independent market studies. The Company’s expectations regarding uses and holding periods of assets
are based on internal long-term budgets and projections, which consider external factors and market
forces, as of the end of each reporting period. Assumptions made by management are consistent with
generally accepted industry approaches and assumptions used for valuation and pricing activities.
As at December 31, 2023, there were no indications of impairment of Emera’s long-lived assets. No
impairment charges were recognized in either 2023 or 2022.
Exhibit 99.2
60
Income
Taxes
Income taxes are determined based on expected tax treatment of transactions recorded in the
consolidated financial statements. In determining income taxes, tax legislation is interpreted in a variety of
jurisdictions, the likelihood that deferred income tax assets will be recovered from future taxable income is
assessed, and assumptions are made about expected timing of reversal of deferred income tax assets
and liabilities. Uncertainty associated with application of tax statutes and regulations and outcomes of tax
audits and appeals, requires that judgments and estimates be made in the accrual process and in
calculation of effective tax rates. Only income tax benefits that meet the “more likely than not” threshold
may be recognized or continue to be recognized. Unrecognized tax benefits are evaluated quarterly and
changes are recorded based on new information, including issuance of relevant guidance by the courts or
tax authorities and developments occurring in examinations of the Company’s tax returns.
The Company believes accounting estimates related to income taxes are critical estimates. Realization of
deferred income tax assets depends on the generation of sufficient taxable income, both operating and
capital, in future periods. A change in estimated valuation allowance could have a material impact on
reported assets and results of operations. Administrative actions of tax authorities, changes in tax law or
regulation, and uncertainty associated with the application of tax statutes and regulations, could change
the Company’s estimate of income taxes, including the potential for elimination or reduction of the
Company’s ability to realize tax benefits and to utilize deferred income tax assets.
Asset Retirement Obligations
Measurement of the FV of AROs requires the Company to make reasonable estimates concerning the
method and timing of settlement associated with legally obligated costs. There are uncertainties in
estimating future asset-retirement costs due to potential events, such as changing legislation or
regulations, and advances in remediation technologies. Emera has AROs associated with remediation of
generation, transmission, distribution and pipeline
assets.
An ARO represents the FV of estimated cash flows necessary to
discharge the future obligation using the
Company’s credit-adjusted risk-free rate. The amounts are reduced by actual
expenditures incurred.
Estimated future cash flows are based on completed depreciation studies, remediation reports, prior
experience, estimated useful lives, and governmental regulatory requirements. The present value of the
liability is recorded and the carrying amount of the related long-lived asset is correspondingly increased.
The amount capitalized at inception is depreciated in the same manner as the related long-lived asset.
Over time, the liability is accreted to its estimated future value. Accretion expense is included as part of
“Depreciation and amortization expense”. Any accretion expense not yet approved by the regulator is
recorded in “PP&E” and included in the next depreciation study.
Accordingly, changes to the ARO or cost
recognition attributable to
changes in the factors discussed above, should not impact the results of
operations of the Company.
Some of the Company’s transmission and distribution assets may have conditional AROs that are not
recognized in the consolidated financial statements as the FV of these obligations could not be
reasonably estimated given insufficient information to do so. A conditional ARO refers to a legal obligation
to perform an asset retirement activity in which the timing and/or method of settlement are conditional on
a future event that may or may not be within the control of the entity. Management monitors these
obligations and a liability is recognized at FV when an amount can be determined.
As at December 31, 2023, AROs recorded on the balance sheet were $192 million (2022 – $174 million).
The Company estimates the undiscounted amount of cash flow required to settle the obligations is
approximately $426 million (2022 – $429 million), which will be incurred between 2023 and 2061. The
majority of these costs will be incurred between 2028 and 2050.
Exhibit 99.2
61
Financial Instruments
The Company is required to determine the FV of all derivatives except those that qualify for the normal
purchase, normal sale exception. FV is the price that would be received for the sale of an asset or paid to
transfer a liability in an orderly arms-length transaction between market participants at the measurement
date. FV measurements are required to reflect assumptions that market participants would use in pricing
an asset or liability based on the best available information, including the risks inherent in a particular
valuation technique, such as a pricing model, and the risks inherent in the inputs to the model.
Level Determinations and Classifications
The Company uses Level 1, 2, and 3 classifications in the FV hierarchy. The FV measurement of a
financial instrument is included in only one of the three levels and is based on the lowest level input
significant to the derivation of the FV. FV is determined, directly or
indirectly, using inputs that are
observable for the asset or
liability. Only in limited circumstances does the Company enter into
commodity transactions involving non-standard features
where market observable data is not available or
have contract terms that extend beyond five years.
CHANGES IN ACCOUNTING POLICIES AND
PRACTICES
Future Accounting
Pronouncements
The Company considers the applicability and impact of all ASUs issued by the Financial Accounting
Standards Board (“FASB”). The following updates have been issued by the FASB, but as allowed, have
not yet been adopted by Emera. Any ASUs not included below were assessed and determined to be
either not applicable to the Company or to have an insignificant impact on the consolidated financial
statements.
Improvements to Income Tax Disclosures
In December 2023, the FASB issued ASU 2023-09, Income
Taxes (Topic 740): Improvements to Income
Tax Disclosures. The standard enhances the transparency, decision
usefulness and effectiveness of
income tax disclosures by requiring consistent categories and greater disaggregation of
information in the
reconciliation of income taxes computed using the enacted statutory income tax rate to the actual income
tax provision and effective income tax rate, as well as the disaggregation of income taxes paid (refunded)
by jurisdiction. The standard also requires disclosure of income (loss) before provision for income taxes
and income tax expense (recovery) in accordance with U.S. Securities and Exchange Commission
Regulation S-X 210.4-08(h), Rules of General Application – General Notes to Financial Statements:
Income Tax Expense, and the removal of disclosures no longer
considered cost beneficial or relevant.
The guidance will be effective for annual reporting periods beginning after December 15,
2024, and
interim periods within annual reporting periods beginning after December 15, 2025. Early adoption is
permitted. The standard will be applied on a prospective basis, with retrospective application permitted.
The Company is currently evaluating the impact of adoption of the standard on its consolidated financial
statements.
Exhibit 99.2
62
Improvements to Reportable Segment Disclosures
In November 2023, the FASB issued ASU 2023-07, Segment Reporting
(Topic 280), Improvements to
Reportable Segment Disclosures. The
change in the standard improves reportable segment disclosure
requirements, primarily through enhanced disclosures about
significant segment expenses. The changes
improve financial reporting by requiring disclosure of incremental segment information
on an annual and
interim basis for all public entities to enable investors to develop more decision-useful financial analyses.
The guidance will be effective for annual reporting periods beginning after December 15, 2023, and for
interim periods beginning after December 15, 2024. Early adoption is permitted. The standard will be
applied retrospectively. The Company is currently evaluating the impact of adoption of the standard on its
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)
2023
2023
2023
2023
2022
2022
2022
2022
Operating revenues
$
$
$
$
$
$
$
$
Net income (loss) attributable to
common
shareholders
$
$
$
$
$
$
$
$
Adjusted net income
$
$
$
$
$
$
$
$
EPS – basic
$
1.04
$
$
$
$
$
$
$
EPS – diluted
$
1.04
$
$
$
$
$
$
$
Adjusted EPS – basic
$
0.63
$
$
$
$
$
$
$
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.