2023
Annual Report
2023
Financial
Highlights
Data is as of December 31, 2023,
unless otherwise indicated.
10%
annualized 10-year
total shareholder return
$2.96
annual adjusted EPS1
64%
of adjusted net income2,
excluding Corporate costs,
comes from Florida
$2.9B
invested in 2023, leading
to a 10.2% annual increase
in rate base
4%
dividend increase
in 2023
1 Adjusted earnings per share (“EPS”) is a non-GAAP
ratio, which does not have standardized meaning
under USGAAP. For more information, refer to
“Non-GAAP Financial Measures and Ratios” in
Emera’s Q4 2023 MD&A.
2 Based on 2023 adjusted net income attributable
to common shareholders (“adjusted net income”),
excluding Corporate costs of $356 million and
including holding company interest costs. Adjusted
net income is a non-GAAP measure, which does not
have standardized meaning under USGAAP. For more
information and a reconciliation to the nearest GAAP
measure, refer to “Non-GAAP Financial Measures and
Ratios” in Emera’s Q4 2023 MD&A.
2023 ADJUSTED NET INCOME2Excluding Corporate costsBY BUSINESS SEGMENT 54% Florida electric 21% Canadian electric 18% Gas utilities and infrastructure 4% Other 3% Other electricBY REVENUE TYPE 78% Regulated electric 18% Regulated gas 4% Unregulated Why Invest
in Emera
With our proven strategy and portfolio of high-quality,
regulated utilities, Emera is well positioned to continue
delivering cleaner, more reliable energy for our customers
while also providing our shareholders with long-term growth
in earnings, cash flow and dividends.
VISIBLE GROWTH
PLAN
$9B
capital investment
plan1 through 2026,
with $5.4B+ committed
to decarbonization
and reliability
75%
of CapEx plan
through 2026 is
focused in Florida —
the fastest-growing
US state
7% to 8%
annualized, forecasted
rate-base growth
through 2026
STRONG RECORD OF
DIVIDEND GROWTH
5.4%
annualized dividend growth
since 2000
17 years
of consecutive dividend growth
5.7%
dividend yield2
EFFECTIVE AND
COLLABORATIVE
REGULATORY
ENVIRONMENTS
Highly rated
regulatory environments
96%
of adjusted net income3,
excluding Corporate
costs, derived from our
regulated utilities
STRONG, SUSTAINABLE STRATEGY
47%
18%
reduction in CO2
emissions4, and 77%
reduction in coal
use5, since 2005
of Board Director
Nominees for 2024
identify as members of
a diverse group, other
than gender6
$12M
invested in
our communities
in 2023
0.25 Lost Time
Injury Rate
down 11% from 2022 (0.28) and a 24%
improvement over 5-year average (0.33)
1 Emera’s capital investment plan includes $240 million equity investment in 2024.
2 Based on December 29, 2023, share price of $50.30.
3 Based on 2023 adjusted net income, excluding Corporate costs of $356 million and including holding company interest costs. Adjusted net income
is a non-GAAP measure, which does not have a standardized meaning under USGAAP. For more information and a reconciliation to the nearest
GAAP measure, refer to “Non-GAAP Financial Measures and Ratios” in Emera’s Q4 2023 MD&A.
4 Undergoing final review and verification
5 As a percentage of total GWh generated compared to 2005 levels. Just 13 per cent of energy generated across Emera comes from coal.
6 One Director Nominee identifies as a racialized person and one Director Nominee identifies as a member of the LGBTQ2SI+ community.
1
EMERA 2023 ANNUAL REPORT Emera at
a Glance
Data is as of December 31, 2023,
unless otherwise indicated.
From our origins as a single electric utility, Emera
has grown into an energy leader serving customers
in Canada, the US and the Caribbean. Our companies
include electric and natural gas utilities, gas pipelines,
and energy marketing and trading operations.
1 Based on 2023 adjusted net income, excluding Corporate costs of $356 million and including holding company interest costs. Adjusted net
income is a non-GAAP measure, which does not have a standardized meaning under USGAAP. For more information and a reconciliation to
the nearest GAAP measure, refer to “Non-GAAP Financial Measures and Ratios” in Emera’s Q4 2023 MD&A.
2
HIGHLIGHTS $39Btotal assets$7.6B revenue7,300employees2.5Mcustomers6electric and natural gas utilitiesADJUSTED NET INCOME1Excluding Corporate costsBY GEOGRAPHY 64% Florida 28% Canada 5% New Mexico 3% CaribbeanEMERA 2023 ANNUAL REPORT OUR PURPOSE
Energizing modern life and delivering a cleaner energy
future for all.
OUR VISION
To be the energy provider of choice for our customers, the
employer of choice for our people and a preferred choice
for investors.
OUR VALUES
Our core values shape our culture and guide our work
every day.
• We put safety above all else.
• We put customers at the centre of everything we do.
• We value candour, respect and collaboration.
• We care for each other, the environment and
our communities.
• We set a high bar and take on big things.
OUR
STRATEGY
We’re focused on
safely delivering
cleaner, reliable
energy at a pace
that’s balanced
with the cost
impacts for
our customers.
OUR CLIMATE COMMITMENT
The team across Emera is working together to meet our Climate Commitment goals1 and our vision to achieve
net-zero CO2 emissions by 2050.
2023 PROGRESS
2025 GOAL
2040 GOAL
2050 VISION
47% reduction in
CO2 emissions and 77%
reduction in coal use2
55% reduction
in CO2 emissions
80% reduction in CO2
emissions and last coal unit
retired no later than 2040
Net-Zero
CO2 emissions
1 Our Climate Commitment goals are compared to 2005 levels. Achieving our climate goals on these timelines is subject to external factors
beyond our control, including government policies and regulatory decisions.
2 Still undergoing review and verification. Reduction in coal use is a percentage of total GWh generated compared to 2005 levels.
3
EMERA 2023 ANNUAL REPORT Letter from
the Chair
and the CEO
Fellow shareholders,
We are in an unprecedented time of change and of
opportunity. The energy industry worldwide continues to
grapple with the complexities of transitioning to cleaner
energy while also meeting increasing energy demands. These
new realities are amplified by the added pressures of global
economic factors such as higher interest rates, increasingly
unpredictable weather events and the need to balance the
impacts on costs for customers.
Despite these challenges, we continue to advance our strategy
of safely delivering cleaner, reliable energy in a way that
balances the impacts on costs for customers — and we are
making meaningful progress. We are investing in renewable
and cleaner generation, reliability and system integrity,
infrastructure modernization and expansion, and in new and
emerging technologies.
Our work to deliver for our customers across Emera is
also driving continued value for our shareholders in the
form of sustainable growth in dividends and returns over
the long term.
Jackie Sheppard
Chair, Emera Inc.
Board of Directors
Scott Balfour
President and
CEO, Emera Inc.
4
EMERA 2023 ANNUAL REPORT “ The Emera Team’s belief in our
shared strategy and common values
drives our business forward.”
THE CLEAN ENERGY TRANSITION
There are significant and competing pressures that must
be addressed and carefully balanced in order to deliver a
successful energy transition. A clean energy future must
be achieved in a way that’s balanced with affordability for
customers and without sacrificing reliability — all within a
system that was built at a time of lower energy demand and
with different goals in mind.
As energy policy and objectives continue to evolve, the demand
for cleaner, reliable energy increases and the challenges to
customer affordability intensify. Each of these critical forces
directly impacts the other — affordability is challenged by the
need to invest in cleaner energy and reliability. While renewable
energy is becoming increasingly cost-effective, our systems
were not built to support their intermittency, which means
we must invest in backup energy and in grid modernization
to support reliability. And all of this requires increased capital
investment in an environment where the cost of capital is much
higher, inevitably impacting affordability.
In some cases, government policy is enabling the energy
transition, with programs such as the Inflation Reduction Act
in the US and recent federal incentives in Canada, including
Investment Tax Credits, grants and loans. Current policy
objectives, such as the need to achieve 80 per cent renewable
energy and close coal plants in Nova Scotia by 2030, are being
augmented with anticipated future policies, including the
Environmental Protection Agency Guidelines in the US and
Clean Energy Regulations in Canada. As we navigate long-
term capital investment decisions under these evolving policy
constructs, we are working with governments and regulators
to add our voice to these important discussions to help inform
policy with the goal of developing the most effective and cost-
efficient path forward for customers.
2023 HIGHLIGHTS
We are continuing to make progress on this complex energy
transition, thanks to the dedicated and highly skilled members
of our team across Emera. Their belief in our shared strategy
and common values drives our business forward. Last year, we
reinforced this commitment by refreshing our company-wide
purpose, vision and values — an articulation of why and how we
do what we do — fortifying our commitment to delivering for
our customers every day. We are working together to energize
modern life and deliver a cleaner energy future for all. We
strive to be the energy provider of choice for customers, the
employer of choice for our people and a preferred choice for
investors. We do all this by putting the needs of our customers
at the centre of everything we do. We collaborate and care for
each other, the environment and our communities — and we’re
not afraid to tackle big challenges, including those that arise
as we navigate the complexities of the clean energy transition.
Above all, we value the safety of our teams and communities.
5
EMERA 2023 ANNUAL REPORT “ We are continuing to make progress
on this complex energy transition, thanks
to the dedicated and highly skilled
members of our team across Emera.”
Despite the economic headwinds faced in 2023, we safely
executed on a nearly $3 billion capital program — the largest
annual capital program in our history — with a focus on
decarbonization and reliability. This investment is driving
our progress toward realizing our vision to achieve net-zero
CO2 emissions by 2050. As of 2023, we have reduced CO2
emissions by 47 per cent compared to 2005 levels. Some of
our accomplishments across Emera in 2023 include:
• Tampa Electric brought four new solar projects into service
in 2023, bringing total solar capacity to 1,255 MW — enough
to power more than 200,000 homes. Solar energy has
saved Tampa Electric customers approximately $200 million
in fuel costs over the last five years.
• Tampa Electric reported its best year for reliability, setting
all-time records in four of its five main reliability metrics,
including a 56 per cent reduction in the average duration of
customer outages since 2018.
• Despite the impacts of one hurricane, record low
temperatures, wildfires, historic flooding and unprecedented
daily lightning strikes, NS Power still improved reliability
for customers in 2023. In addition to reducing the average
frequency of outages over the last five years, the team also
achieved a 36 per cent reduction in the duration1 of outages
over the five-year average.
• The Maritime Link performed well, delivering almost
160 per cent of the contracted energy in 2023, accounting
for nearly 20 per cent of NS Power’s energy requirements.
The Maritime Link achieved 99.9 per cent availability for
2023, putting it in the top 10 per cent of high-voltage direct
current links globally.
• At Peoples Gas, the New River, Brightmark and Alliance
renewable natural gas (RNG) projects were completed in
2023. These are now online and providing a clean, cost-
effective source of energy, while also capturing methane
that would otherwise be emitted into the atmosphere.
• New Mexico Gas was recognized by the American Gas
Association for best practices on leak management. Its
Advanced Mobile Leak Detection technology uses lasers
that detect and analyze methane gas emissions. It uses
special software to calculate wind speeds and determine the
precise location of emissions sources, allowing the team to
detect and address leaks more efficiently, reducing the risk
of a safety incident.
1 Customer Average Interruption Duration Index (CAIDI), including the impacts of major weather events
6
EMERA 2023 ANNUAL REPORT • The Barbados Light & Power team achieved record
reliability in 2023 with a 10 per cent improvement in intensity
(a measure that considers the product of the average
interruption duration and frequency rates) compared to
2022 — which was their previous best-performing year. At
Grand Bahama Power, the team signed three Independent
Power Purchase Agreements to add 14.5 MW of solar
to its mix in 2024, while also continuing to advance the
development of 5MW of additional solar to be added to its
generation fleet in 2025.
• New rates came into effect in two of our utilities in January
2023. At Peoples Gas, the increase is helping us continue
to deliver safe, reliable natural gas service to an expanding
customer base. At NS Power, the new rate is helping us meet
the growing demand for electricity, strengthen reliability
and protect our systems against increasingly severe
weather as we work to meet government targets for moving
off of coal generation.
As we continue working to meet our climate objectives, more
than 60 per cent of our $9 billion capital plan through 2026
will be invested in cleaner energy and reliability initiatives
across the business.
SAFETY
The safety of our teams, customers and communities always
comes first. We work to continually improve as we strive for
an Emera that’s predictably safe and where team members
are empowered to speak up for safety and know they should
only perform a task if they’re certain it can be done safely.
And 2023 was no exception as we continued to improve on our
overall safety performance in the past year.
Our lost time injury rate improved by 24 per cent compared to
our average over the last five years, achieving our best-ever
level of safety performance.
Our strong safety culture is underpinned by effective safety
leadership and robust safety programs. In 2023, we placed
even greater focus on reinforcing leadership safety by setting
a goal for 75 per cent of the corporate senior management
team to complete at least one safety engagement every
six months. We were pleased to surpass this goal, achieving
86 per cent.
While we are proud of our achievements in 2023, we know
our work to keep each other safe each and every day is
never complete.
7
EMERA 2023 ANNUAL REPORT FINANCIAL RESULTS
For 2023, we reported annual adjusted earnings1 of
$809 million and adjusted earnings per share (EPS)1 of $2.96.
Adjusted EPS in 2023 was down approximately two per cent
from 2022, which was a record earnings year for Emera when
you adjust for the $45 million after-tax earnings impact of a
litigation settlement received in Q4 2022.
This decrease was primarily due to the impacts of higher
interest rates and unfavourable weather conditions in Florida.
While our annual results for 2023 were down year-over-year,
we continue to build long-term value for our shareholders.
We raised our dividend by four per cent in 2023, continuing
our more than 17-year history of growing our dividend. And
we’ve delivered annualized dividend growth of 5.4 per cent
since 2000.
Across the energy industry, 2023 was not a good year for
North American utility stock total returns. In Canada, the
TSX Capped Utilities Index underperformed by 11.6 per cent
compared to the broader TSX Index. In the US, the utilities
index delivered its worst performance in 50 years compared to
the S&P 500.
Emera’s Total Shareholder Return (TSR) for 2023 was
2.5 per cent, which outperformed both the Canadian and US
utility indices. Over the longer term, we delivered 10 per cent
annualized TSR over the last 10 years.
With demand for clean, reliable energy on the rise, the
drivers for growth remain strong, evidenced by our
forecasted 7-8 per cent rate-base growth CAGR over the
next three years, as we invest to meet the demands of our
customers. We are confident that as we make these customer-
focused investments, and as we work to continue to improve
our balance sheet, we will also deliver long-term value for
Emera’s shareholders.
BOARD CHANGES
We would like to acknowledge long-time Director Andrea
Rosen who is stepping down from the Emera Board this year.
Since joining the Board in 2007, her leadership experience,
financial acumen and experience and knowledge of investment
and commercial banking have been of great benefit to Emera.
We thank Andrea for her many contributions and wish her
continued success.
We are pleased to welcome Brian Porter to the Board. Brian is
the former President and Chief Executive Officer of the Bank
of Nova Scotia (Scotiabank). His extensive expertise in capital
markets and corporate strategy, as well as his experience
in driving growth and leading a public company, will bring
significant value. Welcome, Brian.
THANK YOU
At Emera, we believe good strategy starts with a strong team
and effective execution — and that we all work better because
our strategy and teams are grounded in shared purpose and
values. Our people are the driving force behind our shared
achievements and are essential to our success.
To the Board of Directors and the entire Emera team, thank
you for your ongoing focus on delivering strong results for our
customers, communities and shareholders.
To our valued shareholders, thank you for your ongoing
confidence in Emera.
Jackie Sheppard
Chair, Emera Inc.
Board of Directors
Scott Balfour
President and Chief
Executive Officer, Emera Inc.
1 Adjusted net income and adjusted EPS are non-GAAP measures, which do not have standardized meaning under USGAAP. For more information
and a reconciliation to the nearest GAAP measure, refer to “Non-GAAP Financial Measures and Ratios” in Emera’s Q4 2023 MD&A.
8
EMERA 2023 ANNUAL REPORT Financial Review
Forward-looking Information ............................ 11
Liquidity and Capital Resources ....................... 37
Introduction and Strategic Overview .............. 11
Consolidated Cash Flow Highlights .............. 38
Non-GAAP Financial Measures and Ratios .... 13
Working Capital ................................................ 39
Consolidated Financial Review ......................... 15
Contractual Obligations .................................. 39
Significant Items Affecting Earnings ........... 15
Consolidated Financial Highlights ................ 15
Forecasted Consolidated
Capital Expenditures ....................................... 40
Consolidated Income Statement
Highlights ........................................................... 17
Debt Management ........................................... 40
Credit Ratings ................................................... 42
Business Overview and Outlook ....................... 19
Guaranteed Debt .............................................. 42
Florida Electric Utility ..................................... 19
Outstanding Stock Data .................................. 43
Canadian Electric Utilities .............................. 20
Pension Funding ................................................... 44
Gas Utilities and Infrastructure .................... 24
Off-Balance Sheet Arrangements .................... 44
Other Electric Utilities .................................... 25
Dividend Payout Ratio ........................................ 45
Other ................................................................... 26
Transactions with Related Parties ................... 45
Consolidated Balance Sheet Highlights .......... 27
Enterprise Risk and Risk Management ........... 46
Other Developments ........................................... 28
Financial Highlights ............................................. 28
Florida Electric Utility ..................................... 28
Canadian Electric Utilities .............................. 29
Gas Utilities and Infrastructure .................... 32
Other Electric Utilities ................................... 34
Other ................................................................... 35
Risk Management including Financial
Instruments ........................................................... 57
Disclosure and Internal Controls ...................... 59
Critical Accounting Estimates ........................... 59
Changes in Accounting Policies
and Practices ....................................................... 63
Future Accounting Pronouncements ........... 63
Summary of Quarterly Results ......................... 64
Management Report ........................................... 65
Independent Auditor’s Report .......................... 66
Report of Independent Registered
Public Accounting Firm ...................................... 70
Consolidated Financial Statements ................. 73
Notes to the Consolidated
Financial Statements ......................................... 79
Emera Leadership and Board .......................... 139
Shareholder Information.................................. 140
9
EMERA 2023 ANNUAL REPORT
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 )
Nova Scotia Power Inc. (“NSPI”)
Peoples Gas System, Inc. (“PGS”) (1 )
New Mexico Gas Company, Inc. (“NMGC”)
SeaCoast Gas Transmission, LLC (“SeaCoast”)
Emera Brunswick Pipeline Company Limited
(“Brunswick Pipeline”)
Florida Public Service Commission (“FPSC”) and the
Federal Energy Regulatory Commission (“FERC”)
Nova Scotia Utility and Review Board (“UARB”)
FPSC
New Mexico Public Regulation Commission (“NMPRC”)
FPSC
Canadian Energy Regulator (“CER”)
Barbados Light & Power Company Limited (“BLPC”)
Grand Bahama Power Company Limited (“GBPC”)
Fair Trading Commission, Barbados (“FTC”)
The Grand Bahama Port Authority (“GBPA”)
Equity Investments
NSP Maritime Link Inc. (“NSPML”)
Labrador Island Link Limited Partnership (“LIL”)
Maritimes & Northeast Pipeline Limited Partnership and
Maritimes & Northeast Pipeline, LLC (“M&NP”)
St. Lucia Electricity Services Limited (“Lucelec”)
UARB
Newfoundland and Labrador Board of Commissioners of
Public Utilities
CER and FERC
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.
10
EMERA 2023 ANNUAL REPORT 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.
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.
11
Management’s Discussion & AnalysisEMERA 2023 ANNUAL REPORT 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.
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:
• investing in cleaner and renewable sources of energy, in the related transmission assets, and in energy storage needed to
support intermittent renewables;
• supporting increasing demand from customers and the ongoing electrification of other sectors;
• improving system reliability and resiliency, including replacing aging infrastructure and expanding systems to service new
customers; and
• investing in new internal and customer-facing technologies for improved cost efficiency and better 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:
• A 55 per cent reduction in carbon dioxide emissions by 2025.
• The retirement of Emera’s last existing coal unit no later than 2040.
• An 80 per cent reduction in carbon dioxide emissions by 2040.
Achieving the above climate goals on these timelines is subject to the Company’s regulatory obligations and other external
factors beyond Emera’s control.
Emera seeks to deliver on its Climate Commitment while maintaining its focus on investing in reliability and staying focused on the
cost impacts for customers. Emera is also committed to identifying emerging technologies and continuing to work constructively
with policymakers, regulators, partners, investors and customers to achieve these goals and realize its net-zero vision.
Emera is committed to world-class safety, operational excellence, good governance, excellent customer service, reliability, being
an employer of choice, and building constructive relationships.
12
Management’s Discussion & AnalysisEMERA 2023 ANNUAL REPORT 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:
• held-for-trading (“HFT”) commodity derivative instruments, including adjustments related to the price differential between
the point where natural gas is sourced and where it is delivered, and the related amortization of transportation capacity
recognized as a result of certain Emera Energy marketing and trading transactions;
• the business activities of Bear Swamp Power Company LLC (“Bear Swamp”) included in Emera’s equity income;
• equity securities held in BLPC and Emera Energy; and
• FX hedges entered into to hedge USD denominated operating unit earnings exposure.
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.
13
Management’s Discussion & AnalysisEMERA 2023 ANNUAL REPORT The following reconciles net income attributable to common shareholders to adjusted net income:
For the
millions of dollars (except per share amounts)
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
Three months ended
December 31
2022
2023
$
$
289
114
–
–
$
483
307
(73)
–
$
$
175
1.04
$
$
249
1.80
$ 0.63
$ 0.93
$
$
$
Year ended
December 31
2021
2022
$
$
$
$
$
945
175
(73)
(7)
850
3.56
3.20
$
$
$
510
(213)
–
–
723
1.98
2.81
2023
978
169
–
–
809
3.57
2.96
(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:
For the
millions of dollars
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
Three months ended
December 31
2022
2023
2023
2022
$
307
241
51
264
$ 863
158
–
–
705
$
$
499
206
154
254
$ 1,113
431
$ 1,009
709
185
952
$ 2,855
248
$ 1,045
925
128
1,049
$ 3,147
237
–
–
$
$ 2,910
$ 2,687
(73)
–
755
Year ended
December 31
2021
$
561
611
(6)
902
$ 2,068
(73)
(7)
(299)
–
–
$ 2,367
(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.
14
Management’s Discussion & AnalysisEMERA 2023 ANNUAL REPORT
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
millions of dollars
Adjusted net income
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
Three months ended
December 31
Year ended
December 31
2023
2022
2023
2022
2021
$
$ 115
68
59
4
(71)
$
124
46
72
8
(1)
$ 627
247
214
35
(314)
596
222
221
29
(218)
$ 462
241
198
20
(198)
$ 809
$ 850
$ 723
$
175
114
–
$ 289
$
249
307
(73)
–
$ 483
$
–
169
–
–
978
$
175
(73)
7
945
$
(213)
–
–
510
15
Management’s Discussion & AnalysisEMERA 2023 ANNUAL REPORT
The following table highlights the significant changes in adjusted net income from 2022 to 2023:
For the
millions of dollars
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
Three months ended
December 31
Year ended
December 31
$
249
$
850
17
4
(9)
10
10
31
Decreased earnings quarter-over-quarter at NMGC primarily due to lower asset optimization
(11)
12
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
(21)
13
(9)
(10)
(45)
(3)
175
$
For further details of reportable segments contributions, refer to the “Financial Highlights” section.
(22)
10
(51)
2
(45)
2
809
$
Year ended
December 31
For the
millions of dollars
Operating cash flow before changes in working capital
Change in working capital
Operating cash flow
Investing cash flow
Financing cash flow
2023
2022
2021
$ 2,336
$ 1,147
$ 1,337
(95)
(152)
$ 1,185
$ 2,241
$ (2,917) $ (2,569) $ (2,332)
(234)
913
$
$ 939
$ 1,555
$ 1,311
For further discussion of cash flow, refer to the “Consolidated Cash Flow Highlights” section.
As at
millions of dollars
Total assets
Total long-term debt (including current portion)
2023
2022
2021
December 31
$ 39,480
$ 39,742
$ 34,244
$ 18,365
$ 16,318
$ 14,658
16
Management’s Discussion & AnalysisEMERA 2023 ANNUAL REPORT
CONSOLIDATED INCOME STATEMENT HIGHLIGHTS
For the
millions of dollars
(except per share amounts)
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
EPS – diluted
Adjusted EPS – basic
Adjusted EBITDA
Dividends per common share
declared
Dividends per first preferred shares
Three months ended
December 31
2022
2023
$ 1,972
1,467
505
$
$
51
$ 241
$ 2,358
1,638
$ 720
$
102
$ 206
$ 289
175
$
$
$
483
249
$
$
$
$
$
$
Variance
2023
(386) $ 7,563
5,769
171
(215) $ 1,794
(51) $ 158
(35) $ 925
Year ended
December 31
2022
$ 7,588
5,959
$ 1,629
$
145
$ 709
(194) $ 978
(74) $ 809
$ 945
$ 850
Year ended
December 31
2021
Variance
(25) $ 5,765
4,835
190
$ 930
165
13
93
$
(216) $ 611
33
$ 510
(41) $ 723
$
$
$
$
$
$
277.7
$ 1.04
$ 1.04
$ 0.63
$ 705
269.0
$ 1.80
$ 1.80
$ 0.93
755
$
8.7
273.6
$ (0.76) $ 3.57
$ (0.76) $ 3.57
$ (0.30) $ 2.96
(50) $ 2,910
$
265.5
$ 3.56
$ 3.55
$ 3.20
$ 2,687
8.1
0.01
0.02
257.2
$ 1.98
$
$
$ 1.98
$ (0.24) $ 2.81
$ 2,367
$ 223
$ 0.7175
$ 0.6900
$ 0.0275
$ 2.7875
$ 2.6775
$ 0.1100
$ 2.5750
declared:
Series A
Series B
Series C
Series E
Series F
Series H
Series J
Series L
$ 0.5456
$ 1.5583
$ 1.2873
$ 1.1250
$ 1.0505
$ 1.3140
$ 1.0625
$ 1.1500
$ 0.5456
$ 0.6869
$ 1.1802
$ 1.1250
$ 1.0505
$ 1.2250
$ 1.0625
$ 1.1500
– $ 0.5456
$
$ 0.4873
$ 0.8714
$ 1.1802
$ 0.1071
– $ 1.1250
$
$
– $ 1.0505
$ 0.0890 $ 1.2250
– $ 0.6470
$
– $ 0.1638
$
(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.
17
Management’s Discussion & AnalysisEMERA 2023 ANNUAL REPORT 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.
18
Management’s Discussion & AnalysisEMERA 2023 ANNUAL REPORT 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:
Weighted average CAD/USD
Period end CAD/USD exchange rate
Three months ended
December 31
2022
2023
$
$
1.36
1.32
$
$
1.37
1.35
$
$
Year ended
December 31
2022
$
$
1.34
1.35
2023
1.35
1.32
The table below includes Emera’s significant segments whose contributions to adjusted net income are recorded in USD currency:
For the
millions of USD
Florida Electric Utility
Gas Utilities and Infrastructure (1 )
Other Electric Utilities
Other segment (2)
Total (3)
Three months ended
December 31
2022
2023
$
$
85
41
3
(18)
111
$
$
91
45
7
30
173
$
$
Year ended
December 31
2022
$
$
458
143
23
(50)
574
2023
466
142
26
(95)
539
Includes USD net income from PGS, NMGC, SeaCoast and M&NP.
(1)
(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.
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.
19
Management’s Discussion & AnalysisEMERA 2023 ANNUAL REPORT 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.
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.
20
Management’s Discussion & AnalysisEMERA 2023 ANNUAL REPORT 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.
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.
21
Management’s Discussion & AnalysisEMERA 2023 ANNUAL REPORT 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.
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.
22
Management’s Discussion & AnalysisEMERA 2023 ANNUAL REPORT 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.
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.
23
Management’s Discussion & AnalysisEMERA 2023 ANNUAL REPORT 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.
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.
24
Management’s Discussion & AnalysisEMERA 2023 ANNUAL REPORT 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.
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.
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.
25
Management’s Discussion & AnalysisEMERA 2023 ANNUAL REPORT 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.
26
Management’s Discussion & AnalysisEMERA 2023 ANNUAL REPORT Consolidated Balance Sheet Highlights
Significant changes in the Consolidated Balance Sheets between December 31, 2022 and December 31, 2023 include:
millions of dollars
Assets
Cash and cash equivalents
Increase
(Decrease)
Explanation
$
257 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
(156) Decreased due to settlements of derivative instruments and decreased pricing
and long-term)
on power derivative instruments at NSPI, partially offset by reversal of 2022
contracts at EES
Regulatory assets (current and
(515) Decreased due to higher fuel clause and storm cost recoveries at TEC, and
long-term)
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
(1,079) Decreased due to lower gas transportation assets, decreased cash collateral
(current and long-term)
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
1,380 Increased due to capital additions in excess of depreciation and amortization,
depreciation and amortization
partially offset by the effect of FX translation of Emera's non-Canadian affiliates
Goodwill
(141) 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)
$
754 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
(571) Decreased due to lower commodity prices at EES, NMGC and TEC, decreased
Deferred income tax liabilities, net
of deferred income tax assets
cash collateral position on derivative instruments and lower fuel related
payables at NSPI
185 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
(574) Decreased due to changes in existing positions and reversal of 2022 contracts,
and long-term)
partially offset by new contracts in 2023 at EES
Regulatory liabilities (current and
(501) Decreased due to lower deferrals related to derivative instruments at NSPI and
long-term)
settlement of NMGC gas hedges
Other liabilities (current and
(157) Decreased due to reversal of accrued Cap-and-Trade emissions compliance
long-term)
Common stock
Accumulated other comprehensive
income
Retained earnings
charges at NSPI
700 Increased due to shares issued
(273) Decreased due to the effect of the FX translation of non-Canadian affiliates
219 Increased due to net income in excess of dividends paid
27
Management’s Discussion & AnalysisEMERA 2023 ANNUAL REPORT
Other Developments
Increase in Common Dividends
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
For the
millions of USD (except as indicated)
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
Three months ended
December 31
2022
597
201
91
124
41
$
$
$
$
$
2023
$
613
$ 162
$
85
$ 115
34
$
Year ended
December 31
2022
$ 2,523
$ 832
$ 458
596
$
39
$
2023
$ 2,637
$ 682
$ 466
$ 627
31
$
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
millions of USD
Three months ended
December 31
Year ended
December 31
Contribution to consolidated net income – 2022
Increased operating revenues due to storm cost recovery surcharge revenue (offset in OM&G),
$
91
16
$
458
114
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
39
(25)
150
(136)
(offset in revenue) and timing of deferred clause recoveries
Increased depreciation and amortization due to additions to facilities and generation projects
(8)
(33)
placed in service
Increased interest expense due to higher interest rates and higher borrowings to support capital
(7)
(59)
investments and ongoing operations
Increased state, and municipal taxes due to higher retail sales and higher taxable property
(8)
(33)
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
(6)
(7)
85
$
7
(2)
$ 466
28
Management’s Discussion & AnalysisEMERA 2023 ANNUAL REPORT Operating Revenues – Regulated Electric
Annual electric revenues and sales volumes are summarized in the following table by customer class:
Residential
Commercial
Industrial
Other (1)
Total
Electric Revenues
(millions of USD)
2022
2023
Electric Sales Volumes
(Gigawatt hours (“GWh”))
2022
2023
$ 1,711
803
203
(80)
$ 2,637
$ 1,381
666
176
300
$ 2,523
10,307
6,462
2,082
2,194
21,045
10,109
6,300
2,111
2,352
20,872
(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:
Natural gas
Solar
Purchased power
Coal
Total
Production Volumes (GWh)
2022
2023
17,843
1,748
1,443
744
21,778
17,083
1,492
1,685
1,325
21,585
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
For the
millions of dollars (except as indicated)
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)
Three months ended
December 31
2022
2023
2023
$
439
$ 234
$
68
$
$
$
$ 421
173
$
46
$
– $
$
$
68
81
46
61
$ 1,671
$ 777
247
$
– $
– $
$
$
$ 247
70
$
(7)
215
85
Year ended
December 31
2022
$ 1,675
$ 950
$ 222
(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).
29
Management’s Discussion & AnalysisEMERA 2023 ANNUAL REPORT Canadian Electric Utilities’ contribution to consolidated adjusted net income is summarized in the following table:
For the
millions of dollars
NSPI
Equity investment in LIL
Equity investment in NSPML (1 )
Contribution to consolidated adjusted net income
Three months ended
December 31
2022
2023
$
$
40
16
12
68
$
$
23
15
8
46
2023
$
141
60
46
$ 247
Year ended
December 31
2022
$
131
55
36
$ 222
(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
millions of dollars
Three months ended
December 31
Year ended
December 31
Contribution to consolidated net income – 2022
Increased operating revenues quarter-over-quarter due to new rates, increased residential,
$
46
18
$ 215
(4)
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
(61)
173
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
74
(69)
(8)
(46)
(3)
(5)
5
(17)
(34)
15
–
2
68
$
7
7
247
$
(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
30
Management’s Discussion & AnalysisEMERA 2023 ANNUAL REPORT NSPI
Operating Revenues – Regulated Electric
Annual electric revenues and sales volumes are summarized in the following tables by customer class:
Residential
Commercial
Industrial
Other
Total
Regulated Fuel for Generation and Purchased Power
Annual production volumes are summarized in the following table:
Electric Revenues
(millions of dollars)
2022
2023
Electric Sales Volumes
(GWh)
2022
2023
$
910
463
219
41
$ 1,633
$ 834
427
353
28
$ 1,642
4,986
3,053
2,164
239
10,442
4,822
3,006
2,480
148
10,456
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
Production Volumes
(GWh)
2022
2023
3,086
1,946
881
553
145
6,611
3,251
1,149
128
4,528
11,139
3,771
1,650
910
897
251
7,479
2,423
1,105
127
3,655
11,134
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.
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.
31
Management’s Discussion & AnalysisEMERA 2023 ANNUAL REPORT GAS UTILITIES AND INFRASTRUCTURE
For the
millions of USD (except as indicated)
Operating revenues – regulated gas (1 )
Operating revenues – non-regulated
Total operating revenue
Regulated cost of natural gas
Contribution to consolidated net income
Contribution to consolidated net income – CAD
Three months ended
December 31
2022
2023
290
3
293
99
43
59
$ 372
2
374
181
53
72
$
$
$
$
$
$
$
$
$
Year ended
December 31
2022
$ 1,296
12
$ 1,308
614
$
170
$
221
$
2023
$ 1,114
15
$ 1,129
$ 391
158
$
214
$
(1) Operating revenues – regulated gas includes $11 million of finance income from Brunswick Pipeline (2022 – $13 million) for the 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:
For the
millions of USD
PGS
NMGC
Other
Contribution to consolidated net income
Three months ended
December 31
2022
2023
$
$
21
14
8
43
$
$
17
22
14
53
2023
$
79
43
36
$ 158
Year ended
December 31
2022
$
$
82
35
53
170
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.
Net Income
Highlights of the net income changes are summarized in the following table:
For the
millions of USD
Three months ended
December 31
Year ended
December 31
Contribution to consolidated net income – 2022
Decreased operating revenues due to lower fuel revenues at PGS and NMGC, and lower off-
$
$
53
(71)
170
(181)
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
(10)
82
(10)
6
2
223
(20)
(3)
Increased interest expense due to higher interest rates and increased borrowings to support
(10)
(33)
ongoing operations and capital investments
Other
Contribution to consolidated net income – 2023
3
43 $
–
158
$
32
Management’s Discussion & AnalysisEMERA 2023 ANNUAL REPORT
Operating Revenues – Regulated Gas
Annual gas revenues and sales volumes are summarized in the following tables by customer class:
Residential
Commercial
Industrial (1)
Other (2)
Total (3)
Gas Revenues
(millions of USD)
2022
2023
$ 537
315
69
147
$ 1,068
$
614
354
64
217
$ 1,249
Gas Volumes
(Therms)
2022
421
836
1,429
227
2,913
2023
414
839
1,615
266
3,134
(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.
Annual gas sales by type are summarized in the following table:
Transportation
System supply
Total
Gas Volumes by Type
(millions of Therms)
2022
2023
2,461
673
3,134
2,206
707
2,913
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.
33
Management’s Discussion & AnalysisEMERA 2023 ANNUAL REPORT
OTHER ELECTRIC UTILITIES
For the
millions of USD (except as indicated)
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
Three months ended
December 31
2022
2023
Year ended
December 31
2022
2023
$ 104
57
$
3
$
4
$
–
$
2
$
5
$
6
$
323
345
$ 165
$
$
$
$
$
$
$
$
$
98
$ 390
54
$ 204
7
26
$
8
$
35
54
$
$
1
(46) $
(62) $
$ 398
$ 223
23
$
29
$
– $
54
$
$
$
(4)
(35)
(48)
2
28
37
1,260
1,362
$ 150
301
325
161
1,239
1,340
166
$
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:
For the
millions of USD
BLPC
GBPC
Other
Contribution to consolidated adjusted net income
Three months ended
December 31
2022
2023
$
$
4
–
(1)
3
$
$
5
1
1
7
$
$
Year ended
December 31
2022
$
$
11
10
2
23
2023
18
11
(3)
26
Net Income
Highlights of the net income changes are summarized in the following table:
For the
millions of USD
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
Three months ended
December 31
Year ended
December 31
$
(46) $
6
(35)
(8)
(3)
19
54
(6)
5
$
54
(2)
28
$
34
Management’s Discussion & AnalysisEMERA 2023 ANNUAL REPORT 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
For the
millions of dollars
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)
$
$
$
$
Three months ended
December 31
2022
2023
Year ended
December 31
2022
2023
$
35
5
40
$
(71) $
72
3
75
112
41
$
304
303
$
$
96
27
$ 123
$
(314) $
167
$ (147) $
143
16
159
(218)
179
(39)
(1) $
(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).
Other’s contribution to consolidated adjusted net income is summarized in the following table:
For the
millions of dollars
Emera Energy
EES
Other
Corporate – see breakdown of adjusted contribution below
Block Energy LLC (1)
Other
Contribution to consolidated adjusted net income (loss)
(1) Previously Emera Technologies LLC
Three months ended
December 31
2022
2023
Year ended
December 31
2022
2023
$
$
$
19
6
(91)
(4)
(1)
(71) $
$
40
1
(37)
(5)
–
(1) $
$
46
18
(356)
(18)
(4)
(314) $
68
2
(267)
(18)
(3)
(218)
35
Management’s Discussion & AnalysisEMERA 2023 ANNUAL REPORT
Net Income
Highlights of the net income changes are summarized in the following table:
For the
millions of dollars
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
Three months ended
December 31
Year ended
December 31
$
$
303
(37)
(39)
(47)
Decreased OM&G, pre-tax, primarily due to the timing of long-term compensation and
12
10
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
(8)
7
(51)
26
(45)
(194)
(45)
(12)
Other
Contribution to consolidated net income (loss) – 2023
3
41
$
11
(147)
$
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.
36
Management’s Discussion & AnalysisEMERA 2023 ANNUAL REPORT 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.
Corporate
Corporate’s adjusted loss is summarized in the following table:
For the
millions of dollars
Operating expenses ( 1)
Interest expense
Income tax recovery
Preferred dividends
TGH award, after tax and legal costs
Other (2) (3)
Corporate adjusted net loss (4)
Three months ended
December 31
2022
2023
$
$
$
7
88
(25)
18
–
3
(91) $
$
20
79
(35)
16
(45)
2
(37) $
2023
73
329
(111)
66
–
(1)
Year ended
December 31
2022
$
83
278
(109)
63
(45)
(3)
(267)
(356) $
(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.
37
Management’s Discussion & AnalysisEMERA 2023 ANNUAL REPORT 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.
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
Cash, cash equivalents and restricted cash, beginning of period
Provided by (used in):
Operating cash flow before changes in working capital
Change in working capital
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
2023
2022
$ Change
$ 332
$
417
$
(85)
2,336
(95)
$ 2,241
(2,917)
939
(7)
$ 588
$
1,147
(234)
913
(2,569)
1,555
16
$ 332
1,189
139
$ 1,328
(348)
(616)
(23)
256
$
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:
• $1,771 million – Florida Electric Utility (2022 – $1,481 million);
• $461 million – Canadian Electric Utilities (2022 – $518 million);
• $673 million – Gas Utilities and Infrastructure (2022 – $578 million);
• $63 million – Other Electric Utilities (2022 – $63 million); and
• $8 million – Other (2022 – $6 million).
38
Management’s Discussion & AnalysisEMERA 2023 ANNUAL REPORT 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
Asset retirement obligations
Pension and post-retirement
obligations (4)
$ 1,670
836
696
274
556
778
10
28
$ 264
807
495
249
215
111
2
29
$ 3,047
719
405
263
62
70
1
38
Equity investment commitments (5)
Other
240
154
–
147
–
56
$
$ 666
626
388
312
–
1
1
47
–
46
525
587
338
312
5
–
2
32
–
35
$ 12,318
7,438
2,597
3,435
–
–
407
155
–
221
$ 18,490
11,013
4,919
4,845
838
960
423
329
240
659
$ 5,242
$ 2,319
$ 4,661
$ 2,087
$ 1,836
$ 26,571
$ 42,716
(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.
39
Management’s Discussion & AnalysisEMERA 2023 ANNUAL REPORT 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 EXPENDITURES
The 2024 forecasted consolidated capital investments are as follows:
millions of dollars
Generation
New renewable generation
Electric transmission
Electric distribution
Gas transmission and distribution
Facilities, equipment, vehicles, and other
Florida
Electric Utility
$ 266
280
119
496
–
–
88
142
–
567
$ 1,728
63
$ 436
$
Canadian
Electric
Utilities
Gas
Utilities and
Infrastructure
Other Electric
Utilities
$
143
$
- $
30
$
Other
Total
- $
–
–
–
566
51
617
$
–
–
58
–
17
105
$
–
–
–
–
4
4
439
280
207
696
566
702
$ 2,890
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.
millions of Canadian dollars (unless otherwise indicated)
Emera – Unsecured committed revolving credit facility
TEC (in USD) – Unsecured committed revolving credit facility
NSPI – Unsecured committed revolving credit facility
Emera – Unsecured non-revolving facility
Emera – Unsecured non-revolving facility
Emera – Unsecured non-revolving facility
TECO Finance (in USD) – Unsecured committed revolving credit
facility
NSPI – Unsecured non-revolving facility
PGS (in USD) – Unsecured revolving facility
TEC (in USD) – Unsecured revolving facility
TEC (in USD) – Unsecured revolving facility
NMGC (in USD) – Unsecured revolving credit facility
NMGC (in USD) – Unsecured non-revolving facility
Other (in USD) – Unsecured committed revolving credit facilities
Maturity
June 2027
December 2026
December 2027
December 2024
February 2024
August 2024
December 2026
July 2024
December 2028
February 2024
April 2024
December 2026
March 2024
Various
$
Credit
Facilities
$ 900
800
800
400
400
400
400
400
250
200
200
125
23
21
$
Undrawn
and
Available
635
93
468
–
200
–
215
–
195
200
200
104
–
15
Utilized
265
707
332
400
200
400
185
400
55
–
–
21
23
6
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:
Emera
Syndicated credit facilities
Debt to capital ratio
Less than or equal to 0.70 to 1
0.57 : 1
Financial Covenant
Requirement
As at
December 31, 2023
40
Management’s Discussion & AnalysisEMERA 2023 ANNUAL REPORT
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.
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.
41
Management’s Discussion & AnalysisEMERA 2023 ANNUAL REPORT 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:
Emera Inc.
TEC
PGS (1)
NMGC
NSPI
Fitch
S&P
Moody’s
DBRS
BBB (Negative)
A (Negative)
A (Negative)
BBB+ (Negative)
N/A
BBB- (Negative)
BBB+ (Negative)
N/A
N/A
BBB- (Negative)
Baa3 (Negative)
A3 (Negative)
N/A
N/A
N/A
N/A
N/A
N/A
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.
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
millions of dollars
Loss from operations
Net gains (losses) (1)
Year ended December 31
2022
2023
$
$
(62) $
$
349
(73)
(131)
(1)
Includes $750 million (2022 – $262 million) in interest and dividend income, net, from non-guarantor subsidiaries.
42
Management’s Discussion & AnalysisEMERA 2023 ANNUAL REPORT Summarized Balance Sheet
The Company has the following categories on the balance sheet related to guaranteed debt:
As at
millions of dollars
Current assets (1)
Goodwill
Other assets (2)
Total assets (3)
Current liabilities (4)
Long-term liabilities (5)
Total liabilities
2023
$ 223
5,871
6,243
$ 12,337
$ 1,451
6,815
$ 8,266
December 31
2022
$
172
6,012
6,402
$ 12,586
$ 1,903
6,431
$ 8,334
(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.
OUTSTANDING STOCK DATA
Common Stock
Issued and outstanding:
Balance, December 31, 2022
Issuance of common stock under ATM program (1 )
Issued under the DRIP, net of discounts
Senior management stock options exercised and Employee Share Purchase Plan
Balance, December 31, 2023
millions of
shares
millions of
dollars
269.95
8.29
5.26
0.62
284.12
$ 7,762
397
272
31
$ 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.
43
Management’s Discussion & AnalysisEMERA 2023 ANNUAL REPORT 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.
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
Assets as at December 31, 2023
Accounting obligation at December 31, 2023
Accounting expense (income) during fiscal 2023
Off-Balance Sheet Arrangements
TECO Energy
NSPI
Caribbean
Total
$ 907
$ 896
4
$
$ 1,381
$ 1,361
$
$
$
(16) $
10
16
1
$ 2,298
$ 2,273
$
(11)
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.
44
Management’s Discussion & AnalysisEMERA 2023 ANNUAL REPORT 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.
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:
• Transactions between NSPI and NSPML related to the Maritime Link assessment are reported in the Consolidated Statements
of Income. NSPI’s expense is reported in Regulated fuel for generation and purchased power, totalling $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.
45
Management’s Discussion & AnalysisEMERA 2023 ANNUAL REPORT 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.
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.
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Management’s Discussion & AnalysisEMERA 2023 ANNUAL REPORT 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.
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.
47
Management’s Discussion & AnalysisEMERA 2023 ANNUAL REPORT 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.
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.
48
Management’s Discussion & AnalysisEMERA 2023 ANNUAL REPORT 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.
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.
49
Management’s Discussion & AnalysisEMERA 2023 ANNUAL REPORT 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.
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.
50
Management’s Discussion & AnalysisEMERA 2023 ANNUAL REPORT 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.
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.
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Management’s Discussion & AnalysisEMERA 2023 ANNUAL REPORT FOREIGN EXCHANGE RISK
The Company is exposed to foreign currency exchange rate changes. Emera operates internationally, with an increasing amount
of the Company’s net income earned outside of Canada. As such, Emera is exposed to movements in exchange rates between the
CAD and, particularly, the USD, which could positively or adversely affect results.
Consistent with the Company’s risk management policies, Emera manages currency risks through matching United States
denominated debt to finance its United States operations and may use foreign currency derivative instruments to hedge specific
transactions and earnings exposure. The Company may enter FX forward and swap contracts to limit exposure on certain foreign
currency transactions such as fuel purchases, revenue streams and capital expenditures, and on net income earned outside of
Canada. The regulatory framework for the Company’s rate-regulated subsidiaries permits the recovery of prudently incurred
costs, including FX.
The Company does not utilize derivative financial instruments for foreign currency trading or speculative purposes or to hedge
the value of its investments in foreign subsidiaries. Exchange gains and losses on net investments in foreign subsidiaries do not
impact net income as they are reported in 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.
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Management’s Discussion & AnalysisEMERA 2023 ANNUAL REPORT 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.
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.
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Management’s Discussion & AnalysisEMERA 2023 ANNUAL REPORT 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.
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.
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Management’s Discussion & AnalysisEMERA 2023 ANNUAL REPORT 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.
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.
55
Management’s Discussion & AnalysisEMERA 2023 ANNUAL REPORT 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.
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.
56
Management’s Discussion & AnalysisEMERA 2023 ANNUAL REPORT 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.
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.
57
Management’s Discussion & AnalysisEMERA 2023 ANNUAL REPORT 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.
DERIVATIVE ASSETS AND LIABILITIES RECOGNIZED ON THE BALANCE SHEET
As at
millions of dollars
Regulatory Deferral:
Derivative instrument assets (1 )
Derivative instrument liabilities (2)
Regulatory assets (1 )
Regulatory liabilities (2)
Net asset
HFT Derivatives:
Derivative instrument assets (1 )
Derivatives instruments liabilities (2)
Net liability
Other Derivatives:
Derivative instrument assets (1 )
Derivatives instruments liabilities (2)
Net asset (liability)
(1) Current and other assets.
(2) Current and long-term liabilities.
December 31
2023
December 31
2022
$
$
16
(76)
88
(17)
11
$ 238
(25)
30
(230)
13
$
$ 202
$ 153
(421)
(219) $
(1,025)
(872)
22
(7)
15
$
$
5
(28)
(23)
$
$
$
REALIZED AND UNREALIZED GAINS (LOSSES) RECOGNIZED IN NET INCOME
For the
millions of dollars
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
Year ended December 31
2022
2023
$
62
$
210
$ 1,037
$
64
$
(9) $
17
$
8
$ 1,107
$
$
(22)
(24)
(46)
228
(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
millions of dollars
Total unrealized gain in AOCI – net of tax
December 31,
2023
Interest rate
hedge
December 31,
2022
Interest rate
hedge
$
14
$
16
58
Management’s Discussion & AnalysisEMERA 2023 ANNUAL REPORT
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.
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).
59
Management’s Discussion & AnalysisEMERA 2023 ANNUAL REPORT PENSION AND OTHER POST-RETIREMENT EMPLOYEE BENEFITS
The Company provides post-retirement benefits to employees, including defined benefit pension plans. The cost of providing
these benefits is dependent upon many factors that result from actual plan experience and assumptions of future expectations.
The accounting related to employee post-retirement benefits is a critical accounting estimate. Changes in the estimated benefit
obligation, affected by employee demographics – including age, compensation levels, employment periods, contribution levels
and earnings – could have a material impact on reported assets, liabilities, accumulated other comprehensive income and results
of operations. Changes in key actuarial assumptions, including anticipated rates of return on plan assets and discount rates used
in determining the accrued benefit obligation and benefit costs, could change annual funding requirements. This could have a
significant impact on the Company’s annual earnings and cash requirements.
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:
TECO Energy Group Retirement Plan
TECO Energy Group Supplemental Executive
Retirement Plan (1)
Discount rate
for benefit
cost purposes
5.55%
5.45%/5.31%
TECO Energy Group Benefit Restoration Plan (1)
TECO Energy Post-retirement Health and
5.48/5.30/5.49%
5.53%/6.14%
Welfare Plan
New Mexico Gas Company Retiree Medical Plan
NSPI
GBPC Salaried
GBPC Union
5.55%
5.17%, 5.19%
5.75%
5.75%
2023
Expected
return on
plan assets
7.05%
N/A
N/A
N/A
2.50%
6.25%
6.00%
5.35%
Discount rate
for benefit
cost purposes
2.78%
2.35/5.33%
2.27/4.19/5.48%
2.84%
2.85%
3.25%, 3.48%
5.75%
5.75%
2022
Expected
return on
plan assets
6.50%
N/A
N/A
N/A
1.50%
5.75%
6.00%
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).
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).
60
Management’s Discussion & AnalysisEMERA 2023 ANNUAL REPORT 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.
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.
61
Management’s Discussion & AnalysisEMERA 2023 ANNUAL REPORT 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.
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.
62
Management’s Discussion & AnalysisEMERA 2023 ANNUAL REPORT 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.
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.
63
Management’s Discussion & AnalysisEMERA 2023 ANNUAL REPORT Management’s Discussion & Analysis
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
(except per share amounts)
Q4
2023
Q3
2023
Q2
2023
Q1
2023
Q4
2022
Q3
2022
Q2
2022
Q1
2022
Operating revenues
Net income (loss) attributable to
$ 1,972
$ 289
$ 1,740
101
$
$ 1,418
28
$
$ 2,433
$ 560
$ 2,358
$ 483
$ 1,835
$ 167
$ 1,380
$
$ 2,015
(67) $ 362
common shareholders
Adjusted net income
EPS – basic
EPS – diluted
Adjusted EPS – basic
$ 175
$ 1.04
$ 1.04
$ 0.63
$ 204
$ 0.37
$ 0.37
$ 0.75
$ 162
$ 0.10
$ 0.10
$ 0.60
$ 268
$ 2.07
$ 2.07
$ 0.99
$ 249
$ 1.80
$ 1.80
$ 0.93
$ 203
$ 0.63
$ 0.63
$ 0.76
$ 156
$ 242
$ (0.25) $ 1.38
$ (0.25) $ 1.38
$ 0.92
$ 0.59
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.
64
EMERA 2023 ANNUAL REPORT Management Report
Management’s Responsibility for Financial Reporting
The accompanying consolidated financial statements of Emera Incorporated and the information in this annual report are the
responsibility of management and have been approved by the Board of Directors (“Board”).
The consolidated financial statements have been prepared by management in accordance with United States Generally
Accepted Accounting Principles. When alternative accounting methods exist, management has chosen those it considers most
appropriate in the circumstances. In preparation of these consolidated financial statements, estimates are sometimes necessary
when transactions affecting the current accounting period cannot be finalized with certainty until future periods. Management
represents that such estimates, which have been properly reflected in the accompanying consolidated financial statements,
are based on careful judgments and are within reasonable limits of materiality. Management has determined such amounts on
a reasonable basis in order to ensure that the consolidated financial statements are presented fairly in all material respects.
Management has prepared the financial information presented elsewhere in the annual report and has ensured that it is
consistent with that in the consolidated financial statements.
Emera Incorporated maintains effective systems of internal accounting and administrative controls, consistent with reasonable
cost. Such systems are designed to provide reasonable assurance that the financial information is reliable and accurate, and that
Emera Incorporated’s assets are appropriately accounted for and adequately safeguarded.
The Board is responsible for ensuring that management fulfils its responsibilities for financial reporting and is ultimately
responsible for reviewing and approving the consolidated financial statements. The Board carries out this responsibility
principally through its Audit Committee.
The Audit Committee is appointed by the Board, and its members are directors who are not officers or employees of Emera
Incorporated. The Audit Committee meets periodically with management, as well as with the internal auditors and with the
external auditors, to discuss internal controls over the financial reporting process, auditing matters and financial reporting issues,
to satisfy itself that each party is properly discharging its responsibilities, and to review the annual report, the consolidated
financial statements and the external auditors’ report. The Audit Committee reports its findings to the Board for consideration
when approving the consolidated financial statements for issuance to the shareholders. The Audit Committee also considers, for
review by the Board and approval by the shareholders, the appointment of the external auditors.
The consolidated financial statements have been audited by Ernst & Young LLP, the external auditors, in accordance with
Canadian Generally Accepted Auditing Standards and with the standards of the Public Company Accounting Oversight Board.
Ernst & Young LLP has full and free access to the Audit Committee.
February 26, 2024
“Scott Balfour”
President and Chief Executive Officer
“Gregory Blunden”
Chief Financial Officer
65
EMERA 2023 ANNUAL REPORT Independent Auditor’s Report
To the Shareholders and the Board of Directors of Emera Incorporated
Opinion
We have audited the consolidated financial statements of Emera Incorporated (the “Company”), which comprise the Consolidated
Balance Sheets as at December 31, 2023 and 2022, and the Consolidated Statements of Income, Consolidated Statements of
Comprehensive Income, Consolidated Statements of Changes in Equity and Consolidated Statements of Cash Flows for the years
then ended, and notes to the consolidated financial statements, including a summary of significant accounting policies.
In our opinion, the accompanying consolidated financial statements present fairly, in all material respects, the consolidated
financial position of the Company as at December 31, 2023 and 2022, and the consolidated results of its operations and its
consolidated cash flows for the years then ended in accordance with United States generally accepted accounting principles
(“USGAAP”).
Basis for opinion
We conducted our audit in accordance with Canadian generally accepted auditing standards. Our responsibilities under those
standards are further described in the Auditor’s responsibilities for the audit of the consolidated financial statements section of
our report. We are independent of the Company in accordance with the ethical requirements that are relevant to our audit of
the consolidated financial statements in Canada, and we have fulfilled our other ethical responsibilities in accordance with these
requirements. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our opinion.
Key audit matters
Key audit matters are those matters that, in our professional judgment, were of most significance in the audit of the consolidated
financial statements of the current period. These matters were addressed in the context of the audit of the consolidated financial
statements as a whole, and in forming the auditor’s opinion thereon, and we do not provide a separate opinion on these matters.
For each matter below, our description of how our audit addressed the matter is provided in that context.
We have fulfilled the responsibilities described in the Auditor’s responsibilities for the audit of the consolidated financial
statements section of our report, including in relation to these matters. Accordingly, our audit included the performance
of procedures designed to respond to our assessment of the risks of material misstatement of the consolidated financial
statements. The results of our audit procedures, including the procedures performed to address the matters below, provide the
basis for our audit opinion on the accompanying consolidated financial statements.
Key Audit Matter
Accounting for the effects of rate regulation
As disclosed in note 6 of the consolidated financial statements, the Company has $3.1 billion in regulatory
assets and $1.8 billion in regulatory liabilities. The Company’s rate-regulated subsidiaries are subject to
regulation by various federal, state and provincial regulatory authorities in the geographic regions in
which they operate. The regulatory rates are designed to recover the prudently incurred costs of providing
the regulated products or services and provide a reasonable return on the equity invested or assets, as
applicable. In addition to regulatory assets and liabilities, rate regulation impacts multiple financial statement
line items, including, but not limited to, property, plant and equipment (“PP&E”), operating revenues and
expenses, income taxes, and depreciation expense.
Auditing the impact of rate regulation on the Company’s financial statements is complex and highly
judgmental due to the significant judgments made by the Company to support its accounting and disclosure
for regulatory matters when final regulatory decisions or orders have not yet been obtained or when
regulatory formulas are complex. There is also subjectivity involved in assessing the potential impact of
future regulatory decisions on the financial statements. Although the Company expects to recover costs
from customers through rates, there is a risk that the regulator will not approve full recovery of the costs
incurred. The Company’s judgments include making an assessment of the probability of recovery of and
return on costs incurred, of the potential disallowance of part of the cost incurred, or of the probable refund
to customers of gains or amounts previously collected from customers through future rates.
66
EMERA 2023 ANNUAL REPORT Independent Auditor’s Report
How Our Audit
Addressed the Key
Audit Matter
Accounting for the effects of rate regulation
We performed audit procedures that included, amongst others, assessing the Company’s evaluation of the
probability of future recovery for regulatory assets, PP&E, and refund of regulatory liabilities by obtaining
and reviewing relevant regulatory orders, filings, testimony, hearings and correspondence, and other publicly
available information. For regulatory matters for which regulatory decisions or orders have not yet been
obtained, we inspected the rate-regulated subsidiaries’ filings for any evidence that might contradict the
Company’s assertions, and reviewed other regulatory orders, filings and correspondence for other entities
within the same or similar jurisdictions to assess the likelihood of recovery or refund in future rates based on
the regulator’s treatment of similar costs under similar circumstances. We obtained and evaluated an analysis
from the Company and corroborated that analysis with letters from legal counsel, when appropriate, regarding
cost recoveries, gains or amounts previously collected from customers or future changes in rates. We also
assessed the methodology, accuracy and completeness of the Company’s calculations of regulatory asset and
liability balances based on provisions and formulas outlined in rate orders and other correspondence with the
regulators. We evaluated the Company’s disclosures related to the impacts of rate regulation.
Key Audit Matter
Fair value (“FV”) measurement of derivative financial instruments
Held-for-trading (“HFT”) derivative assets of $348 million and liabilities of $567 million, disclosed in note 15
to the consolidated financial statements, are measured at FV. The Company recognized $1,037 million in
realized and unrealized gains during the year with respect to HFT derivatives.
How Our Audit
Addressed the Key
Audit Matter
Auditing the Company’s valuation of HFT derivatives is complex and highly judgmental due to the complexity
of the contract terms and valuation models, and the significant estimation required in determining the FV of
the contracts. In determining the FV of HFT derivatives, significant assumptions about future economic and
market assumptions with uncertain outcomes are used, including third-party sourced forward commodity
pricing curves based on illiquid markets, internally developed correlation factors and basis differentials.
These assumptions have a significant impact on the FV of the HFT derivatives.
We performed audit procedures that included, amongst others, reviewing executed contracts and
agreements for the identification of inputs and assumptions impacting the valuation of derivatives. With
the support of our valuation specialists, we assessed the methodology and mathematical accuracy of the
Company’s valuation models and compared the commodity pricing curves used by the Company to current
market and economic data. For the forward commodity pricing curves, we compared the Company’s pricing
curves to independently sourced pricing curves. We also assessed the methodology and mathematical
accuracy of the Company’s calculations to develop correlation factors and basis differentials. In addition,
we assessed whether the FV hierarchy disclosures in note 16 to the consolidated financial statements
were consistent with the source of the significant inputs and assumptions used in determining the FV
of derivatives.
Other information
Management is responsible for the other information. The other information comprises:
• Management’s Discussion and Analysis
• The information, other than the consolidated financial statements and our auditor’s reports thereon, in the Annual Report
Our opinion on the consolidated financial statements does not cover the other information and we do not express any form of
assurance conclusion thereon.
In connection with our audit of the consolidated financial statements, our responsibility is to read the other information, and in
doing so, consider whether the other information is materially inconsistent with the consolidated financial statements or our
knowledge obtained in the audit or otherwise appears to be materially misstated.
67
EMERA 2023 ANNUAL REPORT Independent Auditor’s Report
We obtained Management’s Discussion & Analysis prior to the date of this auditor’s report. If, based on the work we have
performed, we conclude that there is a material misstatement of this other information, we are required to report that fact.
We have nothing to report in this regard.
The Annual Report is expected to be made available to us after the date of the auditor’s report. If based on the work we will
perform on this other information, we conclude there is a material misstatement of other information, we are required to report
that fact to those charged with governance.
Responsibilities of management and those charged with governance for the consolidated financial statements
Management is responsible for the preparation and fair presentation of the consolidated financial statements in accordance
with USGAAP, and for such internal control as management determines is necessary to enable the preparation of consolidated
financial statements that are free from material misstatement, whether due to fraud or error.
In preparing the consolidated financial statements, management is responsible for assessing the Company’s ability to continue
as a going concern, disclosing, as applicable, matters related to going concern and using the going concern basis of accounting
unless management either intends to liquidate the Company or to cease operations, or has no realistic alternative but to do so.
Those charged with governance are responsible for overseeing the Company’s financial reporting process.
Auditor’s responsibilities for the audit of the consolidated financial statements
Our objectives are to obtain reasonable assurance about whether the consolidated financial statements as a whole are free
from material misstatement, whether due to fraud or error, and to issue an auditor’s report that includes our opinion. Reasonable
assurance is a high level of assurance, but is not a guarantee that an audit conducted in accordance with Canadian generally
accepted auditing standards will always detect a material misstatement when it exists. Misstatements can arise from fraud
or error and are considered material if, individually or in the aggregate, they could reasonably be expected to influence the
economic decisions of users taken on the basis of these consolidated financial statements.
As part of an audit in accordance with Canadian generally accepted auditing standards, we exercise professional judgment and
maintain professional skepticism throughout the audit. We also:
• Identify and assess the risks of material misstatement of the consolidated financial statements, whether due to fraud
or error, design and perform audit procedures responsive to those risks, and obtain audit evidence that is sufficient and
appropriate to provide a basis for our opinion. The risk of not detecting a material misstatement resulting from fraud is
higher than for one resulting from error, as fraud may involve collusion, forgery, intentional omissions, misrepresentations,
or the override of internal control.
• Obtain an understanding of internal control relevant to the audit in order to design audit procedures that are appropriate in
the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control.
• Evaluate the appropriateness of accounting policies used and the reasonableness of accounting estimates and related
disclosures made by management.
• Conclude on the appropriateness of management’s use of the going concern basis of accounting and, based on the
audit evidence obtained, whether a material uncertainty exists related to events or conditions that may cast significant
doubt on the Company’s ability to continue as a going concern. If we conclude that a material uncertainty exists, we are
required to draw attention in our auditor’s report to the related disclosures in the consolidated financial statements or, if
such disclosures are inadequate, to modify our opinion. Our conclusions are based on the audit evidence obtained up to
the date of our auditor’s report. However, future events or conditions may cause the Company to cease to continue as a
going concern.
• Evaluate the overall presentation, structure and content of the consolidated financial statements, including the disclosures,
and whether the consolidated financial statements represent the underlying transactions and events in a manner that
achieves fair presentation.
• Obtain sufficient appropriate audit evidence regarding the financial information of the entities or business activities
within the Company to express an opinion on the consolidated financial statements. We are responsible for the direction,
supervision and performance of the group audit. We remain solely responsible for our audit opinion.
68
EMERA 2023 ANNUAL REPORT Independent Auditor’s Report
We communicate with those charged with governance regarding, among other matters, the planned scope and timing of the audit
and significant audit findings, including any significant deficiencies in internal control that we identify during our audit.
We also provide those charged with governance with a statement that we have complied with relevant ethical requirements
regarding independence, and to communicate with them all relationships and other matters that may reasonably be thought
to bear on our independence, and where applicable, related safeguards.
From the matters communicated with those charged with governance, we determine those matters that were of most significance
in the audit of the consolidated financial statements of the current period and are therefore the key audit matters. We describe
these matters in our auditor’s report unless law or regulation precludes public disclosure about the matter or when, in extremely
rare circumstances, we determine that a matter should not be communicated in our report because the adverse consequences of
doing so would reasonably be expected to outweigh the public interest benefits of such communication.
The engagement partner on the audit resulting in this independent auditor’s report is Tracy Brennan.
Chartered Professional Accountants
Halifax, Canada
February 26, 2024
69
EMERA 2023 ANNUAL REPORT Report of Independent Registered
Public Accounting Firm
To the Shareholders and the Board of Directors of Emera Incorporated
Opinion on the Consolidated Financial Statements
We have audited the accompanying Consolidated Balance Sheets of Emera Incorporated (the “Company“) as of December
31, 2023 and 2022, the related Consolidated Statements of Income, Consolidated Statements of Comprehensive Income,
Consolidated Statements of Changes in Equity and Consolidated Statements of Cash Flows for the years then ended, and the
related notes (collectively referred to as the “consolidated financial statements“). In our opinion, the consolidated financial
statements present fairly, in all material respects, the consolidated financial position of the Company as of December 31, 2023
and 2022, and the consolidated results of its operations and its consolidated cash flows for each of the two years in the period
ended December 31, 2023, in conformity with United States generally accepted accounting principles.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company‘s management. Our responsibility is to express an
opinion on the Company‘s consolidated financial statements based on our audits. We are a public accounting firm registered with
the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to
the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and
Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the
audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement,
whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal
control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over
financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over
financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements,
whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on
a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included
evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall
presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
70
EMERA 2023 ANNUAL REPORT Report of Independent Registered Public Accounting Firm
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current period audit of the financial statements
that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures
that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The
communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken
as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit
matters or on the accounts or disclosures to which they relate.
Description of the
Matter
How We Addressed
the Matter in Our
Audit
Accounting for the effects of rate regulation
As disclosed in note 6 of the consolidated financial statements, the Company has $3.1 billion in regulatory
assets and $1.8 billion in regulatory liabilities. The Company’s rate-regulated subsidiaries are subject to
regulation by various federal, state and provincial regulatory authorities in the geographic regions in
which they operate. The regulatory rates are designed to recover the prudently incurred costs of providing
the regulated products or services and provide a reasonable return on the equity invested or assets, as
applicable. In addition to regulatory assets and liabilities, rate regulation impacts multiple financial
statement line items, including, but not limited to, PP&E, operating revenues and expenses, income taxes,
and depreciation expense.
Auditing the impact of rate regulation on the Company’s financial statements is complex and highly
judgmental due to the significant judgments made by the Company to support its accounting and disclosure
for regulatory matters when final regulatory decisions or orders have not yet been obtained or when
regulatory formulas are complex. There is also subjectivity involved in assessing the potential impact of
future regulatory decisions on the financial statements. Although the Company expects to recover costs
from customers through rates, there is a risk that the regulator will not approve full recovery of the costs
incurred. The Company’s judgments include making an assessment of the probability of recovery of and
return on costs incurred, of the potential disallowance of part of the cost incurred, or of the probable refund
of gains or amounts previously collected from customers through future rates.
We performed audit procedures that included, amongst others, assessing the Company’s evaluation of the
probability of future recovery for regulatory assets, PP&E, and refund of regulatory liabilities by obtaining
and reviewing relevant regulatory orders, filings, testimony, hearings and correspondence, and other publicly
available information. For regulatory matters for which regulatory decisions or orders have not yet been
obtained, we inspected the rate-regulated subsidiaries’ filings for any evidence that might contradict the
Company’s assertions, and reviewed other regulatory orders, filings and correspondence for other entities
within the same or similar jurisdictions to assess the likelihood of recovery or refund in future rates based on
the regulator’s treatment of similar costs under similar circumstances. We obtained and evaluated an analysis
from the Company and corroborated that analysis with letters from legal counsel, when appropriate, regarding
cost recoveries, gains or amounts previously collected from customers or future changes in rates. We also
assessed the methodology, accuracy and completeness of the Company’s calculations of regulatory asset and
liability balances based on provisions and formulas outlined in rate orders and other correspondence with the
regulators. We evaluated the Company’s disclosures related to the impacts of rate regulation.
71
EMERA 2023 ANNUAL REPORT Report of Independent Registered Public Accounting Firm
Description of the
Matter
FV measurement of derivative financial instruments
HFT derivative assets of $348 million and liabilities of $567 million, disclosed in note 15 to the consolidated
financial statements, are measured at FV. The Company recognized $1,037 million in realized and unrealized
gains during the year with respect to HFT derivatives.
How We Addressed
the Matter in Our
Audit
Auditing the Company’s valuation of HFT derivatives is complex and highly judgmental due to the complexity
of the contract terms and valuation models, and the significant estimation required in determining the FV of
the contracts. In determining the FV of HFT derivatives, significant assumptions about future economic and
market assumptions with uncertain outcomes are used, including third-party sourced forward commodity
pricing curves based on illiquid markets, internally developed correlation factors and basis differentials.
These assumptions have a significant impact on the FV of the HFT derivatives.
We performed audit procedures that included, amongst others, reviewing executed contracts and
agreements for the identification of inputs and assumptions impacting the valuation of derivatives. With
the support of our valuation specialists, we assessed the methodology and mathematical accuracy of the
Company’s valuation models and compared the commodity pricing curves used by the Company to current
market and economic data. For the forward commodity pricing curves, we compared the Company’s pricing
curves to independently sourced pricing curves. We also assessed the methodology and mathematical
accuracy of the Company’s calculations to develop correlation factors and basis differentials. In addition,
we assessed whether the FV hierarchy disclosures in note 16 to the consolidated financial statements
were consistent with the source of the significant inputs and assumptions used in determining the FV
of derivatives.
Chartered Professional Accountants
We have served as the Company’s auditor since 1998.
Halifax, Canada
February 26, 2024
72
EMERA 2023 ANNUAL REPORT Emera Incorporated
Consolidated Statements of Income
For the
millions of dollars (except per share amounts)
Operating revenues
Regulated electric
Regulated gas
Non-regulated
Total operating revenues (note 5)
Operating expenses
Regulated fuel for generation and purchased power
Regulated cost of natural gas
Operating, maintenance and general expenses (“OM&G”)
Provincial, state, and municipal taxes
Depreciation and amortization
GBPC Impairment charge (note 22)
Total operating expenses
Income from operations
Income from equity investments (note 7)
Other income, net (note 8)
Interest expense, net (note 9)
Income before provision for income taxes
Income tax expense (note 10)
Net income
Non-controlling interest in subsidiaries
Preferred stock dividends
Net income attributable to common shareholders
Weighted average shares of common stock outstanding (in millions) (note 12)
Basic
Diluted
Earnings per common share (note 12)
Basic
Diluted
Dividends per common share declared
The accompanying notes are an integral part of these consolidated financial statements.
Consolidated Financial Statements
Year ended December 31
2022
2023
$ 5,746
1,489
328
7,563
$ 5,473
1,681
434
7,588
1,881
527
1,879
433
1,049
–
5,769
1,794
146
158
925
1,173
128
1,045
1
66
$ 978
2,171
800
1,596
367
952
73
5,959
1,629
129
145
709
1,194
185
1,009
1
63
$ 945
274
274
266
266
$ 3.57
$
3.57
$ 2.7875
$ 3.56
$ 3.55
$ 2.6775
73
EMERA 2023 ANNUAL REPORT
Consolidated Financial Statements
Emera Incorporated
Consolidated Statements of Comprehensive Income
For the
millions of dollars
Net income
Other comprehensive (loss) income, net of tax
Foreign currency translation adjustment (1 )
Unrealized gains (losses) on net investment hedges (2) (3)
Cash flow hedges – reclassification adjustment for gains included in income (4)
Unrealized losses on available-for-sale investment
Net change in unrecognized pension and post-retirement benefit obligation (5)
Other comprehensive (loss) income (6)
Comprehensive income
Comprehensive income attributable to non-controlling interest
Comprehensive Income of Emera Incorporated
Year ended December 31
2022
2023
$ 1,045
$ 1,009
(270)
38
(2)
–
(39)
(273)
772
1
$ 771
629
(97)
(2)
(1)
24
553
1,562
1
$ 1,561
The accompanying notes are an integral part of these consolidated financial statements.
(1) Net of tax recovery of $7 million for the year ended December 31, 2023 (2022 – $7 million expense).
(2) The Company has designated $1.2 billion United States dollar (USD) denominated Hybrid Notes as a hedge of the foreign currency exposure of its net
investment in USD denominated operations.
(3) Net of tax expense of nil for the year ended December 31, 2023 (2022 – $6 million recovery).
(4) Net of tax expense of nil for the year ended December 31, 2023 (2022 – $1 million recovery).
(5) Net of tax expense of $1 million for the year ended December 31, 2023 (2022 – $1 million expense).
(6) Net of tax recovery of $6 million for the year ended December 31, 2023 (2022 – $1 million expense).
74
EMERA 2023 ANNUAL REPORT Emera Incorporated
Consolidated Balance Sheets
As at
millions of dollars
Assets
Current assets
Cash and cash equivalents
Restricted cash (note 32)
Inventory (note 14)
Derivative instruments (notes 15 and 16)
Regulatory assets (note 6)
Receivables and other current assets (note 18)
Property, plant and equipment (“PP&E”), net of accumulated depreciation
and amortization of $9,994 and $9,574, respectively (note 20)
Other assets
Deferred income taxes (note 10)
Derivative instruments (notes 15 and 16)
Regulatory assets (note 6)
Net investment in direct finance and sales type leases (note 19)
Investments subject to significant influence (note 7)
Goodwill (note 22)
Other long-term assets (note 32)
Total assets
The accompanying notes are an integral part of these consolidated financial statements.
Consolidated Financial Statements
December 31
2023
December 31
2022
$
567
21
790
174
339
1,817
3,708
$
310
22
769
296
602
2,897
4,896
24,376
22,996
208
66
2,766
621
1,402
5,871
462
11,396
$ 39,480
237
100
3,018
604
1,418
6,012
461
11,850
$ 39,742
75
EMERA 2023 ANNUAL REPORT
Consolidated Financial Statements
Emera Incorporated
Consolidated Balance Sheets (continued)
As at
millions of dollars
Liabilities and Equity
Current liabilities
Short-term debt (note 23)
Current portion of long-term debt (note 25)
Accounts payable
Derivative instruments (notes 15 and 16)
Regulatory liabilities (note 6)
Other current liabilities (note 24)
Long-term liabilities
Long-term debt (note 25)
Deferred income taxes (note 10)
Derivative instruments (notes 15 and 16)
Regulatory liabilities (note 6)
Pension and post-retirement liabilities (note 21)
Other long-term liabilities (notes 7 and 26)
Equity
Common stock (note 11)
Cumulative preferred stock (note 28)
Contributed surplus
Accumulated other comprehensive income (“AOCI”) (note 13)
Retained earnings
Total Emera Incorporated equity
Non-controlling interest in subsidiaries (note 29)
Total equity
Total liabilities and equity
Commitments and contingencies (note 27)
The accompanying notes are an integral part of these consolidated financial statements.
Approved on behalf of the Board of Directors
December 31
2023
December 31
2022
$ 1,433
676
1,454
386
168
427
4,544
$ 2,726
574
2,025
888
495
579
7,287
17,689
2,352
118
1,604
265
820
22,848
15,744
2,196
190
1,778
281
825
21,014
8,462
1,422
82
305
1,803
12,074
14
12,088
$ 39,480
7,762
1,422
81
578
1,584
11,427
14
11,441
$ 39,742
“M. Jacqueline Sheppard”
Chair of the Board
“Scott Balfour”
President and Chief Executive Officer
76
EMERA 2023 ANNUAL REPORT
Emera Incorporated
Consolidated Statements of Cash Flows
For the
millions of dollars
Operating activities
Net income
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization
Income from equity investments, net of dividends
Allowance for funds used during construction (“AFUDC”) – equity
Deferred income taxes, net
Net change in pension and post-retirement liabilities
NSPI Fuel adjustment mechanism (“FAM”)
Net change in Fair Value (“FV”) of derivative instruments
Net change in regulatory assets and liabilities
Net change in capitalized transportation capacity
GBPC impairment charge
Other operating activities, net
Changes in non-cash working capital (note 30)
Net cash provided by operating activities
Investing activities
Additions to PP&E
Other investing activities
Net cash used in investing activities
Financing activities
Change in short-term debt, net
Proceeds from short-term debt with maturities greater than 90 days
Repayment of short-term debt with maturities greater than 90 days
Proceeds from long-term debt, net of issuance costs
Retirement of long-term debt
Net (repayments) proceeds under committed credit facilities
Issuance of common stock, net of issuance costs
Dividends on common stock
Dividends on preferred stock
Other financing activities
Net cash provided by financing activities
Effect of exchange rate changes on cash, cash equivalents, and restricted cash
Net increase (decrease) in cash, cash equivalents, and restricted cash
Cash, cash equivalents, and restricted cash, beginning of year
Cash, cash equivalents, and restricted cash, end of year
Cash, cash equivalents, and restricted cash consists of:
Cash
Short-term investments
Restricted cash
Cash, cash equivalents, and restricted cash
Supplementary Information to Consolidated Statements of Cash Flows (note 30)
The accompanying notes are an integral part of these consolidated financial statements.
Consolidated Financial Statements
Year ended December 31
2022
2023
$ 1,045
$ 1,009
1,060
(22)
(38)
97
(68)
(88)
(666)
554
434
–
28
(95)
2,241
959
(61)
(52)
152
(48)
(162)
206
(471)
(445)
73
(13)
(234)
913
(2,937)
20
(2,917)
(2,596)
27
(2,569)
(66)
548
(1,086)
1,932
(151)
(96)
424
(488)
(66)
(12)
939
(7)
256
332
$ 588
1,028
544
(680)
784
(367)
511
277
(472)
(63)
(7)
1,555
16
(85)
417
$ 332
$ 559
8
21
$ 588
$ 302
8
22
$ 332
77
EMERA 2023 ANNUAL REPORT
Consolidated Financial Statements
Emera Incorporated
Consolidated Statements of Changes in Equity
Common
Stock
Preferred
Stock
Contributed
Surplus
AOCI
Retained
Earnings
Non-
Controlling
Interest
Total Equity
$ 7,762 $ 1,422
$
81
$
578
–
(273)
$ 1,584
1,044
$
–
14
1
–
$ 11,441
1,045
(273)
millions of dollars
Balance, December 31, 2022
Net income of Emera Inc.
Other comprehensive loss, net of
tax recovery of $6 million
Dividends declared on preferred
stock (note 28)
Dividends declared on common
stock ($2.7875/share)
–
–
–
–
Issued under the at-the-market
397
program (”ATM“), net of after-tax
issuance costs
Issued under the Dividend
272
–
–
–
–
–
–
–
–
–
–
–
–
–
(66)
–
(66)
–
(759)
–
(759)
–
–
–
–
–
–
397
272
Reinvestment Program ("DRIP"),
net of discount
Senior management stock options
exercised and Employee Common
Share Purchase Plan (“ECSPP”)
31
–
1
–
–
–
32
Other
Balance, December 31, 2023
–
$ 8,462
–
$ 1,422
$
–
82
–
–
$
305
$ 1,803
$
(1)
14
(1)
$ 12,088
$ 7,242
$ 1,422
$
79
$
Balance, December 31, 2021
Net income of Emera Inc.
Other comprehensive income, net
of tax expense of $1 million
Dividends declared on preferred
stock (note 28)
Dividends declared on common
stock ($2.6775/share)
Issued under the ATM, net of
after-tax issuance costs
Issued under the DRIP, net of
discount
Senior management stock options
exercised and ECSPP
Disposal of non-controlling interest
of Dominica Electricity Services
Ltd (”Domlec“)
Other
Balance, December 31, 2022
–
–
–
–
248
238
34
–
–
–
–
–
–
–
–
–
–
–
$ 7,762 $ 1,422
$
–
–
–
–
–
–
2
–
25
–
$ 1,348
1,008
$
553
–
34
1
–
$ 10,150
1,009
553
–
(63)
–
(63)
–
(709)
–
(709)
–
–
–
–
–
–
–
–
–
–
248
238
–
36
(20)
(20)
–
81
–
–
$
578
$ 1,584
$
(1)
14
(1)
$ 11,441
The accompanying notes are an integral part of these consolidated financial statements.
78
EMERA 2023 ANNUAL REPORT Emera Incorporated
Notes to the Consolidated Financial Statements
As at December 31, 2023 and 2022
1. Summary of Significant Accounting Policies
NATURE OF OPERATIONS
Emera Incorporated (“Emera” or the “Company”) is an energy and services company which invests in electricity generation,
transmission and distribution, and gas transmission and distribution.
At December 31, 2023, Emera’s reportable segments include the following:
• Florida Electric Utility, which consists of Tampa Electric (“TEC”), a vertically integrated regulated electric utility, serving
approximately 840,000 customers in West Central Florida;
• Canadian Electric Utilities, which includes:
• Nova Scotia Power Inc. (“NSPI”), a vertically integrated regulated electric utility and the primary electricity supplier in
Nova Scotia, serving approximately 549,000 customers; and
• Emera Newfoundland & Labrador Holdings Inc. (“ENL”), consisting of two transmission investments related to an
824 megawatt (“MW”) hydroelectric generating facility at Muskrat Falls on the Lower Churchill River in Labrador,
developed by Nalcor Energy. ENL’s two investments are:
• a 100 per cent equity interest in NSP Maritime Link Inc. (“NSPML”), which developed the Maritime Link Project, a
$1.8 billion transmission project, including AFUDC; and
• a 31 per cent equity interest in the partnership capital of Labrador-Island Link Limited Partnership (“LIL”), a
$3.7 billion electricity transmission project in Newfoundland and Labrador.
• Gas Utilities and Infrastructure, which includes:
• Peoples Gas System Inc. (“PGS”), a regulated gas distribution utility, serving approximately 490,000 customers across
Florida. Effective January 1, 2023, Peoples Gas System ceased to be a division of Tampa Electric Company 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.;
• New Mexico Gas Company, Inc. (“NMGC”), a regulated gas distribution utility, serving approximately 540,000 customers
in New Mexico;
• Emera Brunswick Pipeline Company Limited (“Brunswick Pipeline”), a 145-kilometre pipeline delivering re-gasified
liquefied natural gas from Saint John, New Brunswick to the United States border under a 25-year firm service
agreement with Repsol Energy North America Canada Partnership (“Repsol Energy”), which expires in 2034;
• SeaCoast Gas Transmission, LLC (“SeaCoast”), a regulated intrastate natural gas transmission company offering
services in Florida; and
• a 12.9 per cent equity interest in Maritimes & Northeast Pipeline (“M&NP”), a 1,400-kilometre pipeline that transports
natural gas throughout markets in Atlantic Canada and the northeastern United States.
• Other Electric Utilities, which includes Emera (Caribbean) Incorporated (“ECI”), a holding company with regulated electric
utilities that include:
• The Barbados Light & Power Company Limited (“BLPC”), a vertically integrated regulated electric utility on the island of
Barbados, serving approximately 134,000 customers;
• Grand Bahama Power Company Limited (“GBPC”), a vertically integrated regulated electric utility on Grand Bahama
Island, serving approximately 19,000 customers; and
• a 19.5 per cent equity interest in St. Lucia Electricity Services Limited (“Lucelec”), a vertically integrated regulated
electric utility on the island of St. Lucia.
79
EMERA 2023 ANNUAL REPORT • Emera’s other reportable segment includes investments in energy-related non-regulated companies which include:
• Emera Energy, which consists of:
• Emera Energy Services (“EES”), a physical energy business that purchases and sells natural gas and electricity
and provides related energy asset management services;
• Brooklyn Power Corporation (“Brooklyn Energy”), a 30 MW biomass co-generation electricity facility in Brooklyn,
Nova Scotia; and
• a 50.0 per cent joint venture interest in Bear Swamp Power Company LLC (“Bear Swamp”), a 660 MW pumped
storage hydroelectric facility in northwestern Massachusetts.
• Emera US Finance LP (“Emera Finance”) and TECO Finance, Inc. (“TECO Finance”), financing subsidiaries of Emera;
• Block Energy LLC (previously Emera Technologies LLC), a wholly owned technology company focused on finding ways to
deliver renewable and resilient energy to customers;
• Emera US Holdings Inc., a wholly owned holding company for certain of Emera’s assets located in the United States; and
• Other investments.
BASIS OF PRESENTATION
These consolidated financial statements are prepared and presented in accordance with United States Generally Accepted
Accounting Principles (“USGAAP”) and in the opinion of management, include all adjustments that are of a recurring nature
and necessary to fairly state the financial position of Emera.
All dollar amounts are presented in Canadian dollars (“CAD”), unless otherwise indicated.
PRINCIPLES OF CONSOLIDATION
These consolidated financial statements include the accounts of Emera Incorporated, its majority-owned subsidiaries, and
a variable interest entity (“VIE”) in which Emera is the primary beneficiary. Emera uses the equity method of accounting to
record investments in which the Company has the ability to exercise significant influence, and for VIEs in which Emera is not the
primary beneficiary.
The Company performs ongoing analysis to assess whether it holds any VIEs or whether any reconsideration events have arisen
with respect to existing VIEs. To identify potential VIEs, management reviews contractual and ownership arrangements such as
leases, long-term purchase power agreements, tolling contracts, guarantees, jointly owned facilities and equity investments. VIEs
of which the Company is deemed the primary beneficiary must be consolidated. The primary beneficiary of a VIE has both the
power to direct the activities of the VIE that most significantly impacts its economic performance and the obligation to absorb
losses or the right to receive benefits of the VIE that could potentially be significant to the VIE. In circumstances where Emera
has an investment in a VIE but is not deemed the primary beneficiary, the VIE is accounted for using the equity method. For
further details on VIEs, refer to note 32.
Intercompany balances and transactions have been eliminated on consolidation, except for the net profit on certain transactions
between certain non-regulated and regulated entities in accordance with accounting standards for rate-regulated entities.
The net profit on these transactions, which would be eliminated in the absence of the accounting standards for rate-regulated
entities, is recorded in non-regulated operating revenues. An offset is recorded to PP&E, regulatory assets, regulated fuel for
generation and purchased power, or OM&G, depending on the nature of the transaction.
USE OF MANAGEMENT ESTIMATES
The preparation of consolidated financial statements in accordance with USGAAP requires management to make estimates and
assumptions. These may affect reported amounts of assets and liabilities at the date of the financial statements and reported
amounts of revenues and expenses during the reporting periods. Significant areas requiring use of management estimates
relate to rate-regulated assets and liabilities, accumulated reserve for cost of removal, pension and post-retirement benefits,
unbilled revenue, useful lives for depreciable assets, goodwill and long-lived assets impairment assessments, income taxes, asset
retirement obligations (“ARO”), and valuation of financial instruments. Management evaluates the Company’s estimates on an
ongoing basis based upon historical experience, current and expected conditions and assumptions believed to be reasonable at
the time the assumption is made, with any adjustments recognized in income in the year they arise.
80
Notes to the Consolidated Financial StatementsEMERA 2023 ANNUAL REPORT REGULATORY MATTERS
Regulatory accounting applies where rates are established by, or subject to approval by, an independent third-party regulator.
Rates are designed to recover prudently incurred costs of providing regulated products or services and provide an opportunity
for a reasonable rate of return on invested capital, as applicable. For further detail, refer to note 6.
FOREIGN CURRENCY TRANSLATION
Monetary assets and liabilities denominated in foreign currencies are converted to CAD at the rates of exchange prevailing at the
balance sheet date. The resulting differences between the translation at the original transaction date and the balance sheet date
are included in income.
Assets and liabilities of foreign operations whose functional currency is not the Canadian dollar are translated using exchange
rates in effect at the balance sheet date and the results of operations at the average exchange rate in effect for the period.
The resulting exchange gains and losses on the assets and liabilities are deferred on the balance sheet in AOCI.
The Company designates certain USD denominated debt held in CAD functional currency companies as hedges of net
investments in USD denominated foreign operations. The change in the carrying amount of these investments, measured at
exchange rates in effect at the balance sheet date is recorded in Other Comprehensive Income (“OCI”).
REVENUE RECOGNITION
Regulated Electric and Gas Revenue:
Electric and gas revenues, including energy charges, demand charges, basic facilities charges and clauses and riders, are
recognized when obligations under the terms of a contract are satisfied, which is when electricity and gas are delivered to
customers over time as the customer simultaneously receives and consumes the benefits. Electric and gas revenues are
recognized on an accrual basis and include billed and unbilled revenues. Revenues related to the sale of electricity and gas are
recognized at rates approved by the respective regulators and recorded based on metered usage, which occurs on a periodic,
systematic basis, generally monthly or bi-monthly. At the end of each reporting period, electricity and gas delivered to customers,
but not billed, is estimated and corresponding unbilled revenue is recognized. The Company’s estimate of unbilled revenue at
the end of the reporting period is calculated by estimating the megawatt hours (“MWh”) or therms delivered to customers at the
established rates expected to prevail in the upcoming billing cycle. This estimate includes assumptions as to the pattern of energy
demand, weather, line losses and inter-period changes to customer classes.
Non-regulated Revenue:
Marketing and trading margins are comprised of Emera Energy’s corresponding purchases and sales of natural gas and
electricity, pipeline capacity costs and energy asset management revenues. Revenues are recorded when obligations under terms
of the contract are satisfied and are presented on a net basis reflecting the nature of contractual relationships with customers
and suppliers.
Energy sales are recognized when obligations under the terms of the contracts are satisfied, which is when electricity is delivered
to customers over time.
Other non-regulated revenues are recorded when obligations under the terms of the contract are satisfied.
Other:
Sales, value add, and other taxes, except for gross receipts taxes discussed below, collected by the Company concurrent with
revenue-producing activities are excluded from revenue.
FRANCHISE FEES AND GROSS RECEIPTS
TEC and PGS recover from customers certain costs incurred, on a dollar-for-dollar basis, through prices approved by the Florida
Public Service Commission (“FPSC”). The amounts included in customers’ bills for franchise fees and gross receipt taxes are
included as “Regulated electric” and “Regulated gas” revenues in the Consolidated Statements of Income. Franchise fees and
gross receipt taxes payable by TEC and PGS are included as an expense on the Consolidated Statements of Income in “Provincial,
state and municipal taxes”.
81
Notes to the Consolidated Financial StatementsEMERA 2023 ANNUAL REPORT NMGC is an agent in the collection and payment of franchise fees and gross receipt taxes and is not required by a tariff to present
the amounts on a gross basis. Therefore, NMGC’s franchise fees and gross receipt taxes are presented net with no line item
impact on the Consolidated Statements of Income.
PP&E
PP&E is recorded at original cost, including AFUDC or capitalized interest, net of contributions received in aid of construction.
The cost of additions, including betterments and replacements of units, are included in “PP&E” on the Consolidated Balance
Sheets. When units of regulated PP&E are replaced, renewed or retired, their cost, plus removal or disposal costs, less salvage
proceeds, is charged to accumulated depreciation, with no gain or loss reflected in income. Where a disposition of non-regulated
PP&E occurs, gains and losses are included in income as the dispositions occur.
The cost of PP&E represents the original cost of materials, contracted services, direct labour, AFUDC for regulated property or
interest for non-regulated property, ARO, and overhead attributable to the capital project. Overhead includes corporate costs
such as finance, information technology and labour costs, along with other costs related to support functions, employee benefits,
insurance, procurement, and fleet operating and maintenance. Expenditures for project development are capitalized if they are
expected to have a future economic benefit.
Normal maintenance projects and major maintenance projects that do not increase overall life of the related assets are expensed
as incurred. When a major maintenance project increases the life or value of the underlying asset, the cost is capitalized.
Depreciation is determined by the straight-line method, based on the estimated remaining service lives of the depreciable assets
in each functional class of depreciable property. For some of Emera’s rate-regulated subsidiaries, depreciation is calculated
using the group remaining life method, which is applied to the average investment, adjusted for anticipated costs of removal less
salvage, in functional classes of depreciable property. The service lives of regulated assets require regulatory approval.
Intangible assets, which are included in “PP&E” on the Consolidated Balance Sheets, consist primarily of computer software and
land rights. Amortization is determined by the straight-line method, based on the estimated remaining service lives of the asset
in each category. For some of Emera’s rate-regulated subsidiaries, amortization is calculated using the amortizable life method
which is applied to the net book value to date over the remaining life of those assets. The service lives of regulated intangible
assets require regulatory approval.
GOODWILL
Goodwill is calculated as the excess of the purchase price of an acquired entity over the estimated FV of identifiable assets
acquired and liabilities assumed at the acquisition date. Goodwill is carried at initial cost less any write-down for impairment and
is adjusted for the impact of foreign exchange (“FX”). Goodwill is subject to assessment for impairment at the reporting unit level
annually, or if an event or change in circumstances indicates that the FV of a reporting unit may be below its carrying value. When
assessing goodwill for impairment, the Company has the option of first performing a qualitative assessment to determine whether
a quantitative assessment is necessary. In performing a qualitative assessment management considers, among other factors,
macroeconomic conditions, industry and market considerations and overall financial performance.
If the Company performs a qualitative assessment and determines it is more likely than not that its FV is less than its carrying
amount, or if the Company chooses to bypass the qualitative assessment, a quantitative test is performed. The quantitative test
compares the FV of the reporting unit to its carrying amount, including goodwill. If the carrying amount of the reporting unit
exceeds its FV, an impairment loss is recorded. Management estimates the FV of the reporting unit by using the income approach,
or a combination of the income and market approach. The income approach uses a discounted cash flow analysis which relies on
management’s best estimate of the reporting unit’s projected cash flows. The analysis includes an estimate of terminal values
based on these expected cash flows using a methodology which derives a valuation using an assumed perpetual annuity based
on the reporting unit’s residual cash flows. The discount rate used is a market participant rate based on a peer group of publicly
traded comparable companies and represents the weighted average cost of capital of comparable companies. For the market
approach, management estimates FV based on comparable companies and transactions within the utility industry. Significant
assumptions used in estimating the FV of a reporting unit using an income approach include discount and growth rates, rate case
assumptions including future cost of capital, valuation of the reporting unit’s net operating loss (“NOL”) and projected operating
and capital cash flows. Adverse changes in these assumptions could result in a future material impairment of the goodwill
assigned to Emera’s reporting units.
82
Notes to the Consolidated Financial StatementsEMERA 2023 ANNUAL REPORT As of December 31, 2023, $5,868 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.
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 details, refer to note 22.
INCOME TAXES AND INVESTMENT TAX CREDITS
Emera recognizes deferred income tax assets and liabilities for the future tax consequences of events that have been included
in financial statements or income tax returns. Deferred income tax assets and liabilities are determined based on the difference
between the carrying value of assets and liabilities on the Consolidated Balance Sheets, and their respective tax bases using
enacted tax rates in effect for the year in which the differences are expected to reverse. The effect of a change in income tax
rates on deferred income tax assets and liabilities is recognized in earnings in the period when the change is enacted, unless
required to be offset to a regulatory asset or liability by law or by order of the regulator. Emera recognizes the effect of income
tax positions only when it is more likely than not that they will be realized. Management reviews all readily available current and
historical information, including forward-looking information, and the likelihood that deferred income tax assets will be recovered
from future taxable income is assessed and assumptions are made about the expected timing of reversal of deferred income tax
assets and liabilities. If management subsequently determines it is likely that some or all of a deferred income tax asset will not
be realized, a valuation allowance is recorded to reflect the amount of deferred income tax asset expected to be realized.
Generally, investment tax credits are recorded as a reduction to income tax expense in the current or future periods to the extent
that realization of such benefit is more likely than not. Investment tax credits earned on regulated assets by TEC, PGS and NMGC
are deferred and amortized as required by regulatory practices.
TEC, PGS, NMGC and BLPC collect income taxes from customers based on current and deferred income taxes. NSPI, ENL and
Brunswick Pipeline collect income taxes from customers based on income tax that is currently payable, except for the deferred
income taxes on certain regulatory balances specifically prescribed by regulators. For the balance of regulated deferred income
taxes, NSPI, ENL and Brunswick Pipeline recognize regulatory assets or liabilities where the deferred income taxes are expected
to be recovered from or returned to customers in future years. These regulated assets or liabilities are grossed up using the
respective income tax rate to reflect the income tax associated with future revenues that are required to fund these deferred
income tax liabilities, and the income tax benefits associated with reduced revenues resulting from the realization of deferred
income tax assets. GBPC is not subject to income taxes.
Emera classifies interest and penalties associated with unrecognized tax benefits as interest and operating expense, respectively.
For further detail, refer to note 10.
DERIVATIVES AND HEDGING ACTIVITIES
The Company manages its exposure to normal operating and market risks relating to commodity prices, 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.
83
Notes to the Consolidated Financial StatementsEMERA 2023 ANNUAL REPORT 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
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.
Emera classifies gains and losses on derivatives as a component of non-regulated operating revenues, fuel for generation
and purchased power, other expenses, inventory, and OM&G, depending on the nature of the item being economically hedged.
Transportation capacity arising as a result of marketing and trading derivative transactions is recognized as an asset in
“Receivables and other current assets” and amortized over the period of the transportation contract term. Cash flows from
derivative activities are presented in the same category as the item being hedged within operating or investing activities on
the Consolidated Statements of Cash Flows. Non-hedged derivatives are included in operating cash flows on the Consolidated
Statements of Cash Flows.
Derivatives, as reflected on the Consolidated Balance Sheets, are not offset by the FV amounts of cash collateral with the same
counterparty. Rights to reclaim cash collateral are recognized in “Receivables and other current assets” and obligations to return
cash collateral are recognized in “Accounts payable”.
LEASES
The Company determines whether a contract contains a lease at inception by evaluating whether the contract conveys the right
to control the use of an identified asset for a period of time in exchange for consideration.
Emera has leases with independent power producers (“IPP”) and other utilities for annual requirements to purchase wind and
hydro energy over varying contract lengths which are classified as finance leases. These finance leases are not recorded on the
Company’s Consolidated Balance Sheets as payments associated with the leases are variable in nature and there are no minimum
fixed lease payments. Lease expense associated with these leases is recorded as “Regulated fuel for generation and purchased
power” on the Consolidated Statements of Income.
Operating lease liabilities and right-of-use assets are recognized on the Consolidated Balance Sheets based on the present value
of the future minimum lease payments over the lease term at commencement date. As most of Emera’s leases do not provide
an implicit rate, the incremental borrowing rate at commencement of the lease is used in determining the present value of
future lease payments. Lease expense is recognized on a straight-line basis over the lease term and is recorded as “Operating,
maintenance and general” on the Consolidated Statements of Income.
84
Notes to the Consolidated Financial StatementsEMERA 2023 ANNUAL REPORT Where the Company is the lessor, a lease is a sales-type lease if certain criteria are met and the arrangement transfers control
of the underlying asset to the lessee. For arrangements where the criteria are met due to the presence of a third-party residual
value guarantee, the lease is a direct financing lease.
For direct finance leases, a net investment in the lease is recorded that consists of the sum of the minimum lease payments and
residual value, net of estimated executory costs and unearned income. The difference between the gross investment and the cost
of the leased item is recorded as unearned income at the inception of the lease. Unearned income is recognized in income over
the life of the lease using a constant rate of interest equal to the internal rate of return on the lease.
For sales-type leases, the accounting is similar to the accounting for direct finance leases however, the difference between the FV
and the carrying value of the leased item is recorded at lease commencement rather than deferred over the term of the lease.
Emera has certain contractual agreements that include lease and non-lease components, which management has elected to
account for as a single lease component.
CASH, CASH EQUIVALENTS AND RESTRICTED CASH
Cash equivalents consist of highly liquid short-term investments with original maturities of three months or less at acquisition.
RECEIVABLES AND ALLOWANCE FOR CREDIT LOSSES
Utility customer receivables are recorded at the invoiced amount and do not bear interest. Standard payment terms for
electricity and gas sales are approximately 30 days. A late payment fee may be assessed on account balances after the due date.
The Company recognizes allowances for credit losses to reduce accounts receivable for amounts expected to be uncollectable.
Management estimates credit losses related to accounts receivable by considering historical loss experience, customer deposits,
current events, the characteristics of existing accounts and reasonable and supportable forecasts that affect the collectability
of the reported amount. Provisions for credit losses on receivables are expensed to maintain the allowance at a level considered
adequate to cover expected losses. Receivables are written off against the allowance when they are deemed uncollectible.
INVENTORY
Fuel and materials inventories are valued at the lower of weighted-average cost or net realizable value, unless evidence indicates
the weighted-average cost will be recovered in future customer rates.
ASSET IMPAIRMENT
Long-Lived Assets:
Emera assesses whether there has been an impairment of long-lived assets and intangibles when a triggering event occurs, such
as a significant market disruption or sale of a business.
The assessment involves comparing undiscounted expected future cash flows to the carrying value of the asset. When the
undiscounted cash flow analysis indicates a long-lived asset is not recoverable, the amount of the impairment loss is determined
by measuring the excess of the carrying amount of the long-lived asset over its estimated FV. The Company’s assumptions relating
to future results of operations or other recoverable amounts, are based on a combination of historical experience, fundamental
economic analysis, observable market activity and independent market studies. The Company’s expectations regarding uses and
holding periods of assets are based on internal long-term budgets and projections, which consider external factors and market
forces, as of the end of each reporting period. The assumptions made are consistent with generally accepted industry approaches
and assumptions used for valuation and pricing activities.
As at December 31, 2023, there are no indications of impairment of Emera’s long-lived assets. No impairment charges related to
long-lived assets were recognized in 2023 or 2022.
Equity Method Investments:
The carrying value of investments accounted for under the equity method are assessed for impairment by comparing the FV of
these investments to their carrying values, if a FV assessment was completed, or by reviewing for the presence of impairment
indicators. If an impairment exists, and it is determined to be other-than-temporary, a charge is recognized in earnings equal to
the amount the carrying value exceeds the investment’s FV. No impairment of equity method investments was required in either
2023 or 2022.
85
Notes to the Consolidated Financial StatementsEMERA 2023 ANNUAL REPORT Financial Assets:
Equity investments, other than those accounted for under the equity method, are measured at FV, with changes in FV recognized
in the Consolidated Statements of Income. Equity investments that do not have readily determinable FV are recorded at cost
minus impairment, if any, plus or minus changes resulting from observable price changes in orderly transactions for the identical
or similar investments. No impairment of financial assets was required in either 2023 or 2022.
ASSET RETIREMENT OBLIGATIONS
An ARO is recognized if a legal obligation exists in connection with the future disposal or removal costs resulting from the
permanent retirement, abandonment or sale of a long-lived asset. A legal obligation may exist under an existing or enacted law
or statute, written or oral contract, or by legal construction under the doctrine of promissory estoppel.
An ARO represents the FV of estimated cash flows necessary to discharge the future obligation, using the Company’s credit
adjusted risk-free rate. The amounts are reduced by actual expenditures incurred. Estimated future cash flows are based on
completed depreciation studies, remediation reports, prior experience, estimated useful lives, and governmental regulatory
requirements. The present value of the liability is recorded and the carrying amount of the related long-lived asset is
correspondingly increased. The amount capitalized at inception is depreciated in the same manner as the related long-lived asset.
Over time, the liability is accreted to its estimated future value. AROs are included in “Other long-term liabilities” and accretion
expense is included as part of “Depreciation and amortization”. Any regulated accretion expense not yet approved by the
regulator is recorded in “Property, plant and equipment” and included in the next depreciation study.
Some of the Company’s transmission and distribution assets may have conditional AROs that are not recognized in the
consolidated financial statements, as the FV of these obligations could not be reasonably estimated, given insufficient
information to do so. A conditional ARO refers to a legal obligation to perform an asset retirement activity in which the
timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity.
Management monitors these obligations and a liability is recognized at FV in the period in which an amount can be determined.
COST OF REMOVAL (“COR”)
TEC, PGS, NMGC and NSPI recognize non-ARO COR as regulatory liabilities. The non-ARO COR represent funds received
from customers through depreciation rates to cover estimated future non-legally required COR of PP&E upon retirement.
The companies accrue for COR over the life of the related assets based on depreciation studies approved by their respective
regulators. The costs are estimated based on historical experience and future expectations, including expected timing and
estimated future cash outlays.
STOCK-BASED COMPENSATION
The Company has several stock-based compensation plans: a common share option plan for senior management; an employee
common share purchase plan; a deferred share unit (“DSU”) plan; a performance share unit (“PSU”) plan; and a restricted share
unit (“RSU”) plan. The Company accounts for its plans in accordance with the FV-based method of accounting for stock-based
compensation. Stock-based compensation cost is measured at the grant date, based on the calculated FV of the award, and is
recognized as an expense over the employee’s or director’s requisite service period using the graded vesting method. Stock-
based compensation plans recognized as liabilities are initially measured at FV and re-measured at FV at each reporting date,
with the change in liability recognized in income
EMPLOYEE BENEFITS
The costs of the Company’s pension and other post-retirement benefit programs for employees are expensed over the periods
during which employees render service. The Company recognizes the funded status of its defined-benefit and other post-
retirement plans on the balance sheet and recognizes changes in funded status in the year the change occurs. The Company
recognizes unamortized gains and losses and past service costs in “AOCI” or “Regulatory assets” on the Consolidated Balance
Sheets. The components of net periodic benefit cost other than the service cost component are included in “Other income, net”
on the Consolidated Statements of Income. For further detail, refer to note 21.
86
Notes to the Consolidated Financial StatementsEMERA 2023 ANNUAL REPORT 2. 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.
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.
3. Dispositions
On March 31, 2022, Emera completed the sale of its 51.9 per cent interest in Domlec for proceeds which approximated its carrying
value. Domlec was included in the Company’s Other Electric reportable segment up to its date of sale. The sale did not have a
material impact on earnings.
87
Notes to the Consolidated Financial StatementsEMERA 2023 ANNUAL REPORT 4. Segment Information
Emera manages its reportable segments separately due in part to their different operating, regulatory and geographical
environments. Segments are reported based on each subsidiary’s contribution of revenues, net income attributable to common
shareholders and total assets, as reported to the Company’s chief operating decision maker.
millions of dollars
For the year ended December 31, 2023
Operating revenues from
external customers (1 )
Inter-segment revenues (1 )
Total operating revenues
Regulated fuel for generation and
purchased power
Regulated cost of natural gas
OM&G
Provincial, state and municipal taxes
Depreciation and amortization
Income from equity investments
Other income, net
Interest expense, net (2)
Income tax expense (recovery)
Non-controlling interest in subsidiaries
Preferred stock dividends
Net income (loss) attributable to
common shareholders
Capital expenditures
As at December 31, 2023
Total assets
Investments subject to
significant influence
Goodwill
Florida
Electric
Utility
Canadian
Electric
Utilities
Gas Utilities
and
Infrastructure
Other
Electric
Utilities
Inter-
Segment
Eliminations
Other
Total
$ 3,548 $ 1,671
$ 1,510
$ 526
$ 308
$
– $ 7,563
8
3,556
920
–
1,671
699
14
1,524
–
–
–
830
289
571
–
69
271
117
–
–
384
45
276
109
32
170
(9)
–
–
527
405
91
126
21
11
129
64
–
–
–
526
275
–
130
3
68
4
7
23
–
1
–
$ 627 $ 247
$
214
$ 37
31
339
–
–
151
5
8
12
20
332
(44)
–
66
$ (147) $
(53)
(53)
(13)
–
7,563
1,881
–
(21)
–
–
–
527
1,879
433
1,049
146
158
925
–
128
–
1
–
–
66
– $ 978
19
$ 1,736 $ 450
$ 664
$ 63
$
8
$
– $ 2,921
$ 21,119 $ 8,634
– $ 1,236
$
$ 7,735
118
$
$ 1,311
$ 48
$ 1,938 $ (1,257) $ 39,480
– $ 1,402
$
– $
$ 4,628 $
– $ 1,240
$
– $
3
$
– $ 5,871
(1) All significant inter-company balances and transactions have been eliminated on consolidation except for certain transactions between non-regulated and
regulated entities. Management believes elimination of these transactions would understate PP&E, OM&G, or regulated fuel for generation and purchased
power. Inter-company transactions that have not been eliminated are measured at the amount of consideration established and agreed to by the related
parties. Eliminated transactions are included in determining reportable segments.
(2) Segment net income is reported on a basis that includes internally allocated financing costs of $95 million for the year ended December 31, 2023, between
the Florida Electric Utility, Gas Utilities and Infrastructure and Other segments.
88
Notes to the Consolidated Financial StatementsEMERA 2023 ANNUAL REPORT millions of dollars
For the year ended December 31, 2022
Operating revenues from
external customers (1 )
Inter-segment revenues (1 )
Total operating revenues
Regulated fuel for generation and
purchased power
Regulated cost of natural gas
OM&G
Provincial, state and municipal taxes
Depreciation and amortization
Income from equity investments
Other income (expenses), net
Interest expense, net (2)
GBPC impairment charge
Income tax expense (recovery)
Non-controlling interest in subsidiaries
Preferred stock dividends
Net income (loss) attributable to
common shareholders
Capital expenditures
As at December 31, 2022
Total assets
Investments subject to
significant influence
Goodwill
Florida
Electric
Utility
Canadian
Electric
Utilities
Gas Utilities
and
Infrastructure
Other
Electric
Utilities
Inter-
Segment
Eliminations
Other
Total
$ 3,280 $ 1,675
$ 1,697
$ 518
$ 418
$
– $ 7,588
7
3,287
1,086
–
1,675
803
7
1,704
–
–
–
625
235
507
–
68
185
–
121
–
–
338
43
259
87
24
136
–
(8)
–
–
800
365
83
118
21
13
81
–
70
–
–
$ 596 $ 215
$
221
$
–
518
290
–
123
3
61
4
–
19
73
–
1
–
(48) $
22
440
–
–
156
3
7
17
23
288
–
2
–
63
(39) $
(36)
(36)
(8)
–
7,588
2,171
17
–
(11)
–
–
–
800
1,596
367
952
129
145
709
–
73
–
185
–
1
–
–
63
– $ 945
$ 1,425 $ 507
$
574
$ 63
$
6
$
– $ 2,575
$ 21,053 $ 8,223
– $ 1,241
$
$ 7,737
$ 128
$ 1,337
$ 49
$ 2,835
$
– $
$ (1,443) $ 39,742
– $ 1,418
$ 4,739 $
– $ 1,270
$
– $
3
$
– $ 6,012
(1) All significant inter-company balances and transactions have been eliminated on consolidation except for certain transactions between non-regulated and
regulated entities. Management believes elimination of these transactions would understate PP&E, OM&G, or regulated fuel for generation and purchased
power. Inter-company transactions that have not been eliminated are measured at the amount of consideration established and agreed to by the related
parties. Eliminated transactions are included in determining reportable segments.
(2) Segment net income is reported on a basis that includes internally allocated financing costs of $13 million for the year ended December 31, 2022, between
the Gas Utilities and Infrastructure and Other segments.
GEOGRAPHICAL INFORMATION
Revenues (based on country of origin of the product or service sold)
For the
millions of dollars
United States
Canada
Barbados
The Bahamas
Dominica
Property Plant and Equipment:
As at
millions of dollars
United States
Canada
Barbados
The Bahamas
Year ended December 31
2022
2023
$ 5,310
1,727
389
137
–
$ 7,563
$ 5,346
1,725
384
122
11
$ 7,588
December 31
2023
December 31
2022
$ 18,588
4,878
576
334
$ 24,376
$ 17,382
4,689
583
342
$ 22,996
89
Notes to the Consolidated Financial StatementsEMERA 2023 ANNUAL REPORT 5. Revenue
The following disaggregates the Company’s revenue by major source:
millions of dollars
For the year ended December 31, 2023
Regulated Revenue
Residential
Commercial
Industrial
Other electric
Regulatory deferrals
Other (1)
Finance income (2) (3)
Regulated revenue
Non-Regulated Revenue
Marketing and trading margin (4)
Other non-regulated operating revenue
Mark-to-market (3)
Non-regulated revenue
Total operating revenues
For the year ended December 31, 2022
Regulated Revenue
Residential
Commercial
Industrial
Other electric
Regulatory deferrals
Other (1)
Finance income (2) (3)
Regulated revenue
Non-Regulated
Marketing and trading margin (4)
Other non-regulated operating revenue
Mark-to-market (3)
Non-regulated revenue
Total operating revenues
Florida
Electric
Utility
Canadian
Electric
Utilities
Electric
Other
Electric
Utilities
Gas
Gas Utilities
and
Infrastructure
Other
Inter-
Segment
Eliminations
Other
Total
$ 2,307
1,083
274
395
(522)
19
–
$ 3,556
$ 910
463
219
41
–
38
–
$ 1,671
$ 183
285
33
7
12
6
–
$ 526
–
–
–
–
–
–
- $
–
–
–
-
- $
$
$ 3,556
$ 1,671
$ 526
$ 1,799
869
230
398
(27)
18
–
$ 3,287
$ 834
427
353
28
–
33
–
$ 1,675
$ 184
282
32
6
6
8
–
518
$
–
–
–
–
–
–
– $
–
–
–
–
– $
$
$ 3,287
$ 1,675
$ 518
$
724
425
93
–
–
199
62
$ 1,503
–
21
–
21
$
$ 1,524
$ 800
461
83
–
–
283
61
$ 1,688
–
16
–
$
16
$ 1,704
$
- $
–
–
–
–
–
–
$
- $
–
(13)
–
–
(8)
- $ 4,124
2,256
606
443
(510)
254
62
(21) $ 7,235
96
27
216
$ 339
$ 339
96
–
25
(23)
(9)
207
(32) $ 328
(53) $ 7,563
$
$
$
– $
–
–
–
–
–
–
$
– $
–
–
(7)
–
–
(7)
–
$ 3,617
2,039
691
432
(21)
335
61
(14) $ 7,154
143
16
281
$ 440
$ 440
–
(10)
(12)
143
22
269
(22) $ 434
(36) $ 7,588
$
$
(1) Other includes rental revenues, which do not represent revenue from contracts with customers.
(2) Revenue related to Brunswick Pipeline’s service agreement with Repsol Energy Canada.
(3) Revenue which does not represent revenues from contracts with customers.
(4) Includes gains (losses) on settlement of energy related derivatives, which do not represent revenue from contracts with customers.
Remaining Performance Obligations
Remaining performance obligations primarily represent gas transportation contracts, lighting contracts, and long-term steam
supply arrangements with fixed contract terms. As of December 31, 2023, the aggregate amount of the transaction price
allocated to remaining performance obligations was $488 million (2022 – $450 million). This amount includes $134 million of
future performance obligations related to a gas transportation contract between SeaCoast and PGS through 2040. This amount
excludes contracts with an original expected length of one year or less and variable amounts for which Emera recognizes revenue
at the amount to which it has the right to invoice for services performed. Emera expects to recognize revenue for the remaining
performance obligations through 2043.
90
Notes to the Consolidated Financial StatementsEMERA 2023 ANNUAL REPORT
6. Regulatory Assets and Liabilities
Regulatory assets represent prudently incurred costs that have been deferred because it is probable they will be recovered
through future rates or tolls collected from customers. Management believes existing regulatory assets are probable for recovery
either because the Company received specific approval from the applicable regulator, or due to regulatory precedent established
for similar circumstances. If management no longer considers it probable that an asset will be recovered, deferred costs are
charged to income.
Regulatory liabilities represent obligations to make refunds to customers or to reduce future revenues for previous collections.
If management no longer considers it probable that a liability will be settled, the related amount is recognized in income.
For regulatory assets and liabilities that are amortized, the amortization is as approved by the respective regulator.
As at
millions of dollars
Regulatory assets
Deferred income tax regulatory assets
TEC capital cost recovery for early retired assets
NSPI FAM
Pension and post-retirement medical plan
Cost recovery clauses
Deferrals related to derivative instruments
Storm cost recovery clauses
Environmental remediations
Stranded cost recovery
NMGC winter event gas cost recovery
Other
Current
Long-term
Total regulatory assets
Regulatory liabilities
Accumulated reserve – COR
Deferred income tax regulatory liabilities
Cost recovery clauses
BLPC Self-insurance fund ("SIF") (note 32)
Deferrals related to derivative instruments
NMGC gas hedge settlements (note 18)
Other
Current
Long-term
Total regulatory liabilities
December 31
2023
December 31
2022
$ 1,233
671
395
364
151
88
52
26
25
–
100
$ 3,105
$ 339
2,766
$ 3,105
849
830
32
29
17
–
15
$ 1,772
$ 168
1,604
$ 1,772
$ 1,166
674
307
369
707
30
138
27
27
69
106
$ 3,620
$ 602
3,018
$ 3,620
895
877
70
30
230
162
9
$ 2,273
495
$
1,778
$ 2,273
Deferred Income Tax Regulatory Assets and Liabilities
To the extent deferred income taxes are expected to be recovered from or returned to customers in future years, a regulatory
asset or liability is recognized as appropriate.
91
Notes to the Consolidated Financial StatementsEMERA 2023 ANNUAL REPORT
TEC Capital Cost Recovery for Early Retired Assets
This regulatory asset is related to the remaining net book value of Big Bend Power Station Units 1 through 3 and smart meter
assets that were retired. The balance earns a rate of return as permitted by the FPSC and is recovered as a separate line item on
customer bills for a period of 15 years. This recovery mechanism is authorized by and survives the term of the settlement agreement
approved by the FPSC in 2021. For further information, refer to “Big Bend Modernization Project” in the TEC section below.
NSPI FAM
NSPI has a FAM, approved by the UARB, allowing NSPI to recover fluctuating fuel and certain fuel-related costs from customers
through regularly scheduled fuel rate adjustments. Differences between prudently incurred fuel costs and amounts recovered
from customers through electricity rates in a year are deferred to a FAM regulatory asset or liability and recovered from or
returned to customers in subsequent periods.
Pension and Post-Retirement Medical Plan
This asset is primarily related to the deferred costs of pension and post-retirement benefits at TEC, PGS and NMGC. It is included
in rate base and earns a rate of return as permitted by the FPSC and NMPRC, as applicable. It is amortized over the remaining
service life of plan participants.
Cost Recovery Clauses
These assets and liabilities are related to TEC, PGS and NMGC clauses and riders. They are recovered or refunded through cost-
recovery mechanisms approved by the FPSC or New Mexico Public Regulation Commission (“NMPRC”), as applicable, on a dollar-
for-dollar basis in a subsequent period.
Deferrals Related to Derivative Instruments
This asset is primarily related to NSPI deferring changes in FV of derivatives that are documented as economic hedges or that
do not qualify for NPNS exemption, as a regulatory asset or liability as approved by the UARB. The realized gain or loss is
recognized when the hedged item settles in regulated fuel for generation and purchased power, other income, inventory, or
OM&G, depending on the nature of the item being economically hedged.
Storm Cost Recovery Clauses
TEC and PGS Storm Reserve:
The storm reserve is for hurricanes and other named storms that cause significant damage to TEC and PGS systems. As allowed
by the FPSC, if charges to the storm reserve exceed the storm liability, the excess is to be carried as a regulatory asset. TEC and
PGS can petition the FPSC to seek recovery of restoration costs over a 12-month period or longer, as determined by the FPSC, as
well as replenish the reserve. In 2022, TEC and PGS were impacted by Hurricane Ian. For further information, refer to “TEC Storm
Reserve” in the Florida Electric Utility section below.
NSPI Storm Rider:
NSPI has a UARB approved storm rider for each of 2023, 2024 and 2025, which gives NSPI the option to apply to the UARB for
recovery of costs if major storm restoration expenses exceed approximately $10 million in a given year.
GBPC Storm Restoration:
This asset represents storm restoration costs incurred by GBPC. GBPC maintains insurance for its generation facilities and, as
with most utilities, its transmission and distribution networks are not covered by commercial insurance.
In January 2020, the Grand Bahama Port Authority (“GBPA”) approved recovery of $15 million USD of 2019 costs related to
Hurricane Dorian, over a five-year period from 2021 through 2025.
Restoration costs associated with Hurricane Matthew in 2016 are being recovered through an approved fuel charge. For further
information, refer to “Storm Restoration Costs – Hurricane Matthew” in the GBPC section below.
92
Notes to the Consolidated Financial StatementsEMERA 2023 ANNUAL REPORT Environmental Remediations
This asset is primarily related to PGS costs associated with environmental remediation at Manufactured Gas Plant sites. The
balance is included in rate base, partially offsetting the related liability, and earns a rate of return as permitted by the FPSC.
The timing of recovery is based on a settlement agreement approved by the FPSC.
Stranded Cost Recovery
Due to decommissioning of a GBPC steam turbine in 2012, the GBPA approved recovery of a $21 million USD stranded cost
through electricity rates; it is included in rate base and expected to be included in rates in future years.
NMGC Winter Event Gas Cost Recovery
In February 2021, the State of New Mexico experienced an extreme cold weather event that resulted in an incremental
$108 million USD for gas costs above what it would normally have paid during this period. NMGC normally recovers gas supply
and related costs through a purchased gas adjustment clause (“PGAC”). On June 15, 2021, the NMPRC approved recovery of
$108 million USD and related borrowing costs in customer rates over a period of 30 months from July 1, 2021, to December 31, 2023.
Accumulated Reserve – COR
This regulatory liability represents the non-ARO COR reserve in TEC, PGS, NMGC and NSPI. AROs represent the FV of estimated
cash flows associated with the Company’s legal obligation to retire its PP&E. Non-ARO COR represent estimated funds received
from customers through depreciation rates to cover future COR of PP&E value upon retirement that are not legally required. This
reduces rate base for ratemaking purposes. This liability is reduced as COR are incurred and increased as depreciation is recorded
for existing assets and as new assets are put into service.
NMGC Gas Hedge Settlements
This regulatory liability represents regulatory deferral of gas options exercised above strike price but settled subsequent to the
period end. The value from cash settlement of these options flows to customers via the PGAC.
Other Regulatory Assets and Liabilities
Comprised of regulatory assets and liabilities that are not individually significant.
REGULATORY ENVIRONMENTS AND UPDATES
Florida Electric Utility
TEC is regulated by the FPSC and is also subject to regulation by the Federal Energy Regulatory Commission. The FPSC sets
rates at a level that allows utilities such as TEC to collect total revenues or revenue requirements equal to their cost of providing
service, plus an appropriate return on invested capital. Base rates are determined in FPSC rate setting hearings which can occur
at the initiative of TEC, the FPSC or other interested parties.
TEC’s approved regulated return on equity (“ROE”) range for 2023 and 2022 was 9.25 per cent to 11.25 per cent based on an
allowed equity capital structure of 54 per cent. An ROE of 10.20 per cent (2022 – 10.20 per cent) is used for the calculation of the
return on investments for clauses.
Base Rates:
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.
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.
93
Notes to the Consolidated Financial StatementsEMERA 2023 ANNUAL REPORT Fuel Recovery and Other Cost Recovery Clauses:
TEC has a fuel recovery clause approved by the FPSC, allowing the opportunity to recover fluctuating fuel expenses from
customers through annual fuel rate adjustments. The FPSC annually approves cost-recovery rates for purchased power, capacity,
environmental and conservation costs, including a return on capital invested. Differences between prudently incurred fuel
costs and the cost-recovery rates and amounts recovered from customers through electricity rates in a year are deferred to a
regulatory asset or liability and recovered from or returned to customers in subsequent periods.
On 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.
The mid-course fuel adjustment requested by TEC on January 19, 2022, was approved on March 1, 2022. The rate increase,
effective with the first billing cycle in April 2022, covered higher fuel and capacity costs of $169 million USD, and was spread over
customer bills from April 1, 2022 through December 2022.
Big Bend Modernization Project:
TEC invested $876 million USD, including $91 million USD of AFUDC, between 2018 and 2022 to modernize the Big Bend Power
Station. The modernization project repowered Big Bend Unit 1 with natural gas combined-cycle technology and eliminated coal
as this unit’s fuel. As part of the modernization project, TEC in 2020 retired the Unit 1 components that would not be used in the
modernized plant and did the same for Big Bend Unit 2 in 2021. TEC retired Big Bend Unit 3 in 2023 as it was in the best interests
of the customers from an economic, environmental risk and operational perspective. On December 31, 2021, the remaining costs
of the retired Big Bend coal generation assets, Units 1 through 3, of $636 million USD and $267 million USD in accumulated
depreciation were reclassified to a regulatory asset on the balance sheet.
TEC’s 2021 settlement agreement provides for cost recovery of the Big Bend Modernization project in two phases. The first phase
was a revenue increase to cover the costs of the assets in service during 2022, among other items. The remainder of the project
costs were recovered as part of the 2023 subsequent year adjustment. The settlement agreement also includes a new charge
to recover the remaining costs of the retired Big Bend coal generation assets, Units 1 through 3, which are spread over 15 years,
effective January 1, 2022. This recovery mechanism was authorized by and survives the term of the settlement agreement
approved by the FPSC in 2021.
Storm Reserve:
In September 2022, TEC was impacted by Hurricane Ian, with $119 million USD of restoration costs charged against TEC’s FPSC
approved storm reserve. Total restoration costs charged to the storm reserve exceeded the reserve balance and have been
deferred as a regulatory asset for future recovery.
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.
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.
94
Notes to the Consolidated Financial StatementsEMERA 2023 ANNUAL REPORT Storm Protection Cost Recovery Clause and Settlement Agreement:
The Storm Protection Plan (“SPP”) Cost Recovery Clause provides a process for Florida investor-owned utilities, including TEC,
to recover transmission and distribution storm hardening costs for incremental activities not already included in base rates.
Differences between prudently incurred clause-recoverable costs and amounts recovered from customers through electricity
rates in a year are deferred and recovered from or returned to customers in a subsequent year. A settlement agreement was
approved on August 10, 2020, and TEC’s cost recovery began in January 2021. The current approved plan addressed the years
2023, 2024 and 2025 and was approved by the FPSC on October 4, 2022.
Canadian Electric Utilities
NSPI
NSPI is a public utility as defined in the Public Utilities Act of Nova Scotia (“Public Utilities Act”) and is subject to regulation
under the Public Utilities Act by the UARB. The Public Utilities Act gives the UARB supervisory powers over NSPI’s operations and
expenditures. Electricity rates for NSPI’s customers are also subject to UARB approval. NSPI is not subject to a general annual
rate review process, but rather participates in hearings held from time to time at NSPI’s or the UARB’s request.
NSPI is regulated under a cost-of-service model, with rates set to recover prudently incurred costs of providing electricity
service to customers and provide a reasonable return to investors. NSPI’s approved regulated ROE range for 2023 and 2022 was
8.75 per cent to 9.25 per cent based on an actual five quarter average regulated common equity component of up to 40 per cent
of approved rate base.
General Rate Application (“GRA”):
On February 2, 2023, the UARB approved the GRA settlement agreement between NSPI, key customer representatives and
participating interest groups. This resulted in average customer rate increases of 6.9 per cent effective on February 2, 2023, and
further average increases of 6.5 per cent on January 1, 2024, with any under or over-recovery of fuel costs addressed through
the UARB’s established FAM process. It also established a storm rider and a demand-side management rider. On March 27, 2023,
the UARB issued a final order approving the electricity rates effective on February 2, 2023.
Fuel Recovery:
For the period of 2020 through 2022, NSPI operated under a three-year fuel stability plan with no fuel rate adjustments related
to the under-recovery of fuel and fuel-related costs in the period.
On January 29, 2024, NSPI applied to the UARB for approval of a structure that would begin to recover the outstanding 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.
Storm Rider:
The storm rider was effective as of the GRA decision date. The application for deferral and recovery of the storm rider is made
in the year following the year of the incurred cost, with recovery beginning in the year after the application. Total major storm
restoration expense for 2023 was $31 million, of which $21 million was deferred to the storm rider.
Hurricane Fiona:
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.
95
Notes to the Consolidated Financial StatementsEMERA 2023 ANNUAL REPORT Maritime Link:
The Maritime Link is a $1.8 billion (including AFUDC) transmission project including two 170-kilometre sub-sea cables, connecting
the island of Newfoundland and Nova Scotia. The Maritime Link entered service on January 15, 2018 and NSPI started interim
assessment payments to NSPML at that time.
Any difference between the amounts recovered from customers through rates and those approved by the UARB through the
NSPML interim assessment application will be addressed through the FAM.
Nova Scotia Cap-and-Trade (“Cap-and-Trade”) Program:
As of December 31, 2022, the FAM included a cumulative $166 million in fuel costs related to the accrued purchase of emissions
credits and $6 million related to credits purchased from provincial auctions. On March 16, 2023, the Province of Nova Scotia
provided NSPI with emissions allowances sufficient to achieve compliance for the 2019 through 2022 period. As such, compliance
costs accrued of $166 million were reversed in Q1 2023. The credits NSPI purchased from provincial auctions in the amount of
$6 million were not refunded and no further costs were incurred to achieve compliance with the Cap-and-Trade Program.
Extra Large Industrial Active Demand Tariff:
On July 5, 2023, NSPI received approval from the UARB to change the methodology in which fuel cost recovery from an
industrial customer is calculated. Due to significant volatility in commodity prices in 2022, the previous methodology did not
result in a reasonable determination of the fuel cost to serve this customer. The change in methodology, effective January
1, 2022, results in a shifting of fuel costs from this industrial customer to the FAM. This adjustment was recorded in Q2 2023
resulting in a $51 million increase to the FAM regulatory asset and an offsetting decrease to unbilled revenue within Receivables
and other current assets. This adjustment had minimal impact on earnings.
NSPML
Equity earnings from the Maritime Link are dependent on the approved ROE and operational performance of NSPML. NSPML’s
approved regulated ROE range is 8.75 per cent to 9.25 per cent, based on an actual five-quarter average regulated common
equity component of up to 30 per cent.
Nalcor’s Nova Scotia Block (“NS Block”) delivery obligations commenced on August 15, 2021 and delivery will continue over the
next 35 years pursuant to the agreements.
In February 2022, the UARB issued its decision and Board Order approving NSPML’s requested rate base of approximately
$1.8 billion less $9 million of costs ($7 million after-tax) that would not have otherwise been recoverable if incurred by NSPI.
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.
On December 21, 2023, NSPML received approval to collect up to $164 million (2023 – $164 million) from NSPI for the recovery of
costs associated with the Maritime Link in 2024; subject to a holdback of up to $4 million a month, as discussed above.
96
Notes to the Consolidated Financial StatementsEMERA 2023 ANNUAL REPORT Gas Utilities and Infrastructure
PGS
PGS is regulated by the FPSC. The FPSC sets rates at a level that allows utilities such as PGS to collect total revenues or revenue
requirements equal to their cost of providing service, plus an appropriate return on invested capital.
PGS’s approved ROE range for 2023 and 2022 was 8.9 per cent to 11.0 per cent with a 9.9 per cent midpoint, based on an allowed
equity capital structure of 54.7 per cent.
Base Rates:
On April 4, 2023, PGS filed a rate case with the FPSC and a hearing for the matter was held in September 2023. On November 9,
2023, the FPSC approved a $118 million USD increase to base revenues which includes $11 million USD transferred from the
cast iron and bare steel replacement rider, for a net incremental increase to base revenues of $107 million USD. This reflects a
10.15 per cent midpoint ROE with an allowed equity capital structure of 54.7 per cent. A final order was issued on December 27,
2023, with the new rates effective January 2024.
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.
Fuel Recovery:
PGS recovers the costs it pays for gas supply and interstate transportation for system supply through its PGAC. This clause is
designed to recover actual costs incurred by PGS for purchased gas, gas storage services, interstate pipeline capacity, and other
related items associated with the purchase, distribution, and sale of natural gas to its customers. These charges may be adjusted
monthly based on a cap approved annually by the FPSC.
Recovery of Energy Conservation and Pipeline Replacement Programs:
The FPSC annually approves a conservation charge that is intended to permit PGS to recover prudently incurred expenditures
in developing and implementing cost effective energy conservation programs which are required by Florida law and approved
and monitored by the FPSC. PGS also has a Cast Iron/Bare Steel Pipe Replacement clause to recover the cost of accelerating the
replacement of cast iron and bare steel distribution lines in the PGS system. In February 2017, the FPSC approved expansion of
the Cast Iron/Bare Steel clause to allow recovery of accelerated replacement of certain obsolete plastic pipe. The majority of cast
iron and bare steel pipe has been removed from its system, with replacement of obsolete plastic pipe continuing until 2028 under
the rider.
NMGC
NMGC is subject to regulation by the NMPRC. The NMPRC sets rates at a level that allows NMGC to collect total revenues equal to
its cost of providing service, plus an appropriate return on invested capital.
NMGC’s approved ROE for 2023 and 2022 was 9.375 per cent on an allowed equity capital structure of 52 per cent.
Base Rates:
On September 14, 2023, NMGC filed a rate case with the NMPRC for new base rates to become effective Q4 2024. NMGC
requested $49 million USD 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.
Fuel Recovery:
NMGC recovers gas supply costs through a PGAC. This clause recovers actual costs for purchased gas, gas storage services,
interstate pipeline capacity, and other related items associated with the purchase, transmission, distribution, and sale of natural
gas to its customers. On a monthly basis, NMGC can adjust charges based on the next month’s expected cost of gas and any prior
month under-recovery or over-recovery. The NMPRC requires that NMGC annually file a reconciliation of the PGAC period costs
and recoveries. NMGC must file a PGAC Continuation Filing with the NMPRC every four years to establish that the continued use
of the PGAC is reasonable and necessary. NMGC received approval of its PGAC Continuation in December 2020, for the four-year
period ending December 2024.
97
Notes to the Consolidated Financial StatementsEMERA 2023 ANNUAL REPORT Integrity Management Programs (“IMP”) Regulatory Asset:
A portion of NMGC’s annual spending on infrastructure is for IMP, or the replacement and update of legacy systems. These programs
are driven both by NMGC integrity management plans and federal and state mandates. In December 2020, NMGC received approval
through its rate case to defer costs through an IMP regulatory asset for certain of its IMP capital investments occurring between
January 1, 2022 and December 31, 2023 and petitioned recovery of the regulatory asset in its rate case filed on December 13, 2021.
On November 30, 2022, the NMPRC issued a Final Order that included approval of recovery of the IMP regulatory asset.
Brunswick Pipeline
Brunswick Pipeline is a 145-kilometre pipeline delivering natural gas from the Saint John LNG import terminal near Saint John,
New Brunswick to markets in the northeastern United States. Brunswick Pipeline entered into a 25-year firm service agreement
commencing in July 2009 with Repsol Energy North America Canada Partnership. The agreement provides for a predetermined
toll increase in the fifth and fifteenth year of the contract. The pipeline is considered a Group II pipeline regulated by the Canada
Energy Regulator (“CER”). The CER Gas Transportation Tariff is filed by Brunswick Pipeline in compliance with the requirements
of the CER Act and sets forth the terms and conditions of the transportation rendered by Brunswick Pipeline.
Other Electric Utilities
BLPC
BLPC is regulated by the Fair Trading Commission (“FTC”), under the Utilities Regulation (Procedural) Rules 2003. BLPC is
regulated under a cost-of-service model, with rates set to recover prudently incurred costs of providing electricity service to
customers plus an appropriate return on capital invested. BLPC’s approved regulated return on rate base was 10 per cent for
2023 and 2022.
Licenses:
BLPC currently operates pursuant to a single integrated license to generate, transmit and distribute electricity on the island
of Barbados until 2028. In 2019, the Government of Barbados passed legislation requiring multiple licenses for the supply of
electricity. In 2021, BLPC reached commercial agreement with the Government of Barbados for each of the license types, subject
to the passage of implementing legislation. The timing of the final enactment is unknown at this time, but BLPC will work towards
the implementation of the licenses once enacted.
Base Rates:
In 2021, BLPC submitted a general rate review application to the FTC. In September 2022, the FTC granted BLPC interim rate
relief, allowing an increase in base rates of approximately $1 million USD per month. On February 15, 2023, the FTC issued
a decision on the application which included the following significant items: an allowed regulatory ROE of 11.75 per cent, an
equity capital structure of 55 per cent, a directive to update the major components of rate base to September 16, 2022, and a
directive to establish regulatory liabilities 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.
98
Notes to the Consolidated Financial StatementsEMERA 2023 ANNUAL REPORT Fuel Recovery:
BLPC’s fuel costs flow through a fuel pass-through mechanism which provides opportunity to recover all prudently incurred fuel
costs from customers in a timely manner. The calculation of the fuel charge is adjusted on a monthly basis and reported to the
FTC for approval.
Clean Energy Transition Program (“CETP”):
On May 31, 2023, the FTC approved BLPC’s application to establish an alternative cost recovery mechanism to recover prudently
incurred costs associated with its CETP (the “Decision”). The mechanism is intended to facilitate the timely recovery between
rate cases of costs associated with approved renewable energy assets. BLPC will be required to submit an individual application
for the recovery of costs of each asset through the cost recovery mechanism, meeting the minimum criteria as set out in the
Decision. On October 5, 2023, BLPC applied to the FTC to recover the costs of a battery storage system through the CETP.
Fuel Hedging:
On October 21, 2021, the FTC approved BLPC’s application to implement a fuel hedging program which will be incorporated into
the calculation of the fuel clause adjustment. On November 10, 2021, BLPC requested the FTC review the required 50/50 cost
sharing arrangement between BLPC and customers in relation to the hedging administrative costs, or any gains and losses
associated with the hedging program.
GBPC
GBPC is regulated by the GBPA. The GBPA has granted GBPC a licensed, regulated and exclusive franchise to produce, transmit
and distribute electricity on the island until 2054. Rates are set to recover prudently incurred costs of providing electricity
service to customers plus an appropriate return on rate base. GBPC’s approved regulated return on rate base was 8.32 per cent
for 2023 (2022 – 8.23 per cent).
Base Rates:
There is a fuel pass-through mechanism and tariff review policy with new rates submitted every three years. On January 14,
2022, the GBPA issued its decision on GBPC’s application for rate review that was filed with the GBPA on September 23, 2021.
The decision, which became effective April 1, 2022, allows for an increase in revenues of $3.5 million USD. The rates include a
regulatory ROE of 12.84 per cent.
Fuel Recovery:
GBPC’s fuel costs flow through a fuel pass-through mechanism which provides the opportunity to recover all prudently incurred
fuel costs from customers in a timely manner.
Effective November 1, 2022, GBPC’s fuel pass through charge was increased due to an increase in global oil prices impacting the
unhedged fuel cost. In 2023, the fuel pass through charge was adjusted monthly, in-line with actual fuel costs.
Storm Restoration Costs – Hurricane Matthew:
As part of the recovery of costs incurred as a result of Hurricane Matthew, in 2016, the GBPA approved a fixed per kWh fuel
charge and allowed the difference between this and the actual cost of fuel to be applied to the Hurricane Matthew regulatory
asset. As part of its decision on GBPC’s application for rate review, issued January 14, 2022, and effective April 1, 2022, the GBPA
approved the continued amortization of the remaining regulatory asset over the three year period ending December 31, 2024.
99
Notes to the Consolidated Financial StatementsEMERA 2023 ANNUAL REPORT 7. Investments Subject to Significant Influence and Equity Income
millions of dollars
LIL (1)
NSPML
M&NP (2)
Lucelec (2)
Bear Swamp (3)
Carrying Value
As at December 31
2022
2023
Equity Income
For the year ended
December 31
2022
2023
$
747
489
118
48
–
$ 1,402
$
740
501
128
49
–
$ 1,418
$
63
46
21
4
12
$ 146
$
58
29
21
4
17
$ 129
Percentage
of
Ownership
2023
31.0
100.0
12.9
19.5
50.0
(1) Emera indirectly owns 100 per cent of the Class B units, which comprises 24.5 per cent of the total units issued. Percentage ownership in LIL is subject
to change, based on the balance of capital investments required from Emera and Nalcor Energy to complete construction of the LIL. Emera’s ultimate
percentage investment in LIL will be determined upon final costing of all transmission projects related to the Muskrat Falls development, including the LIL,
Labrador Transmission Assets and Maritime Link Projects, such that Emera’s total investment in the Maritime Link and LIL will equal 49 per cent of the cost
of all of these transmission developments.
(2) Emera has significant influence over the operating and financial decisions of these companies through Board representation and therefore, records its
investment in these entities using the equity method.
(3) The investment balance in Bear Swamp is in a credit position primarily as a result of a $179 million distribution received in 2015. Bear Swamp’s credit
investment balance of $81 million (2022 – $95 million) is recorded in Other long-term liabilities on the Consolidated Balance Sheets.
Equity investments include a $10 million difference between the cost and the underlying FV of the investees’ assets as at the date
of acquisition. The excess is attributable to goodwill.
Emera accounts for its variable interest investment in NSPML as an equity investment (note 32). NSPML’s consolidated
summarized balance sheets are illustrated as follows:
As at
millions of dollars
Balance Sheets
Current assets
PP&E
Regulatory assets
Non-current assets
Total assets
Current liabilities
Long-term debt (1)
Non-current liabilities
Equity
Total liabilities and equity
(1 ) The project debt has been guaranteed by the Government of Canada.
8. Other Income, Net
For the
millions of dollars
Interest income
AFUDC
Pension non-current service cost recovery
FX gains (losses)
TECO Guatemala Holdings award (1 )
Other
December 31
2023
December 31
2022
$
21
1,473
272
29
$ 1,795
48
$
1,109
149
489
$ 1,795
$
17
1,517
265
29
$ 1,828
48
$
1,149
130
501
$ 1,828
Year ended December 31
2022
2023
$
$
43
38
35
20
–
22
$ 158
$
25
52
24
(26)
63
7
145
(1) On December 15, 2022, a payment of $63 million 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 in TGH, a wholly-owned
subsidiary of TECO Energy.
100
Notes to the Consolidated Financial StatementsEMERA 2023 ANNUAL REPORT 9. Interest Expense, Net
Interest expense, net consisted of the following:
For the
millions of Canadian dollars
Interest on debt
Allowance for borrowed funds used during construction
Other
10. Income Taxes
Year ended December 31
2022
2023
$
954
(16)
(13)
$ 925
$ 727
(21)
3
$ 709
The income tax provision, for the years ended December 31, differs from that computed using the enacted combined Canadian
federal and provincial statutory income tax rate for the following reasons:
millions of dollars
Income before provision for income taxes
Statutory income tax rate
Income taxes, at statutory income tax rate
Deferred income taxes on regulated income recorded as regulatory assets and regulatory liabilities
Tax credits
Foreign tax rate variance
Amortization of deferred income tax regulatory liabilities
Tax effect of equity earnings
GBPC impairment charge
Other
Income tax expense
Effective income tax rate
2023
2022
$ 1,173
29.0%
340
(72)
(53)
(36)
(33)
(15)
–
(3)
$ 128
11%
$ 1,194
29.0%
346
(70)
(18)
(44)
(33)
(10)
21
(7)
$ 185
15%
On August 16, 2022, the United States Inflation Reduction Act (“IRA”) was signed into legislation. The IRA includes numerous tax
incentives for clean energy, such as the extension and modification of existing investment and production tax credits for projects
placed in service through 2024 and introduces new technology-neutral clean energy related tax credits beginning in 2025. As of
December 31, 2023, the Company has recorded a $30 million (2022 – $9 million) regulatory liability on the Consolidated Balance
Sheets in recognition of its obligation to pass the incremental tax benefits realized to customers.
The following table reflects the composition of taxes on income from continuing operations presented in the Consolidated
Statements of Income for the years ended December 31:
millions of dollars
Current income taxes
Canada
United States
Deferred income taxes
Canada
United States
Investment tax credits
United States
Operating loss carryforwards
Canada
United States
Income tax expense
2023
2022
$
$
26
5
25
8
93
128
122
252
(29)
(7)
(93)
(2)
(94)
(121)
$ 128
$ 185
101
Notes to the Consolidated Financial StatementsEMERA 2023 ANNUAL REPORT The following table reflects the composition of income before provision for income taxes presented in the Consolidated
Statements of Income for the years ended December 31:
millions of dollars
Canada
United States
Other
Income before provision for income taxes
2023
2022
$
171
964
38
$ 1,173
$
173
1,063
(42)
$ 1,194
The deferred income tax assets and liabilities presented in the Consolidated Balance Sheets as at December 31 consisted of
the following:
millions of dollars
Deferred income tax assets:
Tax loss carryforwards
Tax credit carryforwards
Derivative instruments
Regulatory liabilities
Other
Total deferred income tax assets before valuation allowance
Valuation allowance
Total deferred income tax assets after valuation allowance
Deferred income tax (liabilities):
PP&E
Derivative instruments
Investments subject to significant influence
Regulatory assets
Other
Total deferred income tax liabilities
Consolidated Balance Sheets presentation:
Long-term deferred income tax assets
Long-term deferred income tax liabilities
Net deferred income tax liabilities
2023
2022
$ 1,195
454
205
175
372
2,401
(363)
$ 2,038
$ 1,207
415
45
264
341
2,272
(312)
$ 1,960
$ (3,223) $ (2,981)
(125)
(181)
(310)
(322)
$ (4,182) $ (3,919)
(235)
(216)
(196)
(312)
$
$
208
(2,352)
237
(2,196)
$ (2,144) $ (1,959)
Considering all evidence regarding the utilization of the Company’s deferred income tax assets, it has been determined that
Emera is more likely than not to realize all recorded deferred income tax assets, except for certain loss carryforwards and
unrealized capital losses on long-term debt and investments. A valuation allowance of $363 million has been recorded as at
December 31, 2023 (2022 – $312 million) related to the loss carryforwards, long-term debt and investments.
The Company intends to indefinitely reinvest earnings from certain foreign operations. Accordingly, as at December 31, 2023,
$4.7 billion (2022 – $3.8 billion) in cumulative temporary differences for which deferred taxes might otherwise be required, have
not been recognized. It is impractical to estimate the amount of income and withholding tax that might be payable if a reversal of
temporary differences occurred.
102
Notes to the Consolidated Financial StatementsEMERA 2023 ANNUAL REPORT Emera’s NOL, capital loss and tax credit carryforwards and their expiration periods as at December 31, 2023 consisted of
the following:
millions of dollars
Canada
NOL
Capital loss
United States
Federal NOL
State NOL
Tax credit
Other
NOL
Tax
Carryforwards
Subject to
Valuation
Allowance
Net Tax
Carryforwards
Expiration
Period
$ 2,914
73
$ (1,164) $ 1,750
(73)
–
2026–2043
Indefinite
$
$ 1,360
1,003
454
(1) $ 1,359
1,002
451
(1)
(3)
2036–Indefinite
2026–Indefinite
2025–2043
$
81
$
(28) $
53
2024–2030
The following table provides details of the change in unrecognized tax benefits for the years ended December 31 as follows:
millions of dollars
Balance, January 1
Increases due to tax positions related to current year
Increases due to tax positions related to a prior year
Decreases due to tax positions related to a prior year
Balance, December 31
2023
33
5
1
(2)
37
$
$
2022
28
5
2
(2)
33
$
$
Unrecognized tax benefits relate to the timing of certain tax deductions at NSPI and research and development tax credits
primarily at TEC. The total amount of unrecognized tax benefits as at December 31, 2023 was $37 million (2022 – $33 million),
which would affect the effective tax rate if recognized. The total amount of accrued interest with respect to unrecognized tax
benefits was $9 million (2022 – $7 million) with $2 million interest expense recognized in the Consolidated Statements of Income
(2022 – $1 million). No penalties have been accrued. The balance of unrecognized tax benefits could change in the next 12 months
as a result of resolving Canada Revenue Agency (“CRA”) and Internal Revenue Service audits. A reasonable estimate of any
change cannot be made at this time.
During 2022, the CRA issued notices of reassessment to NSPI for the 2013 through 2016 taxation years. NSPI and the CRA are
currently in a dispute with respect to the timing of certain tax deductions for its 2006 through 2010 and 2013 through 2016
taxation years. The ultimate permissibility of the tax deductions is not in dispute; rather, it is the timing of those deductions. The
cumulative net amount in dispute to date is $126 million (2022 – $126 million), including interest. NSPI has prepaid $55 million of
the amount in dispute, as required by CRA.
On November 29, 2019, NSPI filed a Notice of Appeal with the Tax Court of Canada with respect to its dispute of the 2006
through 2010 taxation years. Should NSPI be successful in defending its position, all payments including applicable interest will
be refunded. If NSPI is unsuccessful in defending any portion of its position, the resulting taxes and applicable interest will be
deducted from amounts previously paid, with the difference, if any, either owed to, or refunded from, the CRA. The related tax
deductions will be available in subsequent years.
Should NSPI be similarly reassessed by the CRA for years not currently in dispute, further payments will be required; however,
the ultimate permissibility of these deductions would be similarly not in dispute.
NSPI and its advisors believe that NSPI has reported its tax position appropriately. NSPI continues to assess its options to
resolving the dispute; however, the outcome of the Notice of Appeal process is not determinable at this time.
Emera files a Canadian federal income tax return, which includes its Nova Scotia provincial income tax. Emera’s subsidiaries
file Canadian, US, Barbados, and St. Lucia income tax returns. As at December 31, 2023, the Company’s tax years still open to
examination by taxing authorities include 2005 and subsequent years.
103
Notes to the Consolidated Financial StatementsEMERA 2023 ANNUAL REPORT
11. Common Stock
Authorized: Unlimited number of non-par value common shares.
Issued and outstanding:
Balance, January 1
Issuance of common stock under ATM program (1 ) (2)
Issued under the DRIP, net of discounts
Senior management stock options exercised and Employee
Share Purchase Plan
Balance, December 31
millions of
shares
269.95
8.29
5.26
0.62
2023
millions of
dollars
$ 7,762
397
272
31
millions of
shares
261.07
4.07
4.21
0.60
2022
millions of
dollars
$ 7,242
248
238
34
284.12
$ 8,462
269.95
$ 7,762
(1) For the year ended December 31, 2022, a total of 4,072,469 common shares were issued under Emera’s ATM program at an average price of $61.31 per share
for gross proceeds of $250 million ($248 million net of after-tax issuance costs).
(2) For the year ended December 31, 2023, a total of 8,287,037 common shares were issued under Emera’s ATM program at an average price of $48.27 per share
for gross proceeds of $400 million ($397 million net of after-tax issuance costs).
As at December 31, 2023, the following common shares were reserved for issuance: 6 million (2022 – 6 million) under the senior
management stock option plan, 2 million (2022 – 2.7 million) under the employee common share purchase plan and 18 million
(2022 – 10 million) under the DRIP.
The issuance of common shares under the common share compensation arrangements does not allow the plans to exceed
10 per cent of Emera’s outstanding common shares. As at December 31, 2023, Emera was in compliance with this requirement.
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.
12. Earnings Per Share
Basic earnings per share is determined by dividing net income attributable to common shareholders by the weighted average
number of common shares outstanding during the period. Diluted EPS is computed by dividing net income attributable to
common shareholders by the weighted average number of common shares outstanding during the period, adjusted for the
exercise and/or conversion of all potentially dilutive securities. Such dilutive items include Company contributions to the senior
management stock option plan, convertible debentures and shares issued under the DRIP.
The following table reconciles the computation of basic and diluted earnings per share:
For the
millions of dollars (except per share amounts)
Numerator
Net income attributable to common shareholders
Diluted numerator
Denominator
Weighted average shares of common stock outstanding – basic
Stock-based compensation
Weighted average shares of common stock outstanding – diluted
Earnings per common share
Basic
Diluted
Year ended December 31
2022
2023
$ 977.7
977.7
$ 945.1
945.1
273.6
0.2
273.8
265.5
0.4
265.9
$
$
3.57
3.57
$ 3.56
$ 3.55
104
Notes to the Consolidated Financial StatementsEMERA 2023 ANNUAL REPORT 13. Accumulated Other Comprehensive Income
The components of AOCI are as follows:
millions of dollars
For the year ended December 31, 2023
Balance, January 1, 2023
Other comprehensive (loss) income before
reclassifications
Amounts reclassified from AOCI
Net current period other comprehensive (loss)
income
Unrealized
(loss) gain on
translation of
self-sustaining
foreign
operations
Net change in
net investment
hedges
Losses on
derivatives
recognized
as cash flow
hedges
Net change
on available-
for-sale
investments
Net change in
unrecognized
pension
and post-
retirement
benefit costs
Total AOCI
$ 639
$
(270)
–
(270)
(62) $
38
16
$
–
(2) $
–
(13) $ 578
–
(232)
–
38
(2)
(2)
–
–
(39)
(39)
(41)
(273)
Balance, December 31, 2023
$ 369
$
(24) $
14
$
(2) $
(52) $
305
For the year ended December 31, 2022
Balance, January 1, 2022
Other comprehensive income (loss) before
$
10
629
$
35
(97)
reclassifications
Amounts reclassified from AOCI
Net current period other comprehensive income
–
629
–
(97)
$
18
$
(1) $
–
(2)
(2)
(1)
–
(1)
(37) $
–
25
531
24
24
22
553
(loss)
Balance, December 31, 2022
$ 639
$
(62) $
16
$
(2) $
(13) $ 578
The reclassifications out of AOCI are as follows:
For the
millions of dollars
Affected line item in the Consolidated Financial Statements
Gains on derivatives recognized as cash flow hedges
Interest rate hedge
Net change in unrecognized pension and post-retirement benefit costs
Interest expense, net
Actuarial losses
Past service costs
Amounts reclassified into obligations
Other income, net
Other income, net
Pension and post-retirement benefits
Total before tax
Income tax expense
Total net of tax
Total reclassifications out of AOCI, net of tax, for the period
14. Inventory
As at
millions of dollars
Fuel
Materials
Total
Year ended December 31
2022
2023
$
$
$
$
(2) $
(2)
$
–
2
(40)
(38)
(1)
(39) $
(41) $
10
–
15
25
(1)
24
22
December 31
2023
December 31
2022
$ 382
408
$ 790
$
$
404
365
769
105
Notes to the Consolidated Financial StatementsEMERA 2023 ANNUAL REPORT
15. Derivative Instruments
Derivative assets and liabilities relating to the foregoing categories consisted of the following:
As at
millions of dollars
Regulatory deferral:
Commodity swaps and forwards
FX forwards
Physical natural gas purchases and sales
HFT derivatives:
Power swaps and physical contracts
Natural gas swaps, futures, forwards, physical contracts
Other derivatives:
Equity derivatives
FX forwards
Total gross current derivatives
Impact of master netting agreements:
Regulatory deferral
HFT derivatives
Total impact of master netting agreements
Total derivatives
Current (1)
Long-term (1)
Total derivatives
Derivative Assets
Derivative Liabilities
December 31
2023
December 31
2022
December 31
2023
December 31
2022
$
$
16
3
–
19
29
319
348
4
18
22
389
(3)
(146)
(149)
$
186
18
52
256
89
340
429
–
5
5
690
(18)
(276)
(294)
76
3
–
79
36
531
567
–
7
7
653
(3)
(146)
(149)
$ 240
174
66
$ 240
$ 396
296
100
396
$
$ 504
386
118
$ 504
$
42
1
–
43
77
1,224
1,301
5
23
28
1,372
(18)
(276)
(294)
$ 1,078
888
190
$ 1,078
(1) Derivative assets and liabilities are classified as current or long-term based upon the maturities of the underlying contracts.
CASH FLOW HEDGES
On May 26, 2021, a treasury lock was settled for a gain of $19 million that is being amortized through interest expense over
10 years as the underlying hedged item settles.
The amounts related to cash flow hedges recorded in AOCI consisted of the following:
For the
millions of dollars
Realized gain in interest expense, net
Total gains in net income
As at
millions of dollars
Total unrealized gain in AOCI – effective portion, net of tax
Year ended December 31
2022
Interest rate
hedge
2023
Interest rate
hedge
$
$
2
2
$
$
2
2
December 31
2023
Interest rate
hedge
December 31
2022
Interest rate
hedge
$
14
$
16
The Company expects $2 million of unrealized gains currently in AOCI to be reclassified into net income within the next
12 months.
106
Notes to the Consolidated Financial StatementsEMERA 2023 ANNUAL REPORT
REGULATORY DEFERRAL
The Company has recorded the following changes with respect to derivatives receiving regulatory deferral:
millions of dollars
For the year ended December 31
Physical
natural gas
purchases
Commodity
swaps and
forwards
Physical
natural gas
purchases
Commodity
swaps and
forwards
FX
forwards
2023
Unrealized gain (loss) in regulatory assets
Unrealized gain (loss) in regulatory liabilities
Realized (gain) loss in regulatory assets
Realized (gain) loss in regulatory liabilities
Realized (gain) loss in inventory (1 )
Realized (gain) in regulated fuel for generation
$
– $
(3)
–
–
–
(49)
(109) $
(73)
(5)
2
4
(9)
(3) $
–
–
–
(10)
(4)
– $
(69) $
28
–
–
–
(64)
343
48
(41)
(121)
(146)
and purchased power (2)
Other
Total change derivative instruments
–
(52) $
(14)
(204) $
–
(17) $
–
(36) $
–
14
$
$
FX
forwards
2022
1
16
–
–
1
–
–
18
(1) Realized (gains) losses will be recognized in fuel for generation and purchased power when the hedged item is consumed.
(2) Realized (gains) losses on derivative instruments settled and consumed in the period and hedging relationships that have been terminated or the hedged
transaction is no longer probable.
As at December 31, 2023, the Company had the following notional volumes designated for regulatory deferral that are expected
to settle as outlined below:
millions
Physical natural gas purchases:
Natural gas (Mmbtu)
Commodity swaps and forwards purchases:
Natural gas (Mmbtu)
Power (MWh)
Coal (metric tonnes)
FX swaps and forwards:
FX contracts (millions of USD)
Weighted average rate
% of USD requirements
2024
2025–2026
7
16
1
1
6
10
1
–
$
241
1.3155
63%
$
70
1.3197
17%
HFT DERIVATIVES
The Company has recognized the following realized and unrealized gains (losses) with respect to HFT derivatives:
For the
millions of dollars
Power swaps and physical contracts in non-regulated operating revenues
Natural gas swaps, forwards, futures and physical contracts in non-regulated operating revenues
Total gains in net income
Year ended December 31
2022
2023
$
(6) $
1,043
$ 1,037
$
17
47
64
As at December 31, 2023, the Company had the following notional volumes of outstanding HFT derivatives that are expected to
settle as outlined below:
millions
Natural gas purchases (Mmbtu)
Natural gas sales (Mmbtu)
Power purchases (MWh)
Power sales (MWh)
2024
296
338
1
1
2025
80
86
–
–
2026
50
16
–
–
2027
38
6
–
–
2028 and
thereafter
30
4
–
–
107
Notes to the Consolidated Financial StatementsEMERA 2023 ANNUAL REPORT
OTHER DERIVATIVES
As at December 31, 2023, the Company had equity derivatives in place to manage the cash flow risk associated with forecasted
future cash settlements of deferred compensation obligations and FX forwards in place to manage cash flow risk associated with
forecasted USD cash inflows. The equity derivatives hedge the return on 2.9 million shares and extends until December 2024.
The FX forwards have a combined notional amount of $508 million USD and expire in 2023, 2024 and 2025.
For the
millions of dollars
Unrealized gain (loss) in OM&G
Unrealized gain (loss) in other income, net
Realized loss in OM&G
Realized loss in other income, net
Total gains (losses) in net income
2023
Year ended December 31
2022
FX
Forwards
Equity
Derivatives
FX
Forwards
Equity
Derivatives
$
– $
28
–
(11)
17
$
$
$
4
–
(13)
–
(9) $
– $
(18)
–
(6)
(24) $
(5)
–
(17)
–
(22)
CREDIT RISK
The Company is exposed to credit risk with respect to amounts receivable from customers, energy marketing collateral deposits
and derivative assets. Credit risk is the potential loss from a counterparty’s non-performance under an agreement. The Company
manages credit risk with policies and procedures for counterparty analysis, exposure measurement, and exposure monitoring and
mitigation. Credit assessments are conducted on all new customers and counterparties, and deposits or collateral are requested
on any high-risk accounts.
The Company assesses the potential for credit losses on a regular basis and, where appropriate, maintains provisions. With
respect to counterparties, the Company has implemented procedures to monitor the creditworthiness and credit exposure of
counterparties and to consider default probability in valuing the counterparty positions. The Company monitors counterparties’
credit standing, including those that are experiencing financial problems, have significant swings in default probability rates, have
credit rating changes by external rating agencies, or have changes in ownership. Net liability positions are adjusted based on the
Company’s current default probability. Net asset positions are adjusted based on the counterparty’s current default probability.
The Company assesses credit risk internally for counterparties that are not rated.
As at December 31, 2023, the maximum exposure the Company had to credit risk was $1.2 billion (2022 – $1.9 billion), which
included accounts receivable net of collateral/deposits and assets related to derivatives.
It is possible that volatility in commodity prices could cause the Company to have material credit risk exposures with one or
more counterparties. If such counterparties fail to perform their obligations under one or more agreements, the Company could
suffer a material financial loss. The Company transacts with counterparties as part of its risk management strategy for managing
commodity price, FX and interest rate risk. Counterparties that exceed established credit limits can provide a cash deposit or
letter of credit to the Company for the value in excess of the credit limit where contractually required. The total cash deposits/
collateral on hand as at December 31, 2023 was $310 million (2022 – $386 million), which mitigated the Company’s maximum
credit risk exposure. The Company uses the cash as payment for the amount receivable or returns the deposit/collateral to the
customer/counterparty where it is no longer required by the Company.
The Company enters into commodity master arrangements with its counterparties to manage certain risks, including credit risk
to these counterparties. The Company generally enters into International Swaps and Derivatives Association agreements, North
American Energy Standards Board agreements and, or Edison Electric Institute agreements. The Company believes entering
into such agreements offers protection by creating contractual rights relating to creditworthiness, collateral, non-performance
and default.
As at December 31, 2023, the Company had $142 million (2022 – $131 million) in financial assets, considered to be past due,
which have been outstanding for an average 64 days. The FV of these financial assets was $127 million (2022 – $114 million), the
difference of which was included in the allowance for credit losses. These assets primarily relate to accounts receivable from
electric and gas revenue.
108
Notes to the Consolidated Financial StatementsEMERA 2023 ANNUAL REPORT CONCENTRATION RISK
The Company’s concentrations of risk consisted of the following:
As at
Receivables, net
Regulated utilities:
Residential
Commercial
Industrial
Other
Cash collateral
Trading group:
Credit rating of A- or above
Credit rating of BBB- to BBB+
Not rated
Other accounts receivable
Derivative Instruments (current and long-term)
Credit rating of A- or above
Credit rating of BBB- to BBB+
Not rated
CASH COLLATERAL
The Company’s cash collateral positions consisted of the following:
As at
millions of dollars
Cash collateral provided to others
Cash collateral received from others
December 31, 2023
December 31, 2022
millions of
dollars
% of total
exposure
millions of
dollars
% of total
exposure
$
476
194
84
103
94
951
47
33
108
188
151
1,290
138
7
95
240
$ 1,530
31%
13%
5%
7%
6%
62%
3%
2%
7%
12%
10%
84%
$
455
192
121
122
–
890
125
75
307
507
585
1,982
9%
1%
6%
16%
100%
202
8
186
396
$ 2,378
19%
8%
5%
5%
0%
37%
5%
3%
13%
21%
25%
83%
9%
0%
8%
17%
100%
December 31
2023
December 31
2022
$
$
101
22
$
$
224
112
Collateral is posted in the normal course of business based on the Company’s creditworthiness, including its senior unsecured
credit rating as determined by certain major credit rating agencies. Certain derivatives contain financial assurance provisions
that require collateral to be posted if a material adverse credit-related event occurs. If a material adverse event resulted
in the senior unsecured debt falling below investment grade, the counterparties to such derivatives could request ongoing
full collateralization.
As at December 31, 2023, the total FV of derivatives in a liability position was $504 million (December 31, 2022 – $1,078 million).
If the credit ratings of the Company were reduced below investment grade, the full value of the net liability position could be
required to be posted as collateral for these derivatives.
16. FV Measurements
The Company is required to determine the FV of all derivatives except those which qualify for the NPNS exemption (see note 1)
and uses a market approach to do so. The three levels of the FV hierarchy are defined as follows:
Level 1 – Where possible, the Company bases the fair valuation of its financial assets and liabilities on quoted prices in active
markets (“quoted prices”) for identical assets and liabilities.
109
Notes to the Consolidated Financial StatementsEMERA 2023 ANNUAL REPORT Level 2 – Where quoted prices for identical assets and liabilities are not available, the valuation of certain contracts must
be based on quoted prices for similar assets and liabilities with an adjustment related to location differences. Also, certain
derivatives are valued using quotes from over-the-counter clearing houses.
Level 3 – Where the information required for a Level 1 or Level 2 valuation is not available, derivatives must be valued using
unobservable or internally-developed inputs. The primary reasons for a Level 3 classification are as follows:
• While valuations were based on quoted prices, significant assumptions were necessary to reflect seasonal or monthly
shaping and locational basis differentials.
• The term of certain transactions extends beyond the period when quoted prices are available and, accordingly, assumptions
were made to extrapolate prices from the last quoted period through the end of the transaction term.
• The valuations of certain transactions were based on internal models, although quoted prices were utilized in the valuations.
Derivative assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the
FV measurement.
The following tables set out the classification of the methodology used by the Company to FV its derivatives:
As at
millions of dollars
Assets
Regulatory deferral:
Commodity swaps and forwards
FX forwards
HFT derivatives:
Level 1
Level 2
December 31, 2023
Total
Level 3
$
$
7
–
7
6
3
9
$
- $
–
–
–
34
13
3
16
18
184
Power swaps and physical contracts
Natural gas swaps, futures, forwards, physical contracts and
(5)
42
23
108
37
131
34
202
–
4
4
48
43
–
43
–
13
13
–
–
56
$
(8) $
18
–
18
158
30
3
33
24
19
43
7
7
83
75
–
–
–
34
–
–
–
–
365
365
18
4
22
240
73
3
76
24
397
421
–
–
7
7
504
$ (331) $ (264)
365
related transportation
Other derivatives:
FX forwards
Equity derivatives
Total assets
Liabilities
Regulatory deferral:
Commodity swaps and forwards
FX forwards
HFT derivatives:
Power swaps and physical contracts
Natural gas swaps, futures, forwards and physical contracts
Other derivatives:
FX forwards
Total liabilities
Net assets (liabilities)
110
Notes to the Consolidated Financial StatementsEMERA 2023 ANNUAL REPORT
As at
millions of dollars
Assets
Regulatory deferral:
Commodity swaps and forwards
FX forwards
Physical natural gas purchases and sales
HFT derivatives:
Power swaps and physical contracts
Natural gas swaps, futures, forwards, physical contracts and
related transportation
Other derivatives:
FX forwards
Total assets
Liabilities
Regulatory deferral:
Commodity swaps and forwards
FX forwards
HFT derivatives:
Power swaps and physical contracts
Natural gas swaps, futures, forwards and physical contracts
Other derivatives:
FX forwards
Equity derivatives
Total liabilities
Net assets (liabilities)
Level 1
Level 2
December 31, 2022
Total
Level 3
$
120
$
–
–
120
9
3
$
48
18
–
66
31
72
12
103
–
132
15
–
15
2
51
53
–
5
73
59
$
5
174
9
1
10
28
118
146
23
–
179
$
(5) $
–
– $ 168
18
52
238
52
52
4
34
38
–
90
–
–
–
44
109
153
5
396
24
1
25
1
825
826
31
994
1,025
–
–
826
(736) $
23
5
1,078
(682)
The change in the FV of the Level 3 financial assets for the year ended December 31, 2023 was as follows:
millions of dollars
Regulatory
Deferral
Physical
natural gas
purchases
HFT Derivatives
Power
Natural gas
Balance, January 1, 2023
Realized gains (losses) included in fuel for generation and purchased power
Unrealized gains (losses) included in regulatory assets and liabilities
Total realized and unrealized gains (losses) included in non-regulated
$
$
52
(49)
(3)
–
$
$
4
–
–
(4)
34
–
–
–
Total
90
(49)
(3)
(4)
operating revenues
Balance, December 31, 2023
$
–
$
–
$
34
$
34
The change in the FV of the Level 3 financial liabilities for the year ended December 31, 2023 was as follows:
millions of dollars
Balance, January 1, 2023
Total realized and unrealized gains included in non-regulated operating revenues
Balance, December 31, 2023
HFT Derivatives
Power
Natural gas
Total
$
$
1
(1)
–
$
$
825
(460)
$ 365
$
826
(461)
365
111
Notes to the Consolidated Financial StatementsEMERA 2023 ANNUAL REPORT
Significant unobservable inputs used in the FV measurement of Emera’s natural gas and power derivatives include third-party
sourced pricing for instruments based on illiquid markets. Significant increases (decreases) in any of these inputs in isolation
would result in a significantly lower (higher) FV measurement. Other unobservable inputs used include internally developed
correlation factors and basis differentials; own credit risk; and discount rates. Internally developed correlations and basis
differentials are reviewed on a quarterly basis based on statistical analysis of the spot markets in the various illiquid term
markets. Discount rates may include a risk premium for those long-term forward contracts with illiquid future price points to
incorporate the inherent uncertainty of these points. Any risk premiums for long-term contracts are evaluated by observing
similar industry practices and in discussion with industry peers.
The Company uses a modelled pricing valuation technique for determining the FV of Level 3 derivative instruments. The following
table outlines quantitative information about the significant unobservable inputs used in the FV measurements categorized
within Level 3 of the FV hierarchy:
millions of dollars
FV
Assets
Liabilities
Significant
Unobservable Input
Low
High
Weighted
average (1)
As at December 31, 2023
HFT derivatives – Natural gas swaps,
futures, forwards and physical
contracts
34
365
Third-party pricing
$ 1.27
$ 16.25
$ 4.85
Total
Net liability
$
34
$
$
365
331
As at December 31, 2022
Regulatory deferral – Physical
natural gas purchases
HFT derivatives – Power swaps and
physical contracts
HFT derivatives – Natural gas swaps,
futures, forwards and physical
contracts
$
52
$
4
34
–
1
Third-party pricing
$ 5.79
$ 31.85
$ 12.27
Third-party pricing
$ 43.24
$ 269.10
$ 138.79
825
Third-party pricing
$ 2.45
$ 33.88
$ 12.01
Total
Net liability
$
90
$
$
826
736
(1) Unobservable inputs were weighted by the relative FV of the instruments.
Long-term debt is a financial liability not measured at FV on the Consolidated Balance Sheets. The balance consisted of
the following:
As at
millions of dollars
December 31, 2023
December 31, 2022
Carrying
Amount
FV
Level 1
Level 2
Level 3
Total
$ 18,365
$ 16,318
$ 16,621
$ 14,670
$
$
–
–
$ 16,363
$ 14,284
$ 258
$ 386
$ 16,621
$ 14,670
The Company has designated $1.2 billion USD denominated Hybrid Notes as a hedge of the foreign currency exposure of its net
investment in USD denominated operations. The Company’s Hybrid Notes are contingently convertible into preferred shares in
the event of bankruptcy or other related events. A redemption option on or after June 15, 2026 is available and at the control of
the Company. The Hybrid Notes are classified as Level 2 financial assets. As at December 31, 2023, the FV of the Hybrid Notes
was $1.2 billion (2022 – $1.1 billion). An after-tax foreign currency gain of $38 million was recorded in AOCI for the year ended
December 31, 2023 (2022 – $97 million after-tax loss).
112
Notes to the Consolidated Financial StatementsEMERA 2023 ANNUAL REPORT 17. Related Party Transactions
In the ordinary course of business, Emera provides energy and other services and enters into transactions with its subsidiaries,
associates and other related companies on terms similar to those offered to non-related parties. Intercompany balances and
intercompany transactions have been eliminated on consolidation, except for the net profit on certain transactions between
non-regulated and regulated entities in accordance with accounting standards for rate-regulated entities. All material amounts
are under normal interest and credit terms.
Significant transactions between Emera and its associated companies are as follows:
• Transactions between NSPI and NSPML related to the Maritime Link assessment are reported in the Consolidated
Statements of Income. NSPI’s expense is reported in Regulated fuel for generation and purchased power, totalling
$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.
• 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.
18. Receivables and Other Current Assets
As at
millions of dollars
Customer accounts receivable – billed
Capitalized transportation capacity (1 )
Customer accounts receivable – unbilled
Prepaid expenses
Income tax receivable
Allowance for credit losses
NMGC gas hedge settlement receivable (2)
Other
Total receivables and other current assets
December 31
2023
December 31
2022
$
805
358
363
105
10
(15)
–
191
$ 1,817
$ 1,096
781
424
82
9
(17)
162
360
$ 2,897
(1) Capitalized transportation capacity represents the value of transportation/storage received by EES on asset management agreements at the inception of
the contracts. The asset is amortized over the term of each contract.
(2) Offsetting amount is included in regulatory liabilities for NMGC as gas hedges are part of the PGAC. For more information, refer to note 6.
113
Notes to the Consolidated Financial StatementsEMERA 2023 ANNUAL REPORT 19. Leases
LESSEE
The Company has operating leases for buildings, land, telecommunication services, and rail cars. Emera’s leases have remaining
lease terms of 1 year to 62 years, some of which include options to extend the leases for up to 65 years. These options are
included as part of the lease term when it is considered reasonably certain they will be exercised.
As at
millions of dollars
Right-of-use asset
Lease liabilities
Current
Long-term
Total lease liabilities
Classification
December 31
2023
December 31
2022
Other long-term assets
$
54
$
Other current liabilities
Other long-term liabilities
3
55
58
$
$
58
3
59
62
The Company recorded lease expense of $127 million for the year ended December 31, 2023 (2022 – $138 million), of which
$119 million (2022 – $131 million) related to variable costs for power generation facility finance leases, recorded in “Regulated fuel
for generation and purchased power” in the Consolidated Statements of Income.
Future minimum lease payments under non-cancellable operating leases for each of the next five years and in aggregate
thereafter are as follows:
millions of dollars
2024
2025
2026
2027
2028
Thereafter
Minimum lease payments
Less imputed interest
Total
$
6
$
5
$
3
$
3
$
3
$
111
$
$
Total
131
(73)
58
Additional information related to Emera’s leases is as follows:
For the
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows for operating leases (millions of dollars)
Right-of-use assets obtained in exchange for lease obligations:
Operating leases (millions of dollars)
Weighted average remaining lease term (years)
Weighted average discount rate – operating leases
Year ended December 31
2022
2023
$
8
$
8
$
1
44
3.93%
$
1
44
3.98%
LESSOR
The Company’s net investment in direct finance and sales-type leases primarily relates to Brunswick Pipeline, Seacoast,
compressed natural gas (“CNG”) stations, a renewable natural gas (“RNG”) facility and heat pumps.
The Company manages its risk associated with the residual value of the Brunswick Pipeline lease through proper routine
maintenance of the asset.
Customers have the option to purchase CNG station assets by paying a make-whole payment at the date of the purchase based
on a targeted internal rate of return or may take possession of the CNG station asset at the end of the lease term for no cost.
Customers have the option to purchase heat pumps at the end of the lease term for a nominal fee.
Commencing in October 2023, the Company leased a RNG facility to a biogas producer that is classified as a sales-type lease. The
term of the facility lease is 15 years, with a nominal value purchase at the end of the term and a net investment of approximately
$35 million USD.
114
Notes to the Consolidated Financial StatementsEMERA 2023 ANNUAL REPORT Commencing in January 2022, the Company leased Seacoast pipeline, a 21-mile, 30-inch lateral that is classified as a sales-type
lease. The term of the pipeline lateral lease is 34 years with a net investment of $100 million USD. The lessee of the pipeline
lateral has renewal options for an additional 16 years. These renewal options have not been included as part of the pipeline lateral
lease term as it is not reasonably certain that they will be exercised.
Direct finance and sales-type lease unearned income is recognized in income over the life of the lease using a constant rate of
interest equal to the internal rate of return on the lease and is recorded as “Operating revenues – regulated gas” and “Other
income, net” on the Consolidated Statements of Income.
The total net investment in direct finance and sales-type leases consist of the following:
As at
millions of dollars
Total minimum lease payment to be received
Less: amounts representing estimated executory costs
Minimum lease payments receivable
Estimated residual value of leased property (unguaranteed)
Less: Credit loss reserve
Less: unearned finance lease income
Net investment in direct finance and sales-type leases
Principal due within one year (included in “Receivables and other current assets”)
Net Investment in direct finance and sales type leases – long-term
December 31
2023
December 31
2022
$ 1,360
$ 1,393
(190)
(205)
$ 1,170
183
(2)
(693)
$ 1,188
183
–
(733)
$ 658
37
621
$
$ 638
34
604
$
As at December 31, 2023, future minimum lease payments to be received for each of the next five years and in aggregate
thereafter were as follows:
millions of dollars
2024
2025
2026
2027
2028
Thereafter
Total
Minimum lease payments to be received
Less: executory costs
Total
$ 97
$ 99
$ 98
$ 97
$
96
$ 873
$ 1,360
(190)
$ 1,170
20. Property, Plant and Equipment
PP&E consisted of the following regulated and non-regulated assets:
As at
millions of dollars
Generation
Transmission
Distribution
Gas transmission and distribution
General plant and other (1 )
Total cost
Less: Accumulated depreciation (1 )
Construction work in progress (1 )
Net book value
Estimated useful life
3 to 131
10 to 80
4 to 80
6 to 92
2 to 71
December 31
2023
December 31
2022
$ 13,500
2,835
7,417
5,536
2,985
32,273
(9,994)
22,279
2,097
$ 24,376
$ 13,083
2,731
6,978
5,061
2,723
30,576
(9,574)
21,002
1,994
$ 22,996
(1) SeaCoast owns a 50% undivided ownership interest in a jointly owned 26-mile pipeline lateral located in Florida, which went into service in 2020. At
December 31, 2023, SeaCoast’s share of plant in service was $27 million USD (2022 – $27 million USD), and accumulated depreciation of $2 million USD
(2022 – $1 million USD). SeaCoast’s undivided ownership interest is financed with its funds and all operations are accounted for as if such participating
interest were a wholly owned facility. SeaCoast’s share of direct expenses of the jointly owned pipeline is included in “OM&G” in the Consolidated
Statements of Income.
115
Notes to the Consolidated Financial StatementsEMERA 2023 ANNUAL REPORT 21. Employee Benefit Plans
Emera maintains a number of contributory defined-benefit (“DB”) and defined-contribution (“DC”) pension plans, which cover
substantially all of its employees. In addition, the Company provides non-pension benefits for its retirees. These plans cover
employees in Nova Scotia, New Brunswick, Newfoundland and Labrador, Florida, New Mexico, Barbados, and Grand Bahama Island.
Emera’s net periodic benefit cost included the following:
BENEFIT OBLIGATION AND PLAN ASSETS
The changes in benefit obligation and plan assets, and the funded status for all plans were as follows:
For the
millions of dollars
2023
Year ended December 31
2022
Change in Projected Benefit Obligation (“PBO”) and
Accumulated Post-retirement Benefit Obligation (“APBO”)
Defined benefit
pension plans
Non-pension
benefit plans
Defined benefit
pension plans
Non-pension
benefit plans
Balance, January 1
Service cost
Plan participant contributions
Interest cost
Plan amendments
Benefits paid
Actuarial losses (gains)
Settlements and curtailments
FX translation adjustment
Balance, December 31
Change in plan assets
Balance, January 1
Employer contributions
Plan participant contributions
Benefits paid
Actual return on assets, net of expenses
Settlements and curtailments
FX translation adjustment
Balance, December 31
Funded status, end of year
$ 2,158
30
6
111
–
(147)
146
(8)
(23)
$ 2,273
$ 2,163
42
6
(147)
262
(8)
(20)
2,298
25
$
$
$
$
$
$ 243
3
6
13
(14)
(29)
10
–
(5)
$ 227
$
$
$
46
23
6
(29)
3
–
(1)
48
$
(179) $
$
$
$
2,624
41
6
80
–
(174)
(480)
(6)
67
2,158
2,702
45
6
(174)
(489)
(6)
79
2,163 $
$
5
318
4
6
9
–
(31)
(79)
–
16
243
51
24
6
(31)
(7)
–
3
46
(197)
The actuarial losses recognized in the period are primarily due to changes in the discount rate, higher than expected indexation,
and compensation-related assumption changes.
PLANS WITH PBO/APBO IN EXCESS OF PLAN ASSETS
The aggregate financial position for all pension plans where the PBO or APBO (for post-retirement benefit plans) exceeded the
plan assets for the years ended December 31 was as follows:
2023
2022
Defined benefit
pension plans
Non-pension
benefit plans
Defined benefit
pension plans
Non-pension
benefit plans
$ 205
$
$
221
$
$
120
37
(83) $
–
(205) $
1,006
914
(92) $
–
(221)
millions of dollars
PBO/APBO
FV of plan assets
Funded status
116
Notes to the Consolidated Financial StatementsEMERA 2023 ANNUAL REPORT PLANS WITH ACCUMULATED BENEFIT OBLIGATION (“ABO”) IN EXCESS OF PLAN ASSETS
The ABO for the DB pension plans was $2,172 million as at December 31, 2023 (2022 – $2,080 million). The aggregate financial
position for those plans with an ABO in excess of the plan assets for the years ended December 31 was as follows:
millions of dollars
ABO
FV of plan assets
Funded status
2023
2022
Defined benefit
pension plans
Defined benefit
pension plans
$
$
$
114
37
(77) $
111
33
(78)
BALANCE SHEET
The amounts recognized in the Consolidated Balance Sheets consisted of the following:
As at
millions of dollars
Other current liabilities
Long-term liabilities
Other long-term assets
AOCI, net of tax and regulatory assets
Less: Deferred income tax (expense) recovery in AOCI
Net amount recognized
December 31
2023
December 31
2022
Defined benefit
pension plans
Non-pension
benefit plans
Defined benefit
pension plans
Non-pension
benefit plans
$
(5) $
(18) $
(13) $
(78)
108
385
(8)
402
(187)
26
20
(1)
(160) $
(80)
98
358
(7)
356
$
$
$
(20)
(201)
24
22
(1)
(176)
AMOUNTS RECOGNIZED IN AOCI AND REGULATORY ASSETS
Unamortized gains and losses and past service costs arising on post-retirement benefits are recorded in AOCI or regulatory
assets. The following table summarizes the change in AOCI and regulatory assets:
millions of dollars
Defined Benefit Pension Plans
Balance, January 1, 2023
Amortized in current period
Current year additions
Change in FX rate
Balance, December 31, 2023
Non-pension benefits plans
Balance, January 1, 2023
Amortized in current period
Current year reductions
Change in FX rate
Balance, December 31, 2023
Regulatory
assets
Actuarial
(gains) losses
Past service
(gains) costs
$ 336
(6)
1
(7)
$ 324
$
$
31
2
(3)
(1)
29
$
$
$
$
15
(3)
41
–
53
$
$
(10) $
3
(1)
–
(8) $
–
–
–
–
–
–
–
(3)
1
(2)
117
Notes to the Consolidated Financial StatementsEMERA 2023 ANNUAL REPORT As at
millions of dollars
Actuarial losses (gains)
Past service gains
Deferred income tax expense
AOCI, net of tax
Regulatory assets
AOCI, net of tax and regulatory assets
BENEFIT COST COMPONENTS
Emera’s net periodic benefit cost included the following:
As at
millions of dollars
Service cost
Interest cost
Expected return on plan assets
Current year amortization of:
Actuarial losses (gains)
Regulatory assets (liability)
Settlement, curtailments
Total
December
2023
December
2022
Defined benefit
pension plans
Non-pension
benefit plans
Defined benefit
pension plans
Non-pension
benefit plans
$
53
$
(8) $
–
8
61
324
385
$
(2)
1
(9)
29
20
$
15
–
7
22
336
$ 358
$
$
(10)
–
1
(9)
31
22
2023
Year ended December 31
2022
Defined benefit
pension plans
Non-pension
benefit plans
Defined benefit
pension plans
Non-pension
benefit plans
$
$
30
111
(161)
1
6
2
(11) $
$
3
13
(2)
(3)
(2)
–
9
$
$
41
80
(144)
8
21
2
8
$
$
4
9
–
–
2
–
15
The expected return on plan assets is determined based on the market-related value of plan assets of $2,577 million as at
January 1, 2023 (2022 – $2,482 million), adjusted for interest on certain cash flows during the year. The market-related value
of assets is based on a five-year smoothed asset value. Any investment gains (or losses) in excess of (or less than) the expected
return on plan assets are recognized on a straight-line basis into the market-related value of assets over a five-year period.
PENSION PLAN ASSET ALLOCATIONS
Emera’s investment policy includes discussion regarding the investment philosophy, the level of risk which the Company is
prepared to accept with respect to the investment of the Pension Funds, and the basis for measuring the performance of the
assets. Central to the policy is the target asset allocation by major asset categories. The objective of the target asset allocation is
to diversify risk and to achieve asset returns that meet or exceed the plan’s actuarial assumptions. The diversification of assets
reduces the inherent risk in financial markets by requiring that assets be spread out amongst various asset classes. Within each
asset class, a further diversification is undertaken through the investment in a broad range of investment and non-investment
grade securities. Emera’s target asset allocation is as follows:
Canadian Pension Plans
Asset class
Short-term securities
Fixed income
Equities:
Canadian
Non-Canadian
118
Target Range at Market
0% to 10%
34% to 49%
7% to 17%
35% to 59%
Notes to the Consolidated Financial StatementsEMERA 2023 ANNUAL REPORT
Non-Canadian Pension Plans
Asset class
Cash and cash equivalents
Fixed income
Equities
Target Range at Market
Weighted Average
0% to 10%
29% to 49%
48% to 68%
Pension Plan assets are overseen by the respective Management Pension Committees in the sponsoring companies. All pension
investments are in accordance with policies approved by the respective Board of Directors of each sponsoring company.
The following tables set out the classification of the methodology used by the Company to FV its investments:
Government
Corporate
Other
Mutual funds
Other
Open-ended investments measured at NAV (1 )
Common collective trusts measured at NAV (2)
Total
–
–
–
–
–
1,006
586
$ 1,592
$
millions of dollars
As at
Cash and cash equivalents
Net in-transits
Equity securities:
Canadian equity
United States equity
Other equity
Fixed income securities:
millions of dollars
As at
Cash and cash equivalents
Net in-transits
Equity securities:
Canadian equity
United States equity
Other equity
Fixed income securities:
NAV
Level 1
Level 2
Total
Percentage
December 31, 2023
$
$
40
(9)
$
–
–
–
–
–
–
–
–
–
–
$
40
(9)
96
141
112
172
90
5
-
(1)
-
-
266
172
90
9
50
5
1,006
586
$ 2,298
2%
-%
4%
6%
5%
8%
4%
-%
2%
-%
44%
25%
100%
–
–
–
–
–
104
83
11
–
(3)
–
–
195
$
70
(70)
87
233
186
104
83
14
68
(3)
790
601
$ 2,163
3%
(3)%
4%
11%
8%
5%
4%
1%
3%
–%
36%
28%
100%
96
141
112
-
-
4
50
6
-
-
440
$
87
233
186
–
–
3
68
–
–
–
577
$
NAV
Level 1
Level 2
Total
Percentage
December 31, 2022
$
$
70
(70)
$
–
–
–
–
–
Government
Corporate
Other
Mutual funds
Other
Open-ended investments measured at NAV (1 )
Common collective trusts measured at NAV (2)
Total
–
–
–
–
–
790
601
$ 1,391
$
(1) Net asset value (“NAV”) investments are open-ended registered and non-registered mutual funds, collective investment trusts, or pooled funds. NAV’s are
calculated at least monthly and the funds honour subscription and redemption activity regularly.
(2) The common collective trusts are private funds valued at NAV. The NAVs are calculated based on bid prices of the underlying securities. Since the prices are
not published to external sources, NAV is used as a practical expedient. Certain funds invest primarily in equity securities of domestic and foreign issuers
while others invest in long duration U.S. investment grade fixed income assets and seeks to increase return through active management of interest rate and
credit risks. The funds honour subscription and redemption activity regularly.
Refer to note 16 for more information on the FV hierarchy and inputs used to measure FV.
119
Notes to the Consolidated Financial StatementsEMERA 2023 ANNUAL REPORT
POST-RETIREMENT BENEFIT PLANS
There are no assets set aside to pay for most of the Company’s post-retirement benefit plans. As is common practice, post-
retirement health benefits are paid from general accounts as required. The primary exception to this is the NMGC Retiree Medical
Plan, which is fully funded.
INVESTMENTS IN EMERA
As at December 31, 2023 and 2022, assets related to the pension funds and post-retirement benefit plans did not hold any
material investments in Emera or its subsidiaries securities. However, as a significant portion of assets for the benefit plan are
held in pooled assets, there may be indirect investments in these securities.
CASH FLOWS
The following table shows expected cash flows for DB pension and other post-retirement benefit plans:
millions of dollars
Expected employer contributions
2024
Expected benefit payments
2024
2025
2026
2027
2028
2029–2033
Defined benefit
pension plans
Non-pension
benefit plans
$
34
$
19
172
163
166
171
173
890
21
21
21
21
20
95
ASSUMPTIONS
The following table shows the assumptions that have been used in accounting for DB pension and other post-retirement
benefit plans:
2023
2022
Defined benefit
pension plans
Non-pension
benefit plans
Defined benefit
pension plans
Non-pension
benefit plans
4.89%
4.88%
3.87%
–
–
5.33%
5.34%
6.56%
3.62%
–
–
4.89%
4.89%
3.85%
6.04%
3.76%
2043
5.31%
5.32%
2.16%
3.61%
5.40%
3.77%
2043
5.33%
5.34%
3.62%
–
–
3.05%
3.18%
6.07%
3.31%
–
–
5.31%
5.32%
3.61%
5.40%
3.77%
2043
2.81%
2.92%
1.32%
3.29%
5.09%
3.77%
2042
(weighted average assumptions)
Benefit obligation – December 31:
Discount rate – past service
Discount rate – future service
Rate of compensation increase
Health care trend – initial (next year)
– ultimate
– year ultimate reached
Benefit cost for year ended December 31:
Discount rate – past service
Discount rate – future service
Expected long-term return on plan assets
Rate of compensation increase
Health care trend – initial (current year)
– ultimate
– year ultimate reached
Actual assumptions used differ by plan.
120
Notes to the Consolidated Financial StatementsEMERA 2023 ANNUAL REPORT
The expected long-term rate of return on plan assets is based on historical and projected real rates of return for the plan’s
current asset allocation, and assumed inflation. A real rate of return is determined for each asset class. Based on the asset
allocation, an overall expected real rate of return for all assets is determined. The asset return assumption is equal to the overall
real rate of return assumption added to the inflation assumption, adjusted for assumed expenses to be paid from the plan.
The discount rate is based on high-quality long-term corporate bonds, with maturities matching the estimated cash flows from
the pension plan.
DEFINED CONTRIBUTION PLAN
Emera also provides a DC pension plan for certain employees. The Company’s contribution for the year ended December 31, 2023
was $45 million (2022 – $41 million).
22. Goodwill
The change in goodwill for the year ended December 31 was due to the following:
millions of dollars
Balance, January 1
Change in FX rate
GBPC impairment charge
Balance, December 31
2023
2022
$ 6,012
(141)
–
$ 5,871
$ 5,696
389
(73)
$ 6,012
Goodwill is subject to an annual assessment for impairment at the reporting unit level. The goodwill on Emera’s Consolidated
Balance Sheets at December 31, 2023, primarily related to TECO Energy (reporting units with goodwill are TEC, PGS, and NMGC).
In 2023, Emera performed qualitative impairment assessments for NMGC and PGS, concluding that the FV of the reporting units
exceeded their respective carrying amounts, and as such, no quantitative assessments were performed and no impairment
charges were recognized. 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 approach 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.
In 2022, the Company elected to bypass a qualitative assessment and performed a quantitative impairment assessment for
GBPC, using the income approach. It was determined that the FV did not exceed its carrying amount, including goodwill. As a
result of this assessment, a goodwill impairment charge of $73 million was recorded in 2022, reducing the GBPC goodwill balance
to nil as at December 31, 2022. This non-cash charge is included in “GBPC impairment charge” on the Consolidated Statements
of Income.
121
Notes to the Consolidated Financial StatementsEMERA 2023 ANNUAL REPORT 23. Short-Term Debt
Emera’s short-term borrowings consist of commercial paper issuances, advances on revolving and non-revolving credit
facilities and short-term notes. Short-term debt and the related weighted-average interest rates as at December 31 consisted of
the following:
millions of dollars
TEC
Advances on revolving credit facilities
Emera
Non-revolving term facilities
Bank indebtedness
TECO Finance
Advances on revolving credit and term facilities
PGS
Advances on revolving credit facilities
NMGC
Advances on revolving credit facilities
GBPC
Advances on revolving credit facilities
Short-term debt
Weighted
average
interest rate
2023
Weighted
average
interest rate
2022
$ 277
5.68%
$ 1,380
5.00%
796
9
6.07%
-%
796
–
5.19%
–%
245
6.54%
481
5.47%
73
25
8
$ 1,433
6.36%
6.46%
5.54%
–
59
10
$ 2,726
–%
5.15%
5.25%
The Company’s total short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity as at
December 31 were as follows:
millions of dollars
TEC – Unsecured committed revolving credit facility
TECO Energy/TECO Finance – revolving credit facility
TECO Finance – Unsecured committed revolving credit facility
Emera – Unsecured non-revolving term facility
Emera – Unsecured non-revolving term facility
PGS – Unsecured revolving credit facility
TEC – Unsecured revolving facility
TEC – Unsecured revolving facility
NMGC – Unsecured revolving credit facility
Other – Unsecured committed revolving credit facilities
Total
Less:
Advances under revolving credit and term facilities
Letters of credit issued within the credit facilities
Total advances under available facilities
Available capacity under existing agreements
Maturity
2026
2026
2026
2024
2024
2028
2024
2024
2026
Various
2023
2022
$ 401
–
$ 1,084
542
529
400
400
331
265
265
165
17
$ 2,773
–
400
400
–
542
–
169
18
$ 3,155
1,433
3
1,436
2,731
4
2,735
$ 1,337
$ 420
The weighted average interest rate on outstanding short-term debt at December 31, 2023 was 5.95 per cent (2022 – 5.01 per cent).
122
Notes to the Consolidated Financial StatementsEMERA 2023 ANNUAL REPORT RECENT SIGNIFICANT FINANCING ACTIVITY BY SEGMENT
Florida Electric Utilities
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.
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.
Gas Utilities and Infrastructure
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.
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 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.
24. Other Current Liabilities
As at
millions of dollars
Accrued charges
Nova Scotia Cap-and-Trade Program provision (note 6)
Accrued interest on long-term debt
Pension and post-retirement liabilities (note 21)
Sales and other taxes payable
Income tax payable
Other
December 31
2023
December 31
2022
$
172
$
–
107
23
11
2
112
$ 427
$
174
172
97
33
14
9
80
579
123
Notes to the Consolidated Financial StatementsEMERA 2023 ANNUAL REPORT 25. Long-Term Debt
Bonds, notes and debentures are at fixed interest rates and are unsecured unless noted below. Included are certain bankers’
acceptances and commercial paper where the Company has the intention and the unencumbered ability to refinance the
obligations for a period greater than one year.
Long-term debt as at December 31 consisted of the following:
millions of dollars
2023
2022
Maturity
2023
2022
Weighted average
interest rate ( 1)
Emera
Bankers acceptances, SOFR loans
Unsecured fixed rate notes
Fixed to floating subordinated notes (USD) (2)
Emera Finance
Unsecured senior notes
TEC (3)
Fixed rate notes and bonds
PGS
Fixed rate notes and bonds
NMGC
Fixed rate notes and bonds
Non-revolving term facility, floating rate
NMGI
Fixed rate notes and bonds
NSPI
Discount Notes (4)
Medium term fixed rate notes
EBP
Senior secured credit facility
ECI
Secured senior notes
Amortizing fixed rate notes
Non-revolving term facility, floating rate
Non-revolving term facility, fixed rate
Secured fixed rate senior notes (5)
Variable
4.84%
6.75%
Variable
2.90%
6.75%
2027
2030
2076
$ 465
500
1,587
$ 2,552
$ 403
500
1,625
$ 2,528
3.65%
3.65%
2024–2046
$ 3,637
$ 3,725
4.61%
4.15%
2024–2051
$ 5,654
$ 4,341
5.63%
3.78%
2028–2053
$ 1,223
$
772
3.78%
Variable
3.11%
Variable
2026–2051
2024
$ 642
30
$
521
108
$ 672
$
629
3.64%
3.64%
2024
$ 198
$ 203
Variable
5.13%
Variable
5.14%
2024–2027
2025–2097
$ 721
3,165
$ 3,886
$ 881
2,665
$ 3,546
Variable
Variable
2026
$ 246
$
249
Variable
4.00%
Variable
2.15%
3.09%
Variable
3.97%
Variable
2.05%
3.06%
2027
2026
2025
2025–2027
2024–2029
$
75
79
29
155
84
$ 422
$
86
100
30
91
142
$ 449
Adjustments
Fair market value adjustment – TECO Energy acquisition
Debt issuance costs
Amount due within one year
Long-Term Debt
$
- $
(125)
(676)
2
(126)
(574)
$
(801) $
(698)
$ 17,689
$ 15,744
(1) Weighted average interest rate of fixed rate long-term debt.
(2) In 2023, the Company recognized $109 million in interest expense (2022 – $110 million) related to its fixed to floating subordinated notes.
(3) A substantial part of TEC’s tangible assets are pledged as collateral to secure its first mortgage bonds. There are currently no bonds outstanding under
TEC’s first mortgage bond indenture.
(4) Discount notes are backed by a revolving credit facility which matures in 2027. Banker’s acceptances are issued under NSPI’s non-revolving term facility
which matures in 2024. NSPI has the intention and unencumbered ability to refinance bankers’ acceptances for a period of greater than one year.
(5) Notes are issued and payable in either USD or BBD.
124
Notes to the Consolidated Financial StatementsEMERA 2023 ANNUAL REPORT
The Company’s total long-term revolving credit facilities, outstanding borrowings and available capacity as at December 31 were
as follows:
millions of dollars
Emera – revolving credit facility (1 )
TEC – Unsecured committed revolving credit facility
NSPI – revolving credit facility (1 )
NSPI – non-revolving credit facility
Emera – Unsecured non-revolving credit facility
NMGC – Unsecured non-revolving credit facility
ECI – revolving credit facilities
Total
Less:
Borrowings under credit facilities
Letters of credit issued inside credit facilities
Use of available facilities
Available capacity under existing agreements
Maturity
2023
2022
June 2027
December 2026
December 2027
July 2024
February 2024
March 2024
October 2024
$ 900
657
800
400
400
30
10
$ 3,197
$ 900
–
800
400
–
108
11
$ 2,219
1,884
6
$ 1,890
1,396
12
$ 1,408
$ 1,307
$
811
(1) Advances on the revolving credit facility can be made by way of overdraft on accounts up to $50 million.
DEBT COVENANTS
Emera and its subsidiaries have debt covenants associated with their credit facilities. Covenants are tested regularly and the
Company is in compliance with covenant requirements. Emera’s significant covenants are listed below:
Emera
Syndicated credit facilities
Debt to capital ratio
Less than or equal to 0.70 to 1
0.57 : 1
Financial Covenant
Requirement
As at
December 31, 2023
RECENT SIGNIFICANT FINANCING ACTIVITY BY SEGMENT
Florida Electric Utility
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 repayment of short-term borrowings outstanding
under the 5-year credit facility. Therefore, $497 million USD of short-term borrowings that were repaid was classified as long-
term debt at December 31, 2023.
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.
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.
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.
125
Notes to the Consolidated Financial StatementsEMERA 2023 ANNUAL REPORT 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.
Other
On August 18, 2023, Emera entered into a $400 million non-revolving term facility with a maturity date of 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. On February 16, 2024, Emera extended the
term of this agreement to a maturity date of February 19, 2025.
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.
LONG-TERM DEBT MATURITIES
As at December 31, long-term debt maturities, including capital lease obligations, for each of the next five years and in aggregate
thereafter are as follows:
millions of dollars
Emera
Emera US Finance LP
TEC
PGS
NMGC
NMGI
NSPI
EBP
ECI
Total
2024
2025
2026
2028
Thereafter
Total
- $ 1,587
992
$
$
$
$ 199
397
397
–
30
198
398
–
51
$ 1,670
$
–
–
–
–
–
–
–
93
–
125
–
139
264
40
246
89
$ 3,047
$
2027
266
–
–
–
–
–
323
–
77
666
–
–
- $ 500
2,248
5,257
760
549
463
–
–
–
–
–
3,000
–
4
$ 12,318
$ 2,552
3,637
5,654
1,223
672
198
3,886
246
422
$ 18,490
62
525
$
26. Asset Retirement Obligations
AROs mostly relate to reclamation of land at the thermal, hydro and combustion turbine sites; and the disposal of polychlorinated
biphenyls in transmission and distribution equipment and a pipeline site. Certain hydro, transmission and distribution assets may
have additional AROs that cannot be measured as these assets are expected to be used for an indefinite period and, as a result, a
reasonable estimate of the FV of any related ARO cannot be made.
The change in ARO for the years ended December 31 is as follows:
millions of dollars
Balance, January 1
Accretion included in depreciation expense
Change in FX rate
Additions
Accretion deferred to regulatory asset (included in PP&E)
Liabilities settled
Revisions in estimated cash flows
Balance, December 31
$
$
2023
174
9
(1)
–
18
(8)
–
$
192
$
2022
174
9
3
1
1
(1)
(13)
174
126
Notes to the Consolidated Financial StatementsEMERA 2023 ANNUAL REPORT 27. Commitments and Contingencies
A. COMMITMENTS
As at December 31, 2023, contractual commitments (excluding pensions and other post-retirement obligations, long-term debt
and asset retirement obligations) for each of the next five years and in aggregate thereafter consisted of the following:
millions of dollars
Transportation (1)
Purchased power (2)
Fuel, gas supply and storage
Capital projects
Equity investment commitments (3)
Other
2024
$
696
274
556
778
240
154
$ 2,698
2028
Thereafter
Total
$
$
2025
495
249
215
111
$
2026
405
263
62
70
–
–
$
2027
388
312
–
1
–
338
312
5
–
–
$ 2,597
3,435
–
–
–
147
$ 1,217
56
$ 856
46
747
35
$ 690
221
$ 6,253
$
$ 4,919
4,845
838
960
240
659
$ 12,461
(1) 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.
(2) Annual requirement to purchase electricity production from IPPs or other utilities over varying contract lengths.
(3) 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 the collection of up to $164 million from NSPI for the 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.
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.
B. LEGAL PROCEEDINGS
Superfund and Former Manufactured Gas Plant Sites
Previously, TEC had been a potentially responsible party (“PRP”) for certain superfund sites through its Tampa Electric and
former PGS divisions, as well as for certain former manufactured gas plant sites through its PGS division. As a result of the
separation of the PGS division into a separate legal entity, Peoples Gas System, Inc. is also now a PRP for those sites (in addition
to third party PRPs for certain sites). While the aggregate joint and several liability associated with these sites has not changed as
a result of the PGS legal separation, the sites continue to present the potential for significant response costs. As at December 31,
2023, the aggregate financial liability of the Florida utilities is estimated to be $15 million ($11 million USD), primarily at PGS. This
estimate assumes that other involved PRPs are credit-worthy entities. This amount has been accrued and is primarily reflected
in the long-term liability section under “Other long-term liabilities” on the Consolidated Balance Sheets. The environmental
remediation costs associated with these sites are expected to be paid over many years.
The estimated amounts represent only the portion of the cleanup costs attributable to the Florida utilities. The estimates to
perform the work are based on the Florida utilities’ experience with similar work, adjusted for site-specific conditions and
agreements with the respective governmental agencies. The estimates are made in current dollars, are not discounted and do not
assume any insurance recoveries.
127
Notes to the Consolidated Financial StatementsEMERA 2023 ANNUAL REPORT In instances where other PRPs are involved, most of those PRPs are believed to be currently credit-worthy and are likely to
continue to be credit-worthy for the duration of the remediation work. However, in those instances that they are not, the
Florida utilities could be liable for more than their actual percentage of the remediation costs. Other factors that could impact
these estimates include additional testing and investigation which could expand the scope of the cleanup activities, additional
liability that might arise from the cleanup activities themselves or changes in laws or regulations that could require additional
remediation. Under current regulations, these costs are recoverable through customer rates established in base rate proceedings.
Other Legal Proceedings
Emera and its subsidiaries may, from time to time, be involved in other legal proceedings, claims and litigation that arise in the
ordinary course of business which the Company believes would not reasonably be expected to have a material adverse effect on
the financial condition of the Company.
C. PRINCIPAL FINANCIAL RISKS AND UNCERTAINTIES
Emera believes the following principal financial risks could materially affect the Company in the normal course of business.
Risks associated with derivative instruments and FV measurements are discussed in note 15 and note 16.
Sound risk management is an essential discipline for running the business efficiently and pursuing the Company’s strategy
successfully. Emera has an enterprise-wide risk management process, overseen by its Enterprise Risk Management Committee
(“ERMC”) and monitored by the Board of Directors, to ensure an effective, consistent and coherent approach to risk
management. The Board of Directors has a Risk and Sustainability Committee (‘RSC”) with a mandate that includes oversight of
the Company’s Enterprise Risk Management framework, including the identification, assessment, monitoring and management
of enterprise risks. It also includes oversight of the Company’s approach to sustainability and its performance relative to its
sustainability objectives.
Regulatory and Political Risk
The Company’s rate-regulated subsidiaries and certain investments subject to significant influence are subject to risk of
the recovery of costs and investments. Regulatory and political risk can include changes in regulatory frameworks, shifts in
government policy, legislative changes, and regulatory decisions.
As cost-of-service utilities with an obligation to serve customers, Emera’s utilities operate under formal regulatory frameworks,
and must obtain regulatory approval to change or add rates and/or riders. Emera also holds investments in entities in which it
has significant influence, and which are subject to regulatory and political risk including NSPML, LIL, and M&NP. As a regulated
Group II pipeline, the tolls of Brunswick Pipeline are regulated by the CER on a complaint basis, as opposed to the regulatory
approval process described above. In the absence of a complaint, the CER does not normally undertake a detailed examination
of Brunswick Pipeline’s tolls, which are subject to a firm service agreement, expiring in 2034, with Repsol Energy North America
Canada Partnership.
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.
128
Notes to the Consolidated Financial StatementsEMERA 2023 ANNUAL REPORT 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.
Foreign Exchange Risk
The Company is exposed to foreign currency exchange rate changes. Emera operates internationally, with an increasing amount
of the Company’s net income earned outside of Canada. As such, Emera is exposed to movements in exchange rates between the
CAD and, particularly, the USD, which could positively or adversely affect results.
Consistent with the Company’s risk management policies, Emera manages currency risks through matching United States
denominated debt to finance its United States operations and may use foreign currency derivative instruments to hedge specific
transactions and earnings exposure. The Company may enter FX forward and swap contracts to limit exposure on certain foreign
currency transactions such as fuel purchases, revenue streams and capital expenditures, and on net income earned outside of
Canada. The regulatory framework for the Company’s rate-regulated subsidiaries permits the recovery of prudently incurred
costs, including FX.
The Company does not utilize derivative financial instruments for foreign currency trading or speculative purposes or to hedge
the value of its investments in foreign subsidiaries. Exchange gains and losses on net investments in foreign subsidiaries do not
impact net income as they are reported in AOCI.
Liquidity and Capital Market Risk
Liquidity risk relates to Emera’s ability to ensure sufficient funds are available to meet its financial obligations. Emera manages
this risk by forecasting cash requirements on a continuous basis to determine whether sufficient funds are available. Liquidity
and capital needs could be financed through internally generated cash flows, asset sales, short-term credit facilities, and ongoing
access to capital markets.
Emera’s access to capital and cost of borrowing is subject to several risk factors, including financial market conditions, market
disruptions and ratings assigned by 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.
129
Notes to the Consolidated Financial StatementsEMERA 2023 ANNUAL REPORT 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.
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.
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.
130
Notes to the Consolidated Financial StatementsEMERA 2023 ANNUAL REPORT 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.
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.
D. GUARANTEES AND LETTERS OF CREDIT
Emera has guarantees and letters of credit on behalf of third parties outstanding. The following significant guarantees and letters
of credit are not included within the Consolidated Balance Sheets as at December 31, 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 that TECO Energy’s and Emera’s long-term senior unsecured credit ratings are
downgraded below investment grade by Moody’s Investor Services (“Moody’s”) or S&P Global Ratings (“S&P”). TECO Energy
would be required to provide its counterparty a letter of credit or cash deposit of $27 million USD.
131
Notes to the Consolidated Financial StatementsEMERA 2023 ANNUAL REPORT TECO Energy issued a guarantee in connection with SeaCoast’s performance obligations under a firm service agreement, which
expires on December 31, 2055, subject to two extension terms at the option of the counterparty with a final expiration date of
December 31, 2071. The guarantee is for a maximum potential amount of $13 million USD if SeaCoast fails to pay or perform
under the firm service agreement. In the event that TECO Energy’s long-term senior unsecured credit ratings are downgraded
below investment grade by Moody’s or S&P, TECO Energy would need to provide either a substitute guarantee from an affiliate
with an investment grade credit rating or a letter of credit or cash deposit of $13 million USD.
Emera Inc. has issued a guarantee of $66 million USD relating to outstanding notes of ECI. This guarantee will automatically
terminate on the date upon which the obligations have been repaid in full.
NSPI has issued guarantees on behalf of its subsidiary, NS Power Energy Marketing Incorporated, 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).
Collaborative Arrangements
For the years ended December 31, 2023 and 2022, the Company has identified the following material collaborative arrangements:
Through NSPI, the Company is a participant in three wind energy projects in Nova Scotia. The percentage ownership of the wind
project assets is based on the relative value of each party’s project assets by the total project assets. NSPI has power purchase
arrangements to purchase the entire net output of the projects and, therefore, NSPI’s portion of the revenues are recorded net
within regulated fuel for generation and purchased power. NSPI’s portion of operating expenses is recorded in “OM&G” on the
Consolidated Statements of Income. In 2023, NSPI recognized $8 million net expense (2022 – $12 million) in “Regulated fuel for
generation and purchased power” and $3 million (2022 – $3 million) in “OM&G” on the Consolidated Statements of Income.
28. Cumulative Preferred Stock
Authorized:
Unlimited number of First Preferred shares, issuable in series.
Unlimited number of Second Preferred shares, issuable in series.
Annual Dividend
per Share
Redemption
Price per Share
Issued and
Outstanding
Net
Proceeds
Issued and
Outstanding
Net
Proceeds
December 31, 2023
December 31, 2022
$ 0.5456
Floating
$ 1.6085
$ 1.1250
$ 1.0505
$ 1.5810
$ 1.0625
$ 1.1500
$ 25.00
$ 25.00
$ 25.00
$ 25.00
$ 25.00
$ 25.00
$ 25.00
$ 26.00
4,866,814
1,133,186
10,000,000
5,000,000
8,000,000
12,000,000
8,000,000
9,000,000
58,000,000
119
$
$
28
$ 245
$ 122
$
195
$ 295
$
196
$ 222
$ 1,422
4,866,814
1,133,186
10,000,000
5,000,000
8,000,000
12,000,000
8,000,000
9,000,000
58,000,000
119
$
28
$
$
245
$ 122
$
195
$ 295
$
196
$ 222
$ 1,422
Series A
Series B
Series C
Series E
Series F
Series H
Series J
Series L
Total
132
Notes to the Consolidated Financial StatementsEMERA 2023 ANNUAL REPORT Characteristics of the First Preferred Shares:
First Preferred Shares (1) (2)
Fixed rate reset (3) (4)
Series A
Series C (5) (6)
Series F
Minimum rate reset (3) (4)
Series B
Series H (5) (7)
Series J
Perpetual fixed rate
Series E (8)
Series L (9)
Initial
Yield
(%)
4.400
4.100
4.202
2.393
4.900
4.250
4.500
4.600
Current
Annual
Dividend
($)
Minimum
Reset
Dividend Yield
(%)
Earliest Redemption
and/or Conversion
Option Date
Redemption
Value
($)
0.5456
1.6085
1.0505
Floating
1.5810
1.0625
1.1250
1.1500
1.84
2.65
2.63
1.84
4.90
4.25
August 15, 2025
August 15, 2028
February 15, 2025
August 15, 2025
August 15, 2028
May 15, 2026
November 15, 2026
25.00
25.00
25.00
25.00
25.00
25.00
25.00
26.00
Right to
Convert on
a one for
one basis
Series B
Series D
Series G
Series A
Series I
Series K
(1) Holders are entitled to receive fixed or floating cumulative cash dividends when declared by the Board of Directors of the Corporation.
(2) On or after the specified redemption dates, the Corporation has the option to redeem for cash the outstanding First Preferred Shares, in whole or in part, at
the specified per share redemption value plus all accrued and unpaid dividends up to but excluding the dates fixed for redemption.
(3) On the redemption and/or conversion option date the reset annual dividend per share will be determined by multiplying $25.00 per share by the annual
fixed or floating dividend rate, which for Series A, C, F and H is the sum of the five-year Government of Canada Bond Yield on the applicable reset date, plus
the applicable reset dividend yield (Series H annual reset rate must be a minimum of 4.90 per cent) and for Series B equals the Government of Treasury Bill
Rate on the applicable reset date, plus 1.84 per cent.
(4) On each conversion option date, the holders have the option, subject to certain conditions, to convert any or all of their Shares into an equal number of
Cumulative Redeemable First Preferred Shares of a specified series. The Company has the right to redeem the outstanding Preferred Shares, Series D,
Series G and Series I shares without the consent of the holder every five years thereafter for cash, in whole or in part at a price of $25.00 per share plus
all accrued and unpaid dividends up to but excluding the date fixed for redemption and $25.50 per share plus all accrued and unpaid dividends up to
but excluding the date fixed for redemption in the case of redemptions on any other date after August 15, 2028, February 15, 2025 and August 15, 2028,
respectively. The reset dividend yield for Series I equals the Government of Treasury Bill Rate on the applicable reset date, plus 2.54 per cent.
(5) On July 6, 2023, Emera announced it would not redeem the outstanding Preferred Shares, Series C and Series H 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 Series D Shares
and no Series H Shares were converted into Series I shares.
(6) The annual fixed dividend per share for Series C Shares was reset from $1.1802 to $1.6085 for the five-year period from and including August 15, 2028.
(7) The annual fixed dividend per share for Series H Shares was reset from $1.2250 to $1.5810 for the five-year period from and including August 15, 2028.
(8) First Preferred Shares, Series E are redeemable at $25.00 per share.
(9) First Preferred Shares, Series L are redeemable at $26.00 on or after November 15, 2026 to November 15, 2027, decreasing $0.25 each year until
November 15, 2030 and $25.00 per share thereafter.
First Preferred Shares are neither redeemable at the option of the shareholder nor have a mandatory redemption date. They are
classified as equity and the associated dividends are deducted on the Consolidated Statements of Income before arriving at “Net
income attributable to common shareholders” and shown on the Consolidated Statement of Changes in Equity as a deduction
from retained earnings.
The First Preferred Shares of each series rank on a parity with the First Preferred Shares of every other series and are entitled to
a preference over the Second Preferred Shares, the Common Shares, and any other shares ranking junior to the First Preferred
Shares with respect to the payment of dividends and the distribution of the remaining property and assets or return of capital of
the Company in the liquidation, dissolution or wind-up, whether voluntary or involuntary.
In the event the Company fails to pay, in aggregate, eight quarterly dividends on any series of the First Preferred Shares, the
holders of the First Preferred Shares, for only so long as the dividends remain in arrears, will be entitled to attend any meeting
of shareholders of the Company at which directors are to be elected and to vote for the election of two directors out of the total
number of directors elected at any such meeting.
29. Non-Controlling Interest in Subsidiaries
As at
millions of dollars
Preferred shares of GBPC
December 31
2023
December 31
2022
$
$
14 $
$
14
14
14
133
Notes to the Consolidated Financial StatementsEMERA 2023 ANNUAL REPORT
PREFERRED SHARES OF GBPC:
Authorized:
10,000 non-voting cumulative redeemable variable perpetual preferred shares.
Issued and outstanding:
Outstanding as at December 31
2023
2022
number of
shares
millions of
dollars
number of
shares
millions of
dollars
10,000
$
14
10,000
$
14
GBPC NON–VOTING CUMULATIVE VARIABLE PERPETUAL PREFERRED STOCK:
The preferred shares are redeemable by GBPC after June 17, 2021, at $1,000 Bahamian per share plus accrued and unpaid
dividends and are entitled to a 6.0 per cent per annum fixed cumulative preferential dividend to be paid semi-annually.
The Preferred Shares rank behind GBPC’s current and future secured and unsecured debt and ahead of all of GBPC’s current and
future common stock.
30. Supplementary Information to Consolidated Statements of Cash Flows
For the
millions of dollars
Changes in non-cash working capital:
Inventory
Receivables and other current assets (1 )
Accounts payable
Other current liabilities (2)
Total non-cash working capital
Year ended December 31
2022
2023
$
(31) $
653
(538)
(179)
(214)
(636)
423
193
$
(95) $
(234)
(1)
Includes $162 million related to the January 2023 settlement of NMGC gas hedges (2022 – ($162) million). Offsetting regulatory liability is included in
operating cash flow before working capital resulting in no impact to net cash provided by operating activities.
(2) Includes ($166) million related to the Nova Scotia Cap-and-Trade program (2022 – $172 million). For further detail, refer to note 6. Offsetting regulatory asset
(FAM) balance is included in operating cash flow before working capital resulting in no impact to net cash provided by operating activities.
For the
millions of dollars
Supplemental disclosure of cash paid:
Interest
Income taxes
Supplemental disclosure of non-cash activities:
Common share dividends reinvested
Decrease in accrued capital expenditures
Reclassification of short-term debt to long-term debt
Reclassification of long-term debt to short-term debt
Supplemental disclosure of operating activities:
Net change in short-term regulatory assets and liabilities
31. Stock-Based Compensation
Year ended December 31
2022
2023
$ 930
43
$
$ 699
67
$
$ 271
$
$
(19) $
657
$
- $
237
(13)
–
500
$ 123
$
(157)
EMPLOYEE COMMON SHARE PURCHASE PLAN AND COMMON SHAREHOLDERS DIVIDEND
REINVESTMENT AND SHARE PURCHASE PLAN
Eligible employees may participate in the ECSPP. As of December 31, 2023, the plan allows employees to make cash contributions
of a minimum of $25 to a maximum of $20,000 CAD or $15,000 USD per year for the purpose of purchasing common shares of
Emera. The Company also contributes 20 per cent of the employees’ contributions to the plan.
134
Notes to the Consolidated Financial StatementsEMERA 2023 ANNUAL REPORT
The plan allows reinvestment of dividends for all participants except where prohibited by law. The maximum aggregate number of
Emera common shares reserved for issuance under this plan is 7 million common shares. As at December 31, 2023, Emera was in
compliance with this requirement.
Compensation cost for shares issued under the ECSPP for the year ended December 31, 2023 was $3 million (2022 – $3 million)
and was included in “OM&G” on the Consolidated Statements of Income.
The Company also has a Common Shareholders DRIP, which provides an opportunity for shareholders residing in Canada to
reinvest dividends and purchase common shares. This plan provides for a discount of up to 5 per cent from the average market
price of Emera’s common shares for common shares purchased in connection with the reinvestment of cash dividends. The
discount was 2 per cent in 2023.
STOCK-BASED COMPENSATION PLANS
Stock Option Plan
The Company has a stock option plan that grants options to senior management of the Company for a maximum term of 10 years.
The option price of the stock options is the closing price of the Company’s common shares on the Toronto Stock Exchange on
the last business day on which such shares were traded before the date on which the option is granted. The maximum aggregate
number of shares issuable under this plan is 14.7 million shares. As at December 31, 2023, Emera was in compliance with this
requirement.
Stock options granted in 2021 and prior vest in 25 per cent increments on the first, second, third and fourth anniversaries of the
date of the grant. Stock options granted in 2022 and thereafter vest in 20 per cent increments on the first, second, third, fourth
and fifth anniversaries of the date of the grant. If an option is not exercised within 10 years, it expires and the optionee loses all
rights thereunder. The holder of the option has no rights as a shareholder until the option is exercised and shares have been
issued. The total number of stocks to be optioned to any optionee shall not exceed five per cent of the issued and outstanding
common stocks on the date the option is granted.
For stock options granted in 2021 and prior, unless a stock option has expired, vested options may be exercised within the
27 months following the option holder’s date of retirement, six months following a termination without just cause or death, and
within sixty days following the date of termination for just cause or resignation. Commencing with the 2022 stock option grant,
vested options may be exercised during the full term of the option following the option holders date of retirement, six months
following a termination without just cause or death, and within sixty days following the date of termination for just cause or
resignation. If stock options are not exercised within such time, they expire.
The Company uses the Black-Scholes valuation model to estimate the compensation expense related to its stock-based
compensation and recognizes the expense over the vesting period on a straight-line basis.
The following table shows the weighted average FV per stock option along with the assumptions incorporated into the valuation
models for options granted, for the year-ended December 31:
Weighted average FV per option
Expected term (1)
Risk-free interest rate (2)
Expected dividend yield (3)
Expected volatility (4)
2023
2022
$
6.32
5 years
3.53%
5.05%
20.07%
$
5.35
5 years
1.79%
4.55%
18.87%
(1) The expected term of the option awards is calculated based on historical exercise behaviour and represents the period of time that the options are expected
to be outstanding.
(2) Based on the Bank of Canada five-year government bond yields.
(3) Incorporates current dividend rates and historical dividend increase patterns.
(4) Estimated using the five-year historical volatility.
135
Notes to the Consolidated Financial StatementsEMERA 2023 ANNUAL REPORT The following table summarizes stock option information for 2023:
Outstanding as at December 31, 2022
Granted
Exercised
Forfeited
Vested
Options outstanding December 31, 2023
Total Options
Non-Vested Options (1)
Weighted
average
exercise price
per share
Number of
Options
Number of
Options
Weighted
average grant
date fair-value
2,853,879
483,100
(146,475)
(94,900)
N/A
$ 50.41
54.64
43.94
56.32
N/A
1,348,400
483,100
N/A
(51,625)
(526,620)
$
3,095,604
$ 51.20
1,253,255
$
4.08
6.32
N/A
3.61
3.58
5.17
Options exercisable December 31, 2023 (2) (3)
1,842,349
$ 48.39
(1) As at December 31, 2023, there was $5 million of unrecognized compensation related to stock options not yet vested which is expected to be recognized
over a weighted average period of approximately 3 years (2022 – $4 million, 3 years).
(2) As at December 31, 2023, the weighted average remaining term of vested options was 5 years with an aggregate intrinsic value of $8 million (2022 – 5 years,
$10 million).
(3) As at December 31, 2023, the FV of options that vested in the year was $2 million (2022 – $2 million).
Compensation cost recognized for stock options for the year ended December 31, 2023 was $2 million (2022 – $2 million), which
was included in “OM&G” on the Consolidated Statements of Income.
As at December 31, 2023, cash received from option exercises was $6 million (2022 – $9 million). The total intrinsic value of
options exercised for the year ended December 31, 2023 was $2 million (2022 – $4 million). The range of exercise prices for the
options outstanding as at December 31, 2023 was $32.35 to $60.03 (2022 – $32.35 to $60.03).
SHARE UNIT PLANS
The Company has DSU, PSU and RSU plans. The plans and the liabilities are marked-to-market at the end of each period based on
an average common share price at the end of the period.
Deferred Share Unit Plans
Under the Directors’ DSU plan, Directors of the Company may elect to receive all or any portion of their compensation in DSUs
in lieu of cash compensation, subject to requirements to receive a minimum portion of their annual retainer in DSUs. Directors’
fees are paid on a quarterly basis and, at the time of each payment of fees, the applicable amount is converted to DSUs. A DSU
has a value equal to one Emera common share. When a dividend is paid on Emera’s common shares, the Director’s DSU account
is credited with additional DSUs. DSUs cannot be redeemed for cash until the Director retires, resigns or otherwise leaves the
Board. The cash redemption value of a DSU equals the market value of a common share at the time of redemption, pursuant
to the plan. Following retirement or resignation from the Board, the value of the DSUs credited to the participant’s account is
calculated by multiplying the number of DSUs in the participant’s account by Emera’s closing common share price on the date
DSUs are redeemed.
Under the executive and senior management DSU plan, each participant may elect to defer all or a percentage of their annual
incentive award in the form of DSUs with the understanding, for participants who are subject to executive share ownership
guidelines, a minimum of 50 per cent of the value of their actual annual incentive award (25 per cent in the first year of the
program) will be payable in DSUs until the applicable guidelines are met.
When short-term incentive awards are determined, the amount elected is converted to DSUs, which have a value equal to the
market price of an Emera common share. When a dividend is paid on Emera’s common shares, each participant’s DSU account
is allocated additional DSUs equal in value to the dividends paid on an equivalent number of Emera common shares. Following
termination of employment or retirement, and by December 15 of the calendar year after termination or retirement, the value of
the DSUs credited to the participant’s account is calculated by multiplying the number of DSUs in the participant’s account by the
average of Emera’s stock closing price for the fifty trading days prior to a given calculation date. Payments are made in cash.
In addition, special DSU awards may be made from time to time by the Management Resources and Compensation Committee
(“MRCC”), to selected executives and senior management to recognize singular achievements or by achieving certain
corporate objectives.
136
Notes to the Consolidated Financial StatementsEMERA 2023 ANNUAL REPORT A summary of the activity related to employee and director DSUs for the year ended December 31, 2023 is presented in the
following table:
Outstanding as at December 31, 2022
Granted including DRIP
Exercised
Outstanding and exercisable as at December 31, 2023
Employee
DSU
627,223
85,740
N/A
712,963
Weighted
Average Grant
Date FV
$ 41.55
47.66
N/A
$ 42.29
Director
DSU
Weighted
Average Grant
Date FV
664,258
117,893
(53,093)
729,058
$ 45.83
49.99
49.39
$ 46.24
Compensation cost recovery recognized for employee and director DSU’s for the year ended December 31, 2023 was $2 million
(2022 – $6 million). Tax expense related to this compensation cost recovery for share units realized for the year ended
December 31, 2023 was $1 million (2022 – $2 million). The aggregate intrinsic value of the outstanding shares for the year ended
December 31, 2023 for employees was $36 million (2022 – $33 million). The aggregate intrinsic value of the outstanding shares
for the year ended December 31, 2023 for directors was $37 million (2022 – $34 million). Cash payments made during the year
ended December 31, 2023 associated with the DSU plan were $3 million (2022 – $8 million).
Performance Share Unit Plan
Under the PSU plan, certain executive and senior employees are eligible for long-term incentives payable through the plan.
PSUs are granted annually for three-year overlapping performance cycles, resulting in a cash payment. PSUs are granted based
on the average of Emera’s stock closing price for the fifty trading days prior to the effective grant date. Dividend equivalents are
awarded and paid in the form of additional PSUs. The PSU value varies according to the Emera common share market price and
corporate performance.
PSUs vest at the end of the three-year cycle and the payouts will be calculated and approved by the MRCC early in the following
year. The value of the payout considers actual service over the performance cycle and may be pro-rated in certain departure
scenarios. In the case of retirement, as defined in the PSU plan, grants may continue to vest in full and payout in normal course
post-retirement.
A summary of the activity related to employee PSUs for the year ended December 31, 2023 is presented in the following table:
Outstanding as at December 31, 2022
Granted including DRIP
Exercised
Forfeited
Outstanding as at December 31, 2023
Employee
PSU
690,446
386,261
(323,155)
(10,187)
743,365
Weighted
Average Grant
Date FV
$ 56.24
52.71
54.62
55.15
$ 55.13
Aggregate
intrinsic value
$
40
$
41
Compensation cost recognized for the PSU plan for the year ended December 31, 2023 was $11 million (2022 – $18 million). Tax
benefits related to this compensation cost for share units realized for the year ended December 31, 2023 were $3 million (2022 –
$5 million). Cash payments made during the year ended December 31, 2023 associated with the PSU plan were $19 million
(2022 – $24 million).
Restricted Share Unit Plan
Under the RSU plan, certain executive and senior employees are eligible for long-term incentives payable through the plan. RSUs
are granted annually for three-year overlapping performance cycles, resulting in a cash payment. RSUs are granted based on
the average of Emera’s stock closing price for the fifty trading days prior to the effective grant date. Dividend equivalents are
awarded and paid in the form of additional RSUs. The RSU value varies according to the Emera common share market price.
RSUs vest at the end of the three-year cycle and the payouts will be calculated and approved by the MRCC early in the following
year. The value of the payout considers actual service over the performance cycle and may be pro-rated in certain departure
scenarios. In the case of retirement, as defined in the RSU plan, grants may continue to vest in full and payout in normal course
post-retirement.
137
Notes to the Consolidated Financial StatementsEMERA 2023 ANNUAL REPORT A summary of the activity related to employee RSUs for the year ended December 31, 2023 is presented in the following table:
Outstanding as at December 31, 2022
Granted including DRIP
Exercised
Forfeited
Outstanding as at December 31, 2023
Employee
RSU
Weighted
Average Grant
Date FV
508,468
236,537
(171,537)
(10,827)
562,641
$ 56.25
52.07
54.62
54.76
$ 55.01
Aggregate
intrinsic value
$
30
$
32
Compensation cost recognized for the RSU plan for the year ended December 31, 2023 was $10 million (2022 – $9 million). Tax
benefits related to this compensation cost for share units realized for the year ended December 31, 2023 were $3 million (2022 –
$2 million). Cash payments made during the year ended December 31, 2023 associated with the RSU plan were $10 million
(2022– nil).
32. Variable Interest Entities
Emera holds a variable interest in NSPML, a VIE for which it was determined that Emera is not the primary beneficiary since it
does not have the controlling financial interest of NSPML. When the critical milestones were achieved, Nalcor Energy was deemed
the primary beneficiary of the asset for financial reporting purposes as it has authority over the majority of the direct activities
that are expected to most significantly impact the economic performance of the Maritime Link. Thus, Emera began recording the
Maritime Link as an equity investment.
BLPC has established a SIF, primarily for the purpose of building a fund to cover risk against damage and consequential loss to
certain generating, transmission and distribution systems. ECI holds a variable interest in the SIF for which it was determined
that ECI was the primary beneficiary and, accordingly, the SIF must be consolidated by ECI. In its determination that ECI controls
the SIF, management considered that, in substance, the activities of the SIF are being conducted on behalf of ECI’s subsidiary
BLPC and BLPC, alone, obtains the benefits from the SIF’s operations. Additionally, because ECI, through BLPC, has rights to all
the benefits of the SIF, it is also exposed to the risks related to the activities of the SIF. Any withdrawal of SIF fund assets by the
Company would be subject to existing regulations. Emera’s consolidated VIE in the SIF is recorded as “Other long-term assets”,
“Restricted cash” and “Regulatory liabilities” on the Consolidated Balance Sheets. Amounts included in restricted cash represent
the cash portion of funds required to be set aside for the BLPC SIF.
The Company has identified certain long-term purchase power agreements that meet the definition of variable interests as the
Company has to purchase all or a majority of the electricity generation at a fixed price. However, it was determined that the
Company was not the primary beneficiary since it lacked the power to direct the activities of the entity, including the ability to
operate the generating facilities and make management decisions.
The following table provides information about Emera’s portion of material unconsolidated VIEs:
As at
millions of dollars
Unconsolidated VIEs in which Emera has variable interests
NSPML (equity accounted)
33. Subsequent Events
December 31, 2023
December 31, 2022
Total assets
Maximum
exposure to
loss
Total assets
Maximum
exposure to
loss
$
489
$
6
$
501
$
6
These financial statements and notes reflect the Company’s evaluation of events occurring subsequent to the balance sheet date
through February 26, 2024, the date the financial statements were issued.
138
Notes to the Consolidated Financial StatementsEMERA 2023 ANNUAL REPORT Emera Leadership and Board
As of March 31, 2024
Emera Leadership
Board of Directors
Scott Balfour
President and
Chief Executive Officer,
Emera Inc.
Bruce Marchand
Chief Risk and Sustainability
Officer,
Emera Inc.
Jackie Sheppard
Chair, Emera Board of
Directors
Calgary, Alberta
Mike Barrett
Executive Vice President,
Legal and General Counsel,
Emera Inc.
Greg Blunden
Chief Financial Officer,
Emera Inc.
Archie Collins
President and Chief
Executive Officer,
Tampa Electric
Peter Gregg
President and Chief
Executive Officer,
Nova Scotia Power
Karen Hutt
Executive Vice President,
Business Development
and Strategy,
Emera Inc.
Dan Muldoon
Executive Vice President,
Project Development
and Operations Support,
Emera Inc.
Michael Roberts
Chief Human Resources
Officer,
Emera Inc.
Ryan Shell
President,
New Mexico Gas Company
Judy Steele
President and
Chief Operating Officer,
Emera Energy
Helen Wesley
President,
Peoples Gas
Scott Balfour
President and
Chief Executive Officer
Halifax, Nova Scotia
James Bertram
Calgary, Alberta
Henry Demone
Lunenburg, Nova Scotia
Paula Gold-Williams
San Antonio, Texas
Kent Harvey
New York, New York
Lynn Loewen
Westmount, Quebec
Brian Porter
Toronto, Ontario
Ian Robertson
Oakville, Ontario
Andrea Rosen
Toronto, Ontario
Karen Sheriff
Picton, Ontario
Jochen Tilk
Toronto, Ontario
139
EMERA 2023 ANNUAL REPORT Shareholder Information
For general inquiries, please contact our
corporate office:
Share Listings
Emera Inc.
P.O. Box 910
Halifax, Nova Scotia B3J 2W5
T: 902.450.0507 or 1.888.450.0507
Information regarding Company news
and initiatives, including our 2023 Annual
Report, is available on our website:
www.emera.com
Transfer Agent
TSX Trust Company
P.O. Box 2082, Station C
Halifax, Nova Scotia B3J 3B7
T: 1.877.982.8762
F: 1.888.249.6189
www.tsxtrust.com
Investor Services
T: 902.428.6060 or 1.800.358.1995
F: 902.428.6181
E: investors@emera.com
Financial Analysts,
Portfolio Managers and
Institutional Investors
Dave Bezanson
Vice President, Investor Relations
and Pensions
T: 902.474.2126
E: dave.bezanson@emera.com
Arianne Amirkhalkhali
Senior Manager, Investor Relations
T: 902.425.8130
E: arianne.amirkhalkhali@emera.com
This Annual Report contains forward-
looking information. Actual future
results may differ materially. Additional
financial and operational information
is filed electronically with various
securities commissions in Canada, copies
of which are available electronically
under Emera’s profile on SEDAR+ at
www.sedarplus.ca.
Toronto Stock Exchange (TSX)
Common shares: EMA
Preferred shares: EMA.PR.A, EMA.PR.B,
EMA.PR.C, EMA.PR.E, EMA.PR.F,
EMA.PR.H, EMA.PR.J and EMA.PR.L
Barbados Stock Exchange (BSE)
Depositary receipts: EMABDR
Bahamas International Securities
Exchange (BISX)
Depositary receipts: EMAB
Shares Outstanding
Common shares: 284,117,511
(as of December 31, 2023)
Dividends Paid in 2023
Emera Inc. paid common share dividends
of $0.69 per quarter in Q1, Q2 and Q3
(annualized rate of $2.76 per common
share) and $0.7175 in Q4 (annualized
rate of $2.87 per common share), for an
effective annual common share dividend
rate of $2.7875 per common share.
Dividend Payments
in 2024
Subject to approval by the Board of
Directors, dividends for Emera Inc. are
payable on or about the 15th of February,
May, August and November. A first
quarter common share dividend of
$0.7175, a Series A First Preferred Share
dividend of $0.1364, a Series B First
Preferred Share dividend of $0.4408,
a Series C First Preferred Share dividend
of $0.40213, a Series E First Preferred
Share dividend of $0.28125, a Series F
First Preferred Share dividend of
$0.26263, a Series H First Preferred
Share dividend of $0.39525, a Series J
First Preferred Share dividend of
$0.265625 and a Series L First Preferred
Share dividend of $0.2875 were declared
and paid on February 15, 2024.
Dividend Reinvestment
and Share Purchase Plan
Emera’s Dividend Reinvestment and
Share Purchase Plan is available to
shareholders who reside in Canada.
The plan provides a convenient
and economical means of acquiring
additional common shares through
the reinvestment of dividends with a
discount of up to five per cent. In 2023,
the discount was two per cent. Plan
participants may also contribute cash
payments of up to $5,000 per quarter.
Plan participants pay no commissions,
service charges or brokerage fees
for shares purchased under the plan.
Please contact Investor Services if you
have questions or wish to receive an
enrollment form.
Direct Deposit Service
Registered shareholders may have
dividends deposited directly to any
bank account in Canada. To arrange
this service, please contact TSX Trust
Company. Beneficial shareholders should
contact their financial intermediary.
Quarterly Earnings
Quarterly earnings are expected to
be announced in May, August and
November 2024. Year-end results for
2024 will be released in February 2025.
Emera is represented in the TSX
Composite, TSX Capped Utilities, TSX60
and select MSCI and FTSE World indexes.
140
EMERA 2023 ANNUAL REPORT Our Operating Companies
As of December 31, 2023
TAMPA ELECTRIC
Vertically integrated electric utility
serving about 840,000 customers in
west central Florida.
NOVA SCOTIA POWER
Vertically integrated electric
utility serving approximately
549,000 customers in Nova Scotia.
PEOPLES GAS
Natural gas utility serving
490,000 customers in Florida.
NEW MEXICO GAS
Natural gas utility serving
540,000 customers in New Mexico.
EMERA CARIBBEAN
Vertically integrated electric utilities
serving more than 150,000 customers
on the islands of Barbados and
Grand Bahama.
EMERA NEWFOUNDLAND &
LABRADOR
Owns and operates the Maritime Link
and manages Emera’s investment in an
associated project.
EMERA ENERGY
Energy marketing and trading, asset
management and optimization in Canada
and the US.
EMERA NEW BRUNSWICK
Owns and operates the Brunswick
pipeline, a 145-kilometre natural gas
pipeline in New Brunswick.
BLOCK ENERGY
A technology company focused
on finding new, innovative ways to
deliver renewable and resilient energy
to customers.
www.emera.com
www.emera.com