2022 ANNUAL REPORT
2022 Financial Highlights
Data is as of December 31, 2022, unless otherwise indicated.
8.8%
annualized total
shareholder return over
the last 10 years
5.4%
annualized dividend
growth since 2000
95%+
of earnings from
regulated investments
2022 ADJUSTED NET INCOME*
Excluding Corporate costs
BY BUSINESS
SEGMENT
BY REVENUE
TYPE
53% Florida electric
76% Regulated electric
20% Canadian electric
20% Regulated gas
20% Gas utilities and
infrastructure
4% Other
3% Other electric
4% Unregulated
* Based on 2022 adjusted net income attributable to common shareholders (“adjusted net income”),
excluding Corporate costs of $267 million. 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 2022 MD&A.
1 EMERA AT A GLANCE
2 OUR STRATEGY
4 WHY INVEST IN EMERA
5 LETTER TO SHAREHOLDERS
9 FINANCIAL REVIEW
Emera at a Glance
Data is as of December 31, 2022, 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.
6
electric and
natural gas
utilities in Canada,
the US and the
Caribbean
$7.6B
revenue
2.5M
customers
7,100+
employees
$40B
total assets
10%
annualized growth in
adjusted net income*
since 2017
$5.3B+
of capital plan through
2025 committed to
cleaner energy
and reliability projects
17%
improvement in our lost-time frequency rate
compared to our 5-year average
* 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 2022 MD&A.
EMERA 2022 ANNUAL REPORT
1
Our Strategy
Our world is changing quickly, and we’re ready. For nearly two decades,
we’ve been focused on safely delivering cleaner, reliable energy at a pace
that’s balanced against cost impacts for our customers. We’re delivering
solutions to the key challenges facing our industry: decarbonization,
decentralization and digitalization.
EXPERT
TEAMS
DELIVERING FOR
OUR CUSTOMERS
DRIVING GROWTH
AND REINVESTMENT
We’re a team of experts leading
the way to a cleaner energy
future as we work toward our
2050 net-zero vision.
Every day, we’re safely and
cost-effectively delivering
cleaner, more reliable energy
for our customers.
Delivering for our customers drives
predictable returns and steady
growth for our investors, enabling
us to reinvest in our teams,
companies and communities.
DELIVERING ON OUR CLIMATE COMMITMENT
The team across Emera is working together to meet our Climate Commitment
goals and our vision to achieve net-zero CO2 emissions by 2050.
41% reduction in CO2
emissions since 2005*
1,654 MW installed
renewable capacity
68% reduction in use of
coal in generation (GWh)
since 2005
* Undergoing final review and verification.
2
EMERA 2022 ANNUAL REPORT
We continue to invest in new
technologies and innovation to support
our Climate Commitment.*
2040 GOAL
80% reduction in CO2
emissions and last coal unit
retired no later than 2040
2025 GOAL
55% reduction
in CO2 emissions
2050 VISION
Net-zero
CO2 emissions
* Our Climate Commitment goals are compared to 2005 levels.
EMERA 2022 ANNUAL REPORT
3
Why Invest in Emera
Through our proven strategy and our portfolio of high-quality,
regulated utilities, our expert teams across Emera continue to drive
long-term value for shareholders.
Visible Growth Plan
$8B to $9B capital investment
plan1 through 2025
7% to 8% forecasted rate
base growth through 2025
65% of adjusted net income2, excluding
Corporate costs, came from Florida in 2022
75% of CapEx plan from 2023–2025 is focused
in Florida — the fastest growing US state in 2022
Sustainable
Dividend
Growth
4% to 5%
dividend growth target
through 2025
Constructive
Regulatory
Environments
89% of adjusted net income2,
excluding Corporate costs, derived
from our four core regulated utilities
5.3%
dividend yield3
Highly rated
regulatory environments
Strong, ESG-Driven Strategy
63% of capital plan to 2025
committed to decarbonization
and reliability
$18M invested in our
communities in 20224
Emera’s capital investment plan includes $240 million equity investment in 2023.
1
2 Based on 2022 adjusted net income, excluding Corporate costs of $267 million. 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 2022 MD&A.
3 As of December 31, 2022. Our share price on this date was $51.75.
4 Includes a one-time, $5 million contribution to the University of South Florida to establish the TECO Clean Energy Research Center.
4
EMERA 2022 ANNUAL REPORT
Letter from the Chair and the CEO
FELLOW SHAREHOLDERS,
In 2022, the Emera team advanced our strategy of safely
delivering cleaner, more reliable energy for our customers with
a focus on growth and long-term value for our shareholders.
Despite significant challenges like increasingly intense
weather, rising inflation rates and supply chain disruptions,
Emera’s overall performance in 2022 is a testament to the
strength of our strategy, our team and our diversified portfolio.
STRATEGY IN ACTION
Our role as leaders in the energy transition is driving
growth as we invest strategically to reduce emissions, add
more renewable energy to our generation and improve grid
resiliency to enhance reliability for our customers.
In 2022, the execution of our strategy was realized in our
$2.6 billion capital plan that was largely focused on cleaner
energy and reliability investments. Last year, we achieved
a 41 per cent reduction in CO2 emissions across Emera,
compared to 2005 levels.
Here are just some of the projects our teams advanced last
year that highlight our environmental priorities and how
our strategy continues to drive growth and value for our
customers and shareholders:
• The Big Bend Modernization project at Tampa Electric was
completed in December 2022 on time, on budget and with
a world-class level of safety performance. In addition to
reducing CO2 emissions, the facility is now one of the most
efficient natural gas generation units in North America.
It’s also estimated that this modernization project will save
customers more than $700 million over the 30-year life of
the plant.
Jackie Sheppard
Chair, Emera Inc.
Board of Directors
Scott Balfour
President and
CEO, Emera Inc.
EMERA 2022 ANNUAL REPORT
5
• Tampa Electric continued its investment in solar generation
with clean hydroelectric energy, the Link saved customers in
in 2022, completing the installation of three new solar sites
Nova Scotia almost $100 million last year and will continue
and bringing its total solar generation in service to more
to deliver significant value for decades to come.
than 1,000 MW. With this achievement, Tampa Electric
• The team at Barbados Light & Power brought the Clean
continues to have the highest proportion of solar generation
Energy Bridge (CEB) into service in June 2022. Supplying
per customer of any utility in Florida. Our investments in
roughly 27 per cent of the island’s energy needs, this
solar have allowed us to decrease the carbon intensity of our
33 MW medium-speed diesel generating plant is enhancing
generation mix, and saved customers over $80 million USD
reliability and grid resiliency for customers. The CEB
in avoided fuel costs in 2022.
replaces older, less-efficient infrastructure, reducing fuel
• The Maritime Link is a transformational energy project that
costs and providing critical baseload energy as the country
is a key part of the solution for reducing the use of coal at
transitions to 100 per cent renewable energy.
Nova Scotia Power. By replacing high-carbon generation
6
EMERA 2022 ANNUAL REPORT
SAFETY
Safety is our number one priority, and we are deeply
committed to building a strong safety culture. We continued to
implement comprehensive enterprise-wide safety systems, and
in 2022 the team achieved a ten per cent improvement in our
Occupational Safety and Health Administration (OSHA) injury
rate and a 17 per cent improvement in our lost-time frequency
rate compared to our average over the last five years —
both better than the industry average. This improvement is
particularly notable given that our teams in Nova Scotia and
Florida also responded to two historic hurricanes in 2022 — in
both cases without any lost-time injuries.
Despite our efforts and progress, we lost a colleague at Nova
Scotia Power in 2022. This tragic loss was profoundly felt
across our entire organization and has served to strengthen
our resolve to build an Emera where no one gets hurt.
DIVERSITY, EQUITY AND INCLUSION (DEI)
A strong, diverse team makes our business better. Our
Emera-wide DEI strategy guides our efforts in building and
maintaining a healthy, diverse and inclusive workplace
and culture.
Our Emera DEI Council drives common focus while also
supporting our operating companies in addressing their
unique DEI journeys. Across the organization, voluntary
Employee Resource Groups (ERGs) are in place for Black
employees, Latinx employees, veterans, employees in the
LGBTQ+ community, women engineers, and women in trades
and technology.
We are also committed to building more diverse and inclusive
communities where we live and work. In 2022, we invested
more than $18 million in our communities, with over $2 million
invested from Emera’s DEI Fund.
“
The Emera team was the driving force behind our
achievements in 2022. The work they do delivers for
customers, fuels our growth and positions Emera to
continue to provide predictable, sustainable earnings
and long-term value to our shareholders.”
EMERA 2022 ANNUAL REPORT
7
FINANCIAL RESULTS
For 2022, we reported $850 million in annual adjusted net
income1 and adjusted earnings per share (EPS)1 of $3.20.
Excluding the impact of a litigation award received2 in the
fourth quarter, annual adjusted earnings1 of $805 million is
our highest ever adjusted annual earnings1 and represents an
increase of 11 per cent over the previous year. The equivalent
annual adjusted EPS1 of $3.03 was an eight per cent increase
over the previous year.
Last year, we also increased our dividend by four per cent,
in line with our four to five per cent dividend growth target
through 2025. We are proud of our track record of long-term
dividend growth, having provided 5.4 per cent growth on an
annualized basis since 2000.
While our Total Shareholder Return (TSR) has historically been
strong relative to our energy industry peers, the introduction
and passage of Bill 212 in Nova Scotia directly and indirectly
impacted our share price performance in 2022. We are
focused on addressing this underperformance, and we are
confident in our ability to return to superior performance
for our shareholders. Looking forward, we believe that we
are well positioned to continue our track record of providing
strong and predictable earnings and dividend growth for
our shareholders.
THANK YOU
The Emera team was the driving force behind our achievements
in 2022. The work they do delivers for customers, fuels our
growth and positions Emera to continue to provide predictable,
sustainable earnings and long-term value to our shareholders.
Thank you to Emera’s Board of Directors and the entire Emera
team for your continued commitment and extraordinary work
on behalf of 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 a non-GAAP measure and a non-GAAP ratio, respectively, 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 2022 MD&A.
2 2022 results include the impact of a $45 million after-tax litigation award recognized in the fourth quarter. The impact is $0.17 on adjusted EPS.
8
EMERA 2022 ANNUAL REPORT
Financial Review
Forward-looking Information ............................ 11
Liquidity and Capital Resources ....................... 38
Introduction and Strategic Overview .............. 11
Consolidated Cash Flow Highlights .............. 39
Non-GAAP Financial Measures and Ratios .... 13
Working Capital ................................................ 40
Consolidated Financial Review ......................... 15
Contractual Obligations .................................. 40
Significant Items Affecting Earnings ........... 15
Consolidated Financial Highlights ................ 15
Forecasted Gross Consolidated
Capital Expenditures ....................................... 41
Consolidated Income Statement
Highlights ........................................................... 17
Debt Management ........................................... 41
Credit Ratings ................................................... 43
Business Overview and Outlook ....................... 19
Guaranteed Debt .............................................. 43
Florida Electric Utility ..................................... 19
Outstanding Stock Data .................................. 44
Canadian Electric Utilities .............................. 20
Pension Funding ................................................... 45
Gas Utilities and Infrastructure .................... 23
Off-Balance Sheet Arrangements .................... 45
Other Electric Utilities .................................... 24
Dividend Payout Ratio ........................................ 46
Other ................................................................... 26
Transactions with Related Parties ................... 46
Consolidated Balance Sheet Highlights .......... 27
Enterprise Risk and Risk Management ........... 47
Oher Developments ............................................. 28
Financial Highlights ............................................. 29
Florida Electric Utility ..................................... 29
Canadian Electric Utilities .............................. 30
Gas Utilities and Infrastructure .................... 33
Other Electric Utilities ................................... 35
Other ................................................................... 36
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 2022 ANNUAL REPORT
Management’s Discussion & Analysis
As at February 23, 2023
Management’s Discussion & Analysis (“MD&A”) provides a review of the results of operations of Emera Incorporated and its
subsidiaries and investments during the fourth quarter of 2022 relative to the same quarter in 2021; for the full year of 2022
relative to 2021 and selected financial information for 2020; and its financial position as at December 31, 2022 relative to
December 31, 2021. Throughout this discussion, “Emera” and “Company” refer to Emera Incorporated and all of its consolidated
subsidiaries and investments. The Company’s activities are carried out through five reportable segments: Florida Electric Utility,
Canadian Electric Utilities, Gas Utilities and Infrastructure, Other Electric Utilities, and Other.
This discussion and analysis should be read in conjunction with the Emera annual audited consolidated financial statements and
supporting notes as at and for the year ended December 31, 2022. Emera follows United States Generally Accepted Accounting
Principles (“USGAAP” or “GAAP”).
The accounting policies used by Emera’s rate-regulated entities may differ from those used by Emera’s non-rate-regulated
businesses with respect to the timing of recognition of certain assets, liabilities, revenues and expenses. At December 31, 2022,
Emera’s rate-regulated subsidiaries and investments include:
Emera Rate-Regulated Subsidiary or Equity Investment
Accounting Policies Approved/Examined By
Subsidiary
Tampa Electric – Electric Division of Tampa Electric Company
(“TEC”) (1)
Nova Scotia Power Inc. (“NSPI”)
Peoples Gas System (“PGS”) – Gas Division of TEC (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”)
UARB
Newfoundland and Labrador Board of Commissioners of Public
Utilities (“NLPUB”)
Maritimes & Northeast Pipeline Limited Partnership and
CER and FERC
Maritimes & Northeast Pipeline, LLC (“M&NP”)
St. Lucia Electricity Services Limited (“Lucelec”)
National Utility Regulatory Commission (“NURC”)
(1) Effective January 1, 2023, Peoples Gas System ceased to be a division of TEC and the gas utility was reorganized, resulting in a separate legal entity called
Peoples Gas System, Inc., a wholly owned direct subsidiary of TECO Gas Operations, Inc.
All amounts are in Canadian dollars (“CAD”), except for the Florida Electric Utility, Gas Utilities and Infrastructure, and Other
Electric Utilities sections of the MD&A, which are reported in United States dollar (“USD”) unless otherwise stated.
Additional information related to Emera, including the Company’s Annual Information Form, can be found on SEDAR
at www.sedar.com.
10
EMERA 2022 ANNUAL REPORT Forward-looking Information
This MD&A contains “forward-looking information” and statements which reflect the current view with respect to the Company’s
expectations regarding future growth, results of operations, performance, carbon dioxide emissions reduction goals, business
prospects and opportunities, and may not be appropriate for other purposes within the meaning of applicable Canadian
securities laws. All such information and statements are made pursuant to safe harbour provisions contained in applicable
securities legislation. The words “anticipates”, “believes”, “budget”, “could”, “estimates”, “expects”, “forecast”, “intends”, “may”,
“might”, “plans”, “projects”, “schedule”, “should”, “targets”, “will”, “would” and similar expressions are often intended to identify
forward-looking information, although not all forward-looking information contains these identifying words. The forward-looking
information reflects management’s current beliefs and is based on information currently available to Emera’s management and
should not be read as guarantees of future events, performance or results, and will not necessarily be accurate indications of
whether, or the time at which, such events, performance or results will be achieved.
The forward-looking information is based on reasonable assumptions and is subject to risks, uncertainties and other factors that
could cause actual results to differ materially from historical results or results anticipated by the forward-looking information.
Factors that could cause results or events to differ from current expectations include, without limitation: regulatory and political
risk; operating and maintenance risks; changes in economic conditions; commodity price and availability risk; liquidity and
capital market risk; future dividend growth; timing and costs associated with certain capital investments; expected impacts
on Emera of challenges in the global economy; estimated energy consumption rates; maintenance of adequate insurance
coverage; changes in customer energy usage patterns; developments in technology that could reduce demand for electricity;
global climate change; weather; unanticipated maintenance and other expenditures; system operating and maintenance risk;
derivative financial instruments and hedging; interest rate risk; inflation risk; counterparty risk; disruption of fuel supply; country
risks; environmental risks; foreign exchange (“FX”); regulatory and government decisions, including changes to environmental,
financial reporting and tax legislation; risks associated with pension plan performance and funding requirements; loss of
service area; risk of failure of information technology (“IT”) infrastructure and cybersecurity risks; uncertainties associated with
infectious diseases, pandemics and similar public health threats, such as the COVID-19 novel coronavirus (“COVID-19”) pandemic;
market energy sales prices; labour relations; and availability of labour and management resources.
Readers are cautioned not to place undue reliance on forward-looking information, as actual results could differ materially from
the plans, expectations, estimates or intentions and statements expressed in the forward-looking information. All forward-looking
information in this MD&A is qualified in its entirety by the above cautionary statements and, except as required by law, Emera
undertakes no obligation to revise or update any forward-looking information as a result of new information, future events
or otherwise.
Introduction and Strategic Overview
Based in Halifax, Nova Scotia, Emera owns and operates cost-of-service rate-regulated electric and gas utilities in Canada, the
United States and the Caribbean. Cost-of-service utilities provide essential electric and gas services in designated territories
under franchises and are overseen by regulatory authorities. Emera’s strategic focus continues to be safely delivering cleaner,
affordable and reliable energy to its customers.
The majority of Emera’s investment in rate-regulated businesses are located in Florida with other investments in Nova Scotia,
New Mexico and the Caribbean. Emera’s portfolio of regulated utilities provides reliable earnings, cash flow and dividends.
Earnings opportunities in regulated utilities are generally driven by the magnitude of net investment in the utility (known as
“rate base”), and the amount of equity in the capital structure and the return on that equity (“ROE”) as approved through
regulation. Earnings are also affected by sales volumes and operating expenses.
11
Management’s Discussion & AnalysisEMERA 2022 ANNUAL REPORT Emera’s capital investment plan is $8 – 9 billion over the 2023-to-2025 period (including a $240 million equity investment in
the LIL in 2023), mainly focused in Florida. This results in a forecasted rate base growth of approximately 7 per cent to 8 per cent
through 2025. The capital investment plan continues to include significant investments across the portfolio in renewable and
cleaner generation, reliability and integrity investments, infrastructure modernization, and customer-focused technologies.
Emera’s capital investment plan is being funded primarily through internally generated cash flows and debt raised at the
operating company level. Equity requirements in support of the Company’s capital investment plan are expected to be funded
through the issuance of preferred equity and the issuance of common equity through Emera’s dividend reinvestment plan
(“DRIP”) and at-the-market program (“ATM program”). Maintaining investment-grade credit ratings is a priority of the Company.
Emera has provided annual dividend growth guidance of four to five per cent through 2025. The Company targets a long-term
dividend payout ratio of adjusted net income of 70 to 75 per cent and, while the payout ratio is likely to exceed that target through
and beyond the forecast period, it is expected to return to that range over time. For further information on the non-GAAP measure
“Dividend Payout Ratio of Adjusted Net Income”, refer to the “Non-GAAP Financial Measures and Ratios” section.
Seasonal patterns and other weather events affect demand and operating costs. Similarly, mark-to-market adjustments and
foreign currency exchange can have a material impact on financial results for a specific period. Emera’s consolidated net income
and cash flows are impacted by movements in the USD relative to the Canadian dollar. Emera may hedge both transactional and
translational exposure. These impacts, as well as the timing of capital investments and other factors, mean results in any one
quarter are not necessarily indicative of results in any other quarter, or for the year as a whole.
Energy markets worldwide are facing significant change and Emera is well positioned to respond to shifting customer demands,
digitization, decarbonization, complex regulatory environments, and decentralized generation.
Customers are looking for more choice, better control, and enhanced reliability in a time where costs of decentralized generation
and storage have become more competitive in some regions. Advancing technologies are transforming the way utilities interact
with their customers and generate and transmit energy. In addition, climate change and extreme weather are shaping how
utilities operate and how they invest in infrastructure. There is also an overall need to replace aging infrastructure and further
enhance reliability. Emera will play a role in all of these trends. Emera’s strategy is to fund investments in renewable energy and
technology assets which protect the environment and benefit customers through fuel or operating cost savings.
For example, significant investments to facilitate the use of renewable and low-carbon energy include the Maritime Link in
Atlantic Canada, and the ongoing construction of solar generation and modernization of the Big Bend Power Station at Tampa
Electric. Emera’s utilities are also investing in reliability projects and replacing aging infrastructure. All of these projects
demonstrate Emera’s strategy of safely delivering cleaner, reliable, and affordable energy for its customers.
Building on its decarbonization progress, Emera is continuing its efforts by establishing clear carbon reduction goals and a vision
to achieve net-zero carbon dioxide emissions by 2050.
This vision is inspired by Emera’s strong track record, the Company’s experienced team, and a clear path to Emera’s interim
carbon goals. With existing technologies and resources, and subject to supportive government and regulatory decisions, Emera is
working to achieve the following goals compared to corresponding 2005 levels:
• A 55 per cent reduction in carbon dioxide emissions by 2025.
• The retirement of Emera’s last existing coal unit no later than 2040.
• An 80 per cent reduction in carbon dioxide emissions by 2040.
Achieving the above climate goals on these timelines is subject to the Company’s regulatory obligations and other external
factors beyond Emera’s control.
Emera seeks to deliver on its Climate Commitment while maintaining its focus on investing in reliability and staying focused on the
cost impacts for customers. Emera is also committed to identifying emerging technologies and continuing to work constructively
with policymakers, regulators, partners, investors and customers to achieve these goals and realize its net-zero vision.
Emera is committed to world-class safety, operational excellence, good governance, excellent customer service, reliability, being
an employer of choice, and building constructive relationships.
12
Management’s Discussion & AnalysisEMERA 2022 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. Emera calculates the non-GAAP measures and ratios by adjusting certain GAAP
measures for specific items. Management believes excluding these items better distinguishes the ongoing operations of the
business and allows investors to better understand and evaluate the business. These measures and ratios are discussed and
reconciled below.
Adjusted Net Income Attributable to Common Shareholders, Adjusted Earnings (Loss) Per Common Share
(“EPS”) – Basic and Dividend Payout Ratio of Adjusted Net Income
Emera calculates an adjusted net income attributable to common shareholders (“adjusted net income”) measure by excluding
the effect of mark-to-market (“MTM”) adjustments, impairment charges, the impact of the NSPML unrecoverable costs, and the
2020 gain on sale of Emera Maine.
Management believes excluding from net income the effect of these MTM valuations and changes thereto, until settlement,
better aligns the intent and financial effect of these contracts with the underlying cash flows, and therefore excludes these MTM
adjustments for evaluation of performance and incentive compensation. The MTM adjustments are related to the following:
• held-for-trading (“HFT”) commodity derivative instruments, including adjustments related to the price differential between
the point where natural gas is sourced and where it is delivered, and the related amortization of transportation capacity
recognized as a result of certain Emera Energy marketing and trading transactions;
• the business activities of Bear Swamp Power Company LLC (“Bear Swamp”) included in Emera’s equity income;
• equity securities held in BLPC and a captive reinsurance company in the Other segment; and
• FX hedges entered into to hedge USD denominated operating unit earnings exposure.
For further detail on MTM adjustments, refer to the “Consolidated Financial Review”, “Financial Highlights – Other Electric
Utilities”, and “Financial Highlights – Other” sections.
In Q4 2022, the Company recognized a $73 million non-cash goodwill impairment charge related to GBPC due to a decline in the
fair value of the reporting unit. The fair value decline was driven by the effects of macro-economic factors on the discount rate
calculation, including the risk-free rate assumption. Management believes excluding from net income the effect of this charge
better distinguishes ongoing operations of the business and allows investors to better understand and evaluate the Company.
For further details on this GBPC impairment charge, refer to “Significant Items Impacting Earnings”, and “Financial Highlights –
Other” sections.
In February 2022, the UARB issued a decision to disallow the recovery of $9 million in costs ($7 million after-tax) included in
NSPML’s final capital cost application. The after-tax unrecoverable costs were recognized in “Income from equity investments”
in Emera’s Consolidated Statements of Income. Management believes excluding these unrecoverable costs from the calculation
of adjusted net income better reflects the underlying operations in the period. For further details on the NSPML unrecoverable
costs, refer to the “Business Overview and Outlook – Canadian Electric Utilities” and “Financial Highlights – Canadian Electric
Utilities” sections.
In 2020, the Company recognized a gain on the sale of Emera Maine and certain non-cash impairment charges. Management
believes excluding these from net income better distinguishes ongoing operations of the business and allows investors to better
understand and evaluate the business.
Adjusted EPS – basic and dividend payout ratio of adjusted net income are non-GAAP ratios which are calculated using adjusted
net income, as described above. For further details on dividend payout ratio of adjusted net income, see the “Dividend Payout
Ratio” section.
Emera calculates adjusted net income for the Canadian Electric Utilities, Other Electric Utilities, and Other segments.
Reconciliation to the nearest GAAP measure is included in each segment. Refer to “Financial Highlights – Canadian Electric
Utilities”, “Financial Highlights – Other Electric Utilities” and “Financial Highlights – Other” sections.
13
Management’s Discussion & AnalysisEMERA 2022 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 )
Impairment charges, after-tax (2)
NSPML unrecoverable costs (3)
Gain on sale, after tax and transaction costs (4)
Adjusted net income attributable to common shareholders
EPS – basic
Adjusted EPS – basic
Three months ended
December 31
2021
2022
2022
2021
Year ended
December 31
2020
$
$
483
307
(73)
–
–
$
$
249
1.80
$ 0.93
$
$
$
324
156
–
–
–
168
1.24
0.64
$
$
$
$
$
945
175
(73)
(7)
–
850
3.56
3.20
$
$
$
$
510
(213)
–
–
–
723
$
938
(10)
(26)
–
309
665
1.98
2.81
$
$
3.78
2.68
(1) Net of income tax expense of $124 million for the three months ended December 31, 2022 (2021 – $63 million expense) and $73 million expense for the year
ended December 31, 2022 (2021 – $86 million recovery) (2020 – $8 million recovery).
(2) Net of income tax expense of nil for the three months and year ended December 31, 2022 (2021 – nil) (2020 – $1 million expense).
(3) Emera accounts for NSPML as an equity investment and therefore the after-tax unrecoverable costs were recorded in “Income from equity investments” on
Emera’s Consolidated Statements of Income.
(4) Net of income tax expense of $276 million for the year ended December 31, 2020.
EBITDA and Adjusted EBITDA
Earnings before interest, income taxes, depreciation and amortization (“EBITDA”) and adjusted EBITDA are non-GAAP financial
measures used by Emera. These financial measures are used by numerous investors and lenders to better understand cash flows
and credit quality. EBITDA is useful to assess Emera’s operating performance and indicates the Company’s ability to service or
incur debt, invest in capital, and finance working capital requirements.
Similar to adjusted net income calculations described above, adjusted EBITDA represents EBITDA absent the income effect of
MTM adjustments, impairment charges, the NSPML unrecoverable costs, and the 2020 gain on sale of Emera Maine.
The following is a reconciliation of net income to EBITDA and Adjusted EBITDA:
For the
millions of dollars
Net income (1)
Interest expense, net
Income tax expense (recovery)
Depreciation and amortization
EBITDA
MTM gain (loss), excluding income tax
Impairment charges, excluding income tax
NSPML unrecoverable costs (2)
Gain on sale, net of transaction costs (excluding income tax)
Adjusted EBITDA
Three months ended
December 31
2021
2022
2022
$
499
206
154
254
$ 1,113
431
$
338
151
85
227
$ 801
$ 1,009
709
185
952
$ 2,855
248
$
2021
561
611
902
$ 2,068
(6)
(73)
–
–
755
$
$
219
–
–
–
582
(73)
(7)
–
(299)
–
–
–
$ 2,367
$ 2,687
Year ended
December 31
2020
$
984
679
341
881
$ 2,885
(18)
(25)
–
585
$ 2,343
(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 2022 ANNUAL REPORT
Consolidated Financial Review
SIGNIFICANT ITEMS AFFECTING EARNINGS
GBPC Impairment Charge
In Q4 2022, Emera recognized a goodwill impairment charge of $73 million ($0.27 per common share) for GBPC due to a decline
in the fair value of the reporting unit. Although the cash flows of GBPC have not changed significantly compared to previous
periods, the decline in the fair value was driven by the effects of macro-economic factors on discount rate calculations, including
the risk-free rate assumption. This non-cash charge was recorded in “Impairment charge” on the Consolidated Statements of
Income and reduced the GBPC goodwill balance to nil. For further details, refer to note 22 in the consolidated financial statements.
TECO Guatemala Holdings (“TGH”) International Arbitration and Award
On December 15, 2022, a payment of $63 million ($45 million after tax and legal costs, or $0.17 per common share), was made
by the Republic of Guatemala to TECO Energy in satisfaction of the second and final award issued by the International Centre
of the Settlement of Investment Disputes tribunal regarding a dispute over an investment of TGH, a wholly owned subsidiary of
TECO Energy. The dispute related to the 2007 intervention by the government of Guatemala in an ongoing independent rate-
setting process to unilaterally set a new and lower tariff. The payment was recognized in “Other income, net” on the Consolidated
Statements of Income. For further details, refer to note 27 in the consolidated financial statements.
Earnings Impact of MTM Gain (Loss), After-Tax
MTM gain, after-tax increased $151 million to $307 million in Q4 2022, compared to $156 million in Q4 2021, and for the year
ended December 31, increased $388 million to $175 million compared to a MTM loss, after-tax of $213 million for the same period
in 2021. These increases were due to changes in existing positions and reversal of losses in 2022, partially offset by higher
amortization in 2022 of gas transportation assets at Emera Energy.
CONSOLIDATED FINANCIAL HIGHLIGHTS
For the
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
Impairment charges, after-tax
NSPML unrecoverable costs
Gain on sale, after tax and transaction costs
Net income attributable to common shareholders
Three months ended
December 31
Year ended
December 31
2022
2021
2022
2021
$
$ 124
46
72
8
(1)
$
85
67
55
5
(44)
$ 596
222
221
29
(218)
$ 462
241
198
20
(198)
2020
501
221
162
33
(252)
$ 249
307
(73)
–
–
$ 483
$ 168
156
–
–
–
324
$
$ 850
$ 723
$ 665
175
(73)
(7)
–
945
$
(213)
–
–
–
510
(10)
(26)
–
309
$ 938
$
15
Management’s Discussion & AnalysisEMERA 2022 ANNUAL REPORT
The following table highlights the significant changes in adjusted net income from 2021 to 2022:
For the
millions of dollars
Adjusted net income – 2021
Operating Unit Performance
Increased earnings at Tampa Electric due to higher revenues as a result of rate increases
effective January 2022, customer growth, and the impact of a weakening CAD. These
were partially offset by higher operating, maintenance and general expenses (”OM&G”),
increased interest expense, and higher depreciation. Year-over-year also increased due to
favourable weather
Increased earnings at Emera Energy Services (“EES”) due to favourable market conditions
Increased earnings at PGS due to higher off-system sales and customer growth, partially
offset by higher OM&G. Year-over-year also increased due to reversal of accumulated
depreciation as a result of the rate case settlement
Increased earnings at Seacoast due to commencement of a 34-year pipeline lateral lease
in 2022
Increased earnings at NMGC were primarily due to higher asset optimization revenues.
Year-over-year increased earnings were partially offset by higher OM&G and increased
depreciation
Decreased earnings at NSPI due to higher OM&G primarily due to increased costs for storm
restoration, IT, power generation, regulatory affairs, and higher depreciation. This was
partially offset by higher sales volumes. Quarter-over-quarter also decreased due to
unfavourable weather
Corporate
TGH award, after tax and legal costs, in Q4 2022. Refer to the ”Significant Items Affecting
Earnings” section
Increased income tax recovery primarily due to increased losses before provision for
income taxes
Increased OM&G, pre-tax, due to the timing of long-term compensation and related hedges
Increased FX loss, pre-tax, primarily due to realized gains in 2021 on FX hedges entered into
to hedge USD denominated operating unit earnings exposure
Increased interest expense, pre-tax, due to higher interest rates and increased total debt
Increased preferred stock dividends due to issuance of preferred shares in 2021
Other Variances
Adjusted net income – 2022
Three months ended
December 31
Year ended
December 31
$
168
$ 723
39
21
2
2
11
134
21
10
9
4
(20)
(10)
45
17
(19)
(9)
(17)
(2)
11
249
$
45
34
(55)
(28)
(27)
(13)
3
850
$
For further details of reportable segments contributions, refer to the “Financial Highlights” section.
Year ended
December 31
2022
2021
2020
$ 1,147
$ 1,337
(234)
(152)
$
$ 1,185
$ (2,569) $ (2,332) $ (1,224)
913
$ 1,420
217
$ 1,637
$ 1,555
$ 1,311
$
(372)
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
16
Management’s Discussion & AnalysisEMERA 2022 ANNUAL REPORT
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)
CONSOLIDATED INCOME STATEMENT HIGHLIGHTS
2022
2021
2020
December 31
$ 39,742
$ 34,244
$ 31,234
$ 16,318
$ 14,658
$ 13,721
For the
millions of dollars
(except per share amounts)
Three months ended
December 31
2021
2022
Variance
2022
Year ended
December 31
2021
Year ended
December 31
2020
Variance
Operating revenues
Operating expenses
Income from operations
Net income attributable to common
shareholders
Adjusted net income
Weighted average shares of
common stock outstanding
(in millions) (1)
EPS – basic
EPS – diluted
Adjusted EPS – basic
Adjusted EBITDA
Dividends per common share
declared
Dividends per first preferred shares
$ 2,358
1,638
$ 720
$ 1,868
1,352
516
$
$ 490
(286)
$ 204
$ 7,588 $ 5,765
4,835
$ 930
5,959
$ 1,629
$ 1,823
(1,124)
$ 699
$ 5,506
4,359
$ 1,147
$ 483
$ 249
$
324
$ 168
$
$
159
81
$ 945
$ 850
$ 510
$ 723
$ 435
$ 127
$ 938
$ 665
269.0
$ 1.80
$ 1.80
$ 0.93
$ 755
260.8
$ 1.24
$ 1.20
$ 0.64
$ 582
8.2
$ 0.56
$ 0.60
$ 0.29
173
$
265.5
$ 3.56
$ 3.55
$ 3.20
$ 2,687
257.2
$ 1.98
$ 1.98
$ 2.81
$ 2,367
8.3
$ 1.58
$ 1.57
$ 0.39
320
$
247.8
$ 3.78
$ 3.78
$ 2.68
$ 2,343
$ 0.6900
$ 0.6625
$ 0.0275
$ 2.6775
$ 2.5750
$ 0.1025
$ 2.4750
declared:
Series A
Series B
Series C
Series E
Series F
Series H
Series J
Series L
$ 0.5456
$ 0.6869
$ 1.1802
$ 1.1250
$ 1.0505
$ 1.2250
$ 1.0625
$ 1.1500
$ 0.5456
$ 0.4873
$ 1.1802
$ 1.1250
$ 1.0505
$ 1.2250
$ 0.6470
$ 0.1638
– $ 0.6155
$ 0.6965
– $ 1.1802
– $ 1.1250
– $ 1.0535
– $ 1.2250
$
$ 0.1996
$
$
$
$
$ 0.4155
$ 0.9862
$
$
–
–
(1) Effective February 10, 2022, deferred share units are no longer able to be settled in shares and are therefore excluded from weighted average shares of
common stock outstanding.
Operating Revenues
For Q4 2022, operating revenues increased $490 million compared to Q4 2021 and, absent increased MTM gains of $195 million,
increased $295 million. For the year ended December 31, 2022, operating revenues increased $1,823 million compared to 2021
and, absent increased MTM gains of $555 million, increased by $1,268 million. The increases in both periods were due to: higher
fuel revenues at NMGC, Tampa Electric PGS and BLPC; new rates effective January 2022 and customer growth at Tampa Electric;
the impact of a weaker CAD; higher off-system sales and customer growth at PGS; and increased marketing and trading margin
due to favourable market conditions at EES. Year-over-year also increased due to increased sales volumes at NSPI and favourable
weather at Tampa Electric.
17
Management’s Discussion & AnalysisEMERA 2022 ANNUAL REPORT
Operating Expenses
For Q4 2022, operating expenses increased $286 million compared to Q4 2021 and, absent the GBPC impairment charge of
$73 million, increased by $213 million. For the year ended December 31, 2022, operating expenses increased $1,124 million
compared to 2021 and, absent the GBPC impairment charge of $73 million, increased by $1,051 million. The increases in both
periods were due to: higher natural gas prices at NMGC and PGS; the impact of a weaker CAD; and increased OM&G at Tampa
Electric, Corporate, NSPI, NMGC and PGS. Year-over-year also increased due to higher natural gas and fuel prices at Tampa
Electric and BLPC.
Other Income, Net
Other income, net increased for Q4 2022 and the year ended December 31, 2022, compared to the same periods in 2021,
primarily due to the TGH award in Q4 2022.
Net Income and Adjusted Net Income
Net income attributable to common shareholders for Q4 2022, as compared to Q4 2021, was favourably impacted by the
$151 million increase in MTM gains, after-tax and unfavourably impacted by the $73 million GBPC impairment charge. Absent
these changes, adjusted net income increased $81 million. The increase was primarily due to: the TGH award in Q4 2022; higher
earnings contribution from Tampa Electric, Emera Energy and NMGC; and the impact of a weaker CAD. These were partially
offset by lower earnings contribution from NSPI and increased corporate OM&G due to the timing of long-term compensation
and related hedges, and higher corporate interest expense.
Net income attributable to common shareholders for the year ended 2022, as compared to the same period in 2021, was
favourably impacted by the $388 million increase in MTM gains, after-tax and unfavourably impacted by the $73 million GBPC
impairment charge as well as the $7 million in NSPML unrecoverable costs. Absent these changes, adjusted net income increased
$127 million. The increase was primarily due to: higher earnings contributions from Tampa Electric, Emera Energy, PGS and
Seacoast; the TGH award in Q4 2022; and the impact of a weaker CAD. These were partially offset by increased corporate OM&G
due to the timing of long-term compensation and related hedges, higher corporate interest expense, realized gains on corporate
FX hedges in 2021, increased preferred stock dividends and lower earnings contribution from NSPI.
EPS and Adjusted EPS – Basic
EPS and Adjusted EPS – basic were higher for Q4 2022, and for the year ended December 31, 2022, due to the impact of higher
earnings as discussed above, partially offset by the impact of the increase in weighted average shares of common stock outstanding.
Effect of Foreign Currency Translation
Emera operates in Canada, the United States and various Caribbean countries and, as such, generates revenues and incurs
expenses denominated in local currencies which are translated into CAD for financial reporting. Changes in translation rates,
particularly in the value of the USD against the CAD, can positively or adversely affect results.
In general, Emera’s earnings benefit from a weakening CAD and are adversely impacted by a strengthening CAD. The impact
in any period is driven by rate changes, the timing and percentage of earnings from foreign operations, and the impact of FX
hedges entered into to hedge USD denominated operating unit earnings exposure.
18
Management’s Discussion & AnalysisEMERA 2022 ANNUAL REPORT Results of foreign operations are translated at the weighted average rate of exchange, and assets and liabilities of foreign
operations are translated at period end rates. The relevant CAD/USD exchange rates for 2022 and 2021 are as follows:
Weighted average CAD/USD
Period end CAD/USD exchange rate
Three months ended
December 31
2021
2022
$
$
1.37
1.35
$
$
1.26
1.27
$
$
Year ended
December 31
2021
$
$
1.26
1.27
2022
1.34
1.35
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
Other Electric Utilities
Gas Utilities and Infrastructure (1 )
Other segment (2)
Total (3)
Three months ended
December 31
2021
2022
$
$
91
7
45
30
173
$
$
67
4
37
(20)
88
$
$
Year ended
December 31
2021
$
$
369
16
130
(98)
417
2022
458
23
143
(50)
574
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 $222 million USD in MTM gain, after-tax, for the three months ended December 31, 2022 (2021 – $122 million USD MTM gain, after-tax) and MTM
gain, after-tax of $130 million USD for the year ended December 31, 2022 (2021 – $164 million USD MTM loss, after-tax) and the GBPC impairment charge of
$54 million USD for the three months and year ended December 31, 2022 (2021 – nil).
The impact of the weakening CAD, partially offset by the unrealized losses on FX hedges increased net income by $42 million in
Q4 2022 and $30 million for the year ended December 31, 2022, compared to the same periods in 2021. Weakening of the CAD
increased adjusted net income by $14 million in Q4 2022 and $28 million for the year ended December 31, 2022, compared to the
same periods in 2021. Impacts of the weakening CAD include the impacts of corporate FX hedges in the Other segment.
Business Overview and Outlook
FLORIDA ELECTRIC UTILITY
Florida Electric Utility consists of Tampa Electric, a vertically integrated regulated electric utility engaged in the generation,
transmission and distribution of electricity, serving customers in West Central Florida. Tampa Electric has $12.1 billion USD of
assets and approximately 827,000 customers at December 31, 2022. Tampa Electric owns 6,549 megawatts (“MW”) of generating
capacity, of which 78 per cent is natural gas-fired, 15 per cent is solar and 7 per cent is coal. Tampa Electric owns 2,171 kilometres
of transmission facilities and 19,916 kilometres of distribution facilities. Tampa Electric meets the planning criteria for reserve
capacity established by the FPSC, which is a 20 per cent reserve margin over firm peak demand.
Tampa Electric’s approved regulated ROE range is 9.25 per cent to 11.25 per cent, based on an allowed equity capital structure of
54 per cent. An ROE of 10.20 per cent will be used for the calculation of the return on investments for clauses.
Tampa Electric anticipates earning within its ROE range in 2023. New base rates effective January 1, 2023, as a result of the 2021
settlement agreement, will result in higher 2023 USD earnings than in 2022. Normalizing 2022 for weather, Tampa Electric sales
volumes in 2023 are projected to be higher than in 2022 due to customer growth. Tampa Electric expects customer growth rates
in 2023 to be comparable to 2022, reflective of the current expected economic growth in Florida.
On January 23, 2023, Tampa Electric requested an adjustment to its fuel charges to recover the 2022 fuel under-recovery of
$518 million USD over a period of 21 months. The request also included an adjustment to 2023 projected fuel costs to reflect
the reduction in natural gas prices since September 2022 for a projected reduction of $170 million USD for the balance of 2023.
The proposed changes will be decided by the FPSC in March 2023, and recovery is expected to begin in April 2023.
19
Management’s Discussion & AnalysisEMERA 2022 ANNUAL REPORT On September 28, 2022, Hurricane Ian made landfall in Southwest Florida as a Category 4 hurricane and, as a result,
approximately 291,000 customers lost power. The majority of Hurricane Ian restoration costs were charged against Tampa
Electric’s FPSC approved storm reserve, resulting in minimal impact to earnings for 2022. The total cost of restoration was
$126 million USD, with approximately $119 million USD charged to the storm reserve. Total restoration costs charged to the storm
reserve have exceeded the reserve balance and have been deferred as a regulatory asset for future recovery. On January 23,
2023, Tampa Electric petitioned the FPSC for recovery of the storm reserve regulatory asset and the replenishment of the
balance in the reserve to the previous approved reserve level of $56 million USD, for a total of approximately $131 million USD.
The proposed changes will be decided by the FPSC in March 2023, and recovery is expected to begin in April 2023 through
March 2024.
The mid-course fuel adjustment requested by Tampa Electric on January 19, 2022, was approved on March 1, 2022. The rate
increase, effective with the first billing cycle in April 2022, covered higher fuel and capacity costs of $169 million USD and was
spread over customer bills from April 1, 2022 through December 2022.
In 2023, capital investment in the Florida Electric Utility segment is expected to be $1.3 billion USD (2022 – $1.1 billion USD),
including allowance for funds used during construction (“AFUDC”). Capital projects include solar investments, grid modernization
and storm hardening investments.
CANADIAN ELECTRIC UTILITIES
Canadian Electric Utilities includes NSPI and ENL. NSPI is a vertically integrated regulated electric utility engaged in the
generation, transmission and distribution of electricity and the primary electricity supplier to customers in Nova Scotia. ENL
is a holding company with equity investments in NSPML and LIL: two transmission investments related to the development of
an 824 MW hydroelectric generating facility at Muskrat Falls on the Lower Churchill River in Labrador.
NSPI
With $6.8 billion of assets and approximately 541,000 customers, NSPI owns 2,420 MW of generating capacity, of which
approximately 44 per cent is coal-fired; 28 per cent is natural gas and/or oil; 19 per cent is hydro and wind; 7 per cent is petcoke
and 2 per cent is biomass-fueled generation. In addition, NSPI has contracts to purchase renewable energy from independent
power producers (“IPPs”), which own 546 MW of capacity. NSPI also has rights to 153 MW of Maritime Link capacity, representing
Nalcor Energy’s (“Nalcor”) Nova Scotia Block (“NS Block”) delivery obligations, as discussed below. NSPI owns approximately
5,000 kilometres of transmission facilities and 28,000 kilometres of distribution facilities.
NSPI’s approved regulated ROE range is 8.75 per cent to 9.25 per cent, based on an actual five-quarter average regulated
common equity component of up to 40 per cent of approved rate base.
NSPI anticipates earning near the low end of its allowed ROE range in 2023, and below the allowed range in 2024. NSPI expects
earnings and sales volumes to be higher in 2023 than 2022.
NSPI operated under a three-year fuel stability plan which resulted in an average annual overall rate increase of 1.5 per cent to
recover fuel costs for the period of 2020 through 2022. These rates include recovery of Maritime Link costs (discussed below in
the “ENL, NSPML” section).
20
Management’s Discussion & AnalysisEMERA 2022 ANNUAL REPORT On November 9, 2022, the Nova Scotia provincial government enacted Bill 212, “Public Utilities Act (amended)”. The legislation
limits non-fuel rate increases in NSPI’s 2022 General Rate Application (“GRA”) to the UARB, excluding increases relating to
demand side management (“DSM”) costs, to a total of 1.8 per cent between the effective date of the UARB’s decision and the end
of 2024. The legislation also:
• requires revenue generated from the non-fuel rate increase to be used only to improve the reliability of service to ratepayers,
• limits NSPI’s return on equity to 9.25 per cent and equity ratio to 40 per cent, and
• limits the rate used to accrue interest on regulatory deferrals to the Bank of Canada policy interest rate plus 1.75 per cent,
unless otherwise directed by the UARB.
Actions required to address the impact of Bill 212, “Public Utilities Act (amended)”, include a material reduction in NSPI’s planned
capital investments and operating costs over the 2023 through 2024 period. Such deferral of capital investment and operating
costs may result in higher customer costs in future periods. The legislation will have a direct and negative impact on the financial
performance of NSPI and has had a negative impact on NSPI’s credit quality. For more information on this risk, refer to the “Risk
Management and Financial Instruments – Regulatory and Political Risk” section.
On November 24, 2022, NSPI filed with the UARB a comprehensive settlement agreement between NSPI, key customer
representatives and participating interest groups (“NSPI Settlement Agreement”) in relation to its GRA filed in January 2022.
The NSPI Settlement Agreement was structured to be consistent with the amendments to the Public Utilities Act made under
Bill 212, which included a 1.8 per cent cap on non-fuel rate increases for 2023 and 2024. Bill 212, “Public Utilities Act (amended),”
is described further above. The NSPI Settlement Agreement also addresses the recovery of fuel costs over the settlement period
and establishes a DSM rider. This will result in a combined fuel and non-fuel rate increase of 6.9 per cent each year for 2023
and 2024 and annualized incremental revenue (fuel and non-fuel) of $105 million in 2023 and $115 million in 2024. In addition,
any under or over recovery of fuel costs will be addressed through the UARB’s established FAM process. NSPI’s ROE range will
continue to be 8.75 per cent to 9.25 per cent, based on an actual five-quarter average regulated common equity component of
up to 40 per cent. The NSPI Settlement Agreement also establishes a storm rider for each of 2023, 2024 and 2025, which gives
NSPI the option to apply to the UARB for recovery of costs if major storm restoration expense exceeds approximately $10 million
in a given year. On February 2, 2023, NSPI received the UARB’s decision, which substantially approved the NSPI Settlement
Agreement as filed. Approved rate increases will be effective as of the date of the decision.
On September 24, 2022, Nova Scotia was struck by Hurricane Fiona, which made landfall as a post-tropical storm equivalent
to a Category 2 hurricane. The storm had sustained winds of over 100 kilometres per hour and peak gusts of approximately
180 kilometres per hour. This historic storm for Nova Scotia caused significant and widespread damage to NSPI’s transmission and
distribution system and at the height of the storm approximately 415,000 customers lost power. The total cost of the restoration
was approximately $115 million, of which $91 million was capitalized to Property, plant and equipment (“PP&E”) and $24 million
deferred to Other long-term assets for future amortization, subject to UARB approval. NSPI intends to submit an application to the
UARB requesting to defer the recognition of incremental operating costs related to storm restoration. If the deferral is approved,
this balance will be reclassified to “Regulatory assets” and amortized over the UARB approved recognition period.
Energy from renewable sources has increased with Nalcor’s NS Block delivery obligations from the Muskrat Falls hydroelectric
project (“Muskrat Falls”) commencing in 2021. Nalcor is obligated to provide NSPI with approximately 900 GWh of energy
annually over 35 years. In addition, for the first five years of the NS Block, Nalcor is obligated to provide approximately 240 GWh
of additional energy from the Supplemental Energy Block transmitted through the Maritime Link. Nalcor’s final commissioning of
the LIL has experienced delays and it’s expected that final commissioning of the LIL will be completed in 2023. During these final
stages of commissioning, there will be interruptions in supply, with any resultant delivery shortfalls being delivered on a timely
basis in accordance with the Energy and Capacity Agreement. NSPI has the option of purchasing additional market-priced energy
from Nalcor through the Energy Access Agreement. The Energy Access Agreement enables NSPI to access a market-priced bid
from Nalcor for up to 1.8 Terawatt hours (“TWh”) of energy in any given year and, on average, 1.2 TWh of energy per year through
August 31, 2041.
Capital investment for 2023, including AFUDC, is expected to be approximately $375 million (2022 – $540 million). NSPI is
primarily investing in capital projects required to support power system reliability and reliable service for customers.
21
Management’s Discussion & AnalysisEMERA 2022 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.
NSPI continues to work with both levels of government to comply with these laws and regulations to maximize efficiency of
emission control measures and minimize customer cost. NSPI anticipates that costs prudently incurred to achieve legislated
compliance will be recoverable under NSPI’s regulatory framework. NSPI faces risks associated with achieving climate-related
and environmental legislative requirements, including the risk of non-compliance, which could adversely affect NSPI’s operations
and financial performance. For further discussion on these risks and environmental legislation and regulations, refer to the
“Enterprise Risk and Risk Management” section. Recent developments related to provincial and federal environmental laws and
regulations are outlined below.
Nova Scotia Cap-and-Trade Program Regulations:
NSPI is a participant in the Nova Scotia Cap-and-Trade Program (“Cap-and-Trade Program”) and is subject to the 2019 through
2022 compliance period. NSPI received granted emissions allowances under the Cap-and-Trade Program and is permitted to
purchase up to five per cent of the credits available at provincial auctions. Any remaining allowance shortfall requires the
purchase of reserve credits directly from the provincial government, which are anticipated to be priced at a premium to provincial
auction pricing. Compliance is forecast to be achieved through granted emissions allowances and credit purchases under the
Cap-and-Trade Program, including reserve credits. Lower than forecast Muskrat Falls energy received during the compliance
period has resulted in the increased deployment of higher carbon-emitting generation sources. The Province of Nova Scotia has
agreed to provide approximately $165 million of relief from the 2019 through 2022 compliance costs, which was equal to the
total cost of compliance forecast at the time of the fuel update submitted by NSPI to the UARB in September 2022 as part of the
GRA. Discussions related to the final amount of relief and how this relief will be provided are ongoing. Further, NSPI’s regulatory
framework provides for the recovery of costs prudently incurred to comply with the Cap-and-Trade Program Regulations pursuant
to NSPI’s FAM.
Carbon Pricing Regulations:
On November 9, 2022, the Nova Scotia provincial government enacted Bill 208, “Environment Act (amended)”. The legislation
provides the framework for Nova Scotia’s system to comply with the federal government’s 2023 through 2030 carbon pollution
pricing regulations laid out in the Pan-Canadian Framework on Clean Growth and Climate Change. Nova Scotia’s proposed
system utilizes an output-based pricing system that will implement performance standards for large industrial greenhouse
gas emitters to achieve emission reduction goals. Subsequent regulations will be required to detail how the pricing system
will operate. The Province of Nova Scotia’s proposed output-based pricing system is subject to the approval of the federal
government. If an agreement is not reached between the federal and provincial governments on a Nova Scotia system that
meets the federal compliance criteria, Nova Scotia will be subject to the federal carbon pollution pricing backstop which uses
emissions performances standards that vary by fuel type, and a carbon price that will start at $65 per tonne in 2023 and increase
by $15 per tonne annually, reaching $170 per tonne by 2030. NSPI’s regulatory framework provides for the recovery of costs
prudently incurred to comply with carbon pricing programs pursuant to NSPI’s FAM.
Nova Scotia Renewable Energy Regulations:
Under the provincially legislated Renewable Energy Regulations, 40 per cent of electric sales must be generated from renewable
sources. This standard was predicated on receipt of the full NS Block. Due to the delay of the NS Block, the provincial government
provided NSPI with an alternative compliance plan that requires NSPI to achieve 40 per cent of electric sales generated from
renewable sources over the 2020 through 2022 period. With delivery of the NS Block commencing later than anticipated, as well
as further interruptions in supply due to delays in the LIL, NSPI did not achieve the requirements of the alternative compliance
plan. The Renewable Energy Regulations require NSPI to have acted in a duly diligent manner. If NSPI is found not to have acted
in a duly diligent manner, it could be subject to a maximum penalty of $10 million.
22
Management’s Discussion & AnalysisEMERA 2022 ANNUAL REPORT ENL
Total equity earnings from NSPML and LIL are expected to be higher in 2023, compared to 2022. Both the NSPML and LIL
investments are recorded as “Investments subject to significant influence” on Emera’s Consolidated Balance Sheets.
NSPML
Equity earnings from the Maritime Link are dependent on the approved ROE and operational performance of NSPML. NSPML’s
approved regulated ROE range is 8.75 per cent to 9.25 per cent, based on an actual five-quarter average regulated common
equity component of up to 30 per cent.
The Maritime Link assets entered service on January 15, 2018, enabling the transmission of energy between Newfoundland and
Nova Scotia, improved reliability and ancillary benefits, supporting the efficiency and reliability of energy in both provinces.
Nalcor continues to advance towards completion of the LIL, and it’s expected final commissioning will be achieved in 2023.
Nalcor’s NS Block delivery obligations commenced on August 15, 2021, and the NS Block will be delivered over the next 35 years
pursuant to the project agreements. As Nalcor is in the final stages of commissioning the LIL, there will be commissioning related
interruptions in supply with any resultant delivery shortfalls being delivered on a timely basis in accordance with the Energy and
Capacity Agreement.
In February 2022, the UARB issued its decision and Board Order approving NSPML’s requested rate base of approximately
$1.8 billion less $9 million of costs ($7 million after-tax) that would not have otherwise been recoverable if incurred by NSPI.
NSPML also received approval to collect up to $168 million (2021 – $172 million) from NSPI for the recovery of costs associated
with the Maritime Link in 2022. This was subject to a holdback of up to $2 million per month, beginning April 2022, contingent
on receiving at least 90 per cent of NS Block deliveries, including Supplemental Energy deliveries.
In December 2022, NSPML received UARB approval to collect up to $164 million from NSPI for the recovery of costs associated
with the Maritime Link in 2023. This continues to be subject to a holdback of up to $2 million a month, as discussed above. On
December 22, 2022, the UARB clarified its earlier direction regarding the holdback and NSPI can now release the holdback to
NSPML when 90 per cent of NS Block deliveries, including Supplemental Energy deliveries, is achieved. This enabled NSPI to pay
NSPML approximately $4 million of the 2022 holdback. As of December 31, 2022, an additional $14 million in aggregate has been
held back by NSPI. Determination of allocation of the $14 million between NSPML and NSPI will be subject to a regulatory process
that is expected to commence in early 2023 to review the holdback mechanism.
NSPML does not anticipate any significant capital investment in 2023.
LIL
ENL is a limited partner with Nalcor in LIL. Construction of the LIL is complete and Nalcor is forecasting it will achieve final
commissioning in 2023.
Equity earnings from the LIL investment are based upon the book value of the equity investment and the approved ROE. Emera’s
current equity investment is $740 million, comprised of $410 million in equity contribution and $330 million of accumulated
equity earnings. Emera’s total equity contribution in the LIL, excluding accumulated equity earnings, is estimated to be
approximately $650 million after the Lower Churchill projects are completed.
Cash earnings and return of equity will begin after commissioning of the LIL by Nalcor, which is anticipated in 2023, and until that
point Emera will continue to record AFUDC earnings.
GAS UTILITIES AND INFRASTRUCTURE
Gas Utilities and Infrastructure includes PGS, NMGC, SeaCoast, Brunswick Pipeline and Emera’s non-consolidated investment in
M&NP. PGS is a regulated gas distribution utility engaged in the purchase, distribution and sale of natural gas serving customers
in Florida. NMGC is an intrastate regulated gas distribution utility engaged in the purchase, transmission, distribution and sale
of natural gas serving customers in New Mexico. SeaCoast is a regulated intrastate natural gas transmission company offering
services in Florida. Brunswick Pipeline is a regulated 145-kilometre pipeline delivering re-gasified liquefied natural gas from
Saint John, New Brunswick, to markets in the northeastern United States.
23
Management’s Discussion & AnalysisEMERA 2022 ANNUAL REPORT Peoples Gas System
With $2.5 billion USD of assets and approximately 468,000 customers, the PGS system includes 24,300 kilometres of natural
gas mains and 13,500 kilometres of service lines. Natural gas throughput (the amount of gas delivered to its customers, including
transportation-only service) was 2 billion therms in 2022.
The approved ROE range for PGS is 8.9 per cent to 11.0 per cent, based on an allowed equity capital structure of 54.7 per cent.
An ROE of 9.9 per cent is used for the calculation of return on investments for clauses.
New Mexico Gas Company, Inc.
With $2.0 billion USD of assets and approximately 545,000 customers, NMGC’s system includes approximately 2,426 kilometres
of transmission pipelines and 17,781 kilometres of distribution pipelines. Annual natural gas throughput was approximately
926 million therms in 2022.
The approved ROE for NMGC is 9.375 per cent, on an allowed equity capital structure of 52 per cent.
Gas Utilities and Infrastructure Outlook
Gas Utilities and Infrastructure USD earnings are anticipated to be higher in 2023 than 2022, primarily due to a base rate
increase at NMGC, effective January 2023.
PGS expects 2023 rate base growth and USD earnings to be consistent with 2022 as higher revenues from customer growth
offset increased interest expenses and the effect of inflation. Increased residential and commercial sales volumes and customer
growth are anticipated in 2023. PGS anticipates earning below its allowed ROE range in 2023 primarily due to rate base growth.
As a result, on February 3, 2023, PGS notified the FPSC that it is planning to file a base rate proceeding in April 2023 for new
rates effective January 2024.
The PGS rate case settlement, which was approved in November 2020, provides the ability to reverse a total of $34 million USD
of accumulated depreciation through 2023. Through December 31, 2022, PGS reversed $14 million USD accumulated depreciation.
The reversal of the remaining accumulated depreciation is expected to occur over 2023.
NMGC expects 2023 rate base and USD earnings to be higher in 2023 than 2022 due to base rate increases effective January
2023, as discussed below, and rate base growth to expand the distribution system and to continue to reliably serve customers.
NMGC anticipates earning near its authorized ROE in 2023 and expects customer growth rates to be consistent with historical
trends. NMGC’s asset optimization revenues for 2022 were well above the historical average, and may not recur in 2023.
On December 13, 2021, NMGC filed a rate case with the NMPRC for new rates to become effective January 2023. On May 20, 2022,
NMGC filed an unopposed settlement agreement with the NMPRC for an increase of $19 million USD in annual base revenues.
The rates reflect the recovery of increased operating costs and capital investments in pipelines and related infrastructure. The
NMPRC approved the settlement agreement on November 30, 2022.
In 2018, SeaCoast executed a 34-year agreement to provide long-term firm gas transportation service via a 21-mile, 30-inch
pipeline lateral. The lease of the pipeline lateral commenced January 1, 2022.
In 2023, capital investment in the Gas Utilities and Infrastructure segment is expected to be approximately $475 million USD
(2022 – $436 million USD), including AFUDC. PGS will make investments to expand its system and support customer growth.
NMGC will continue to make investments to maintain the reliability of its system and support customer growth.
OTHER ELECTRIC UTILITIES
Other Electric Utilities includes Emera (Caribbean) Incorporated (“ECI”), a holding company with regulated electric utilities. ECI’s
regulated utilities include vertically integrated regulated electric utilities of BLPC on the island of Barbados, GBPC on Grand
Bahama Island, and a 19.5 per cent interest in Lucelec on the island of St. Lucia, which is accounted for on the equity basis.
On March 31, 2022, Emera completed the sale of its 51.9 per cent interest in Dominica Electricity Services Ltd. (“Domlec”) for
proceeds which approximated carrying value. Domlec was included in the Other Electric Utilities segment in Q1 2022. The sale did
not have a material impact on earnings.
24
Management’s Discussion & AnalysisEMERA 2022 ANNUAL REPORT BLPC
With $505 million USD of assets and approximately 133,000 customers, BLPC owns 276 MW of generating capacity, of which
96 per cent is oil-fired and four per cent is solar. BLPC owns approximately 188 kilometres of transmission facilities and
3,789 kilometres of distribution facilities. BLPC’s approved regulated return on rate base for 2022 was 10 per cent.
GBPC
With $338 million USD of assets and approximately 19,000 customers, GBPC owns 98 MW of oil-fired generation, approximately
90 kilometres of transmission facilities and 670 kilometres of distribution facilities. GBPC’s approved regulatory return on rate
base for 2023 is 8.32 per cent (2022 – 8.23 per cent).
Other Electric Utilities Outlook
Absent the impact of the GBPC impairment charge in Q4 2022, Other Electric Utilities’ USD earnings in 2023 are expected to
increase over the prior year primarily as a result of higher earnings due to higher base rates at BLPC.
BLPC currently operates pursuant to a franchise to generate, transmit and distribute electricity on the island of Barbados
until 2028. In 2019, the Government of Barbados passed legislation amending the number of licenses required for the supply
of electricity from a single integrated license which currently exists, to multiple licenses for Generation, Transmission and
Distribution, Storage, Dispatch and Sales. In March 2021, BLPC reached commercial agreement with the Government of Barbados
for each of the license types, subject to the passage of implementing legislation. The new licenses are expected to take effect
in 2023 on completion of the legislative process. The Dispatch license will have a term of five years with the remaining licenses
having terms ranging from 25-30 years. BLPC anticipates that any increased costs associated with the implementation of the new
multi-licensed structure will be recoverable through BLPC’s regulatory framework. BLPC is awaiting final enactment and will work
towards implementation of the licenses once received.
On October 4, 2021 BLPC submitted a general rate review application to the FTC. The application seeks a rate adjustment and
the implementation of a cost reflective rate structure that will facilitate the changes expected in the newly reformed electricity
market and the country’s transition toward 100 per cent renewable energy generation. The application seeks recovery of capital
investment in plant, equipment and related infrastructure and results in an increase in annual non-fuel revenue of approximately
$23 million USD upon approval. The application includes a request for an allowed regulatory ROE of 12.50 per cent on an allowed
equity capital structure of 65 per cent. On September 16, 2022, the FTC granted BLPC interim rate relief, allowing an increase
in base rates of approximately $3 million USD for the remainder of 2022 and approximately $1 million USD per month for
2023. Interim rate relief is effective from September 16, 2022 until the implementation of final rates. The hearing concluded in
October 2022. On February 15, 2023, the FTC issued a decision on the BLPC rate review application which included the following
significant items: an allowed regulatory ROE of 11.75 per cent, an equity capital structure of 55 per cent, a directive to update
the major components of rate base to September 16, 2022, and a directive to establish regulatory liabilities of approximately
$70 million USD related to the self-insurance fund, accumulated depreciation, and taxes. The impacts to BLPC’s rate base and
final rates are not yet determinable but management does not expect the decision to have a material impact on Emera’s adjusted
net income. BLPC will seek to clarify aspects of the FTC decision in its compliance filing and is also considering filing a submission
to the FTC for a review of the decision. BLPC expects a decision on final rates from the FTC in 2023.
On January 14, 2022, the GBPA issued its decision on GBPC’s rate application. The decision, which became effective April 1, 2022,
allows for an increase in revenues of $3.5 million USD. The new rates include a regulatory ROE of 12.84 per cent.
Effective November 1, 2022, GBPC’s fuel pass through charge was increased due to an increase in global oil prices impacting the
unhedged fuel cost. In 2023, the fuel pass through charge will be adjusted monthly, in-line with actual fuel costs.
In 2023, capital investment in the Other Electric Utilities segment is expected to be approximately $65 million USD (2022 –
$48 million USD), primarily in more efficient and cleaner sources of generation, including renewables and battery storage.
25
Management’s Discussion & AnalysisEMERA 2022 ANNUAL REPORT OTHER
The Other segment includes those business operations that in a normal year are below the required threshold for reporting
as separate segments; and corporate expense and revenue items that are not directly allocated to the operations of Emera’s
subsidiaries and investments.
Business operations in the Other segment include Emera Energy and Emera Technologies LLC (“ETL”). Emera Energy consists
of EES, a wholly owned physical energy marketing and trading business and an equity investment in a 50 per cent joint venture
ownership of Bear Swamp, a 660 MW pumped storage hydroelectric facility in northwestern Massachusetts. ETL is a wholly
owned technology company focused on finding ways to deliver renewable and resilient energy to customers.
Corporate items included in the Other segment are certain corporate-wide functions including executive management, strategic
planning, treasury services, legal, financial reporting, tax planning, corporate business development, corporate governance,
investor relations, risk management, insurance, acquisition and disposition related costs, gains or losses on select assets sales,
and corporate human resource activities. It includes interest revenue on intercompany financings and interest expense on
corporate debt in both Canada and the United States. It also includes costs associated with corporate activities that are not
directly allocated to the operations of Emera’s subsidiaries and investments.
Earnings from EES are generally dependent on market conditions. In particular, volatility in natural gas and electricity markets,
which can be influenced by weather, local supply constraints and other supply and demand factors, can provide higher levels
of margin opportunity. The business is seasonal, with Q1 and Q4 usually providing the greatest opportunity for earnings. EES is
generally expected to deliver annual adjusted net income within its guidance range of $15 to $30 million USD ($45 to $70 million
USD of margin).
Absent the TGH award in Q4 2022, the adjusted net loss from the Other segment is expected to be higher in 2023, based on EES
returning to its normal earnings range in 2023 and increased interest expense. The increase is expected to be partially offset by
decreased taxes due to a higher net loss.
The Other segment does not anticipate any significant capital investment in 2023.
26
Management’s Discussion & AnalysisEMERA 2022 ANNUAL REPORT Consolidated Balance Sheet Highlights
Significant changes in the Consolidated Balance Sheets between December 31, 2021 and December 31, 2022 include:
millions of dollars
Assets
Cash and cash equivalents
Increase
(Decrease)
Explanation
$
(84) Decreased due to increased investment in PP&E at regulated utilities and
dividends on common stock. These were partially offset by proceeds from
short-term debt issuance at Emera and Tampa Electric, increased proceeds
under committed credit facilities at NSPI and Emera, cash from operations, and
issuance of common stock
Inventory
231 Increased due to higher commodity prices at Emera Energy and NSPI, increased
materials inventory at Tampa Electric and the effect of the FX translation of
Emera’s foreign affiliates
Derivative instruments (current
95 Increased due to reversal of 2021 contracts at Emera Energy
and long-term)
Regulatory assets (current and
long-term)
1,054 Increased due to higher fuel cost recovery clauses at Tampa Electric, increased
FAM deferrals, driven mainly by increased Cap-and Trade emissions compliance
charges, and increased deferred income tax regulatory assets at NSPI, the
effect of the FX translation of Emera’s foreign affiliates, recognition of storm
reserve asset at Tampa Electric due to restoration costs from Hurricane Ian in
excess of the storm reserve liability, and increased pension and post-retirement
plan deferrals at Tampa and NSPI. These were partially offset by recovery of gas
costs from the NMGC 2021 winter event
Receivables and other assets
1,165 Increased due to higher gas transportation assets and higher trade receivables
(current and long-term)
PP&E, net of accumulated
depreciation and amortization
Net investment in direct finance
and sales type leases
due to higher commodity prices at Emera Energy, fuel option receivable at
NMGC and the effect of the FX translation of Emera’s foreign affiliates
2,643 Increased due to the effect of the FX translation of Emera’s foreign affiliates,
and capital additions. These were partially offset by reclassification of
Seacoast’s pipeline lateral on commencement of the lease in 2022
101 Increased due to commencement of the pipeline lease at Seacoast in 2022
Goodwill
316 Increased due to the effect of the FX translation of Emera’s foreign affiliates,
partially offset by the GBPC impairment
27
Management’s Discussion & AnalysisEMERA 2022 ANNUAL REPORT
millions of dollars
Liabilities and Equity
Short-term debt and long-term
debt (including current portion)
Accounts payable
Deferred income tax liabilities, net
of deferred income tax assets
Increase
(Decrease)
Explanation
$ 2,644 Increased due to the effect of the FX translation of Emera’s foreign affiliates,
issuance of short-term debt at Emera and Tampa Electric, and net borrowings
under the committed credit facility at NSPI and Emera
540 Increased due to increased commodity prices at Emera Energy, Tampa Electric
and NMGC, the effect of the FX translation of Emera’s foreign affiliates, higher
cash collateral position on derivative instruments at NSPI, and timing of
payments at Tampa Electric and NSPI
386 Increased due to tax deductions in excess of accounting depreciation related
to PP&E, increase in net regulatory assets, decrease in net derivative liabilities,
and the effect of the FX translation of Emera’s foreign affiliates, partially offset
by net increase in tax loss carryforwards
Derivative instruments (current
396 Increased due to new contracts in 2022, partially offset by reversal of 2021
and long-term)
contracts and changes in existing positions at Emera Energy
Regulatory liabilities (current and
218 Increased due to NMGC gas hedge settlements and the effect of the FX
long-term)
Pension and post-retirement
liabilities
translation of Emera’s foreign affiliates, partially offset by decreased storm
reserve at Tampa Electric due to restoration costs incurred from Hurricane Ian
(89) Decreased due to favourable changes in actuarial assumptions, partially offset
by lower investment returns
Other liabilities (current and
170 Increased due to accrued emissions compliance charges at NSPI and the effect
long-term)
Common stock
of the FX translation of Emera’s foreign affiliates
520 Increased due to Emera’s ATM equity program and shares issued under
the DRIP
Accumulated other comprehensive
553 Increased due to the effect of the FX translation of Emera’s foreign affiliates
income
Retained earnings
Other Developments
236 Increased due to net income in excess of dividends paid
USGAAP Reporting Extension
Emera was granted exemptive relief by Canadian securities regulators on September 13, 2022, and under the Companies Act
(Nova Scotia) on October 12, 2022, each allowing Emera to continue to report its financial results in accordance with USGAAP
(collectively the “Exemptive Relief”). The Exemptive Relief will terminate on the earliest of: (i) January 1, 2027; (ii) if the Company
ceases to have rate-regulated activities, the first day of the Company’s financial year that commences after the Company ceases
to have rate-regulated activities; and (iii) the first day of the Company’s financial year that commences on or following the later
of: (a) the effective date prescribed by the International Accounting Standards Board (“IASB”) for the mandatory application of a
standard within IFRS specific to entities with rate-regulated activities (“Mandatory Rate-regulated Standard”); and (b) two years
after the IASB publishes the final version of a Mandatory Rate-regulated Standard. The Exemptive Relief replaces similar relief
that had been granted to Emera in 2018 and would have expired by no later than January 1, 2024.
Increase in Common Dividends
On September 22, 2022, the Emera Board of Directors approved an increase in the annual common share dividend rate to $2.76
from $2.65. The first payment was effective November 15, 2022. Emera also extended its dividend growth rate target of four to
five per cent through 2025.
APPOINTMENTS
Effective July 1, 2022, Michael Barrett was appointed Executive Vice President and General Counsel for Emera. Mr. Barrett was
most recently the General Counsel for Emera.
Effective June 30, 2022, Bruce Marchand was appointed Chief Risk and Sustainability Officer for Emera. Mr. Marchand was most
recently the Chief Legal and Compliance Officer for Emera.
28
Management’s Discussion & AnalysisEMERA 2022 ANNUAL REPORT
Financial Highlights
FLORIDA ELECTRIC UTILITY
All amounts are reported in USD, unless otherwise stated.
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
2021
561
212
67
85
44
$
$
$
$
$
2022
$ 597
$ 201
91
$
124
$
41
$
Year ended
December 31
2021
$ 2,174
713
$
$
369
$ 462
34
$
2022
$ 2,523
$ 832
$ 458
$ 596
39
$
The impact of the change in the FX rate increased CAD earnings for the three months and year ended December 31, 2022, by
$10 million and $23 million, respectively.
Net Income
Highlights of the net income changes are summarized in the following table:
For the
millions of USD
Contribution to consolidated net income – 2021
Increased operating revenues due to higher rates effective January 2022, higher fuel recovery
clause revenue as a result of increased fuel costs, and customer growth. Year-over-year also
increased due to favourable weather
Fuel for generation and purchased power decreased in Q4 due to lower natural gas prices
quarter-over-quarter. Year-over-year, fuel increased due to higher natural gas prices
Increased OM&G due to timing of deferred clause recoveries. Year-over-year the increase is
also due to higher transmission and distribution costs, higher benefit costs and higher
insurance costs
Increased depreciation and amortization due to additions to facilities and the in-service of
generation projects
Increased interest expense due to higher interest rates and higher borrowings to support
Tampa Electric’s ongoing operations, including fuel under-recoveries, and capital investments
Decreased AFUDC earnings due to timing of Big Bend modernization and solar projects
Increased income tax expense year-over-year primarily due to increased income before
provision for income taxes
Other
Contribution to consolidated net income – 2022
Three months ended
December 31
Year ended
December 31
$
67
$
369
36
11
349
(119)
(6)
(52)
(5)
(15)
(16)
(4)
(32)
(10)
–
8
91
(36)
4
$ 458
$
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)
Electric Sales Volumes
(Gigawatt hours (“GWh”))
2022
2021
2022
2021
$ 1,381
666
176
300
$ 2,523
$ 1,156
602
172
244
$ 2,174
10,109
6,300
2,111
2,352
20,872
9,941
6,144
2,122
2,000
20,207
(1) Other includes sales to public authorities, off-system sales to other utilities and regulatory deferrals related to clauses.
29
Management’s Discussion & AnalysisEMERA 2022 ANNUAL REPORT Regulated Fuel for Generation and Purchased Power
Annual production volumes are summarized in the following table:
Natural gas
Purchased power
Solar
Coal
Total
Production Volumes (GWh)
2022
2021
17,083
1,685
1,492
1,325
21,585
16,142
2,301
1,252
1,342
21,037
Tampa Electric’s fuel costs are affected by commodity prices and generation mix that is largely dependent on economic dispatch
of the generating fleet, bringing the lowest cost options on first (renewable energy from solar), such that the incremental cost
of production increases as sales volumes increase. Generation mix may also be affected by plant outages, plant performance,
availability of lower priced short-term purchased power, availability of renewable solar generation, and compliance with
environmental standards and regulations.
Regulatory Environment
Tampa Electric is regulated by the FPSC and is also subject to regulation by the FERC. The FPSC sets rates at a level that allows
utilities such as Tampa Electric to collect total revenues or revenue requirements equal to their cost of providing service, plus an
appropriate return on invested capital. Base rates are determined in FPSC rate setting hearings which can occur at the initiative
of Tampa Electric, the FPSC or other interested parties. For further details on Tampa Electric’s regulatory environment, base
rates and recovery mechanisms, refer to note 7 in the consolidated financial statements.
CANADIAN ELECTRIC UTILITIES
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
Three months ended
December 31
2021
2022
Year ended
December 31
2021
2022
$ 421
173
$
$
46
$
$
$
$ 389
$ 263
67
$
– $
$
$
46
61
67
93
$ 1,675
$ 950
$ 222
$ 215
85
$
$ 1,501
817
$
241
$
(7) $
$
$
241
75
–
– $
(1) Regulated fuel for generation and purchased power includes NSPI’s FAM and fixed cost deferrals on the Consolidated Statements of Income, however it is
excluded in the segment overview.
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
2021
2022
$
$
23
15
8
46
$
$
43
14
10
67
2022
$ 131
55
36
$ 222
Year ended
December 31
2021
$
$
141
51
49
241
(1) Excludes $7 million in NSPML unrecoverable costs, after-tax, for the year ended December 31, 2022 (2021 – nil).
30
Management’s Discussion & AnalysisEMERA 2022 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 – 2021
Increased operating revenues due to increased electric revenues related to recovery of fuel costs
from an industrial customer, increased residential and commercial class sales volumes, and
increased electricity pricing effective January 1, 2022. Quarter-over-quarter increase partially
offset by unfavourable weather
Decreased regulated fuel for generation and purchased power quarter-over-quarter due to
lower Cap-and-Trade Program provision and lower Maritime Link assessment costs. Increased
regulated fuel for generation and purchased power year-over year due to increased Nova Scotia
Cap-and-Trade program provision, increased commodity prices and higher sales volume, partially
offset by a favourable change in generation mix
Decreased FAM and fixed cost deferrals year-over-year due to increased recovery of fuel costs,
partially offset by increased Cap-and-Trade provision. Quarter-over-quarter decreased due to
increased recovery of fuel costs and decreased Cap-and-Trade provision
Increased OM&G due to higher costs for storm restoration, IT, power generation, and
regulatory affairs
Increased depreciation and amortization due to increased PP&E in-service
Decreased income tax expense primarily due to increased tax deductions in excess of accounting
depreciation and amortization related to PP&E and deferrals and decreased income before
provision for income taxes. This was partially offset by the benefit of tax loss carryforwards
recognized as a deferred income tax regulatory liability
Year-over-year decrease in net income from equity investment in NSPML primarily due to the
Maritime Link holdback
NSPML unrecoverable costs
Other
Contribution to consolidated net income – 2022
NSPI
Operating Revenues – Regulated Electric
Annual electric revenues and sales volumes are summarized in the following tables by customer class:
Three months ended
December 31
Year ended
December 31
$
67
$ 241
32
174
90
(133)
(120)
(16)
(20)
(5)
(47)
(13)
7
18
(2)
–
(3)
46
(13)
(7)
11
$ 215
$
Residential
Commercial
Industrial
Other
Total
Electric Revenues
(millions of dollars)
Electric Sales Volumes
(GWh)
2022
2021
2022
2021
$ 834
427
353
28
$ 1,642
$
797
407
237
27
$ 1,468
4,822
3,006
2,480
148
10,456
4,661
2,902
2,480
153
10,196
31
Management’s Discussion & AnalysisEMERA 2022 ANNUAL REPORT Regulated Fuel for Generation and Purchased Power
Annual production volumes are summarized in the following table:
Coal
Natural gas
Purchased power – other
Petcoke
Oil
Total non-renewables
Purchased power
Wind and hydro
Biomass
Total renewables
Total production volumes
Production Volumes
(GWh)
2022
2021
3,771
1,650
910
897
251
7,479
2,423
1,105
127
3,655
11,134
4,623
1,673
865
519
81
7,761
1,977
1,007
160
3,144
10,905
NSPI’s fuel costs are affected by commodity prices and generation mix, which is largely dependent on economic dispatch of the
generating fleet. NSPI brings the lowest cost options on stream first after renewable energy from IPPs, including Community
Feed-in Tariff (“COMFIT”) participants, for which NSPI has power purchase agreements in place, and the NS Block of energy,
including the Supplemental Energy Block. NSPI pays annual assessments approved by the UARB to NSPML for use of the
Maritime Link, and therefore utilizes all transmitted NS Block and Supplemental Energy Block energy received which carries no
additional fuel cost.
NSPI-owned hydro and wind have no fuel cost component. After hydro and wind, historically, petcoke and coal have the lowest
per-unit fuel cost, followed by natural gas. Oil, biomass and purchased power have the next lowest fuel cost, depending on the
relative pricing of each. Generation mix may also be affected by plant outages, availability of renewable generation, availability
of energy from the NS Block, plant performance, and compliance with environmental standards including the Cap-and-
Trade Program.
The generation mix has undergone significant transformation with the addition of non-dispatchable renewable energy sources
such as wind, including from IPPs and COMFIT, which typically have a higher cost per MWh than NSPI-owned generation or other
purchased power sources.
The provision for the Cap-and-Trade program was an $18 million recovery for the three months ended December 31, 2022 (2021 –
$35 million expense) and a $134 million expense for the year ended December 31, 2022 (2021 – $38 million expense). For further
information on this non-cash accrual, the estimated costs and the FAM regulatory balance, refer to note 7 in the consolidated
financial statements.
Regulatory Environment – NSPI
NSPI is a public utility as defined in the Public Utilities Act and is subject to regulation under the Public Utilities Act by the UARB.
The Public Utilities Act gives the UARB supervisory powers over NSPI’s operations and expenditures. Electricity rates for NSPI’s
customers are subject to UARB approval. NSPI is not subject to a general annual rate review process, but rather participates
in hearings held from time to time at NSPI’s or the UARB’s request. For further details on NSPI’s regulatory environment and
recovery mechanisms, refer to note 7 in the consolidated financial statements.
32
Management’s Discussion & AnalysisEMERA 2022 ANNUAL REPORT GAS UTILITIES AND INFRASTRUCTURE
All amounts are reported in USD, unless otherwise stated.
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
2021
2022
$ 372
2
$
374
$ 181
53
$
72
$
$ 307
2
$ 309
$ 139
44
$
55
$
Year ended
December 31
2021
$ 1,006
12
$ 1,018
375
$
$ 157
198
$
2022
$ 1,296
12
$ 1,308
$ 614
$
170
$ 221
(1) Operating revenues – regulated gas includes $13 million of finance income from Brunswick Pipeline (2021 – $12 million) for the three months ended
December 31, 2022 and $47 million (2021 – $46 million) for the year ended December 31 2022; however, it is excluded from the gas revenues and cost of
natural gas analysis below.
Gas Utilities and Infrastructure’s contribution to consolidated net income is summarized in the following table:
For the
millions of USD
PGS
NMGC
Other
Contribution to consolidated net income
Three months ended
December 31
2021
2022
$
$
17
22
14
53
$
$
17
15
12
44
$
$
Year ended
December 31
2021
$
77
33
47
$ 157
2022
82
35
53
170
The impact of the change in the FX rate increased CAD earnings for the three months and year ended December 31, 2022, by
$4 million and $6 million, respectively.
Net Income
Highlights of the net income changes are summarized in the following table:
For the
millions of USD
Contribution to consolidated net income – 2021
Increased gas revenues due to higher purchased gas adjustment clause revenues at NMGC and
PGS as a result of higher gas prices, higher off-system sales, and customer growth at PGS
Increased asset optimization revenues at NMGC. In 2022, NMGC’s 30 per cent share of asset
optimization revenues were well above the historical average, and may not reoccur in 2023
Increased cost of natural gas sold due to higher gas prices at NMGC and PGS, and higher off-
system sales at PGS
Increased OM&G primarily due to higher labour and benefits costs at NMGC and PGS, and higher
contractor costs at PGS
Increased depreciation and amortization due to asset growth at PGS and NMGC. Year-over-year,
the increase was more than offset by the reversal of accumulated depreciation as a result of
the rate case settlement at PGS
Increased interest expense due to higher interest rates
Increased income tax expense primarily due to increased income before provision for
income taxes
Other
Contribution to consolidated net income – 2022
Three months ended
December 31
Year ended
December 31
$
44
$ 157
55
10
280
10
(42)
(239)
(3)
(22)
(2)
(4)
(2)
(3)
$
53 $
6
(10)
(7)
(5)
170
33
Management’s Discussion & AnalysisEMERA 2022 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)
Gas Volumes
(Therms)
2022
2021
2022
2021
$ 614
354
64
217
$ 1,249
$
510
301
53
96
$ 960
421
836
1,429
227
2,913
405
799
1,434
137
2,775
(1) Industrial gas revenue includes sales to power generation customers.
(2) Other gas revenue includes off-system sales to other utilities and various other items.
(3) Total gas revenue excludes $47 million of finance income from Brunswick Pipeline (2021 – $46 million).
Regulated Cost of Natural Gas
PGS and NMGC purchase gas from various suppliers depending on the needs of their customers. In Florida, gas is delivered to
the PGS distribution system through interstate pipelines on which PGS has firm transportation capacity for delivery by PGS to its
customers. NMGC’s natural gas is transported on major interstate pipelines and NMGC’s intrastate transmission and distribution
system for delivery to customers.
In Florida, natural gas service is unbundled for non-residential customers and residential customers who use more than
1,999 therms annually and elect the option. In New Mexico, NMGC is required, if requested, to provide transportation-only
services for all customer classes. The commodity portion of bundled sales is included in operating revenues, at the cost of
the gas on a pass-through basis, therefore no net earnings effect when a customer shifts to transportation-only sales.
Annual gas sales by type are summarized in the following table:
Transportation
System supply
Total
Gas Volumes by Type
(millions of Therms)
2022
2,206
707
2,913
2021
2,154
621
2,775
Regulatory Environments
PGS is regulated by the FPSC. The FPSC sets rates at a level that allows utilities such as PGS to collect total revenues or revenue
requirements equal to their cost of providing service, plus an appropriate return on invested capital.
NMGC is subject to regulation by the NMPRC. The NMPRC sets rates at a level that allows NMGC to collect total revenues equal to
its cost of providing service, plus an appropriate return on invested capital.
For further information on PGS and NMGC’s regulatory environment and recovery mechanisms, refer to note 7 in the
consolidated financial statements.
34
Management’s Discussion & AnalysisEMERA 2022 ANNUAL REPORT
OTHER ELECTRIC UTILITIES
All amounts are reported in USD, unless otherwise stated.
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
Contribution to consolidated net income – CAD
Electric sales volumes (GWh)
Electric production volumes (GWh)
Average fuel cost in dollars per MWh
$
$
$
$
$
$
$
$
$
Three months ended
December 31
2021
2022
Year ended
December 31
2021
2022
98
54
7
$
$
$
98
52
4
$ 398
$ 223
23
$
$
$
$
355
175
16
20
$
8
$
54
1
$
(46) $
(62) $
$
5
– $
$
2
$
6
$
7
330
357
$ 146
$
301
336
161
29
54
$
$
(4) $
(35) $
(48) $
–
1
17
21
1,262
1,359
$ 129
1,239
1,340
166
The impact of the change in the FX rate increased net loss by $3 million for the three months and year ended December 31, 2022
and had a minimal impact on adjusted net income for the same periods.
Other Electric Utilities’ contribution to consolidated adjusted net income is summarized in the following table:
For the
millions of USD
BLPC
GBPC
Other
Contribution to consolidated adjusted net income
Three months ended
December 31
2021
2022
$
$
5
1
1
7
$
$
6
–
(2)
4
$
$
Year ended
December 31
2021
$
$
11
8
(3)
16
2022
11
10
2
23
Net Income
Highlights of the net income changes are summarized in the following table:
For the
millions of USD
Contribution to consolidated net income – 2021
Increased operating revenues – regulated electric year-over-year due to higher fuel revenue at
BLPC as a result of higher fuel prices, partially offset by the sale of Domlec in Q1 2022
Increased fuel for generation and purchased power as a result of higher fuel prices at BLPC
Decreased OM&G due to the sale of Domlec in Q1 2022 and lower generation costs at GBPC,
partially offset by the recognition of Hurricane Dorian insurance proceeds at GBPC in 2021
Goodwill impairment charge at GBPC
Decreased MTM gain on equity securities held in BLPC
Other
Contribution to consolidated net income – 2022
Three months ended
December 31
Year ended
December 31
$
6
$
17
–
(2)
11
(54)
(1)
(6)
(46) $
43
(48)
17
(54)
(5)
(5)
(35)
$
35
Management’s Discussion & AnalysisEMERA 2022 ANNUAL REPORT Regulatory Environments
BLPC is regulated by the FTC, an independent regulator. Rates are set to recover prudently incurred costs of providing electricity
service to customers plus an appropriate return on capital invested.
GBPC is regulated by the GBPA. Rates are set to recover prudently incurred costs of providing electricity service to customers
plus an appropriate return on rate base.
For further details on BLPC and GBPC’s regulatory environments and recovery mechanisms, refer to note 7 in the consolidated
financial statements.
OTHER
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 (loss), after-tax (3)
Contribution to consolidated net income (loss)
$
$
$
$
Three months ended
December 31
2021
2022
Year ended
December 31
2021
2022
$
72
3
75
$
(1) $
304
303
$
39
5
44
(44) $
154
110
$
$
$ 143
16
$ 159
$
(218) $
179
(39) $
102
30
132
(198)
(214)
(412)
(1) Marketing and trading margin represents EES’s purchases and sales of natural gas and electricity, pipeline and storage capacity costs and energy asset
management services’ revenues.
(2) Marketing and trading margin excludes a MTM gain, pre-tax of $430 million in Q4 2022 (2021 – $212 million gain) and a gain of $281 million for the year
ended December 31, 2022 (2021 – $289 million loss).
(3) Net of income tax expense of $124 million for the three months ended December 31, 2022 (2021 – $63 million expense) and $73 million expense for the year
ended December 31, 2022 (2021 – $86 million recovery).
Other’s contribution to consolidated adjusted net income is summarized in the following table:
For the
millions of dollars
Emera Energy
Corporate – see breakdown of adjusted contribution below
Emera Technologies
Other
Contribution to consolidated adjusted net income (loss)
Three months ended
December 31
2021
2022
Year ended
December 31
2021
2022
$
$
$
41
(37)
(5)
–
(1) $
$
17
(57)
(4)
–
(44) $
$
70
(267)
(18)
(3)
(218) $
54
(231)
(17)
(4)
(198)
MTM Adjustments
Emera Energy’s “Marketing and trading margin”, “Non-regulated fuel for generation and purchased power”, “Income from equity
investments” and “Income tax expense (recovery)” are affected by MTM adjustments. Management believes excluding the effect
of MTM valuations, and changes thereto, from income until settlement better matches the financial effect of these contracts
with the underlying cash flows. Variance explanations of the MTM changes for this quarter and for the year are explained in the
chart below.
Emera Energy has a number of asset management agreements (“AMA”) with counterparties, including local gas distribution
utilities, power utilities and natural gas producers in North America. The AMAs involve Emera Energy buying or selling gas for a
specific term, and the corresponding release of the counterparties’ gas transportation/storage capacity to Emera Energy. MTM
adjustments on these AMAs arise on the price differential between the point where gas is sourced and where it is delivered. At
inception, the MTM adjustment is offset fully by the value of the corresponding gas transportation asset, which is amortized over
the term of the AMA contract.
36
Management’s Discussion & AnalysisEMERA 2022 ANNUAL REPORT
Subsequent changes in gas price differentials, to the extent they are not offset by the accounting amortization of the gas
transportation asset, will result in MTM gains or losses recorded in income. MTM adjustments may be substantial during the term
of the contract, especially in the winter months of a contract when delivered volumes and market pricing are usually at peak
levels. As a contract is realized, and volumes reduce, MTM volatility is expected to decrease. Ultimately, the gas transportation
asset and the MTM adjustment reduce to zero at the end of the contract term. As the business grows, and AMA volumes increase,
MTM volatility resulting in gains and losses may also increase.
Emera Corporate has FX forwards to manage the cash flow risk of forecasted USD cash inflows. Fluctuations in the FX rate result
in MTM gains or losses recorded in income.
Net Income
Highlights of the net income changes are summarized in the following table:
For the
millions of dollars
Contribution to consolidated net income (loss) – 2021
Increased marketing and trading margin due to weather driven market conditions that increased
pricing and volatility, which created profitable opportunities for Emera Energy. Year-over-year
increase also reflected sustained higher pricing and volatility
Increased OM&G, pre-tax, primarily due to the timing of long-term compensation and related
hedges
Increased interest expense, pre-tax, due to increased interest rates and increased total debt
Increased FX loss, pre-tax, primarily due to realized gains in 2021 on FX hedges entered into to
hedge USD denominated operating unit earnings exposure
Increased income tax recovery primarily due to increased losses before provision for
income taxes
Increased preferred stock dividends due to issuance of preferred shares in 2021
TGH award, after tax and legal costs
Increased MTM gain, after-tax, due to change in existing positions and larger reversal of MTM
losses in 2022, partially offset by higher amortization of gas transportation assets in 2022 at
Emera Energy
Other
Contribution to consolidated net income (loss) – 2022
Three months ended
December 31
Year ended
December 31
$
110
$
(412)
33
41
(19)
(17)
(55)
(27)
(9)
(28)
5
(2)
45
25
(13)
45
150
7
303
$
393
(8)
(39)
$
Emera Energy
EES derives revenue and earnings from the wholesale marketing and trading of natural gas and electricity within the Company’s
risk tolerances, including those related to value-at-risk (“VaR”) and credit exposure. EES purchases and sells physical natural gas
and electricity, the related transportation and transmission capacity rights, and provides energy asset management services.
The primary market area for the natural gas and power marketing and trading business is northeastern North America, including
the Marcellus and Utica shale supply areas. EES also participates in the Florida, United States Gulf Coast and Midwest/Central
Canadian natural gas markets. Its counterparties include electric and gas utilities, natural gas producers, electricity generators
and other marketing and trading entities. EES operates in a competitive environment, and the business relies on knowledge of
the region’s energy markets, understanding of pipeline and transmission infrastructure, a network of counterparty relationships
and a focus on customer service. EES manages its commodity risk by limiting open positions, utilizing financial products to hedge
purchases and sales, and investing in transportation capacity rights to enable movement across its portfolio.
37
Management’s Discussion & AnalysisEMERA 2022 ANNUAL REPORT 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
2021
2022
Year ended
December 31
2021
2022
$
$
$
20
83
(35)
16
(45)
(2)
(37) $
$
1
65
(18)
14
–
(5)
(57) $
$
83
291
(109)
63
(45)
(16)
(267) $
28
264
(75)
50
–
(36)
(231)
(1) Operating expenses include OM&G and depreciation. In Q4 2021, OM&G and depreciation were offset by a decrease in long-term incentive compensation.
The value of long-term incentive compensation and related hedges are impacted by changes in Emera’s period end share price.
(2) Other includes realized FX gains and losses on FX hedges entered into to hedge USD denominated operating unit earnings exposure.
(3) Includes a realized, pre-tax net loss of $5 million (2021 – $5 million gain) quarter-to-date and a $6 million loss for the year ended December 31, 2022 (2021 –
$18 million gain) on FX hedges, as discussed above.
(4) Excludes a MTM gain, after-tax of $9 million for the three months ended December 31, 2022 (2021 – $3 million loss) and a MTM loss, after-tax of $12 million
for the year ended December 31, 2023 (2021 – $14 million loss).
Liquidity and Capital Resources
The Company generates internally sourced cash from its various regulated and non-regulated energy investments. Utility
customer bases are diversified by both sales volumes and revenues among customer classes. Emera’s non-regulated businesses
provide diverse revenue streams and counterparties to the business. Circumstances that could affect the Company’s ability
to generate cash include changes to global macro-economic conditions, downturns in markets served by Emera, impact of
fuel commodity price changes on collateral requirements and timely recoveries of fuel costs from customers, the loss of one
or more large customers, regulatory decisions affecting customer rates and the recovery of regulatory assets, and changes
in environmental legislation. Emera’s subsidiaries are generally in a financial position to contribute cash dividends to Emera
provided they do not breach their debt covenants, where applicable, after giving effect to the dividend payment, and maintain
their credit metrics.
Emera’s future liquidity and capital needs will be predominately for working capital requirements, ongoing rate base investment,
business acquisitions, greenfield development, dividends and debt servicing. Emera has an $8 – 9 billion capital investment plan
over the 2023-to-2025 period (including a $240 million equity investment in the LIL in 2023), mainly focused in Florida. This plan
includes significant rate base investments across the portfolio in renewable and cleaner generation, infrastructure modernization
and customer-focused technologies. Capital investments at the regulated utilities are subject to regulatory approval.
Emera plans to use cash from operations and debt raised at the utilities to support normal operations, repayment of existing
debt, and capital requirements. Debt raised at certain of the Company’s utilities is subject to applicable regulatory approvals.
Equity requirements in support of the Company’s capital investment plan are expected to be funded through the issuance of
preferred equity and the issuance of common equity through Emera’s DRIP and ATM program.
Emera has credit facilities with varying maturities that cumulatively provide $4.7 billion of credit, with approximately $1.1 billion
undrawn and available at December 31, 2022. The Company was holding a cash balance of $332 million at December 31, 2022. For
further discussion, refer to the “Debt Management” section below. For additional information regarding the credit facilities, refer
to notes 23 and 25 in the consolidated financial statements.
38
Management’s Discussion & AnalysisEMERA 2022 ANNUAL REPORT CONSOLIDATED CASH FLOW HIGHLIGHTS
Significant changes in the Consolidated Statements of Cash Flows between the years ended December 31, 2022 and 2021 include:
millions of dollars
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
2022
2021
$ Change
$
417
$ 254
$ 163
1,147
(234)
$ 913
(2,569)
1,555
16
$ 332
1,337
(152)
$ 1,185
(2,332)
1,311
$
(1)
417
$
$
(190)
(82)
(272)
(237)
244
17
(85)
Cash Flow from Operating Activities
Net cash provided by operating activities decreased $272 million to $913 million for the year ended December 31, 2022, compared
to $1,185 million in 2021.
Cash from operations before changes in working capital decreased $190 million for the year ended December 31, 2022. This
decrease was due to under-recovery of clause-related costs primarily due to higher natural gas prices at Tampa Electric,
unfavourable changes in Tampa Electric’s storm reserve balance as a result of Hurricane Ian, increased fuel for generation
and purchased power at NSPI, and decreased long-term payables due to the Nova Scotia Cap-and-Trade accrued emissions
compliance charges being reclassified to other current liabilities as the liability is anticipated to be settled in 2023. This was
partially offset by the 2021 deferral of gas costs at NMGC resulting from the extreme cold weather event, increased revenues at
Tampa Electric and NSPI, favourable changes in regulatory liabilities due to the NMGC gas hedge settlement, TGH award, and
increased marketing and trading margin at Emera Energy.
Changes in working capital decreased operating cash flows by $82 million for the year ended December 31, 2022. This decrease
was due to unfavourable changes in accounts receivable at NMGC due to the gas hedge settlement, unfavourable changes
in accounts receivable at NSPI, unfavourable changes in cash collateral positions on derivative instruments at NSPI, and the
required prepayment of income taxes and related interest at NSPI. This was partially offset by the Nova Scotia Cap-and-Trade
accrued emissions compliance charges, favourable changes in cash collateral positions at Emera Energy, and favourable changes
in accounts payable at Tampa Electric and NMGC.
Cash Flow Used in Investing Activities
Net cash used in investing activities increased $237 million to $2,569 million for the year ended December 31, 2022, compared to
$2,332 million in 2021. The increase was due to higher capital investment in 2022.
Capital expenditures for the year ended December 31, 2022, including AFUDC, were $2,646 million compared to $2,420 million in
2021. Details of 2022 capital spending by segment are shown below:
• $1,481 million – Florida Electric Utility (2021 – $1,408 million);
• $518 million – Canadian Electric Utilities (2021 – $374 million);
• $578 million – Gas Utilities and Infrastructure (2021 – $522 million);
• $63 million – Other Electric Utilities (2021 – $111 million); and
• $6 million – Other (2021 – $5 million).
39
Management’s Discussion & AnalysisEMERA 2022 ANNUAL REPORT Cash Flow from Financing Activities
Net cash provided by financing activities increased $244 million to $1,555 million for the year ended December 31, 2022,
compared to $1,311 million in 2021. This increase was due to higher proceeds of short-term debt at Tampa Electric, proceeds
from committed credit facilities at NSPI, and term loan issuance at Emera in 2022. These were partially offset by the issuance of
preferred shares in 2021, lower proceeds of long-term debt at Tampa Electric, and net proceeds of long-term debt at NMGC in 2021.
WORKING CAPITAL
As at December 31, 2022, Emera’s cash and cash equivalents were $310 million (2021 – $394 million) and Emera’s investment in
non-cash working capital was $1,173 million (2021 – $491 million). Of the cash and cash equivalents held at December 31, 2022,
$250 million was held by Emera’s foreign subsidiaries (2021 – $194 million). A portion of these funds are invested in countries that
have certain exchange controls, approvals, and processes for repatriation. Such funds are available to fund local operating and
capital requirements unless repatriated.
CONTRACTUAL OBLIGATIONS
As at December 31, 2022, contractual commitments for each of the next five years and in aggregate thereafter consisted of
the following:
millions of dollars
2023
2024
Long-term debt principal
Interest payment obligations (1 )
Transportation (2)
Purchased power (3)
Fuel, gas supply and storage
Capital projects
Asset retirement obligations
Pension and post-retirement
obligations (4)
Equity investment commitments (5)
Other
$
574
720
693
269
1,161
264
15
38
240
154
$
$ 1,613
699
516
243
282
89
2
31
–
142
2025
262
653
423
237
138
4
2
31
–
132
2026
2027
Thereafter
Total
$ 3,110
566
383
228
40
1
1
$ 946
472
367
243
5
–
1
$ 9,937
6,995
2,817
2,145
1
–
415
$ 16,442
10,105
5,199
3,365
1,627
358
436
82
–
49
59
–
42
178
–
189
419
240
708
$ 4,128
$ 3,617
$ 1,882
$ 4,460
$ 2,135
$ 22,677
$ 38,899
(1) Future interest payments are calculated based on the assumption that all debt is outstanding until maturity. For debt instruments with variable rates,
interest is calculated for all future periods using the rates in effect at December 31, 2022, including any expected required payment under associated
swap agreements.
(2) Purchasing commitments for transportation of fuel and transportation capacity on various pipelines. Includes a commitment of $144 million related to a gas
transportation contract between PGS and SeaCoast through 2040.
(3) Annual requirement to purchase electricity production from IPPs or other utilities over varying contract lengths.
(4) The estimated contractual obligation is calculated as the current legislatively required contributions to the registered funded pension plans (excluding the
possibility of wind-up), plus the estimated costs of further benefit accruals contracted under NSPI’s Collective Bargaining Agreement and estimated benefit
payments related to other unfunded benefit plans.
(5) Emera has a commitment to make a final equity contribution to the LIL upon its commissioning. Once commissioned, the commercial agreements between
Emera and Nalcor require true ups to finalize the respective investment obligations of the parties in relation to the Maritime Link and LIL.
NSPI has a contractual obligation to pay NSPML for use of the Maritime Link over approximately 38 years from its January 15, 2018
in-service date. In February 2022, the UARB issued its decision and Board Order approving NSPML’s requested rate base of
approximately $1.8 billion. In December 2022, the UARB approved the collection of $164 million from NSPI for the recovery of
Maritime Link costs in 2023. The timing and amounts payable to NSPML for the remainder of the 38-year commitment period are
subject to UARB approval.
Emera has committed to obtain certain transmission rights for Nalcor, if requested, to enable it to transmit energy which is not
otherwise used in Newfoundland and Labrador or Nova Scotia. Nalcor has the right to transmit this energy from Nova Scotia to
New England energy markets effective August 15, 2021, the date the NS Block delivery obligation commenced, and continuing for
50 years. As transmission rights are contracted, the obligations are included within “Other” in the above table.
40
Management’s Discussion & AnalysisEMERA 2022 ANNUAL REPORT FORECASTED GROSS CONSOLIDATED CAPITAL EXPENDITURES
The 2023 forecasted gross consolidated capital expenditures are as follows:
millions of dollars
Generation
New renewable generation
Transmission
Distribution
Gas transmission and distribution
Facilities, equipment, vehicles, and other
Florida
Electric Utility
Canadian
Electric
Utilities
Gas
Utilities and
Infrastructure
Other Electric
Utilities
Other
Total
$ 120
$
– $
– $
$
276
402
100
479
–
516
$ 1,773
$
–
74
121
–
60
375
–
–
–
639
–
$
639
$
36
4
–
34
–
17
91
$
$
432
406
174
634
639
604
$ 2,889
–
–
–
–
11
11
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 dollars
Emera – Unsecured committed revolving credit facility
TEC (in USD) – Unsecured committed revolving credit facility ( 1)
NSPI – Unsecured committed revolving credit facility
Emera – Unsecured non-revolving facility
Emera – Unsecured non-revolving facility
TEC (in USD) – Unsecured non-revolving facility (2)
TECO Finance (in USD) – Unsecured committed revolving credit
facility
NSPI – Unsecured non-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 2023
August 2023
December 2023
December 2026
July 2024
December 2026
March 2024
Various
Credit
Facilities
$ 900
800
800
400
400
400
Utilized
$ 403
620
497
400
400
400
400
400
125
80
21
355
400
45
80
7
Undrawn
and
Available
$ 497
180
303
–
–
–
45
–
80
–
14
(1) This facility is available for use by Tampa Electric and PGS. At December 31, 2022, $554 million USD was used by Tampa Electric and $66 million USD was
used by PGS.
(2) This facility is available for use by Tampa Electric and PGS. At December 31, 2022, $300 million USD was used by Tampa Electric and $100 million USD was
used by PGS.
Emera and its subsidiaries have certain financial and other covenants associated with their debt and credit facilities. Covenants
are tested regularly, and the Company is in compliance with covenant requirements as at December 31, 2022. Emera’s significant
covenant is listed below:
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, 2022
Recent significant financing activity for Emera and its subsidiaries are discussed below by segment:
Florida Electric Utilities
On December 13, 2022, TEC amended its 364-day non-revolving credit facility to extend the maturity date from December 16, 2022
to December 13, 2023 and reduced the facility amount from $500 million USD to $400 million USD. There were no other
significant changes in commercial terms from the prior agreement.
41
Management’s Discussion & AnalysisEMERA 2022 ANNUAL REPORT
On September 15, 2022, TEC repaid a $250 million USD note upon maturity. The note was repaid using existing credit facilities.
On July 12, 2022, TEC completed an issuance of $600 million USD senior notes. The issuance included $300 million USD senior
notes that bear an interest rate of 3.875 per cent with a maturity date of July 12, 2024, and $300 million USD senior notes that
bear an interest rate of 5 per cent with a maturity date of July 15, 2052. Proceeds from the issuance were used to repay TEC’s
$470 million USD commercial paper, due in 2022, and for general corporate purposes.
Canadian Electric Utilities
On December 16, 2022, NSPI amended its revolving operating credit facility to extend the maturity date from December 16, 2026
to December 16, 2027 and increase the amount of the facility from $600 million to $800 million. There were no other significant
changes in commercial terms from the prior agreement.
On July 15, 2022, NSPI entered into a $400 million non-revolving term credit facility which matures on July 15, 2024. The
credit facility contains customary representation and warranties, events of default and financial and other covenants, and
bears interest at Bankers’ Acceptances or prime rate advances, plus a margin. Proceeds from this facility were used for general
corporate purposes.
Gas Utilities and Infrastructure
On September 23, 2022, NMGC amended its $80 million USD, unsecured, non-revolving term credit facility to extend the maturity
from September 23, 2022, to March 22, 2024. There were no other changes in commercial terms from the prior agreement.
On June 30, 2022, Brunswick Pipeline amended its non-revolving credit agreement to extend the maturity from June 30, 2025
to June 30, 2026. There were no other changes in commercial terms from the prior agreement.
Other Electric Utilities
On March 25, 2022, ECI amended its amortizing floating rate notes to extend the maturity from March 25, 2022 to March 25,
2027. There were no other changes in commercial terms from the prior agreement.
Other
On December 16, 2022, Emera amended its $900 million revolving operating credit facility to extend the maturity date from
June 30, 2026 to June 30, 2027. There were no other significant changes in commercial terms from the prior agreement.
On December 16, 2022, Emera amended its $400 million non-revolving term credit facility to extend the maturity from
December 16, 2022 to December 16, 2023. There were no other significant changes in commercial terms from the prior agreement.
On August 2, 2022, Emera entered into a $400 million non-revolving term facility which matures on August 2, 2023. The credit
agreement contains customary representation and warranties, events of default and financial and other covenants and bears
interest at Bankers’ Acceptances or prime rate advances, plus a margin. Proceeds from this facility were used for general
corporate purposes.
42
Management’s Discussion & AnalysisEMERA 2022 ANNUAL REPORT CREDIT RATINGS
Emera and its subsidiaries have been assigned the following senior unsecured debt ratings:
Fitch ( 1)
S&P (2) (3)
Moody’s (4) (5)
DBRS (6)
Emera Inc.
TECO Energy/TECO Finance
TEC
NMGC
NSPI
BBB (Negative)
N/A
A (Negative)
BBB+ (Negative)
N/A
BBB- (Negative)
N/A
BBB+ (Negative)
N/A
BBB- (Negative)
Baa3 (Negative)
N/A
A3 (Negative)
N/A
N/A
N/A
N/A
N/A
N/A
BBB (high)(stable)
(1) On November 21, 2022, Fitch Ratings (“Fitch”) affirmed its BBB issuer rating for Emera Inc. Fitch also affirmed the A- issuer and A unsecured debt ratings
for TEC and BBB+ for NMGC. Emera and subsidiaries’ outlook was changed to negative from stable.
(2) On November 21, 2022, S&P Global Ratings (“S&P”) affirmed its BBB issuer rating for Emera Inc. and TECO Energy, while affirming the BBB+ issuer credit
ratings for TEC. S&P downgraded NSPI’s issue-level and senior unsecured debt ratings to BBB-. Emera and subsidiaries’ outlook remained at negative.
(3) On October 24, 2022, S&P affirmed its BBB issuer rating for Emera Inc. S&P also affirmed ratings on NSPI, TECO Energy, and TEC affirming the BBB+ issuer
credit ratings for NSPI and TEC. Emera and subsidiaries’ outlook was changed to negative from stable.
(4) On November 2, 2022, Moody’s Investor Services (“Moody’s”) affirmed its Baa3 issuer rating for Emera Inc. Moody’s also affirmed ratings on TECO Finance
and TEC, affirming the TECO Finance Baa1 issuer rating and A3 issuer rating for TEC. Emera and subsidiaries’ outlook was changed to negative from stable.
(5) On June 2, 2022, Moody’s affirmed its Baa1 issuer rating for TECO Finance. Moody’s also affirmed TEC’s A3 issuer rating and changed the outlook to stable
from positive.
(6) On December 20, 2022, DBRS (“Dominion Bond Rating Service”) downgraded its issuer credit and senior unsecured rating for NSPI to BBB (high). NSPI’s
outlook remained unchanged at stable.
The downgrades from both S&P and DBRS of NSPI were attributed to their view of the enactment of Bill 212, “Public Utilities Act
(amended)”, as a political intervention in the regulatory process that resulted in an increase in political risk and a reduction in the
stability and predictability of NSPI’s regulatory environment.
GUARANTEED DEBT
As of December 31, 2022, the Company had $2.75 billion USD senior unsecured notes (“U.S. Notes”) outstanding.
The U.S. Notes are fully and unconditionally guaranteed, on a joint and several basis, by Emera and Emera US Holdings Inc.
(in such capacity, the “Guarantor Subsidiaries”). Emera owns, directly or indirectly, all of the limited and general partnership
interests in Emera US Finance LP. Other subsidiaries of the Company do not guarantee the U.S. Notes (such subsidiaries are
referred to as the “Non-Guarantor Subsidiaries”) however, Emera has unrestricted access to the assets of consolidated entities.
In compliance with Rule 13-01 of Regulation S-X, the Company is including summarized financial information for Emera, Emera
US Holdings Inc., and Emera US Finance LP (together, the “Obligor Group”), on a combined basis after transactions and balances
between the combined entities have been eliminated. Investments in and equity earnings of the Non-Guarantor Subsidiaries have
been excluded from the summarized financial information.
The Obligor Group was not determined using geographic, service line or other similar criteria and, as a result the summarized
financial information includes portions of Emera’s domestic and international operations. Accordingly, this basis of presentation
is not intended to present Emera’s financial condition or results of operations for any purpose other than to comply with the
specific requirements for guarantor reporting.
43
Management’s Discussion & AnalysisEMERA 2022 ANNUAL REPORT 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 losses (1)
(1)
Includes $262 million in interest and dividend income, net, from non-guarantor subsidiaries.
Summarized Balance Sheet
The Company has the following categories on the balance sheet related to guaranteed debt:
As at
millions of dollars
Current assets (1)
Goodwill
Other assets (2)
Total assets (3)
Current liabilities (4)
Long-term liabilities (5)
Total liabilities
Year ended December 31
2021
2022
$
$
(73) $
(131) $
(21)
(86)
2022
$
172
6,012
6,402
$ 12,586
$ 1,903
6,431
$ 8,334
December 31
2021
$ 329
5,628
6,027
$ 11,984
$ 888
6,403
$ 7,291
(1)
Includes $144 million (2021 – $140 million) in amounts due from non-guarantor subsidiaries.
(2) Includes $6,058 million (2021 – $5,749 million) in amounts due from non-guarantor subsidiaries.
(3) Excludes investments in non-guarantor subsidiaries. Consolidated Emera total assets are $39,742 million (2021 – $34,244 million).
(4) Includes $392 million (2021 – $346 million) due to non-guarantor subsidiaries.
(5) Includes $769 million (2021 – $776 million) due to non-guarantor subsidiaries.
OUTSTANDING STOCK DATA
Common Stock
Issued and outstanding:
Balance, December 31, 2021
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, 2022
millions of
shares
millions of
dollars
261.07
4.07
4.21
0.60
269.95
$ 7,242
248
238
34
$ 7,762
(1)
In Q4 2022, 278,545 common shares were issued under Emera’s ATM program at an average price of $54.06 per share for gross proceeds of $15 million
($15 million net of after-tax issuance costs). For the year ended December 31, 2022, 4,072,469 common shares were issued under Emera’s ATM program at
an average price of $61.31 per share for gross proceeds of $250 million ($248 million net of after-tax issuance costs). As at December 31, 2022, an aggregate
gross sales limit of $207 million remained available for issuance under the ATM program.
As at February 16, 2023, the amount of issued and outstanding common shares was 271.4 million.
If all outstanding stock options were converted as at February 16, 2023, an additional 2.9 million common shares would be issued
and outstanding.
Preferred Stock
As at February 16, 2023, Emera had the following preferred shares issued and outstanding: Series A – 4.9 million; Series B –
1.1 million; Series C – 10.0 million; Series E – 5.0 million; Series F – 8.0 million; Series H – 12.0 million; Series J – 8.0 million, and
Series L – 9.0 million. Emera’s preferred shares do not have voting rights unless the Company fails to pay, in aggregate, eight
quarterly dividends.
44
Management’s Discussion & AnalysisEMERA 2022 ANNUAL REPORT Pension Funding
For funding purposes, Emera determines required contributions to its largest defined benefit pension plans based on smoothed
asset values. This reduces volatility in the cash funding requirement as the impact of investment gains and losses are recognized
over a three-year period. The cash required in 2023 for defined benefit pension plans is expected to be $44 million (2022 –
$45 million). All pension plan contributions are tax deductible and will be funded with cash from operations.
Emera’s defined benefit pension plans employ a long-term strategic approach with respect to asset allocation, real return and
risk. The underlying objective is to earn an appropriate return, given the Company’s goal of preserving capital with an acceptable
level of risk for the pension fund investments.
To achieve the overall long-term asset allocation, pension assets are managed by external investment managers per the pension
plan’s investment policy and governance framework. The asset allocation includes investments in the assets of Canadian and
global equities, domestic and global bonds and short-term investments. Emera reviews investment manager performance on a
regular basis and adjusts the plans’ asset mixes as needed in accordance with the pension plans’ investment policy.
Emera’s projected contributions to defined contribution pension plans are $44 million for 2023 (2022 – $41 million).
DEFINED BENEFIT PENSION PLAN SUMMARY
in millions of dollars
Plans by region
Assets as at December 31, 2022
Accounting obligation at December 31, 2022
Accounting expense during fiscal 2022
Off-Balance Sheet Arrangements
TECO Energy
NSPI
Caribbean
Total
$ 880
902
$
10
$
$ 1,273
$ 1,240
$
$
$
(3) $
10
16
1
$ 2,163
$ 2,158
8
$
DEFEASANCE
Upon privatization in 1992, NSPI became responsible for managing a portfolio of defeasance securities that provide principal and
interest streams to match the related defeased debt, which at December 31, 2022 totalled $200 million (2021 – $200 million). The
securities are held in trust for an affiliate of the Province of Nova Scotia. Approximately 66 per cent of the defeasance portfolio
consists of investments in the related debt, eliminating all risk associated with this portion of the portfolio; the remaining
defeasance portfolio has a market value higher than the related debt, reducing the future risk of this portion of the portfolio.
GUARANTEES AND LETTERS OF CREDIT
Emera has guarantees and letters of credit on behalf of third parties outstanding. The following significant guarantees and letters
of credit are not included within the Consolidated Balance Sheets as at December 31, 2022:
TECO Energy has issued a guarantee in connection with SeaCoast’s performance of obligations under a gas transportation
precedent agreement. The guarantee is for a maximum potential amount of $45 million USD if SeaCoast fails to pay or perform
under the contract. The guarantee expires five years after the gas transportation precedent agreement termination date, which
was terminated on January 1, 2022. In the event that TECO Energy’s and Emera’s long-term senior unsecured credit ratings are
downgraded below investment grade by Moody’s or S&P, TECO Energy would be required to provide its counterparty a letter of
credit or cash deposit of $27 million USD.
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.
45
Management’s Discussion & AnalysisEMERA 2022 ANNUAL REPORT Emera Inc. has issued a guarantee of up to $35 million USD relating to outstanding notes of GBPC. The guarantee for the notes
will expire in May 2023.
Emera Inc. has issued a guarantee of $66 million USD relating to outstanding notes of ECI. This guarantee will automatically
terminate on the date upon which the obligations have been repaid in full.
NSPI has issued guarantees on behalf of its subsidiary, NS Power Energy Marketing Incorporated (“NSPEMI”), in the amount of
$119 million USD (2021 – $118 million USD) with terms of varying lengths.
The Company has standby letters of credit and surety bonds in the amount of $145 million USD (December 31, 2021 –
$148 million USD) to third parties that have extended credit to Emera and its subsidiaries. These letters of credit and surety
bonds typically have a one-year term and are renewed annually as required.
Emera Inc., on behalf of NSPI, has a standby letter of credit to secure obligations under a supplementary retirement plan. The
expiry date of this letter of credit was extended to June 2023. The amount committed as at December 31, 2022 was $63 million
(December 31, 2021 – $64 million).
Dividend Payout Ratio
Emera has provided annual dividend growth guidance of four to five per cent through 2025. The Company targets a long-term
dividend payout ratio of adjusted net income of 70 to 75 per cent, and while the payout ratio is likely to exceed that target
through and beyond the forecast period, it is expected to return to that range over time. Emera’s common share dividends paid
in 2022 were $2.6775 ($0.6625 in Q1, Q2, and Q3 and $0.6900 in Q4) per common share and $2.5750 ($0.6375 in Q1, Q2, and Q3
and $0.6625 in Q4) per common share for 2021, representing a dividend payout ratio of 75 per cent in 2022 (2021 – 129 per cent)
and a dividend payout ratio of adjusted net income of 83 per cent in 2022 (2021 – 91 per cent).
On September 22, 2022, the Emera Board of Directors approved an increase in the annual common share dividend rate to $2.76
from $2.65. The first quarterly dividend payment at the increased rate was paid on November 15, 2022.
Transactions with Related Parties
In the ordinary course of business, Emera provides energy and other services and enters into transactions with its subsidiaries,
associates and other related companies on terms similar to those offered to non-related parties. Intercompany balances and
intercompany transactions have been eliminated on consolidation, except for the net profit on certain transactions between non-
regulated and regulated entities in accordance with accounting standards for rate-regulated entities. All material amounts are
under normal interest and credit terms.
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 $157 million for the
year ended December 31, 2022 (2021 – $149 million). NSPML is accounted for as an equity investment and therefore, the
corresponding earnings related to this revenue are reflected in Income from equity investments. For further details, refer to
the “Business Overview and Outlook – Canadian Electric Utilities – ENL” and “Contractual Obligations” sections.
• Natural gas transportation capacity purchases from M&NP are reported in the Consolidated Statements of Income.
Purchases from M&NP reported net in Operating revenues, Non-regulated, totalled $9 million for the year ended
December 31, 2022 (2021 – $19 million).
There were no significant receivables or payables between Emera and its associated companies reported on Emera’s Consolidated
Balance Sheets as at December 31, 2022 and at December 31, 2021.
46
Management’s Discussion & AnalysisEMERA 2022 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 of Directors, to ensure an effective, consistent and coherent approach to risk management. Certain
risk management activities for Emera are overseen by the ERMC to ensure such risks are appropriately identified, assessed,
monitored and subject to appropriate controls.
The Board of Directors established a Risk and Sustainability Committee (“RSC”) in September 2021. The mandate of the RSC is
to assist the Board in carrying out its risk and sustainability oversight responsibilities. The RSC’s mandate includes oversight of
the Company’s Enterprise Risk Management framework, including the identification, assessment, monitoring and management
of enterprise risks. It also includes oversight of the Company’s approach to sustainability and its performance relative to its
sustainability objectives.
The Company’s financial risk management activities are focused on those areas that most significantly impact profitability,
quality and consistency of income, and cash flow. Emera’s risk management focus extends to key operational risks including
safety and environment, which represent core values of Emera. In this section, Emera describes the principal risks that
management believes could materially affect its business, revenues, operating income, net income, net assets, liquidity or capital
resources. The nature of risk is such that no list is comprehensive, and other risks may arise or risks not currently considered
material may become material in the future.
REGULATORY AND POLITICAL RISK
The Company’s rate-regulated subsidiaries and certain investments subject to significant influence are subject to risk of
the recovery of costs and investments. Regulatory and political risk can include changes in regulatory frameworks, shifts in
government policy, legislative changes, and regulatory decisions.
As cost-of-service utilities with an obligation to serve customers, Emera’s utilities operate under formal regulatory frameworks,
and must obtain regulatory approval to change or add rates and/or riders. Emera also holds investments in entities in which it
has significant influence, and which are subject to regulatory and political risk including NSPML, LIL, and M&NP. As a regulated
Group II pipeline, the tolls of Brunswick Pipeline are regulated by the CER on a complaint basis, as opposed to the regulatory
approval process described above. In the absence of a complaint, the CER does not normally undertake a detailed examination
of Brunswick Pipeline’s tolls, which are subject to a firm service agreement, expiring in 2034, with Repsol Energy North America
Canada Partnership. The agreement provides for a predetermined toll increase in the fifth and fifteenth year of the contract.
Regulators administer legislation covering material aspects of the utilities’ businesses, including customer rates and/or riders,
the underlying allowed ROEs, deemed capital structures, capital investment, the terms and conditions for the provision of service,
performance standards, and affiliate transactions. Costs and investments can be recovered upon approval by the respective
regulator as an adjustment to rates and/or riders, which normally require a public hearing process or may be mandated by other
governmental bodies. During public hearing processes, consultants and customer representatives scrutinize the costs, actions
and plans of these rate-regulated companies, and their respective regulators determine whether to allow recovery and to adjust
rates based upon the evidence and any contrary evidence from other parties. In some circumstances, other government bodies
may influence the setting of rates. Regulatory decisions, legislative changes, and prolonged delays in the recovery of costs or
regulatory assets could result in decreased rate affordability for customers and could materially affect Emera and its utilities.
Emera’s utilities generally manage this risk through transparent regulatory disclosure, ongoing stakeholder and government
consultation, and multi-party engagement on aspects such as utility operations, regulatory audits, rate filings and capital
plans. The subsidiaries employ a collaborative regulatory approach through technical conferences and, where appropriate,
negotiated settlements.
Changes in government and shifts in government policy and legislation can impact the commercial and regulatory frameworks
under which Emera and its subsidiaries operate. This includes initiatives regarding deregulation or restructuring of the energy
industry. Deregulation or restructuring of the energy industry may result in increased competition and unrecovered costs that
could adversely affect operations, net income and cash flows. State and local policies in some United States jurisdictions have
sought to prevent or limit the ability of utilities to provide customers the choice to use natural gas while in other jurisdictions
policies have been adopted to prevent limitations on the use of natural gas. Changes in applicable state or local laws and
regulations, including electrification legislation, could adversely impact PGS and NMGC.
47
Management’s Discussion & AnalysisEMERA 2022 ANNUAL REPORT Emera cannot predict future legislative, policy, or regulatory changes, whether caused by economic, political or other factors,
or its ability to respond in an effective and timely manner or the resulting compliance costs. Government interference in the
regulatory process can undermine regulatory stability, predictability, and independence, and could have a material adverse effect
on the Company.
GLOBAL CLIMATE CHANGE RISK
The Company is subject to risks that may arise from the impacts of climate change. There is increasing public concern about
climate change and growing support for reducing carbon dioxide emissions. Municipal, state, provincial and federal governments
have been setting policies and enacting laws and regulations to deal with climate change impacts in a variety of ways, including
decarbonization initiatives and promotion of cleaner energy and renewable energy generation of electricity. Refer to “Changes in
Environmental Legislation” risk below. Insurance companies have begun to limit their exposure to coal-fired electricity generation
and are evaluating the medium and long-term impacts of climate change which may result in fewer insurers, more restrictive
coverage and increased premiums. Refer to the “Markets” section below and “Uninsured Risk”.
Climate change may lead to increased frequency and intensity of weather events and related impacts such as storms, ice storms,
hurricanes, cyclones, heavy rainfall, extreme winds, wildfires, flooding and storm surge. The potential impacts of climate change,
such as rising sea levels and larger storm surges from more intense hurricanes, can combine to produce even greater damage
to coastal generation and other facilities. Climate change is also characterized by rising global temperatures. Increased air
temperatures may bring increased frequency and severity of wildfires within the Company’s service territories. Refer to “Weather
Risk” and “System Operating and Maintenance Risks”.
The Company has made significant investments to facilitate the use of renewable and lower-carbon energy including wind
generation, the Maritime Link in Atlantic Canada, and in Florida, solar generation and modernization of the Big Bend Power
Station. Tampa Electric has taken significant steps to reduce overall emissions at its facilities as a result of its capital investment
plan which has and will continue to reduce carbon dioxide emissions. In 2022, NSPI achieved reductions of carbon dioxide
emissions of approximately 45 per cent from 2005 levels. NSPI expects to exceed the Canadian target of 40-45 per cent
reduction by 2030, as set out in the Canadian Net-Zero Emissions Accountability Act. Both the Government of Nova Scotia and
the Government of Canada have enacted or introduced legislation that includes goals of net-zero GHG emissions by 2050. The
Province of Nova Scotia has established targets with respect to the percentage of renewable energy in NSPI’s generation mix,
reductions in GHG emissions, as well as the goal to phase out coal-fired electricity generation by 2030. Failure to meet such goals
by 2030 could result in material fines, penalties, other sanctions and adverse reputational impacts. NSPI continues to work with
both the provincial and federal governments on measures to seek to address their carbon reduction goals. Future compliance
with provincial and federal GHG emission caps, coal phase out requirements and targets, and renewable standards has been
challenged as a result of the constraints imposed by the enactment of Bill 212, “Public Utilities Act (amended)”. Within Emera’s
natural gas utilities, there are ongoing efforts to reduce methane and carbon dioxide emissions through replacement of aging
infrastructure, more efficient operations, operational and supply chain optimization, and support of public policy initiatives that
address the effects of climate change.
The Company’s long-term capital investment plan includes significant investment across the portfolio in renewable and
cleaner generation, infrastructure modernization, storm hardening, energy storage and customer-focused technologies. All
these initiatives contribute toward mitigating the potential impacts of climate change. The Company continues to engage with
government, regulators, industry partners and stakeholders to share information and participate in the development of climate
change related policies and initiatives.
Physical Impacts
The Company is subject to physical risks that arise, or may arise, from global climate change, including damage to operating
assets from more frequent and intense weather events and from wildfires due to warming air temperatures and increasing
drought conditions. Substantially all of the Company’s fossil fueled generation assets are located at or near coastal sites and, as
such, are exposed to the separate and combined effects of rising sea levels and increasing storm intensity, including storm surges
and flooding. Refer to “Weather Risk” for further information.
48
Management’s Discussion & AnalysisEMERA 2022 ANNUAL REPORT These risks are mitigated to an extent through features such as flood walls at certain plants and through the location of plants
on higher ground. Planned investments in under-grounding parts of the electricity infrastructure contribute to risk mitigation,
as does insurance coverage (for assets other than electricity transmission and distribution assets). In addition, implementation
of regulatory mechanisms for recovery of costs, such as storm reserves and regulatory deferral accounts, help smooth out the
recovery of storm restoration costs over time.
Reputation
Failure to address issues related to climate change could affect Emera’s reputation with stakeholders, its ability to operate and
grow, and the Company’s access to, and cost of, capital. Refer to “Liquidity and Capital Market Risk”. The Company seeks to
mitigate this in part by moving away from higher-carbon generation in favour of lower-carbon generation and non-emitting
renewable generation.
Markets
Changing carbon-related costs, policy and regulatory changes and shifts in supply and demand factors could lead to more
expensive or more scarce products and services that are required by the Company in its operations. This could lead to supply
shortages, delivery delays and the need to source alternate products and services. The Company seeks to mitigate these risks
through close monitoring of such developments and adaptive changes to supply chain procurement strategies.
Given concerns regarding carbon-emitting generation, those assets and businesses may, over time, become difficult (or
uneconomic) to insure in commercial insurance markets. In the short term, this may be mitigated through increased investment
in engineered protection or alternative risk financing (such as funded self-insurance or regulatory structures, including storm
reserves). Longer-term mitigation may be achieved through infrastructure siting decisions and further engineered protections.
This risk may also be mitigated through the continued transition away from high-carbon generation sources to sources with low
or zero carbon dioxide emissions.
Policy
Government and regulatory initiatives, including greenhouse gas emissions standards, air emissions standards and generation
mix standards, are being proposed and adopted in many jurisdictions in response to concerns regarding the effects of climate
change. In some jurisdictions, government policy has included timelines for mandated shutdowns of coal generating facilities,
percentage of electricity generation from renewables, carbon pricing, emissions limits and cap and trade mechanisms. Over
the medium and longer terms, this could potentially lead to a significant portion of hydrocarbon infrastructure assets being
subject to additional regulation and limitations in respect of GHG emissions and operations. The Company is subject to climate-
related and environmental legislative and regulatory requirements. Such legislative and regulatory initiatives could adversely
affect Emera’s operations and financial performance. Refer to “Regulatory and Political Risk” and “Changes in Environmental
Legislation” risk. The Company seeks to mitigate these risks through active engagement with governments and regulators
to pursue transition strategies that meet the needs of customers, stakeholders and the Company. This has included NSPI’s
participation in negotiated equivalency agreements in Nova Scotia to provide for an affordable transition to lower-carbon
generation. Equivalency agreements allow NSPI to achieve compliance with federal GHG emissions regulations by meeting
provincial legislative and regulatory requirements as they are deemed to be equivalent. There is no guarantee that such
equivalency agreements will be renewed or remain in force in the future.
Regulatory
Depending on the regulatory response to government legislation and regulations, the Company may be exposed to the risk
of reduced recovery through rates in respect of the affected assets. Valuation impairments could result from such regulatory
outcomes. Mitigation efforts in respect of these risks include active engagement with policy makers and regulators to find
mechanisms to avoid such impacts while being responsive to customers’ and stakeholders’ objectives.
49
Management’s Discussion & AnalysisEMERA 2022 ANNUAL REPORT Legal
The Company could face litigation or regulatory action related to environmental harms from carbon dioxide emissions or climate
change public disclosure issues. The Company addresses these risks through compliance with all relevant laws, emissions
reduction strategies, and public disclosure of climate change risks.
Water Resources
For thermal plants requiring cooling water, reduced availability of water resulting from climate change could adversely impact
operations or the costs of operations. The Company seeks ways to reduce and recycle water as it does in its Polk power plant
in Florida, where recovered and treated wastewater is used in operations to reduce reliance on fresh water supplies in an area
where water is not as abundant as in other markets.
The Company operates hydroelectric generation in certain of its markets. Such generation depends on availability of water
and the hydrological profile of water sources. Changes in precipitation patterns, water temperatures and air temperatures
could adversely affect the availability of water and consequently the amount of electricity that may be produced from such
facilities. The Company is reinvesting in the efficiency of certain hydroelectric generation facilities to increase generation
capacity and continues to monitor changing hydrology patterns. Such issues may also affect the availability of third-party owned
hydroelectricity purchased power sources.
WEATHER RISK
The Company is subject to risks that arise or may arise from weather including seasonal variations impacting energy sales, more
frequent and intense weather events, changing air temperatures, wildfires and extreme weather conditions associated with
climate change. Refer to “Global Climate Change Risk”.
Fluctuations in the amount of electricity or natural gas used by customers can vary significantly in response to seasonal changes
in weather and could impact the operations, results of operations, financial condition, and cash flows of the Company’s utilities.
For example, Tampa Electric could see lower demand in summer months if temperatures are cooler than expected. Further,
extreme weather conditions such as hurricanes and other severe weather conditions which may be associated with climate
change could cause these seasonal fluctuations to be more pronounced. In the absence of a regulatory recovery mechanism for
unanticipated costs, such events could influence the Company’s results of operations, financial conditions or cash flows.
Extreme weather events create a risk of physical damage to the Company’s assets. High winds can impact structures and cause
widespread damage to transmission and distribution infrastructure, solar generation, and wind powered generation. Increased
frequency and severity of weather events increases the likelihood that the duration of power outages and fuel supply disruptions
could increase. Increased frequency and intensity of flooding and storm surge could adversely affect the operations of utilities
and in particular generation assets. The impact of extreme weather events would be amplified if the same events affect
multiple utilities.
Each of Emera’s regulated electric utilities have programs for storm hardening of transmission and distribution facilities to
minimize damage, but there can be no assurance that these measures will fully mitigate the risk. This risk to transmission
and distribution facilities is typically not insured, and as such the restoration cost is generally recovered through regulatory
processes, either in advance through reserves or designated self-insurance funds, or after the fact through the establishment of
regulatory assets. Recovery is not assured and is subject to prudency review. The risk to generation assets is, in part, mitigated
through the design, siting, construction and maintenance of such facilities, regular risk assessments, engineered mitigation,
emergency storm response plans, and insurance.
The risk of wildfires is addressed primarily through asset management programs for natural gas transmission and distribution
operations, and vegetation management programs for electric transmission and distribution facilities. If it is found to be
responsible for such a fire, the Company could suffer costs, losses and damages, all or some of which may not be recoverable
through insurance, legal, regulatory cost recovery or other processes. If not recovered through these means, they could
materially affect Emera’s business and financial results including its reputation with customers, regulators, governments and
financial markets. Resulting costs could include fire suppression costs, regeneration, timber value, increased insurance costs and
costs arising from damages and losses incurred by third parties.
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Management’s Discussion & AnalysisEMERA 2022 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. Legislative or regulatory changes could influence decisions regarding early retirement of generation facilities
and may result in stranded costs if the Company is not able to fully recover the costs and investment in the affected generation
assets. Recovery is not assured and is subject to prudency review. Legislative or regulatory changes may curtail sales of natural
gas to new customers, which could reduce future customer growth in Emera’s natural gas businesses. Stricter environmental laws
and enforcement of such laws in the future could increase Emera’s exposure to additional liabilities and costs. These changes
could also affect earnings and strategy by changing the nature and timing of capital investments.
In addition to imposing continuing compliance obligations, there are permit requirements, laws and regulations authorizing
the imposition of penalties for non-compliance, including fines, injunctive relief, and other sanctions. The cost of complying
with current and future environmental requirements is, and may be, material to Emera. Failure to comply with environmental
requirements or to recover environmental costs in a timely manner through rates, could have a material adverse effect on Emera.
In addition, Emera’s business could be materially affected by changes in government policy, utility regulation, and environmental
and other legislation that could occur in response to environmental and climate change concerns.
Emera manages its environmental risk by operating in a manner that is respectful and protective of the environment and in
compliance with applicable legal requirements and Company policy. Emera has implemented this policy through the development
and application of environmental management systems in its operating subsidiaries. Comprehensive audit programs are in place
to regularly test compliance.
CYBERSECURITY RISK
Emera is exposed to potential risks related to cyberattacks and unauthorized access. The Company increasingly relies on
IT systems network, and cloud infrastructure to manage its business and safely operate its assets, including controls for
interconnected systems of generation, distribution and transmission as well as financial, billing and other business systems.
Emera also relies on third-party service providers to conduct business. As the Company operates critical infrastructure, it may
be at greater risk of cyberattacks by third parties, which could include nation-state-controlled parties. This risk may be further
elevated by geo-political risks such as the ongoing conflict between Russia and Ukraine.
Cyberattacks can reach the Company’s assets and information via their interfaces with third parties or the public internet and
gain access to critical infrastructures. Cyberattacks can also occur via personnel with direct access to critical assets or trusted
networks. Methods used to attack critical assets could include general purpose or energy-sector-specific malware delivered via
network transfer, removable media, viruses, attachments, or links in e-mails. The methods used by attackers are continuously
evolving and can be difficult to predict and detect.
Despite security measures in place, that are described below, the Company’s systems, assets and information could
experience security breaches that could cause system failures, disrupt operations, or adversely affect safety. Such breaches
could compromise customer, employee-related or other information systems and could result in loss of service to customers,
unavailability of critical assets, safety issues, or the release, destruction, or misuse of critical, sensitive or confidential information.
These breaches could also delay delivery or result in contamination or degradation of hydrocarbon products the Company
transports, stores or distributes.
Cyberattacks or unauthorized accesses may cause costs, losses and damages all, or some of which, may not be recoverable
(through insurance, legal, regulatory cost recovery or other processes). This could materially adversely affect Emera’s business
and financial results including its reputation with customers, regulators, governments and financial markets. Resulting costs
could include, amongst others, response, recovery and remediation costs, increased protection or insurance costs and costs
arising from damages and losses incurred by third parties. If any such security breaches occur, there is no assurance they can be
adequately addressed in a timely manner.
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Management’s Discussion & AnalysisEMERA 2022 ANNUAL REPORT The Company seeks to manage these risks by aligning to a common set of cybersecurity standards and policies derived, in part,
on the National Institute of Standards and Technology’s Cyber Security Framework, periodic security testing, program maturity
objectives, cybersecurity incident readiness program, and employee communication and training. With respect to certain of its
assets, the Company is required to comply with rules and standards relating to cybersecurity and IT including, but not limited to,
those mandated by bodies such as the North American Electric Reliability Corporation, Northeast Power Coordinating Council,
and the United States Department of Homeland Security. The status of key elements of the Company’s cybersecurity program is
reported to the RSC.
PUBLIC HEALTH RISK
An outbreak of infectious disease, a pandemic or a similar public health threat, such as the COVID-19 pandemic, or a fear of any
of the foregoing, could adversely impact the Company, including causing operating, supply chain and project development delays
and disruptions, labour shortages and shutdowns (including as a result of government regulation and prevention measures),
which could have a negative impact on the Company’s operations.
Any adverse changes in general economic and market conditions arising as a result of a public health threat could negatively
impact demand for electricity and natural gas, revenue, operating costs, timing and extent of capital expenditures, results of
financing efforts, or credit risk and counterparty risk; which could result in a material adverse effect on the Company’s business.
The Company maintains pandemic and business contingency plans in each of its operations to manage and help mitigate the
impact of any such public health threat.
ENERGY CONSUMPTION RISK
Emera’s rate-regulated utilities are affected by demand for energy based on changing customer patterns due to fluctuations in
a number of factors including general economic conditions, weather events, customers’ focus on energy efficiency, changes in
rates, and advancements in new technologies such as rooftop solar, electric vehicles and battery storage. Government policies
promoting distributed generation, and new technology developments that enable those policies, have the potential to impact
how electricity enters the system and how it is bought and sold. In addition, increases in distributed generation may impact
demand resulting in lower load and revenues. These changes could negatively impact Emera’s operations, rate base, net earnings,
and cash flows. The Company’s rate-regulated utilities are focused on understanding customer demand, energy efficiency,
and government policy to ensure that the impact of these activities benefit customers, that they do not negatively impact the
reliability of the energy service and that they are addressed through regulations.
FOREIGN EXCHANGE RISK
The Company is exposed to foreign currency exchange rate changes. Emera operates internationally, with an increasing amount
of the Company’s net income earned outside of Canada. As such, Emera is exposed to movements in exchange rates between the
CAD and, particularly, the USD, which could positively or adversely affect results.
Consistent with the Company’s risk management policies, Emera manages currency risks through matching United States
denominated debt to finance its Unites States operations and may use foreign currency derivative instruments to hedge specific
transactions and earnings exposure. The Company may enter FX forward and swap contracts to limit exposure on certain foreign
currency transactions such as fuel purchases, revenue streams and capital expenditures, and on net income earned outside of
Canada. The regulatory framework for the Company’s rate-regulated subsidiaries permits the recovery of prudently incurred
costs, including FX.
The Company does not utilize derivative financial instruments for foreign currency trading or speculative purposes or to hedge
the value of its investments in foreign subsidiaries. Exchange gains and losses on net investments in foreign subsidiaries do not
impact net income as they are reported in Accumulated Other Comprehensive Income (Loss) (“AOCI”) (“AOCL”).
LIQUIDITY AND CAPITAL MARKET RISK
Liquidity risk relates to Emera’s ability to ensure sufficient funds are available to meet its financial obligations. Emera manages
this risk by forecasting cash requirements on a continuous basis to determine whether sufficient funds are available. Liquidity
and capital needs could be financed through internally generated cash flows, asset sales, short-term credit facilities, and ongoing
access to capital markets. The Company reasonably expects liquidity sources to exceed capital needs.
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Management’s Discussion & AnalysisEMERA 2022 ANNUAL REPORT Emera’s access to capital and cost of borrowing is subject to several risk factors, including financial market conditions, market
disruptions and ratings assigned by credit rating agencies. Disruptions in capital markets could prevent Emera from issuing new
securities or cause the Company to issue securities with less than preferred terms and conditions. Emera’s growth plan requires
significant capital investments in PP&E and the risk associated with changes in interest rates could have an adverse effect on the
cost of financing. The Company’s future access to capital and cost of borrowing may be impacted by various market disruptions.
The inability to access cost-effective capital could have a material impact on Emera’s ability to fund its growth plan.
Emera is subject to financial risk associated with changes in its credit ratings. There are a number of factors that rating agencies
evaluate to determine credit ratings, including the Company’s business, its regulatory framework and legislative environment,
political interference in the regulatory process, the ability to recover costs and earn returns, diversification, leverage, liquidity
and increased exposure to climate change-related impacts, including increased frequency and severity of hurricanes and other
severe weather events. A decrease in a credit rating could result in higher interest rates in future financings, increased borrowing
costs under certain existing credit facilities, limit access to the commercial paper market, or limit the availability of adequate
credit support for subsidiary operations. For certain derivative instruments, if the credit ratings of the Company were reduced
below investment grade, the full value of the net liability of these positions could be required to be posted as collateral. Emera
manages these risks by actively monitoring and managing key financial metrics with the objective of sustaining investment grade
credit ratings.
The Company has exposure to its own common share price through the issuance of various forms of stock-based compensation,
which affect earnings through revaluation of the outstanding units every period. The Company uses equity derivatives to reduce
the earnings volatility derived from stock-based compensation.
GENERAL ECONOMIC RISK
The Company has exposure to the macro-economic conditions in North America and in other geographic regions in which Emera
operates. Like most utilities, economic factors such as consumer income, employment and housing affect demand for electricity
and natural gas and, in turn, the Company’s financial results. Adverse changes in general economic conditions and inflation
may impact the ability of customers to afford rate increases arising from increases to fuel, operating, capital, environmental
compliance, and other costs, and therefore could materially affect Emera and its utilities. This may also result in higher credit and
counterparty risk, adverse shifts in government policy and legislation, and/or increased risk to full and timely recovery of costs
and regulatory assets.
Interest Rate Risk
Emera utilizes a combination of fixed and floating rate debt financing for operations and capital expenditures, resulting in an
exposure to interest rate risk. Emera seeks to manage interest rate risk through a portfolio approach that includes the use of
fixed and floating rate debt with staggered maturities. The Company will, from time to time, issue long-term debt or enter interest
rate hedging contracts to limit its exposure to fluctuations in floating interest rate debt.
For Emera’s regulated subsidiaries, the cost of debt is a component of rates and prudently incurred debt costs are recovered
from customers. Regulatory ROE will generally follow the direction of interest rates, such that regulatory ROEs are likely to fall
in times of reducing interest rates and rise in times of increasing interest rates, albeit not directly and generally with a lag period
reflecting the regulatory process. Rising interest rates may also negatively affect the economic viability of project development
and acquisition initiatives.
As with most other utilities and other similar yield-returning investments, Emera’s share price may be affected by changes in
interest rates and could underperform the market in an environment of rising interest rates.
Inflation Risk
The Company may be exposed to changes in inflation that may result in increased operating and maintenance costs, capital
investment, and fuel costs compared to the revenues provided by customer rates. Emera’s utilities have budgeting and
forecasting processes to identify inflationary risk factors and measure operating performance, as well as collective bargaining
agreements that mitigate the short-term impact of inflation on labour costs.
53
Management’s Discussion & AnalysisEMERA 2022 ANNUAL REPORT PROJECT DEVELOPMENT AND LAND USE RIGHTS RISK
The Company’s capital plan includes significant investment in generation, infrastructure modernization, and customer-focused
technologies. Any projects planned or currently in construction, particularly significant capital projects, may be subject to risks
including, but not limited to, impact on costs from schedule delays, risk of cost overruns, ensuring compliance with operating and
environmental requirements and other events within or beyond the Company’s control. The Company’s projects may also require
approvals and permits at the federal, provincial, state, regional and local levels. There is no assurance that Emera will be able to
obtain the necessary project approvals or applicable permits or receive regulatory approval to recover the costs in rates.
Some of the Company’s assets are located on land owned by third parties, including Indigenous Peoples, and may be subject to
land claims. Present or future assets may be located on lands that have been used for traditional purposes and therefore subject
to specific consultations, consents, or conditions for development or operation. If the Company’s rights to locate and operate its
assets on any such lands are subject to expiry or become invalid, it may incur material costs to renew rights or obtain such rights.
If reasonable terms for land-use rights cannot be negotiated, the Company may incur significant costs to remove and relocate its
assets and restore the land. Additional costs incurred could cause projects to be uneconomical to proceed with.
Emera manages these project development and land use rights risks by deploying robust project and risk management
approaches, led by teams with extensive experience in large projects. The Company consults with Indigenous Peoples in
obtaining approvals, constructing, maintaining and operating such facilities, consistent with laws and public policy frameworks.
Emera maintains relationships through on-going communications with stakeholders, including Indigenous Peoples, landowners
and governments.
COUNTERPARTY RISK
Emera is exposed to risk related to its reliance on certain key partners, suppliers, and customers, any of which may endure
financial challenges resulting from commodity price and market volatility, economic instability or adversity, adverse political
or regulatory changes and other causes which may cause or contribute to such parties’ insolvency, bankruptcy, restructuring
or default on their contractual obligations to Emera. Emera is also exposed to potential losses related to amounts receivable
from customers, energy marketing collateral deposits and derivative assets due to a counterparty’s non-performance under
an agreement.
Emera manages this counterparty risk through due diligence and third-party risk assessment processes prior to signing
contracts, contractual rights and remedies, regulatory frameworks, and by monitoring significant developments with its
customers, partners and suppliers. The Company also manages credit risk with policies and procedures for counterparty analysis,
exposure measurement, and exposure monitoring and mitigation. Credit assessments may be conducted on new customers
and counterparties, and deposits or collateral may be requested on certain accounts. There is no assurance that management
strategies will be effective, and significant counterparty defaults could have a material effect on the Company.
COUNTRY RISK
The majority of Emera’s earnings are from outside of Canada, mostly concentrated in the United States. Emera’s investments are
currently in regions where political and economic risks are considered by the Company to be acceptable. For more information,
refer to the “Regulatory and Political Risk” and “General Economic Risk” sections above. Emera’s operations in some countries
may be subject to changes in economic growth, restrictions on the repatriation of income or capital exchange controls, inflation,
the effect of global health, safety and environmental matters, including climate change, or economic conditions and market
conditions, and change in financial policy and availability of credit. The Company mitigates this risk through a rigorous approval
process for investment, and by forecasting cash requirements on a continuous basis to determine whether sufficient funds are
available in all affiliates.
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Management’s Discussion & AnalysisEMERA 2022 ANNUAL REPORT COMMODITY PRICE RISK
The Company’s utility fuel supply is subject to commodity price risk. In addition, Emera Energy is subject to commodity price risk
through its portfolio of commodity contracts and arrangements.
The Company manages this risk through established processes and practices to identify, monitor, report and mitigate these risks.
These include the Company’s commercial arrangements, such as the combination of supply and purchase agreements, asset
management agreements, pipeline transportation agreements, and financial hedging instruments. In addition, its credit policies,
counterparty credit assessments, market and credit position reporting, and other risk management and reporting practices, are
also used to manage and mitigate this risk.
Regulated Utilities
The Company’s utility fuel supply is exposed to broader global conditions, which may include impacts on delivery reliability and
price, despite contracted terms. Supply and demand dynamics in fuel markets can be affected by a wide range of factors which
are difficult to predict and may change rapidly, including but not limited to, currency fluctuations, changes in global economic
conditions, natural disasters, transportation or production disruptions, and geo-political risks, such as political instability,
conflicts, changes to international trade agreements, trade sanctions or embargos. The Company seeks to manage this risk using
financial hedging instruments and physical contracts and through contractual protection with counterparties, where applicable.
The majority of Emera’s regulated electric and gas utilities have adopted and implemented fuel adjustment mechanisms and
purchased gas adjustment mechanisms respectively, which further helps manage commodity price risk, as the regulatory
framework for the Company’s rate-regulated subsidiaries permits the recovery of prudently incurred fuel and gas costs. There
is no assurance that such mechanisms and regulatory frameworks will continue to exist in the future. Prolonged and substantial
increases in fuel prices could result in decreased rate affordability, increased risk of recovery of costs or regulatory assets, and/or
negative impacts on customer consumption patterns and sales.
Emera Energy Marketing and Trading
Emera Energy has employed further measures to manage commodity risk. The majority of Emera Energy’s portfolio of electricity
and gas marketing and trading contracts and, in particular, its natural gas asset management arrangements, are contracted on
a back-to-back basis, avoiding any material long or short commodity positions. However, the portfolio is subject to commodity
price risk, particularly with respect to basis point differentials between relevant markets in the event of an operational issue or
counterparty default. Changes in commodity prices can also result in increased collateral requirements associated with physical
contracts and financial hedges, resulting in higher liquidity requirements and increased costs to the business.
To measure commodity price risk exposure, Emera Energy employs a number of controls and processes, including an estimated
VaR analysis of its exposures. The VaR amount represents an estimate of the potential change in fair value that could occur from
changes in Emera Energy’s portfolio or changes in market factors within a given confidence level, if an instrument or portfolio
is held for a specified time period. The VaR calculation is used to quantify exposure to market risk associated with physical
commodities, primarily natural gas and power positions.
FUTURE EMPLOYEE BENEFIT PLAN PERFORMANCE AND FUNDING RISK
Emera subsidiaries have both defined benefit and defined contribution employee pension plans that cover their employees and
retirees. All defined benefit plans are closed to new entrants, except for the TECO Energy Group Retirement Plan. The cost of
providing these benefit plans varies depending on plan provisions, interest rates, inflation, investment performance and actuarial
assumptions concerning the future. Actuarial assumptions include earnings on plan assets, discount rates (interest rates used
to determine funding levels, contributions to the plans and the pension and post-retirement liabilities) and expectations around
future salary growth, inflation and mortality. Three of the largest drivers of cost are investment performance, interest rates and
inflation, which are affected by global financial and capital markets. Depending on future interest rates and future inflation and
actual versus expected investment performance, Emera could be required to make larger contributions in the future to fund
these plans, which could adversely affect Emera’s cash flows, financial condition and operations.
Each of Emera’s employee defined benefit pension plans are managed according to an approved investment policy and
governance framework. Emera employs a long-term approach with respect to asset allocation and each investment policy outlines
the level of risk which the Company is prepared to accept with respect to the investment of the pension funds in achieving both
the Company’s fiduciary and financial objectives. Studies are routinely undertaken approximately every five years with the
objective that the plans’ asset allocations are appropriate for meeting Emera’s long-term pension objectives.
55
Management’s Discussion & AnalysisEMERA 2022 ANNUAL REPORT LABOUR RISK
Emera’s ability to deliver service to its customers and to execute its growth plan depends on attracting, developing and
retaining a skilled workforce. Utilities are faced with demographic challenges related to trades, technical staff and engineers
with an increasing number of employees expected to retire over the next several years. Failure to attract, develop and retain
an appropriately qualified workforce could adversely affect the Company’s operations and financial results. Emera seeks to
manage this risk through maintaining competitive compensation programs, a dedicated talent acquisition team, human resources
programs and practices, including ethics and diversity training, employee engagement surveys, succession planning for key
positions and apprenticeship programs.
Approximately 32 per cent of Emera’s labour force is represented by unions and subject to collective labour agreements. The
inability to maintain or negotiate future agreements on acceptable terms could result in higher labour costs and work disruptions,
which could adversely affect service to customers and have an adverse effect on the Company’s earnings, cash flow and financial
position. Emera seeks to manage this risk through ongoing discussions and working to maintain positive relationships with local
unions. The Company maintains contingency plans in each of its operations to manage and reduce the effect of any potential
labour disruption.
IT RISK
Emera relies on various IT systems to manage operations. This subjects Emera to inherent costs and risks associated with
maintaining, upgrading, replacing and changing these systems. This includes impairment of its IT, potential disruption of
internal control systems, substantial capital expenditures, demands on management time and other risks of delays, difficulties
in upgrading existing systems, transitioning to new systems or integrating new systems into its current systems. Emera’s digital
transformation strategy, including investment in infrastructure modernization and customer focused technologies, is driving
increased investment in IT solutions, resulting in increased project risks associated with the implementation of these solutions.
Emera manages these risks through IT asset lifecycle planning and management, governance, internal auditing and testing of
systems, and executive oversight. Employees with extensive subject matter expertise assist in risk identification and mitigation,
project management, implementation, change management and training. System resiliency, formal disaster recovery and
backup processes, combined with critical incident response practices, table-top exercises, and simulations, help mitigate
operational disruptions.
INCOME TAX RISK
The computation of the Company’s provision for income taxes is impacted by changes in tax legislation in Canada, the
United States and the Caribbean. Any such changes could affect the Company’s future earnings, cash flows, and financial
position. The value of Emera’s existing deferred tax assets and liabilities are determined by existing tax laws and could be
negatively impacted by changes in laws. Emera monitors the status of existing tax laws to ensure that changes impacting the
Company are appropriately reflected in the Company’s tax compliance filings and financial results.
SYSTEM OPERATING AND MAINTENANCE RISKS
The safe and reliable operation of electric generation and electric and natural gas transmission and distribution systems is
critical to Emera’s operations. There are a variety of hazards and operational risks inherent in operating electric utilities and
natural gas transmission and distribution pipelines. Electric generation, transmission and distribution operations can be impacted
by risks such as mechanical failures, supply chain issues impacting timely access to critical equipment, activities of third parties,
terrorism, cyberattacks, damage to facilities, solar panels and infrastructure caused by hurricanes, storms, falling trees, lightning
strikes, floods, fires and other natural disasters. Natural gas pipeline operations can also be impacted by risks such as leaks,
explosions, mechanical failures, activities of third parties, terrorism, cyberattacks, and damage to the pipeline facilities and
equipment caused by hurricanes, storms, floods, fires and other natural disasters. Refer to “Global Climate Change Risk” and
“Weather Risk”. Electric utility and natural gas transmission and distribution pipeline operation interruption could negatively
affect revenue, earnings, and cash flows as well as customer and public confidence, and public safety.
Emera manages these risks by investing in a highly skilled workforce, operating prudently, preventative maintenance, safety and
operations management systems, third-party risk program, and making effective capital investments. Insurance, warranties, or
recovery through regulatory mechanisms may not cover any or all these losses, which could adversely affect the Company’s
results of operations and cash flows.
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Management’s Discussion & AnalysisEMERA 2022 ANNUAL REPORT Fuel Supply Disruptions
Emera’s electric and natural gas utilities are also exposed to the risk of fuel supply chain disruptions, both within and outside
their service territories, which may be caused by severe weather or natural disasters. This may also be caused by damage to,
operational issues with, terrorist or cyberattacks on, third party fuel production, storage, pipeline, and distribution facilities.
The risk of fuel supply disruptions is managed through contractual protections, maintaining a diversity of fuel suppliers and
transportation contracts, and contracting for access to third-party storage facilities. Significant unanticipated fuel supply
disruptions, such as those which arose from Winter Storm Uri in February 2021, could result in increased exposure to commodity
price risk for Emera’s regulated electric and gas utilities and Emera Energy, and these could have adverse effects on service to
utility customers and on the Company’s reputation, earnings, cash flow and financial position.
UNINSURED RISK
Emera and its subsidiaries maintain insurance to cover accidental loss suffered to its facilities and to provide indemnity in the
event of liability to third parties. This is consistent with Emera’s risk management policies. Certain facilities, in particular coal
and other thermal generation, may, over time, become more difficult (or uneconomic) to insure as a result of the impact of global
climate change. Refer to “Global Climate Change Risk – Markets”. There are certain elements of Emera’s operations which are
not insured. These include a significant portion of its electric utilities’ transmission and distribution assets, as is customary in the
industry. The cost of this coverage is not economically viable. In addition, Emera accepts deductibles and self-insured retentions
under its various insurance policies. Insurance is subject to coverage limits as well as time sensitive claims discovery and
reporting provisions and there can be no assurance that the types of liabilities or losses that may be incurred by the Company
and its subsidiaries will be covered by insurance.
The occurrence of significant uninsured claims, claims in excess of the insurance coverage limits maintained by Emera and its
subsidiaries, or claims that fall within a significant self-insured retention could have a material adverse effect on Emera’s results
of operations, cash flows and financial position, if regulatory recovery is not available.
The Company mitigates its uninsured risk by ensuring insurance limits align with risk exposures, and for uninsured assets and
operations, that appropriate risk assessments and mitigation measures are in place. The regulatory framework for the Company’s
rate-regulated subsidiaries permits the recovery of prudently incurred costs, including uninsured losses.
Risk Management including Financial Instruments
Emera’s risk management policies and procedures provide a framework through which management monitors various risk
exposures. The risk management policies and practices are overseen by the Board of Directors. The Company has established
a number of processes and practices to identify, monitor, report on and mitigate material risks to the Company. This includes
establishment of the ERMC, whose responsibilities include preparing an updated risk dashboard and heat map presented at
regular meetings of the Board’s Risk and Sustainability Committee. Furthermore, a corporate team independent from operations
is responsible for tracking and reporting on market and credit risks.
The Company manages its exposure to normal operating and market risks relating to commodity prices, FX, interest rates and
share prices through contractual protections with counterparties where practicable, and by using financial instruments consisting
mainly of FX forwards and swaps, interest rate options and swaps, equity derivatives, and coal, oil and gas futures, options,
forwards and swaps. In addition, the Company has contracts for the physical purchase and sale of natural gas. These physical
and financial contracts are classified as held-for-trading (“HFT”). Collectively, these contracts and financial instruments are
considered derivatives.
The Company recognizes the fair value of all its derivatives on its balance sheet, except for non-financial derivatives that meet
the normal purchases and normal sales (“NPNS”) exception. Physical contracts that meet the NPNS exception are not recognized
on the balance sheet; these contracts are recognized in income when they settle. A physical contract generally qualifies for the
NPNS exception if the transaction is reasonable in relation to the Company’s business needs, the counterparty owns or controls
resources within the proximity to allow for physical delivery, the Company intends to receive physical delivery of the commodity,
and the Company deems the counterparty creditworthy. The Company continually assesses contracts designated under the NPNS
exception and will discontinue the treatment of these contracts under this exemption where the criteria are no longer met.
57
Management’s Discussion & AnalysisEMERA 2022 ANNUAL REPORT Derivatives qualify for hedge accounting if they meet stringent documentation requirements and can be proven to effectively
hedge the identified risk both at the inception and over the term of the instrument. Specifically, for cash flow hedges, the change
in the fair value of derivatives is deferred to AOCI and recognized in income in the same period the related hedged item is
realized. Where the documentation or effectiveness requirements are not met, the derivatives are recognized at fair value with
any changes in fair value recognized in net income in the reporting period, unless deferred as a result of regulatory accounting.
Derivatives entered into by NSPI, NMGC and GBPC that are documented as economic hedges or for which the NPNS exception
has not been taken, are subject to regulatory accounting treatment. The change in fair value of the derivatives is deferred to
a regulatory asset or liability. The gain or loss is recognized in the hedged item when the hedged item is settled. Management
believes any gains or losses resulting from settlement of these derivatives related to fuel for generation and purchased power
will be refunded to or collected from customers in future rates. Tampa Electric has no derivatives related to hedging as a result of
a FPSC approved five-year moratorium on hedging of natural gas purchases which ended on December 31, 2022. Tampa Electric’s
moratorium on hedging of natural gas purchases will continue through December 31, 2024, as a result of Tampa Electric’s 2021
rate case settlement agreement.
Derivatives that do not meet any of the above criteria are designated as HFT, with changes in fair value normally recorded in
net income of the period. The Company has not elected to designate any derivatives to be included in the HFT category where
another accounting treatment would apply.
DERIVATIVE ASSETS AND LIABILITIES RECOGNIZED ON THE BALANCE SHEET
As at
millions of dollars
Regulatory Deferral:
Derivative instrument assets (1 )
Derivative instrument liabilities (2)
Regulatory assets (1 )
Regulatory liabilities (2)
Net asset (liability)
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.
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 (losses)
December 31
2022
December 31
2021
$ 238
$ 237
(25)
30
(230)
13
$
$
(20)
23
(241)
(1)
$ 153
$
(1,025)
$
(872) $
53
(662)
(609)
$
5
(28)
$
11
–
$
(23) $
11
Year ended
December 31
2021
2022
$
210
$
34
$
64
$
(138)
$
(22) $
(24)
$
$
(46) $
$
228
26
3
29
(75)
(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.
58
Management’s Discussion & AnalysisEMERA 2022 ANNUAL REPORT
As of December 31, 2022, the unrealized gain in AOCI was $16 million, net of tax (2021 – $18 million, net of tax). For the year ended
December 31, 2022, unrealized gains of $2 million (2021 – $1 million), have been reclassified into interest expense.
Disclosure and Internal Controls
Management is responsible for establishing and maintaining adequate disclosure controls and procedures (“DC&P”) and
internal control over financial reporting (“ICFR”), as defined in National Instrument 52-109 Certification of Disclosure in Issuers’
Annual and Interim Filings (“NI 52-109”). The Company’s internal control framework is based on the criteria published in the
Internal Control – Integrated Framework (2013), a report issued by the Committee of Sponsoring Organizations (“COSO”) of the
Treadway Commission. Management, including the Chief Executive Officer and Chief Financial Officer, evaluated the design and
effectiveness of the Company’s DC&P and ICFR as at December 31, 2022 to provide reasonable assurance regarding the reliability
of financial reporting in accordance with USGAAP.
Management recognizes the inherent limitations in internal control systems, no matter how well designed. Control systems
determined to be appropriately designed can only provide reasonable assurance with respect to the reliability of financial
reporting and may not prevent or detect all misstatements.
There were no changes in the Company’s ICFR, during the year ended December 31, 2022, that have materially affected, or are
reasonably likely to materially affect, the Company’s internal control over financial reporting.
Critical Accounting Estimates
The preparation of consolidated financial statements in accordance with USGAAP requires management to make estimates and
assumptions. These may affect the reported amounts of assets and liabilities at the date of the financial statements and reported
amounts of revenues and expenses during the reporting periods. Significant areas requiring use of management estimates
relate to rate-regulated assets and liabilities, accumulated reserve for cost of removal, pension and post-retirement benefits,
unbilled revenue, useful lives for depreciable assets, goodwill and long-lived assets impairment assessments, income taxes, asset
retirement obligations (“ARO”), and valuation of financial instruments. Management evaluates the Company’s estimates on an
ongoing basis based upon historical experience, current and expected conditions and assumptions believed to be reasonable at
the time the assumption is made, with any adjustments recognized in income in the year they arise.
RATE REGULATION
The rate-regulated accounting policies of Emera’s rate-regulated subsidiaries and regulated equity investments are subject
to examination and approval by their respective regulators and may differ from the accounting policies of non-rate-regulated
companies. Differences occur when regulators render their decisions on rate applications or other matters, and generally involve
a difference in the timing of revenue and expense recognition. The accounting for these items is based on expectations of the
future actions of the regulators. Assumptions and judgments used by regulatory authorities continue to have an impact on the
recovery of costs, the rate earned on invested capital, and the timing and amount of assets to be recovered. The application of
regulatory accounting guidance is a critical accounting policy as a change in these assumptions may result in a material impact
on reported assets, liabilities and the results of operations.
As at December 31, 2022, the Company has recorded $3,620 million (2021 – $2,566 million) of regulatory assets and
$2,273 million (2021 – $2,055 million) of regulatory liabilities.
ACCUMULATED RESERVE – COST OF REMOVAL
Tampa Electric, PGS, NMGC and NSPI recognize non-ARO costs of removal (“COR”) as regulatory liabilities. The non-ARO COR
represent estimated funds received from customers through depreciation rates to cover future COR of PP&E upon retirement
that are not legally required. The companies accrue for COR over the life of the related assets based on depreciation studies
approved by their respective regulators. The costs are estimated based on historical experience and future expectations,
including expected timing and estimated future cash outlays. As at December 31, 2022, the balance of the Accumulated reserve –
COR within regulatory liabilities was $895 million (2021 – $819 million).
59
Management’s Discussion & AnalysisEMERA 2022 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.
The pension plan assets are comprised primarily of equity and fixed income investments. Fluctuations in actual equity market
returns and changes in interest rates may result in changes to pension costs in future periods.
The Company’s accounting policy is to amortize the net actuarial gain or loss that exceeds 10 per cent of the greater of the
projected benefit obligation / accumulated post-retirement benefit obligation (“PBO”) and the market-related value of assets,
over active plan members’ average remaining service period. For the largest plans this is currently 8.3 years (8.7 years for 2022
benefit cost) for the Canadian plans and a weighted average of 11.4 years for the United States plans). The Company’s use of
smoothed asset values reduces volatility related to the amortization of actuarial investment experience. As a result, the main
cause of volatility in reported pension cost is the discount rate used to determine the PBO.
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)
TECO Energy Group Benefit Restoration Plan (1)
TECO Energy Post-retirement Health and
Welfare Plan
New Mexico Gas Company Retiree Medical Plan
NSPI
GBPC Salaried
GBPC Union
Discount rate
for benefit
cost purposes
2022
Expected
return on
plan assets
2.78%
6.50%
2.35/5.33%
2.27/4.19/5.48%
2.84%
2.85%
3.25%, 3.48%
5.75%
5.75%
N/A
N/A
N/A
1.50%
5.75%
6.00%
5.35%
Discount rate
for benefit
cost purposes
2.38%
1.84%
1.71%
2.47%
2.49%
2.59%, 2.85%
4.25%
5.65%
2021
Expected
return on
plan assets
6.70%
N/A
N/A
N/A
4.00%
5.25%
6.00%
5.65%
(1) The discount rate and expected return on assets for benefit cost purposes is updated throughout the year as special events occur, such as settlements
and curtailments.
Based on management’s estimate, the reported benefit cost for defined benefit and defined contribution plans was $64 million in
2022 (2021 – $85 million). The reported benefit cost is impacted by numerous assumptions, including the discount rate and asset
return assumptions. A 0.25 per cent change in the discount rate and asset return assumptions would have had +/- impact on the
2022 benefit cost of $0.5 million and $1 million respectively (2021 – $1 million and $3 million).
UNBILLED REVENUE
Electric and gas revenues are billed on a systematic basis over a one or two-month period for NSPI and a one-month period for
other Emera utilities. At the end of each month, the Company must make an estimate of energy delivered to customers since the
date their meter was last read and determine related revenues earned but not yet billed. The unbilled revenue is estimated based
on several factors, including current month’s generation, estimated customer usage by class, weather, line losses, inter-period
changes to customer classes and applicable customer rates. Based on the extent of estimates included in the determination
of unbilled revenue, actual results may differ from the estimate. At December 31, 2022, unbilled revenues totalled $424 million
(2021 – $318 million) on total regulated operating revenues of $7,154 million (2021 – $5,926 million).
60
Management’s Discussion & AnalysisEMERA 2022 ANNUAL REPORT PROPERTY, PLANT AND EQUIPMENT
PP&E represents 58 per cent of total assets on the Company’s balance sheet and include the generation, transmission and
distribution, and other assets of the Company.
Depreciation is determined by the straight-line method, based on the estimated remaining service lives of the depreciable assets
in each category. The service lives of regulated PP&E are determined based on depreciation studies and require appropriate
regulatory approval. Due to the magnitude of the Company’s PP&E, changes in estimated depreciation rates can have a material
impact on depreciation expense and accumulated depreciation.
Depreciation expense was $927 million for the year ended December 31, 2022 (2021 – $877 million).
GOODWILL IMPAIRMENT ASSESSMENTS
Goodwill is calculated as the excess of the purchase price of an acquired entity over the estimated fair values of identifiable
assets acquired, and liabilities assumed at the acquisition date. Goodwill is carried at initial cost less any write-down for
impairment and is adjusted for the impact of foreign exchange. Under the applicable accounting guidance, goodwill is subject
to assessment for impairment at the reporting unit level annually, or if an event or change in circumstances indicates that the
fair value of a reporting unit may be below its carrying value. Application of the goodwill impairment test requires management
judgment on significant assumptions and estimates. When assessing goodwill for impairment, the Company has the option of first
performing a qualitative assessment to determine whether a quantitative assessment is necessary. In performing a qualitative
assessment management considers, among other factors, macroeconomic conditions, industry and market considerations and
overall financial performance.
If the Company performs the qualitative assessment and determines that it is more likely than not that its fair value is less than
its carrying amount, or if the Company chooses to bypass the qualitative assessment, a quantitative test is performed. The
quantitative test compares the fair value of the reporting unit to its carrying amount, including goodwill. If the carrying amount
of the reporting unit exceeds its fair value, an impairment loss is recorded. Significant assumptions used in estimating the fair
value include discount and growth rates, rate case assumptions including future cost of capital, valuation of the reporting units’
net operating loss (“NOL”) and projected operating and capital cash flows. Adverse changes in these assumptions could result in
a future material impairment of the goodwill assigned to Emera’s reporting units.
As of December 31, 2022, $6,009 million of Emera’s goodwill represents the excess of the acquisition purchase price for TECO
Energy (Tampa Electric, PGS and NMGC reporting units) over the fair values assigned to identifiable assets acquired and liabilities
assumed. In Q4 2022, qualitative assessments were performed for Tampa Electric and PGS given the significant excess of fair
value over carrying amounts calculated during the last quantitative test in Q4 2019. Management concluded it was more likely
than not that the fair value of these reporting units exceeded their respective carrying amounts, including goodwill. As such, no
quantitative testing was required. For the NMGC reporting unit, Emera elected to bypass a qualitative assessment and performed
a quantitative impairment assessment using a combination of the income and market approach. This assessment estimated that
the fair value of the NMGC reporting unit exceeded its carrying amount, including goodwill. As a result of this assessment, no
impairment charges were recognized.
In Q4 2022, the Company elected to bypass a qualitative assessment and performed a quantitative impairment assessment
for GBPC, using the income approach, as this reporting unit is sensitive to changes in assumptions due to limited excess of fair
value over the carrying value, including goodwill. Although the cash flows of GBPC have not changed significantly compared to
previous periods, it was determined that the carrying value, including goodwill, exceeded the fair value, due to an increase in
discount rates. The discount rate for the reporting unit was negatively impacted by changes in the macro-economic environment,
including the risk-free rate assumption. As a result of this assessment, a goodwill impairment charge of $73 million was recorded
in 2022, reducing the GBPC goodwill balance to nil as at December 31, 2022. No impairment was recorded in 2021. For further
detail, refer to note 22.
As of December 31, 2022, the Company had goodwill with a total carrying amount of $6,012 million (December 31, 2021 –
$5,696 million). The change in the carrying value of goodwill from 2021 to 2022 was a result of the effect of the FX translation
of Emera’s foreign affiliates, partially offset by the GBPC impairment.
61
Management’s Discussion & AnalysisEMERA 2022 ANNUAL REPORT LONG-LIVED ASSETS IMPAIRMENT ASSESSMENTS
In accordance with accounting guidance for long-lived assets, the Company assesses whether there has been an impairment of
long-lived assets and intangibles when a triggering event occurs, such as a significant market disruption or the sale of a business.
The assessment involves comparing the undiscounted expected future cash flows, to the carrying value of the asset. When the
undiscounted cash flow analysis indicates a long-lived asset is not recoverable, the amount of the impairment loss is determined by
measuring the excess of the carrying amount of the long-lived asset over its estimated fair value.
The Company believes accounting estimates related to asset impairments are critical estimates, as they are highly susceptible
to change and the impact of an impairment on reported assets and earnings could be material. Management is required to
make assumptions based on expectations regarding the results of operations for significant/indefinite future periods and the
current and expected market conditions in such periods. Markets can experience significant uncertainties. Estimates based on
the Company’s assumptions relating to future results of operations or other recoverable amounts are based on a combination of
historical experience, fundamental economic analysis, observable market activity and independent market studies. The Company’s
expectations regarding uses and holding periods of assets are based on internal long-term budgets and projections, which consider
external factors and market forces, as of the end of each reporting period. Assumptions made by management are consistent with
generally accepted industry approaches and assumptions used for valuation and pricing activities.
As at December 31, 2022, there were no indications of impairment of Emera’s long-lived assets. No impairment charges were
recognized in either 2022 or 2021.
INCOME TAXES
Income taxes are determined based on the expected tax treatment of transactions recorded in the consolidated financial
statements. In determining income taxes, tax legislation is interpreted in a variety of jurisdictions, the likelihood that deferred tax
assets will be realized is assessed and assumptions about the expected timing of the reversal of deferred tax assets and liabilities
are made. Uncertainty associated with application of tax statutes and regulations and the outcomes of tax audits and appeals,
requires that judgments and estimates be made in the accrual process and in the calculation of effective tax rates. Only income
tax benefits that meet the “more likely than not” threshold may be recognized or continue to be recognized. Unrecognized tax
benefits are evaluated quarterly and changes are recorded based on new information, including issuance of relevant guidance by
the courts or tax authorities and developments in examinations of the Company’s tax returns.
The Company believes the accounting estimates related to income taxes are critical estimates. The realization of deferred tax
assets is dependent upon the generation of sufficient taxable income, both operating and capital, in future periods. A change
in the estimated valuation allowance could have a material impact on reported assets and results of operations. Administrative
actions of the tax authorities, changes in tax law or regulation, and the uncertainty associated with the application of tax statutes
and regulations, could change the Company’s estimate of income taxes, including the potential for elimination or reduction of the
Company’s ability to realize tax benefits and to utilize deferred tax assets.
ASSET RETIREMENT OBLIGATIONS
Measurement of the fair value of AROs requires the Company to make reasonable estimates concerning the method and timing
of settlement associated with the legally obligated costs. There are uncertainties in estimating future asset-retirement costs
due to potential events, such as changing legislation or regulations, and advances in remediation technologies. Emera has AROs
associated with the remediation of generation, transmission, distribution and pipeline assets.
An ARO represents the fair value of the estimated cash flows necessary to discharge the future obligation using the Company’s
credit-adjusted risk-free rate. The amounts are reduced by actual expenditures incurred. Estimated future cash flows are
based on completed depreciation studies, remediation reports, prior experience, estimated useful lives, and governmental
regulatory requirements. The present value of the liability is recorded and the carrying amount of the related long-lived asset
is correspondingly increased. The amount capitalized at inception is depreciated in the same manner as the related long-lived
asset. Over time, the liability is accreted to its estimated future value. Accretion expense is included as part of “Depreciation and
amortization expense”. Any accretion expense not yet approved by the regulator is recorded in “PP&E” and included in the next
depreciation study. Accordingly, changes to the ARO or cost recognition attributable to changes in the factors discussed above,
should not impact the results of operations of the Company.
62
Management’s Discussion & AnalysisEMERA 2022 ANNUAL REPORT Some of the Company’s transmission and distribution assets may have conditional AROs which are not recognized in the
consolidated financial statements as the fair value of these obligations could not be reasonably estimated given there is
insufficient information to do so. A conditional ARO refers to a legal obligation to perform an asset retirement activity in which
the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity.
Management monitors these obligations and a liability is recognized at fair value when an amount can be determined.
As at December 31, 2022, AROs recorded on the balance sheet were $174 million (2021 – $174 million). The Company estimates the
undiscounted amount of cash flow required to settle the obligations is approximately $429 million (2021 – $422 million), which will
be incurred between 2023 and 2061. The majority of these costs will be incurred between 2028 and 2050.
FINANCIAL INSTRUMENTS
The Company is required to determine the fair value of all derivatives except those which qualify for the normal purchase, normal
sale exception. Fair value is the price that would be received for the sale of an asset or paid to transfer a liability in an orderly
arms-length transaction between market participants at the measurement date. Fair value measurements are required to reflect
assumptions that market participants would use in pricing an asset or liability based on the best available information, including
the risks inherent in a particular valuation technique, such as a pricing model, and the risks inherent in the inputs to the model.
LEVEL DETERMINATIONS AND CLASSIFICATIONS
The Company uses Level 1, 2, and 3 classifications in the fair value hierarchy. The fair value measurement of a financial
instrument is included in only one of the three levels and is based on the lowest level input significant to the derivation of the fair
value. Fair values are determined, directly or indirectly, using inputs that are observable for the asset or liability. Only in limited
circumstances does the Company enter into commodity transactions involving non-standard features where market observable
data is not available or have contract terms that extend beyond five years.
Changes in Accounting Policies and Practices
The new USGAAP accounting policy that is applicable to, and adopted by the Company in 2022, is described as follows:
FACILITATION OF THE EFFECTS OF REFERENCE RATE REFORM ON FINANCIAL REPORTING
The Company adopted Accounting Standard Update (“ASU”) 2022-06, Reference Rate Reform (Topic 848): Deferral of the
Sunset Date of Topic 848 in Q4 2022. The update extends the period of time preparers can utilize the reference rate reform
relief guidance issued under ASU 2020-04, which was adopted by the Company in Q4 2020. The guidance in ASU 2022-06 was
effective as of the date of issuance and entities may elect to apply the guidance prospectively through to December 31, 2024. The
Company has applied the guidance permitted by ASU 2020-04 to certain debt agreements that were amended during the current
period. The Company’s transition from reference rates will not have a material impact on the consolidated financial statements.
Future Accounting Pronouncements
The Company considers the applicability and impact of all ASUs issued by the Financial Accounting Standards Board (“FASB”).
ASUs issued by FASB, but which are not yet effective, were assessed and determined to be either not applicable to the Company
or to have an insignificant impact on the consolidated financial statements.
63
Management’s Discussion & AnalysisEMERA 2022 ANNUAL REPORT Management’s Discussion & Analysis
Summary of Quarterly Results
For the quarter ended
millions of dollars
(except per share amounts)
Operating revenues
Net income (loss) attributable to
common shareholders
Adjusted net income
EPS – basic
EPS – diluted
Adjusted EPS – basic
Q4
2022
Q3
2022
Q2
2022
Q1
2022
Q4
2021
Q3
2021
Q2
2021
Q1
2021
$ 2,358
$ 1,835
$ 1,380
$ 2,015
$ 1,868
$ 1,148
$ 1,137
$ 1,612
$ 483
$ 249
$ 1.80
$ 1.80
$ 0.93
$ 167
$ 203
$ 0.63
$ 0.63
$ 0.76
(67) $ 362
$
$ 156
$ 242
$ (0.25) $ 1.38
$ (0.25) $ 1.38
$ 0.92
$ 0.59
$ 324
$ 168
$ 1.24
$ 1.20
$ 0.64
(70) $
175
(17) $ 273
$
$
$ 243
$ 137
$ (0.27) $ (0.07) $ 1.08
$ (0.27) $ (0.07) $ 1.08
$ 0.96
$ 0.54
$ 0.68
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 2022 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 23, 2023
“Scott Balfour”
President and Chief Executive Officer
“Gregory Blunden”
Chief Financial Officer
65
EMERA 2022 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, 2022 and 2021, 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, 2022 and 2021, 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 7 of the consolidated financial statements, the Company has $3.6 billion in regulatory
assets and $2.3 billion in regulatory liabilities. The Company’s rate-regulated subsidiaries are subject to
regulation by various federal, state and provincial regulatory authorities in the geographic regions in
which they operate. The regulatory rates are designed to recover the prudently incurred costs of providing
the regulated products or services and provide a reasonable return on the equity invested or assets, as
applicable. In addition to regulatory assets and liabilities, rate regulation impacts multiple financial statement
line items, including, but not limited to, property, plant and equipment (“PP&E”), operating revenues and
expenses, income taxes, and depreciation expense.
Auditing the impact of rate regulation on the Company’s financial statements is complex and highly
judgmental due to the significant judgments made by the Company to support its accounting and disclosure
for regulatory matters when final regulatory decisions or orders have not yet been obtained or when
regulatory formulas are complex. There is also subjectivity involved in assessing the potential impact of
future regulatory decisions on the financial statements. Although the Company expects to recover costs
from customers through rates, there is a risk that the regulator will not approve full recovery of the costs
incurred. The Company’s judgments include making an assessment of the probability of recovery of and
return on costs incurred, of the potential disallowance of part of the cost incurred, or of the probable refund
to customers through future rates.
66
EMERA 2022 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 in future rates based on the
regulator’s treatment of similar costs under similar circumstances. We obtained and evaluated an analysis
from the Company and corroborated that analysis with letters from legal counsel, when appropriate,
regarding cost recoveries or future changes in rates. We also assessed the methodology, accuracy and
completeness of the Company’s calculations of regulatory asset and liability balances based on provisions
and formulas outlined in rate orders and other correspondence with the regulators. We evaluated the
Company’s disclosures related to the impacts of rate regulation.
Key Audit Matter
Fair value measurement and disclosure of derivative financial instruments
Held-for-trading (“HFT”) derivative assets of $429 million and liabilities of $1,301 million, disclosed in note 15
to the consolidated financial statements, are measured at fair value. The Company recognized $64 million in
realized and unrealized gains during the year with respect to HFT derivatives.
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 fair
value of the contracts. In determining the fair value of HFT derivatives, significant assumptions about future
economic and market assumptions with uncertain outcomes are used, including third-party sourced forward
commodity pricing curves based on illiquid markets, internally developed correlation factors and basis
differentials. These assumptions have a significant impact on the fair value 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 fair value hierarchy disclosures in note 16 to the consolidated financial statements
were consistent with the source of the significant inputs and assumptions used in determining the fair value
of derivatives.
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 2022 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 2022 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 23, 2023
69
EMERA 2022 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,
2022 and 2021, the related Consolidated Statements of Income, Consolidated Statements of Comprehensive Income, Consolidated
Statements of Changes in Equity and Consolidated Statements of Cash Flows for the years then ended, and the related notes
(collectively referred to as the “consolidated financial statements“). In our opinion, the consolidated financial statements present
fairly, in all material respects, the consolidated financial position of the Company as of December 31, 2022 and 2021, and the
consolidated results of its operations and its consolidated cash flows for each of the two years in the period ended December 31,
2022, in conformity with United States generally accepted accounting principles.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an
opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with
the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to
the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and
Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the
audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement,
whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal
control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over
financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over
financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements,
whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on
a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included
evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall
presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
70
EMERA 2022 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 7 of the consolidated financial statements, the Company has $3.6 billion in regulatory
assets and $2.3 billion in regulatory liabilities. The Company’s rate-regulated subsidiaries are subject to
regulation by various federal, state and provincial regulatory authorities in the geographic regions in
which they operate. The regulatory rates are designed to recover the prudently incurred costs of providing
the regulated products or services and provide a reasonable return on the equity invested or assets, as
applicable. In addition to regulatory assets and liabilities, rate regulation impacts multiple financial
statement line items, including, but not limited to, PP&E, operating revenues and expenses, income taxes,
and depreciation expense.
Auditing the impact of rate regulation on the Company’s financial statements is complex and highly
judgmental due to the significant judgments made by the Company to support its accounting and disclosure
for regulatory matters when final regulatory decisions or orders have not yet been obtained or when
regulatory formulas are complex. There is also subjectivity involved in assessing the potential impact of
future regulatory decisions on the financial statements. Although the Company expects to recover costs
from customers through rates, there is a risk that the regulator will not approve full recovery of the costs
incurred. The Company’s judgments include making an assessment of the probability of recovery of and
return on costs incurred, of the potential disallowance of part of the cost incurred, or of the probable refund
to customers through future rates.
We performed audit procedures that included, amongst others, assessing the Company’s evaluation of the
probability of future recovery for regulatory assets, PP&E, and refund of regulatory liabilities by obtaining
and reviewing relevant regulatory orders, filings, testimony, hearings and correspondence, and other publicly
available information. For regulatory matters for which regulatory decisions or orders have not yet been
obtained, we inspected the rate-regulated subsidiaries’ filings for any evidence that might contradict the
Company’s assertions, and reviewed other regulatory orders, filings and correspondence for other entities
within the same or similar jurisdictions to assess the likelihood of recovery in future rates based on the
regulator’s treatment of similar costs under similar circumstances. We obtained and evaluated an analysis
from the Company and corroborated that analysis with letters from legal counsel, when appropriate,
regarding cost recoveries or future changes in rates. We also assessed the methodology, accuracy and
completeness of the Company’s calculations of regulatory asset and liability balances based on provisions
and formulas outlined in rate orders and other correspondence with the regulators. We evaluated the
Company’s disclosures related to the impacts of rate regulation.
71
EMERA 2022 ANNUAL REPORT Report of Independent Registered Public Accounting Firm
Description of the
Matter
Fair value measurement of derivative financial instruments
Held-for-trading (“HFT”) derivative assets of $429 million and liabilities of $1,301 million, disclosed in note 15
to the consolidated financial statements, are measured at fair value. The Company recognized $64 million in
realized and unrealized gains during the year with respect to HFT derivatives.
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 fair
value of the contracts. In determining the fair value of HFT derivatives, significant assumptions about future
economic and market assumptions with uncertain outcomes are used, including third-party sourced forward
commodity pricing curves based on illiquid markets, internally developed correlation factors and basis
differentials. These assumptions have a significant impact on the fair value 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 fair value hierarchy disclosures in note 16 to the consolidated financial statements
were consistent with the source of the significant inputs and assumptions used in determining the fair value
of derivatives.
Chartered Professional Accountants
We have served as the Company’s auditor since 1998.
Halifax, Canada
February 23, 2023
72
EMERA 2022 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 6)
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
Impairment charges (note 22)
Total operating expenses
Income from operations
Income from equity investments (note 8)
Other income, net (note 9)
Interest expense, net
Income before provision for income taxes
Income tax expense (recovery) (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
2021
2022
$ 5,473
1,681
434
7,588
$ 4,665
1,261
(161)
5,765
2,171
800
1,596
367
952
73
5,959
1,629
129
145
709
1,194
185
1,009
1
63
$ 945
1,763
472
1,368
330
902
–
4,835
930
143
93
611
555
(6)
561
1
50
510
$
266
266
257
258
$ 3.56
$ 3.55
$ 2.6775
$ 1.98
$ 1.98
$ 2.5750
73
EMERA 2022 ANNUAL REPORT
Consolidated Financial Statements
Emera Incorporated
Consolidated Statements of Comprehensive Income
For the
millions of dollars
Net income
Other comprehensive income (loss), net of tax
Foreign currency translation adjustment (1 )
Unrealized (losses) gains on net investment hedges (2) (3)
Cash flow hedges
Net derivative gains (4)
Less: reclassification adjustment for gains included in income
Net effects of cash flow hedges
Unrealized losses on available-for-sale investment
Net change in unrecognized pension and post-retirement benefit obligation (5)
Other comprehensive income (loss) (6)
Comprehensive income
Comprehensive income attributable to non-controlling interest
Comprehensive Income of Emera Incorporated
Year ended December 31
2021
2022
$ 1,009
$
561
629
(97)
(42)
5
–
(2)
(2)
(1)
24
553
1,562
1
$ 1,561
18
(1)
17
–
124
104
665
1
$ 664
The accompanying notes are an integral part of these consolidated financial statements.
(1) Net of tax expense of $7 million for the year ended December 31, 2022 (2021 – $5 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 recovery of $6 million for the year ended December 31, 2022 (2021 – $1 million expense).
(4) Net of tax recovery of $1 million for the year ended December 31, 2022 (2021 – $6 million expense).
(5) Net of tax expense of $1 million for the year ended December 31, 2022 (2021 – $2 million expense).
(6) Net of tax expense of $1 million for the year ended December 31, 2022 (2021 – $14 million expense).
74
EMERA 2022 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 7)
Receivables and other current assets (note 18)
Property, plant and equipment (“PP&E”), net of accumulated depreciation
and amortization of $9,574 and $8,739, respectively (note 20)
Other assets
Deferred income taxes (note 10)
Derivative instruments (notes 15 and 16)
Regulatory assets (note 7)
Net investment in direct finance and sales type leases (note 19)
Investments subject to significant influence (note 8)
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
2022
December 31
2021
$
310
22
769
296
602
2,897
4,896
$ 394
23
538
195
253
1,733
3,136
22,996
20,353
237
100
3,018
604
1,418
6,012
461
11,850
$ 39,742
295
106
2,313
503
1,382
5,696
460
10,755
$ 34,244
75
EMERA 2022 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 (notes 7 and 32)
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 7)
Pension and post-retirement liabilities (note 21)
Other long-term liabilities (notes 8 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
2022
December 31
2021
$ 2,726
574
2,025
888
495
579
7,287
$ 1,742
462
1,485
533
290
366
4,878
15,744
2,196
190
1,778
281
825
21,014
14,196
1,868
149
1,765
370
868
19,216
7,762
1,422
81
578
1,584
11,427
14
11,441
$ 39,742
7,242
1,422
79
25
1,348
10,116
34
10,150
$ 34,244
“M. Jacqueline Sheppard”
Chair of the Board
“Scott Balfour”
President and Chief Executive Officer
76
EMERA 2022 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 equity funds used during construction
Deferred income taxes, net
Net change in pension and post-retirement liabilities
Fuel adjustment mechanism (“FAM”)
Net change in fair value of derivative instruments
Net change in regulatory assets and liabilities
Net change in capitalized transportation capacity
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 proceeds under committed credit facilities
Issuance of common stock, net of issuance costs
Issuance of preferred stock, net of issuance costs (note 28)
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
2021
2022
$ 1,009
$
561
959
(61)
(52)
152
(48)
(162)
206
(471)
(445)
73
(13)
(234)
913
915
(69)
(61)
(37)
(23)
(166)
404
(176)
(107)
–
96
(152)
1,185
(2,596)
27
(2,569)
(2,359)
27
(2,332)
1,028
544
(680)
784
(367)
511
277
–
(472)
(63)
(7)
1,555
16
(85)
417
$ 332
(155)
640
(377)
2,554
(1,660)
82
317
416
(443)
(50)
(13)
1,311
(1)
163
254
417
$
$ 302
8
22
$ 332
$ 237
157
23
417
$
77
EMERA 2022 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
$ 7,242 $ 1,422
$
79
$
millions of dollars
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 at-the-market
program (”ATM“), net of after-tax
issuance costs
Issued under the Dividend
Reinvestment Program ("DRIP"),
net of discount
Senior management stock options
exercised and Employee Share
Purchase Plan
Disposal of non-controlling interest
of Dominica Electricity Services
Ltd (”Domlec“)
Other
Balance, December 31, 2022
–
–
–
–
248
238
34
–
–
25
–
$ 1,348
1,008
$
553
–
34
1
–
Total Equity
$ 10,150
1,009
553
–
(63)
–
(63)
–
(709)
–
(709)
–
–
–
–
–
–
248
238
–
–
–
–
–
–
–
–
–
–
–
–
–
2
–
–
–
36
$ 7,762 $ 1,422
$
–
–
–
–
81
–
–
–
–
$
578
$ 1,584
$
(20)
(1)
14
(20)
(1)
$ 11,441
$ 9,238
561
104
418
(50)
(79) $ 1,495
560
–
$
104
–
–
–
–
(50)
34
1
–
–
–
–
(657)
–
(657)
–
–
–
–
–
–
284
215
–
–
79
$
–
–
25
–
–
$ 1,348
$
–
(1)
34 $ 10,150
38
(1)
$ 1,004
$
79
$
Balance, December 31, 2020
Net income of Emera Inc.
Other comprehensive income, net of
$ 6,705
–
tax expense of $14 million
Issuance of preferred stock, net of
after-tax issuance costs
Dividends declared on preferred
stock (note 28)
Dividends declared on common
stock ($2.5750/share)
Issued under the ATM, net of after-
tax issuance costs
Issued under the DRIP, net of
discount
Senior management stock options
exercised and Employee Share
Purchase Plan
Other
Balance, December 31, 2021
–
–
–
–
284
215
38
–
$ 7,242
–
–
418
–
–
–
–
–
–
$ 1,422
$
–
–
–
–
–
–
–
The accompanying notes are an integral part of these consolidated financial statements.
78
EMERA 2022 ANNUAL REPORT Emera Incorporated
Notes to the Consolidated Financial Statements
As at December 31, 2022 and 2021
1. Summary of Significant Accounting Policies
NATURE OF OPERATIONS
Emera Incorporated (“Emera” or the “Company”) is an energy and services company which invests in electricity generation,
transmission and distribution, and gas transmission and distribution.
At December 31, 2022, Emera’s reportable segments include the following:
• Florida Electric Utility, which consists of Tampa Electric, a vertically integrated regulated electric utility, serving
approximately 827,000 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 541,000 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,
owned and constructed by Nalcor Energy. ENL’s two investments are:
• a 100 per cent investment in NSP Maritime Link Inc. (“NSPML”), which developed the Maritime Link Project, a
$1.8 billion (including allowance for funds used during construction (“AFUDC”)) transmission project; and
• a 31.9 per cent investment 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 (“PGS”), a regulated gas distribution utility, serving approximately 468,000 customers across
Florida;
• New Mexico Gas Company, Inc. (“NMGC”), a regulated gas distribution utility, serving approximately 545,000 customers
in New Mexico;
• Emera Brunswick Pipeline Company Limited (“Brunswick Pipeline”), a 145-kilometre pipeline delivering re-gasified
liquefied natural gas (“LNG”) from Saint John, New Brunswick to the United States border under a 25-year firm service
agreement with Repsol Energy North America Canada Partnership, which expires in 2034;
• SeaCoast Gas Transmission, LLC (“SeaCoast”), a regulated intrastate natural gas transmission company in Florida; and
• a 12.9 per cent 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 133,000 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 2022 ANNUAL REPORT • Emera’s other reportable segment includes investments in energy-related non-regulated companies which includes:
• 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;
• Emera Technologies LLC, a wholly owned technology company focused on finding ways to deliver renewables 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 entity that most significantly impacts its economic performance and the obligation to absorb
losses of the entity that could potentially be significant to the entity. In circumstances where Emera has an investment in a VIE
but is not deemed the primary beneficiary, the VIE is accounted for using the equity method. For further details on VIEs, refer to
note 32.
Intercompany balances and transactions have been eliminated on consolidation, except for the net profit on certain transactions
between certain non-regulated and regulated entities in accordance with accounting standards for rate-regulated entities.
The net profit on these transactions, which would be eliminated in the absence of the accounting standards for rate-regulated
entities, is recorded in non-regulated operating revenues. An offset is recorded to PP&E, regulatory assets, regulated fuel for
generation and purchased power, or OM&G, depending on the nature of the transaction.
USE OF MANAGEMENT ESTIMATES
The preparation of consolidated financial statements in accordance with USGAAP requires management to make estimates and
assumptions. These may affect the reported amounts of assets and liabilities at the date of the financial statements and reported
amounts of revenues and expenses during the reporting periods. Significant areas requiring use of management estimates
relate to rate-regulated assets and liabilities, accumulated reserve for cost of removal, pension and post-retirement benefits,
unbilled revenue, useful lives for depreciable assets, goodwill and long-lived assets impairment assessments, income taxes, asset
retirement obligations (“ARO”), and valuation of financial instruments. Management evaluates the Company’s estimates on an
ongoing basis based upon historical experience, current and expected conditions and assumptions believed to be reasonable at
the time the assumption is made, with any adjustments recognized in income in the year they arise.
80
Notes to the Consolidated Financial StatementsEMERA 2022 ANNUAL REPORT REGULATORY MATTERS
Regulatory accounting applies where rates are established by, or subject to approval by, an independent third-party regulator.
The rates are designed to recover prudently incurred costs of providing the regulated products or services and provide an
opportunity for a reasonable rate of return on invested capital, as applicable. For further detail, refer to note 7.
FOREIGN CURRENCY TRANSLATION
Monetary assets and liabilities denominated in foreign currencies are converted to CAD at the rates of exchange prevailing at the
balance sheet date. The resulting differences between the translation at the original transaction date and the balance sheet date
are included in income.
Assets and liabilities of foreign operations whose functional currency is not the Canadian dollar are translated using exchange
rates in effect at the balance sheet date and the results of operations at the average exchange rate in effect for the period.
The resulting exchange gains and losses on the assets and liabilities are deferred on the balance sheet in AOCI.
The Company designates certain USD denominated debt held in CAD functional currency companies as hedges of net
investments in USD denominated foreign operations. The change in the carrying amount of these investments, measured at the
exchange rates in effect at the balance sheet date is recorded in Other Comprehensive Income (“OCI”).
REVENUE RECOGNITION
Regulated Electric and Gas Revenue:
Electric and gas revenues, including energy charges, demand charges, basic facilities charges and clauses and riders, are
recognized when obligations under the terms of a contract are satisfied, which is when electricity and gas are delivered to
customers over time as the customer simultaneously receives and consumes the benefits. Electric and gas revenues are
recognized on an accrual basis and include billed and unbilled revenues. Revenues related to the sale of electricity and gas are
recognized at rates approved by the respective regulator and recorded based on metered usage, which occurs on a periodic,
systematic basis, generally monthly or bi-monthly. At the end of each reporting period, the electricity and gas delivered to
customers, but not billed, is estimated and the corresponding unbilled revenue is recognized. The Company’s estimate of
unbilled revenue at the end of the reporting period is calculated by estimating the number of megawatt hours (“MWh”) or
therms delivered to customers at the established rates expected to prevail in the upcoming billing cycle. This estimate includes
assumptions as to the pattern of energy demand, weather, line losses and inter-period changes to customer classes.
Non-regulated Revenue:
Marketing and trading margins are comprised of Emera Energy’s corresponding purchases and sales of natural gas and
electricity, pipeline capacity costs and energy asset management revenues. Revenues are recorded when obligations under the
terms of the contract are satisfied and are presented on a net basis, reflecting the nature of the contractual relationships with
customers and suppliers.
Energy sales are recognized when obligations under the terms of the contracts are satisfied, which is when electricity is delivered
to customers over time.
Other non-regulated revenues are recorded when obligations under the terms of the contract are satisfied.
Other:
Sales, value add, and other taxes, except for gross receipts taxes discussed below, collected by the Company concurrent with
revenue-producing activities are excluded from revenue.
LEASES
The Company determines whether a contract contains a lease at inception by evaluating if the contract conveys the right to
control the use of an identified asset for a period of time in exchange for consideration.
Emera has leases with independent power producers (“IPP”) and other utilities with annual requirements to purchase wind
and hydro energy over varying contract lengths that are classified as finance leases. These finance leases are not recorded on
the Company’s Consolidated Balance Sheets, as payments associated with the leases are variable in nature and there are no
minimum fixed lease payments. Lease expense associated with these leases is recorded as “Regulated fuel for generation and
purchased power” on the Consolidated Statements of Income.
81
Notes to the Consolidated Financial StatementsEMERA 2022 ANNUAL REPORT Operating lease liabilities and right-of-use assets are recognized on the Consolidated Balance Sheets based on the present value
of the future minimum lease payments over the lease term at commencement date. As most of Emera’s leases do not provide
an implicit rate, the incremental borrowing rate at commencement of the lease is used in determining the present value of
future lease payments. Lease expense is recognized on a straight-line basis over the lease term and is recorded as “Operating,
maintenance and general” on the Consolidated Statements of Income.
Where the Company is the lessor, a lease is a sales-type lease if certain criteria are met and the arrangement transfers control
of the underlying asset to the lessee. For arrangements where the criteria are met due to the presence of a third-party residual
value guarantee, the lease is a direct financing lease.
For direct finance leases, a net investment in the lease is recorded that consists of the sum of the minimum lease payments and
residual value, net of estimated executory costs and unearned income. The difference between the gross investment and the cost
of the leased item is recorded as unearned income at the inception of the lease. Unearned income is recognized in income over
the life of the lease using a constant rate of interest equal to the internal rate of return on the lease.
For sales-type leases, the accounting is similar to the accounting for direct finance leases, however the difference between the
fair value and the carrying value of the leased item is recorded at lease commencement rather than deferred over the term of
the lease.
Emera has certain contractual agreements that include lease and non-lease components, which management has elected to
account for as a single lease component.
FRANCHISE FEES AND GROSS RECEIPTS
Tampa Electric and PGS recover from customers certain costs incurred, on a dollar-for-dollar basis, through prices approved by
the Florida Public Service Commission (“FPSC”). The amounts included in customers’ bills for franchise fees and gross receipt
taxes are included as “Regulated electric” and “Regulated gas” revenues in the Consolidated Statements of Income. Franchise
fees and gross receipt taxes payable by Tampa Electric and PGS are included as an expense on the Consolidated Statements of
Income in “Provincial, state and municipal taxes”.
NMGC is an agent in the collection and payment of franchise fees and gross receipt taxes and is not required by a tariff to present
the amounts on a gross basis. Therefore, NMGC’s franchise fees and gross receipt taxes are presented net with no line item
impact on the Consolidated Statements of Income.
PROPERTY, PLANT AND EQUIPMENT
PP&E are recorded at original cost, including AFUDC or capitalized interest, net of contributions received in aid of construction.
The cost of additions, including betterments and replacements of units are included in “Property, plant and equipment”. When
units of regulated PP&E are replaced, renewed or retired, their cost, plus removal or disposal costs, less salvage proceeds, is
charged to accumulated depreciation, with no gain or loss reflected in income. Where a disposition of non-regulated PP&E occurs,
gains and losses are included in income as the dispositions occur.
The cost of PP&E represents the original cost of materials, contracted services, direct labour, AFUDC for regulated property or
interest for non-regulated property, ARO, and overhead attributable to the capital project. Overhead includes corporate costs
such as finance, information technology and labour costs, along with other costs related to support functions, employee benefits,
insurance, procurement, and fleet operating and maintenance. Expenditures for project development are capitalized if they are
expected to have a future economic benefit.
Normal maintenance projects and major maintenance projects that do not increase the overall life of the related assets are
expensed as incurred. When a major maintenance project increases the life or value of the underlying asset, the cost is capitalized.
Depreciation is determined by the straight-line method, based on the estimated remaining service lives of the depreciable assets
in each functional class of depreciable property. For some of Emera’s rate-regulated subsidiaries, depreciation is calculated
using the group remaining life method, which is applied to the average investment, adjusted for anticipated costs of removal less
salvage, in functional classes of depreciable property. The service lives of regulated assets require regulatory approval.
82
Notes to the Consolidated Financial StatementsEMERA 2022 ANNUAL REPORT Intangible assets, which are included in “Property, plant and equipment,” consist primarily of computer software and land rights.
Amortization is determined by the straight-line method, based on the estimated remaining service lives of the asset in each
category. For some of Emera’s rate-regulated subsidiaries, amortization is calculated using the amortizable life method which
is applied to the net book value to date over the remaining life of those assets. The service lives of regulated intangible assets
require regulatory approval.
GOODWILL
Goodwill is calculated as the excess of the purchase price of an acquired entity over the estimated fair values of identifiable assets
acquired and liabilities assumed at the acquisition date. Goodwill is carried at initial cost less any write-down for impairment
and is adjusted for the impact of foreign exchange. Under the applicable accounting guidance, goodwill is subject to assessment
for impairment at the reporting unit level annually, or if an event or change in circumstances indicates that the fair value of a
reporting unit may be below its carrying value. When assessing goodwill for impairment, the Company has the option of first
performing a qualitative assessment to determine whether a quantitative assessment is necessary. In performing a qualitative
assessment management considers, among other factors, macroeconomic conditions, industry and market considerations and
overall financial performance.
If the Company performs the qualitative assessment and determines that it is more likely than not that its fair value is less
than its carrying amount, or if the Company chooses to bypass the qualitative assessment, a quantitative test is performed.
The quantitative test compares the fair value of the reporting unit to its carrying amount, including goodwill. If the carrying
amount of the reporting unit exceeds its fair value, an impairment loss is recorded. Management estimates the fair value of
the reporting unit by using the income approach, or a combination of the income and market approach. The income approach
is applied using a discounted cash flow analysis which relies on management’s best estimate of the reporting units’ projected
cash flows. The analysis includes an estimate of terminal values based on these expected cash flows using a methodology which
derives a valuation using an assumed perpetual annuity based on the reporting unit’s residual cash flows. The discount rate
used is a market participant rate based on a peer group of publicly traded comparable companies and represents the weighted
average cost of capital of comparable companies. When using the market approach, management estimates fair value based
on comparable companies and transactions within the utility industry. Significant assumptions used in estimating the fair value
include discount and growth rates, rate case assumptions including future cost of capital, valuation of the reporting units’ net
operating loss (“NOL”) and projected operating and capital cash flows. Adverse changes in these assumptions could result in a
future material impairment of the goodwill assigned to Emera’s reporting units.
As of December 31, 2022, $6,009 million of Emera’s goodwill represents the excess of the acquisition purchase price for TECO
Energy (Tampa Electric, PGS and NMGC reporting units) over the fair values assigned to identifiable assets acquired and liabilities
assumed. In Q4 2022, qualitative assessments were performed for Tampa Electric and PGS given the significant excess of fair
value over carrying amounts calculated during the last quantitative test in Q4 2019. Management concluded it was more likely
than not that the fair value of these reporting units exceeded their respective carrying amounts, including goodwill. As such, no
quantitative testing was required. For the NMGC reporting unit, Emera elected to bypass a qualitative assessment and performed
a quantitative impairment assessment using a combination of the income and market approach. This assessment estimated that
the fair value of the NMGC reporting unit exceeded its carrying amount, including goodwill. As a result of this assessment, no
impairment charges were recognized.
In Q4 2022, the Company elected to bypass a qualitative assessment and performed a quantitative impairment assessment for
GBPC, using the income approach, as this reporting unit is sensitive to changes in assumptions due to limited excess of fair value
over the carrying value, including goodwill. Although the cash flows of GBPC have not changed significantly compared to previous
periods, it was determined that the carrying amount, including goodwill, exceeded the fair value, due to an increase in discount
rates. The discount rate for the reporting unit was negatively impacted by changes in the macro-economic environment, including
the risk-free rate assumption. As a result of this assessment, a goodwill impairment charge of $73 million was recorded in 2022,
reducing the GBPC goodwill balance to nil as at December 31, 2022. No impairment was recorded in 2021. For further detail, refer
to note 22.
83
Notes to the Consolidated Financial StatementsEMERA 2022 ANNUAL REPORT INCOME TAXES AND INVESTMENT TAX CREDITS
Emera recognizes deferred income tax assets and liabilities for the future tax consequences of events that have been included in
the financial statements or income tax returns. Deferred income tax assets and liabilities are determined based on the difference
between the carrying value of assets and liabilities on the Consolidated Balance Sheets, and their respective tax bases using
enacted tax rates in effect for the year in which the differences are expected to reverse. The effect of a change in income tax
rates on deferred income tax assets and liabilities is recognized in earnings in the period when the change is enacted, unless
required to be offset to a regulatory asset or liability by law or by order of the regulator. Emera recognizes the effect of income
tax positions only when it is more likely than not that they will be realized. Management reviews all readily available current and
historical information, including forward-looking information, and the likelihood that deferred tax assets will be recovered from
future taxable income is assessed and assumptions about the expected timing of the reversal of deferred tax assets and liabilities
are made. If management subsequently determines that it is likely that some or all of a deferred income tax asset will not be
realized, then a valuation allowance is recorded to reflect the amount of deferred income tax asset expected to be realized.
Generally, investment tax credits are recorded as a reduction to income tax expense in the current or future periods to the
extent that realization of such benefit is more likely than not. Investment tax credits earned by Tampa Electric, PGS and NMGC
on regulated assets are deferred and amortized over the estimated service lives of the related properties, as required by
regulatory practices.
Tampa Electric, PGS, NMGC and BLPC collect income taxes from customers based on current and deferred income taxes. NSPI,
ENL and Brunswick Pipeline collect income taxes from customers based on income tax that is currently payable except for
the deferred income taxes on certain regulatory balances specifically prescribed by the regulator. For the balance of regulated
deferred income taxes, NSPI, ENL and Brunswick Pipeline recognize regulatory assets or liabilities where the deferred income
taxes are expected to be recovered from or returned to customers in future years. These regulated assets or liabilities are
grossed up using the respective income tax rate to reflect the income tax associated with future revenues that are required
to fund these deferred income tax liabilities, and the income tax benefits associated with reduced revenues resulting from the
realization of deferred income tax assets. GBPC is not subject to income taxes.
Emera classifies interest and penalties associated with unrecognized tax benefits as interest and operating expense, respectively.
For further detail, refer to note 10.
DERIVATIVES AND HEDGING ACTIVITIES
The Company manages its exposure to normal operating and market risks relating to commodity prices, foreign exchange,
interest rates and share prices through contractual protections with counterparties where practicable, and by using financial
instruments consisting mainly of foreign exchange forwards and swaps, interest rate options and swaps, equity derivatives, and
coal, oil and gas futures, options, forwards and swaps. In addition, the Company has contracts for the physical purchase and sale
of natural gas. These physical and financial contracts are classified as held-for-trading (“HFT”). Collectively, these contracts and
financial instruments are considered derivatives.
The Company recognizes the fair value of all its derivatives on its balance sheet, except for non-financial derivatives that meet
the normal purchases and normal sales (“NPNS”) exception. Physical contracts that meet the NPNS exception are not recognized
on the balance sheet; these contracts are recognized in income when they settle. A physical contract generally qualifies for the
NPNS exception if the transaction is reasonable in relation to the Company’s business needs, the counterparty owns or controls
resources within the proximity to allow for physical delivery, the Company intends to receive physical delivery of the commodity,
and the Company deems the counterparty creditworthy. The Company continually assesses contracts designated under the NPNS
exception and will discontinue the treatment of these contracts under this exemption where the criteria are no longer met.
Derivatives qualify for hedge accounting if they meet stringent documentation requirements and can be proven to effectively
hedge the identified risk both at the inception and over the term of the instrument. Specifically, for cash flow hedges, the change
in the fair value of derivatives is deferred to AOCI and recognized in income in the same period the related hedged item is
realized. Where the documentation or effectiveness requirements are not met, the derivatives are recognized at fair value with
any changes in fair value recognized in net income in the reporting period, unless deferred as a result of regulatory accounting.
84
Notes to the Consolidated Financial StatementsEMERA 2022 ANNUAL REPORT Derivatives entered into by NSPI, NMGC and GBPC that are documented as economic hedges or for which the NPNS exception
has not been taken, are subject to regulatory accounting treatment. The change in fair value of the derivatives is deferred to
a regulatory asset or liability. The gain or loss is recognized in the hedged item when the hedged item is settled. Management
believes any gains or losses resulting from settlement of these derivatives related to fuel for generation and purchased power
will be refunded to or collected from customers in future rates. Tampa Electric has no derivatives related to hedging as a result of
a FPSC approved five-year moratorium on hedging of natural gas purchases which ends on December 31, 2022. Tampa Electric’s
moratorium on hedging of natural gas purchases will continue through December 31, 2024, as a result of Tampa Electric’s 2021
rate case settlement agreement.
Derivatives that do not meet any of the above criteria are designated as HFT, with changes in fair value normally recorded in
net income of the period. The Company has not elected to designate any derivatives to be included in the HFT category where
another accounting treatment would apply.
Emera classifies gains and losses on derivatives as a component of fuel for generation and purchased power, other expenses,
inventory, OM&G and PP&E, depending on the nature of the item being economically hedged. Transportation capacity arising as
a result of marketing and trading derivative transactions is recognized as an asset in “Receivables and other current assets” and
amortized over the period of the transportation contract term. Cash flows from derivative activities are presented in the same
category as the item being hedged within operating or investing activities on the Consolidated Statements of Cash Flows.
Non-hedged derivatives are included in operating cash flows on the Consolidated Statements of Cash Flows.
Derivatives, as reflected on the Consolidated Balance Sheets, are not offset by the fair value amounts of cash collateral with the
same counterparty. Rights to reclaim cash collateral are recognized in “Receivables and other current assets” and obligations to
return cash collateral are recognized in “Accounts payable”.
CASH, CASH EQUIVALENTS AND RESTRICTED CASH
Cash equivalents consist of highly liquid short-term investments with original maturities of three months or less at acquisition.
RECEIVABLES AND ALLOWANCE FOR CREDIT LOSSES
Utility customer receivables are recorded at the invoiced amount and do not bear interest. Standard payment terms for
electricity and gas sales are approximately 30 days. A late payment fee may be assessed on account balances after the due date.
The Company recognizes allowances for credit losses to reduce accounts receivable for amounts expected to be uncollectable.
Management estimates credit losses related to accounts receivable by considering historical loss experience, customer deposits,
current events, the characteristics of existing accounts and reasonable and supportable forecasts that affect the collectability
of the reported amount. Provisions for credit losses on receivables are expensed to maintain the allowance at a level considered
adequate to cover expected losses. Receivables are written off against the allowance when they are deemed uncollectible.
INVENTORY
Fuel and materials inventories are valued at the lower of weighted-average cost or net realizable value, unless evidence indicates
that the weighted-average cost will be recovered in future customer rates.
ASSET IMPAIRMENT
Long-Lived Assets:
Emera assesses whether there has been an impairment of long-lived assets and intangibles when a triggering event occurs, such
as a significant market disruption or sale of a business.
The assessment involves comparing the undiscounted expected future cash flows to the carrying value of the asset. When the
undiscounted cash flow analysis indicates a long-lived asset is not recoverable, the amount of the impairment loss is determined
by measuring the excess of the carrying amount of the long-lived asset over its estimated fair value. The Company’s assumptions
relating to future results of operations or other recoverable amounts, are based on a combination of historical experience,
fundamental economic analysis, observable market activity and independent market studies. The Company’s expectations
regarding uses and holding periods of assets are based on internal long-term budgets and projections, which consider external
factors and market forces, as of the end of each reporting period. The assumptions made are consistent with generally accepted
industry approaches and assumptions used for valuation and pricing activities.
As at December 31, 2022, there are no indications of impairment of Emera’s long-lived assets. No impairment charges related to
long-lived assets were recognized in 2022 or 2021.
85
Notes to the Consolidated Financial StatementsEMERA 2022 ANNUAL REPORT Equity Method Investments:
The carrying value of investments accounted for under the equity method are assessed for impairment by comparing the fair
value of these investments to their carrying values, if a fair value assessment was completed, or by reviewing for the presence
of impairment indicators. If an impairment exists, and it is determined to be other-than-temporary, a charge is recognized
in earnings equal to the amount the carrying value exceeds the investment’s fair value. No impairment of equity method
investments was required in either 2022 or 2021.
Financial Assets:
Equity investments, other than those accounted for under the equity method, are measured at fair value, with changes in fair
value recognized in the Consolidated Statements of Income. Equity investments that do not have readily determinable fair
values are recorded at cost minus impairment, if any, plus or minus changes resulting from observable price changes in orderly
transactions for the identical or similar investments. No impairment of financial assets was required in either 2022 or 2021.
ASSET RETIREMENT OBLIGATIONS
An ARO is recognized if a legal obligation exists in connection with the future disposal or removal costs resulting from the
permanent retirement, abandonment or sale of a long-lived asset. A legal obligation may exist under an existing or enacted law
or statute, written or oral contract, or by legal construction under the doctrine of promissory estoppel.
An ARO represents the fair value of the estimated cash flows necessary to discharge the future obligation, using the Company’s
credit adjusted risk-free rate. The amounts are reduced by actual expenditures incurred. Estimated future cash flows are
based on completed depreciation studies, remediation reports, prior experience, estimated useful lives, and governmental
regulatory requirements. The present value of the liability is recorded and the carrying amount of the related long-lived asset
is correspondingly increased. The amount capitalized at inception is depreciated in the same manner as the related long-lived
asset. Over time, the liability is accreted to its estimated future value. AROs are included in “Other long-term liabilities” and
accretion expense is included as part of “Depreciation and amortization”. Any regulated accretion expense not yet approved by
the regulator is recorded in “Property, plant and equipment” and included in the next depreciation study.
Some of the Company’s transmission and distribution assets may have conditional AROs which are not recognized in the
consolidated financial statements, as the fair value of these obligations could not be reasonably estimated, given there is
insufficient information to do so. A conditional ARO refers to a legal obligation to perform an asset retirement activity in which
the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the
entity. Management monitors these obligations and a liability is recognized at fair value in the period in which an amount can
be determined.
COST OF REMOVAL
Tampa Electric, PGS, NMGC and NSPI recognize non-ARO costs of removal (“COR”) as regulatory liabilities. The non-ARO COR
represent funds received from customers through depreciation rates to cover estimated future non-legally required COR of 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.
86
Notes to the Consolidated Financial StatementsEMERA 2022 ANNUAL REPORT STOCK-BASED COMPENSATION
The Company has several stock-based compensation plans: a common share option plan for senior management; an employee
common share purchase plan; a deferred share unit (“DSU”) plan; a performance share unit (“PSU”) plan; and a restricted
share unit (“RSU”) plan. The Company accounts for its plans in accordance with the fair value-based method of accounting for
stock-based compensation. Stock-based compensation cost is measured at the grant date, based on the calculated fair value of
the award, and is recognized as an expense over the employee’s or director’s requisite service period using the graded vesting
method. Stock-based compensation plans recognized as liabilities are initially measured at fair value and re-measured at fair
value at each reporting date, with the change in liability recognized in income.
EMPLOYEE BENEFITS
The costs of the Company’s pension and other post-retirement benefit programs for employees are expensed over the periods
during which employees render service. The Company recognizes the funded status of its defined-benefit and other post-
retirement plans on the balance sheet and recognizes changes in funded status in the year the change occurs. The Company
recognizes the unamortized gains and losses and past service costs in AOCI or regulatory assets. The components of net periodic
benefit cost other than the service cost component are included in “Other income, net” on the Consolidated Statements of
Income. For further detail, refer to note 21.
2. Change in Accounting Policy
The new USGAAP accounting policy that is applicable to, and adopted by the Company in 2022, is described as follows:
FACILITATION OF THE EFFECTS OF REFERENCE RATE REFORM ON FINANCIAL REPORTING
The Company adopted Accounting Standard Update (“ASU”) 2022-06, Reference Rate Reform (Topic 848): Deferral of the Sunset
Date of Topic 848 in Q4 2022. The update extends the period of time preparers can utilize the reference rate reform relief guidance
issued under ASU 2020-04, which was adopted by the Company in Q4 2020. The guidance in ASU 2022-06 was effective as of
the date of issuance and entities may elect to apply the guidance prospectively through to December 31, 2024. The Company has
applied the guidance permitted by ASU 2020-04 to certain debt agreements that were amended during the current period. The
Company’s transition from reference rates will not have a material impact on the consolidated financial statements.
3. Future Accounting Pronouncements
The Company considers the applicability and impact of all ASUs issued by the Financial Accounting Standards Board (“FASB”).
ASUs issued by FASB, but which are not yet effective, were assessed and determined to be either not applicable to the Company
or to have an insignificant impact on the consolidated financial statements.
4. Dispositions
On March 31, 2022, Emera completed the sale of its 51.9 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 2022 ANNUAL REPORT purchased power
1,086
803
–
5. Segment Information
Emera manages its reportable segments separately due in part to their different operating, regulatory and geographical
environments. Segments are reported based on each subsidiary’s contribution of revenues, net income attributable to common
shareholders and total assets, as reported to the Company’s chief operating decision maker.
Florida
Electric
Utility
Canadian
Electric
Utilities
Gas Utilities
and
Infrastructure
Other
Electric
Utilities
Inter-
segment
Eliminations
Other
Total
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
Regulated cost of natural gas
OM&G
Provincial, state and municipal taxes
Depreciation and amortization
Income from equity investments
Other income (expense), net
Interest expense, net (2)
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
$ 3,280 $ 1,675
–
7
3,287
1,675
$ 1,697
7
1,704
–
–
625
235
507
–
68
185
–
121
–
–
338
43
259
87
24
136
–
(8)
–
–
800
365
83
118
21
13
81
–
70
–
–
$ 518
–
518
290
–
123
3
61
4
–
19
73
–
1
–
$ 418
22
440
$
– $ 7,588
(36)
(36)
–
7,588
–
–
156
3
7
17
23
288
–
2
–
63
(8)
–
(11)
–
–
–
17
–
–
–
–
–
2,171
800
1,596
367
952
129
145
709
73
185
1
63
$ 596 $ 215
$ 1,425 $ 507
$
$
221
574
$
$ 63
(48) $
$
(39) $
$
6
– $ 945
– $ 2,575
$ 21,053 $ 8,223
$ 7,737
$ 1,337
$ 2,835
$ (1,443) $ 39,742
– $ 1,241
$
$ 4,739 $
$ 128
– $ 1,270
$ 49
$
$
– $
– $
$
3
– $ 1,418
– $ 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.
88
Notes to the Consolidated Financial StatementsEMERA 2022 ANNUAL REPORT millions of dollars
For the year ended December 31, 2021
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)
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, 2021
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
$ 2,718 $ 1,501
–
6
2,724
1,501
$ 1,276
4
1,280
$ 445
–
445
$ (175) $
18
(157)
– $ 5,765
–
(28)
(28)
894
–
536
654
–
291
–
218
472
325
–
140
–
–
106
(3)
–
(30)
212
43
69
4
2
–
469
–
59
138
72
–
–
246
103
12
132
9
–
–
121
20
11
64
62
–
–
58
4
15
21
1
1
–
8
16
1
256
(150)
–
50
–
–
(5)
–
–
–
–
5,765
1,763
472
1,368
330
902
143
93
611
(6)
1
50
$ 462 $ 241
$ 1,331 $ 366
$
$
198
515
21
$
$ 111
$ (412) $
$
5
$
510
– $
– $ 2,328
$ 17,903 $ 7,418 $ 6,666
$ 1,402
$ 2,034
$ (1,179) $ 34,244
$
$ 4,436 $
– $ 1,215
–
$ 123
$ 1,189
$ 44
$ 68
$
$
– $
$
3
–
–
$ 1,382
$ 5,696
(1) All significant inter-company balances and transactions have been eliminated on consolidation except for certain transactions between non-regulated
and regulated entities. Management believes the elimination of these transactions would understate PP&E, OM&G, or regulated fuel for generation and
purchased power. Inter-company transactions that have not been eliminated are measured at the amount of consideration established and agreed to by
the related parties. Eliminated transactions are included in determining reportable segments.
(2) Segment net income is reported on a basis that includes internally allocated financing costs of $13 million for the year ended December 31, 2021, between
the Gas Utilities and Infrastructure and Other segments.
GEOGRAPHICAL INFORMATION
Revenues (based on country of origin of the product or service sold)
For the
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
Dominica
Year ended December 31
2021
2022
$ 5,346
1,725
384
122
11
$ 3,754
1,566
292
110
43
$ 7,588 $ 5,765
December 31
2022
December 31
2021
4,689
583
342
$ 17,382 $ 14,978
4,440
535
322
78
$ 20,353
–
$ 22,996
89
Notes to the Consolidated Financial StatementsEMERA 2022 ANNUAL REPORT
6. Revenue
The following disaggregates the Company’s revenue by major source:
millions of dollars
For the year ended December 31, 2022
Regulated Revenue
Residential
Commercial
Industrial
Other 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, 2021
Regulated Revenue
Residential
Commercial
Industrial
Other 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
Florida
Electric
Utility
Canadian
Electric
Utilities
Electric
Other
Electric
Utilities
Gas
Gas Utilities
and
Infrastructure
Other
Inter-
segment
Eliminations
Other
Total
$ 1,799
869
230
371
18
$ 834
427
353
28
33
–
$ 3,287
–
$ 1,675
$ 184
282
32
12
8
–
518
$
–
–
–
–
–
–
– $
–
–
–
–
– $
$
$ 3,287
$ 1,675
$ 518
$ 800
461
83
–
283
61
$ 1,688
–
16
–
$
16
$ 1,704
$
– $
–
–
–
–
–
$
– $
–
–
(7)
–
(7)
$ 3,617
2,039
691
411
335
61
(14) $ 7,154
143
16
281
$ 440
$ 440
–
(10)
(12)
143
22
269
$
(22) $ 434
$ (36) $ 7,588
$ 1,449
754
215
289
17
$ 797
407
237
27
33
$ 165
232
26
7
15
–
$ 2,724
–
$ 1,501
–
$ 445
$ 642
379
65
–
122
58
$ 1,266
$
$
– $
–
–
–
–
–
– $
– $ 3,053
1,772
–
541
(2)
323
–
179
(8)
–
58
(10) $ 5,926
–
–
–
– $
–
–
–
– $
–
–
–
–
$ 1,501
$ 445
$
$ 2,724
–
14
–
$
14
$ 1,280
102
30
(289)
$ (157) $
$ (157) $
102
–
23
(21)
(286)
3
(18) $ (161)
(28) $ 5,765
(1) Other includes rental revenues, which do not represent revenue from contracts with customers.
(2) Revenue related to Brunswick Pipeline’s service agreement with Repsol Energy Canada.
(3) Revenue which does not represent revenues from contracts with customers.
(4) Includes gains (losses) on settlement of energy related derivatives, which do not represent revenue from contracts with customers.
Remaining Performance Obligations
Remaining performance obligations primarily represent gas transportation contracts, lighting contracts and long-term steam
supply arrangements with fixed contract terms. As of December 31, 2022, the aggregate amount of the transaction price
allocated to remaining performance obligations was $450 million (2021 – $437 million). This amount includes $144 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 2042.
90
Notes to the Consolidated Financial StatementsEMERA 2022 ANNUAL REPORT
7. Regulatory Assets and Liabilities
Regulatory assets represent prudently incurred costs that have been deferred because it is probable they will be recovered
through future rates or tolls collected from customers. Management believes existing regulatory assets are probable for recovery
either because the Company received specific approval from the applicable regulator, or due to regulatory precedent established
for similar circumstances. If management no longer considers it probable that an asset will be recovered, the deferred costs are
charged to income.
Regulatory liabilities represent obligations to make refunds to customers or to reduce future revenues for previous collections.
If management no longer considers it probable that a liability will be settled, the related amount is recognized in income.
For regulatory assets and liabilities that are amortized, the amortization is as approved by the respective regulator.
As at
millions of dollars
Regulatory assets
Deferred income tax regulatory assets
Cost recovery clauses
Tampa Electric capital cost recovery for early retired assets
Pension and post-retirement medical plan
FAM
Storm reserve
NMGC winter event gas cost recovery
Storm restoration
Deferrals related to derivative instruments
Environmental remediations
Stranded cost recovery
Other
Current
Long-term
Total regulatory assets
Regulatory liabilities
Accumulated reserve – cost of removal
Deferred income tax regulatory liabilities
Deferrals related to derivative instruments
NMGC gas hedge settlements (note 18)
Cost recovery clauses
Self-insurance fund (note 32)
Storm reserve
Other
Current
Long-term
Total regulatory liabilities
December 31
2022
December 31
2021
$ 1,166
707
674
369
307
103
69
35
30
27
27
106
$ 3,620
$ 602
3,018
$ 3,620
895
877
230
162
70
30
–
9
$ 2,273
$ 495
1,778
$ 2,273
$ 1,045
114
657
291
145
–
117
35
23
27
26
86
$ 2,566
$ 253
2,313
$ 2,566
819
863
241
–
35
28
58
11
$ 2,055
$ 290
1,765
$ 2,055
Deferred Income Tax Regulatory Assets and Liabilities
To the extent deferred income taxes are expected to be recovered from or returned to customers in future years, a regulatory
asset or liability is recognized as appropriate.
Cost Recovery Clauses
These assets and liabilities are related to Tampa Electric, PGS and NMGC clauses and riders. They are recovered or refunded
through cost-recovery mechanisms approved by the FPSC or New Mexico Public Regulation Commission (“NMPRC”), as
applicable, on a dollar-for-dollar basis in a subsequent period.
91
Notes to the Consolidated Financial StatementsEMERA 2022 ANNUAL REPORT
Tampa Electric Capital Cost Recovery for Early Retired Assets
This regulatory asset is related to the remaining net book value of Big Bend Power Station Units 1 through 3 and smart meter
assets that were retired. The balance earns a rate of return as permitted by the FPSC and will be recovered as a separate line
item on customer bills for a period of 15 years. This recovery mechanism is authorized by and survives the term of the settlement
agreement approved by the FPSC in 2021. For further information, refer to “Big Bend Modernization Project” in the Tampa
Electric section below.
Pension and Post-Retirement Medical Plan
This asset is primarily related to the deferred costs of pension and post-retirement benefits at Tampa Electric, PGS and NMGC.
It is included in rate base and earns a rate of return as permitted by the FPSC and NMPRC as applicable. It is amortized over the
remaining service life of plan participants.
FAM
This regulated asset is the difference between actual fuel costs and amounts recovered from NSPI customers through electricity
rates in a given year and deferred to a FAM regulatory asset or liability and recovered from or returned to customers in
subsequent periods. For the years 2020 through 2022, differences between actual fuel costs and fuel revenues recovered from
customers will be recovered from customers in future periods. The Nova Scotia Utility and Review Board’s (“UARB”) decision to
approve the fuel stability plan directed that any annual non-fuel revenues above NSPI’s approved range of ROE are to be applied
to the FAM.
Storm Reserve
The storm reserve is for hurricanes and other named storms that cause significant damage to Tampa Electric and PGS systems.
As allowed by the FPSC, if the charges to the storm reserve exceed the storm liability, the excess is to be carried as a regulatory
asset. Tampa Electric and PGS can petition the FPSC to seek recovery of restoration costs over a 12-month period, or longer,
as determined by the FPSC, as well as replenish the reserve. In September 2022, Tampa Electric and PGS were impacted by
Hurricane Ian. For further information, refer to “Storm Reserve – Hurricane Ian” in both Tampa Electric and PGS sections below.
NMGC Winter Event Gas Cost Recovery
In February 2021, the State of New Mexico experienced an extreme cold weather event that resulted in an incremental
$108 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 April 16, 2021, NMGC filed a Motion for Extraordinary
Relief, as permitted by the NMPRC rules, to extend the terms of the repayment of the incremental gas costs and to recover
a carrying charge. On June 15, 2021, the NMPRC approved the recovery of $108 million USD and related borrowing costs over
a period of 30 months beginning July 1, 2021.
Storm Restoration
This asset represents storm restoration costs incurred by GBPC. GBPC maintains insurance for its generation facilities and, as
with most utilities, its transmission and distribution networks are not covered by commercial insurance.
In January 2020, the Grand Bahama Port Authority (“GBPA”) approved the recovery of $15 million USD of costs related to
Hurricane Dorian in 2019, over a five-year period. The recovery was implemented through rates on January 1, 2021.
Restoration costs associated with Hurricane Matthew in 2016 are being recovered through an approved fuel charge. For further
information, refer to “Storm Restoration Costs – Hurricane Matthew” in the GBPC section below.
Deferrals Related to Derivative Instruments
This asset is primarily related to NSPI deferring changes in fair value of derivatives that are documented as economic hedges or
that do not qualify for NPNS exemption, as a regulatory asset or liability as approved by its regulator. The realized gain or loss is
recognized when the hedged item settles in regulated fuel for generation and purchased power, inventory, other income, OM&G
or PP&E, depending on the nature of the item being economically hedged.
92
Notes to the Consolidated Financial StatementsEMERA 2022 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 the decommissioning of a GBPC steam turbine in 2012, the GBPA approved the recovery of a $21 million USD stranded cost
through electricity rates; it is included in rate base and is expected to be included in rates in future years.
Accumulated Reserve – Cost of Removal (“COR”)
This regulatory liability represents the non-ARO COR reserve in Tampa Electric, PGS, NMGC and NSPI. AROs represent the
fair value of estimated cash flows associated with the Company’s legal obligation to retire its PP&E. Non-ARO COR represent
estimated funds received from customers through depreciation rates to cover future COR of PP&E value upon retirement that are
not legally required. This reduces rate base for ratemaking purposes. This liability is reduced as COR are incurred and increased
as depreciation is recorded for existing assets and as new assets are put into service.
NMGC Gas Hedge Settlements
This regulatory liability represents the regulatory deferral of gas options exercised above strike price but will settle in cash in
Q1 2023. The value from the cash settlement of this options will flow through to customers via the PGAC.
REGULATORY ENVIRONMENTS AND UPDATES
Florida Electric Utility
Tampa Electric is regulated by the FPSC and is also subject to regulation by the Federal Energy Regulatory Commission (“FERC”).
The FPSC sets rates at a level that allows utilities such as Tampa Electric to collect total revenues or revenue requirements equal
to their cost of providing service, plus an appropriate return on invested capital. Base rates are determined in FPSC rate setting
hearings which can occur at the initiative of Tampa Electric, the FPSC or other interested parties.
Tampa Electric’s approved regulated return on equity (“ROE”) range for 2022 and 2021 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 (2021 – 10.25 per cent) is used for the calculation
of the return on investments for clauses.
Fuel Recovery and Other Cost Recovery Clauses:
Tampa Electric has a fuel recovery clause approved by the FPSC, allowing the opportunity to recover fluctuating fuel expenses
from customers through annual fuel rate adjustments. The FPSC annually approves cost-recovery rates for purchased power,
capacity, environmental and conservation costs, including a return on capital invested. Differences between the prudently
incurred fuel costs and the cost-recovery rates and amounts recovered from customers through electricity rates in a year are
deferred to a regulatory asset or liability and recovered from or returned to customers in subsequent periods.
On January 23, 2023, Tampa Electric requested an adjustment to its fuel charges to recover the 2022 fuel under-recovery of
$518 million USD over a period of 21 months. The request also included an adjustment to 2023 projected fuel costs to reflect
the reduction in natural gas prices since September 2022 for a projected reduction of $170 million USD for the balance of 2023.
The proposed changes will be decided by the FPSC in March 2023, and recovery is expected to begin in April 2023.
The mid-course fuel adjustment requested by Tampa Electric on January 19, 2022, was approved on March 1, 2022. The rate
increase, effective with the first billing cycle in April 2022, covered higher fuel and capacity costs of $169 million USD, and was
spread over customer bills from April 1, 2022 through December 2022.
93
Notes to the Consolidated Financial StatementsEMERA 2022 ANNUAL REPORT Base Rates:
On October 21, 2021, the FPSC approved a settlement agreement filed by Tampa Electric. The settlement agreement allows for
an increase to rates of $191 million USD annually effective January 2022. This increase consisted of $123 million USD in base rate
charges and $68 million USD to recover the costs of retiring assets including, Big Bend coal generation assets Units 1 through
3 and meter assets. The settlement agreement further includes two subsequent year adjustments of $90 million USD and
$21 million USD, effective January 2023 and January 2024, respectively related to the recovery of future investments in the Big
Bend Modernization project and solar generation. The allowed equity in the capital structure will continue to be 54 per cent from
investor sources of capital. The settlement agreement includes an allowed regulated ROE range of 9.0 per cent to 11.0 per cent
with a 9.95 per cent midpoint. It also provides for a 25 basis point increase in the allowed ROE range and mid-point, and
$10 million USD of additional revenue, if United States Treasury Bond yields exceed a specific threshold set on the date the FPSC
approved the agreement. Under the agreement base rates are frozen from January 1, 2022 to December 31, 2024, unless Tampa
Electric’s earned ROE were to fall below the bottom of the range during that time. The settlement agreement provides for the
deferral of income taxes as a result of changes in tax laws. The changes would be reflected as a regulatory asset or liability and
either result in an increase or a decrease in customer rates through a subsequent regulatory process. The settlement agreement
further creates a mechanism to recover the costs of retiring coal generation units and meter assets over a period of 15 years
which survives the term of that agreement. The settlement agreement sets new depreciation and dismantlement rates effective
January 1, 2022 and contains the provisions that Tampa Electric will not have to file another depreciation study during the term
of the agreement but will file a new depreciation study no more than one year, nor less than 90 days, before the filing of its next
general base rate proceeding. Tampa Electric agreed not to hedge natural gas through the period ending on December 31, 2024.
On August 16, 2022, the FPSC approved Tampa Electric’s request to increase revenue and ROE due to increases in the 30-year
United States Treasury bond yield rate. Effective July 1, 2022, the new mid-point ROE is 10.20 per cent, and the range is
9.25 per cent to 11.25 per cent.
Storm Reserve – Hurricane Ian:
In September 2022, Tampa Electric was impacted by Hurricane Ian. Total restoration costs were $126 million USD, with
$119 million USD of restoration costs charged against Tampa Electric’s FPSC approved storm reserve. Total restoration costs
charged to the storm reserve have exceeded the reserve balance and have been deferred as a regulatory asset for future
recovery. On January 23, 2023, Tampa Electric petitioned the FPSC for recovery of the storm reserve regulatory asset and
the replenishment of the balance in the reserve to the previous approved reserve level of $56 million USD, for a total of
approximately $131 million USD. The proposed changes will be decided by the FPSC in March 2023 and recovery is expected to
begin in April 2023 through March 2024.
Solar Base Rate Adjustments Included in Base Rates:
During 2017 to 2021, Tampa Electric invested $850 million USD in 600 MW of utility-scale solar photovoltaic projects, which
is recoverable through FPSC-approved solar base rate adjustments (“SoBRAs”). AFUDC was earned on these projects during
construction. The FPSC has approved SoBRAs representing a total of 600 MW or $104 million USD annually in estimated revenue
requirements for in-service projects.
On October 12, 2021, the FPSC approved the true-up filing for SoBRA tranche 3, included in base rates as of January 2020.
A $4 million USD true-up was returned to customers during 2021. No true-up for SoBRA tranche 4 was required.
Storm Protection Cost Recovery Clause and Settlement Agreement:
On October 3, 2019, the FPSC issued a rule to implement a Storm Protection Plan (“SPP”) Cost Recovery Clause. This clause
provides a process for Florida investor-owned utilities, including Tampa Electric, to recover transmission and distribution storm
hardening costs for incremental activities not already included in base rates. Differences between prudently incurred clause-
recoverable costs and amounts recovered from customers through electricity rates in a year are deferred and recovered from or
returned to customers in a subsequent year. A settlement agreement was approved on August 10, 2020, and Tampa Electric’s cost
recovery began in January 2021. The current approved plan addressed the years 2020 through 2022, and in April 2022 Tampa
Electric submitted a new plan to determine cost recovery in 2023, 2024 and 2025. On October 4, 2022, the FPSC approved
Tampa Electric’s SPP.
94
Notes to the Consolidated Financial StatementsEMERA 2022 ANNUAL REPORT Big Bend Modernization Project:
Tampa Electric invested $876 million USD, including $91 million USD of AFUDC, during 2018 through 2022 to modernize the
Big Bend Power Station. The modernization project repowered Big Bend Unit 1 with natural gas combined-cycle technology and
eliminated coal as this unit’s fuel. As part of the modernization project, Tampa Electric retired the Unit 1 components that will not
be used in the modernized plant in 2020 and Big Bend Unit 2 in 2021. Tampa Electric plans to retire Big Bend Unit 3 in 2023 as it
is in the best interest of the customers from an economic, environmental risk and operational perspective.
At December 31, 2021, the balance sheet included $636 million USD in electric utility plant and $267 million USD in accumulated
depreciation related to Unit 1 components and Unit 2 and Unit 3 assets. In accordance with Tampa Electric’s 2017 settlement
agreement approved by the FPSC, Tampa Electric continued to account for its existing investment in Unit 1, 2 and 3 in electric
utility plant and depreciated the assets using the current depreciation rates until December 31, 2021, at which point they were
reclassified to a regulatory asset on the balance sheet.
Tampa Electric’s 2021 settlement agreement provides recovery for the Big Bend Modernization project in two phases. The first
phase was a revenue increase to cover the costs of the assets in service during 2022, among other items. The remainder of the
project costs will be recovered as part of the 2023 subsequent year adjustment. The settlement agreement also includes a new
charge to recover the remaining costs of the retiring Big Bend coal generation assets, Units 1 through 3, which will be spread
over 15 years and will survive the termination of the settlement agreement. The special capital recovery schedule for all three
units was applied beginning January 1, 2022. This recovery mechanism is authorized by and survives the term of the settlement
agreement approved by the FPSC in 2021.
Canadian Electric Utilities
NSPI
NSPI is a public utility as defined in the Public Utilities Act of Nova Scotia (“Public Utilities Act”) and is subject to regulation
under the Public Utilities Act by the UARB. The Public Utilities Act gives the UARB supervisory powers over NSPI’s operations and
expenditures. Electricity rates for NSPI’s customers are also subject to UARB approval. NSPI is not subject to a general annual
rate review process, but rather participates in hearings held from time to time at NSPI’s or the UARB’s request.
NSPI is regulated under a cost-of-service model, with rates set to recover prudently incurred costs of providing electricity
service to customers and provide a reasonable return to investors. NSPI’s approved regulated ROE range for 2022 and 2021 was
8.75 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 has a FAM, approved by the UARB, allowing NSPI to recover fluctuating fuel costs from customers through regularly
scheduled fuel rate adjustments. Differences between prudently incurred fuel costs and amounts recovered from customers
through electricity rates in a year are deferred to a FAM regulatory asset or liability and recovered from or returned to customers
in subsequent periods.
For the period of 2020 through 2022, NSPI operated under a three-year fuel stability plan which resulted in an average annual
overall rate increase of 1.5 per cent to recover fuel costs. These rates included recovery of Maritime Link costs.
General Rate Application (“GRA”):
On November 9, 2022, the Nova Scotia provincial government enacted Bill 212, “Public Utilities Act (amended)”. The legislation
limits non-fuel rate increases in NSPI’s 2022 GRA to the UARB, excluding increases relating to demand side management (“DSM”)
costs, to a total of 1.8 per cent between the effective date of the UARB’s decision and the end of 2024. The legislation also:
• requires revenue generated from the non-fuel rate increase to be used only to improve the reliability of service to ratepayers,
• limits NSPI’s return on equity to 9.25 per cent and equity ratio to 40 per cent, and
• limits the rate used to accrue interest on regulatory deferrals to the Bank of Canada policy interest rate plus 1.75 per cent,
unless otherwise directed by the UARB.
95
Notes to the Consolidated Financial StatementsEMERA 2022 ANNUAL REPORT On November 24, 2022, NSPI filed with the UARB a comprehensive settlement agreement between NSPI, key customer
representatives and participating interest groups (“NSPI Settlement Agreement”) in relation to its GRA filed in January 2022. The
NSPI Settlement Agreement was structured to be consistent with the amendments to the Public Utilities Act made under Bill 212,
including the 1.8 per cent cap on non-fuel rate increases for 2023 and 2024. The NSPI Settlement Agreement also addresses the
recovery of fuel costs over the settlement period and establishes a DSM rider. This will result in a combined fuel and non-fuel rate
increase of 6.9 per cent each year for 2023 and 2024, and annualised incremental revenue (fuel and non-fuel) of $105 million
in 2023 and $115 million in 2024. In addition, any under or over recovery of fuel costs will be addressed through the UARB’s
established FAM process. NSPI’s ROE range will continue to be 8.75 per cent to 9.25 per cent, based on an actual five-quarter
average regulated common equity component of up to 40 per cent. The NSPI Settlement Agreement also establishes a storm rider
for each of 2023, 2024 and 2025, which gives NSPI the option to apply to the UARB for recovery of costs if major storm restoration
expense exceeds approximately $10 million in a given year. On February 2, 2023, NSPI received the UARB’s decision, which
substantially approved the Settlement Agreement as filed. Approved rate increases will be effective as of the date of the decision.
Maritime Link:
The Maritime Link is a $1.8 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. As part of a three-year fuel stability plan, electricity rates were set to include
amounts of $164 million and $162 million for 2021 and 2022, respectively. Any difference between the amounts included in the
fuel stability plan and those approved by the UARB through the NSPML interim assessment application will be addressed through
the FAM.
Nova Scotia Cap-and-Trade (“Cap-and-Trade”) Program:
As at December 31, 2022, the FAM includes a recovery of $172 million (December 31, 2021 – $38 million) non-cash accrual
representing the estimated future cost of acquiring emissions credits for the 2019 through 2022 Cap-and-Trade compliance
period. Emissions for the compliance period will not be finalized until the completion of the environmental audit which begins
in March 2023. Emissions are currently based upon audited actual emissions from 2019 through 2021 and unaudited actuals for
2022. The total cost of compliance with the Cap-and-Trade program compliance period could change depending on the price paid
for both credits at remaining provincial auctions and reserve credits purchased from the provincial government, and the results
of the 2022 environmental emissions audit.
Lower than forecast Muskrat Falls energy received during the compliance period has resulted in the increased deployment of
higher carbon-emitting generation sources. The Province of Nova Scotia has agreed to provide approximately $165 million of
relief from the 2019 through 2022 compliance costs, which was equal to the total cost of compliance forecast at the time of the
fuel update submitted by NSPI to the UARB in September 2022 as part of the GRA. Discussions related to the final amount of
relief and how this relief will be provided are ongoing. Further, NSPI’s regulatory framework provides for the recovery of costs
prudently incurred to comply with the Cap-and-Trade Program Regulations pursuant to NSPI’s FAM.
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.
NSPML also received approval to collect up to $168 million (2021 – $172 million) from NSPI for the recovery of costs associated
with the Maritime Link in 2022. This was subject to a holdback of up to $2 million a month, beginning April 2022, contingent on
receiving at least 90 per cent of NS Block deliveries, including Supplemental Energy deliveries.
96
Notes to the Consolidated Financial StatementsEMERA 2022 ANNUAL REPORT In December 2022, NSPML received UARB approval to collect up to $164 million from NSPI for the recovery of costs associated
with the Maritime Link in 2023. This continues to be subject to a holdback of up to $2 million a month, as discussed above. On
December 22, 2022, the UARB clarified its earlier direction regarding the holdback and NSPI can now release the holdback to
NSPML when 90 per cent of NS Block deliveries, including Supplemental Energy deliveries, is achieved. This enabled NSPI to pay
NSPML approximately $4 million of the 2022 holdback. As of December 31, 2022, an additional $14 million in aggregate has been
held-back by NSPI. Determination of the allocation of the $14 million between NSPML and NSPI will be subject to a regulatory
process that is expected to commence in early 2023 to review the holdback mechanism.
Gas Utilities and Infrastructure
PGS
PGS is regulated by the FPSC. The FPSC sets rates at a level that allows utilities such as PGS to collect total revenues or revenue
requirements equal to their cost of providing service, plus an appropriate return on invested capital.
PGS’s approved ROE range for 2022 and 2021 was 8.9 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.
Fuel Recovery:
PGS recovers the costs it pays for gas supply and interstate transportation for system supply through its PGAC. This clause is
designed to recover actual costs incurred by PGS for purchased gas, gas storage services, interstate pipeline capacity, and other
related items associated with the purchase, distribution, and sale of natural gas to its customers. These charges may be adjusted
monthly based on a cap approved annually by the FPSC.
Recovery of Energy Conservation and Pipeline Replacement Programs:
The FPSC annually approves a conservation charge that is intended to permit PGS to recover prudently incurred expenditures
in developing and implementing cost effective energy conservation programs which are required by Florida law and approved
and monitored by the FPSC. PGS also has a Cast Iron/Bare Steel Pipe Replacement clause to recover the cost of accelerating the
replacement of cast iron and bare steel distribution lines in the PGS system. In February 2017, the FPSC approved expansion of
the Cast Iron/Bare Steel clause to allow recovery of accelerated replacement of certain obsolete plastic pipe. The majority of cast
iron and bare steel pipe has been removed from its system, with replacement of obsolete plastic pipe continuing until 2028 under
the rider.
Storm Reserve – Hurricane Ian:
In September 2022, Hurricane Ian impacted PGS’s operations in Fort Myers and Sarasota. The restoration costs were
approximately $2 million USD and $1 million was charged against PGS’s FPSC-approved storm reserve.
Base Rates:
On November 19, 2020, the FPSC approved a settlement agreement filed by PGS. The settlement agreement allows for an
increase to base rates by $58 million USD annually, effective January 1 2021, which is a $34 million USD increase in revenue and
$24 million USD increase of revenues previously recovered through the cast iron and bare steel replacement rider. It provides
PGS the ability to reverse a total of $34 million USD of accumulated depreciation through 2023. During 2022, PGS reversed
$14 million USD of the $34 million USD accumulated depreciation. No amounts were reversed prior to 2022. In addition, the
agreement sets new depreciation rates effective January 1, 2021. Under the agreement base rates are frozen from January 1, 2021
to December 31, 2023, unless its earned ROE were to fall below 8.9 per cent before that time with an allowed equity in the capital
structure of 54.7 per cent from investor sources of capital. The settlement agreement provides for the deferral of income taxes
as a result of changes in tax laws. The changes would be reflected as a regulatory asset or liability and either result in an increase
or a decrease in customer rates through a subsequent regulatory process.
NMGC
NMGC is subject to regulation by the NMPRC. The NMPRC sets rates at a level that allows NMGC to collect total revenues equal to
its cost of providing service, plus an appropriate return on invested capital.
NMGC’s approved ROE for 2022 and 2021 was 9.375 per cent on an allowed equity capital structure of 52 per cent.
97
Notes to the Consolidated Financial StatementsEMERA 2022 ANNUAL REPORT Fuel Recovery:
NMGC recovers gas supply costs through a PGAC. This clause recovers actual costs for purchased gas, gas storage services,
interstate pipeline capacity, and other related items associated with the purchase, transmission, distribution, and sale of natural
gas to its customers. On a monthly basis, NMGC can adjust the charges based on the next month’s expected cost of gas and any
prior month under-recovery or over-recovery. The NMPRC requires that NMGC annually file a reconciliation of the PGAC period
costs and recoveries. NMGC must file a PGAC Continuation Filing with the NMPRC every four years to establish that the continued
use of the PGAC is reasonable and necessary. In December 2020, NMGC received approval of its PGAC Continuation Filing for the
four-year period ending December 2024.
Base Rates:
On December 13, 2021, NMGC filed a rate case with the NMPRC for new rates to become effective January 2023. On May 20, 2022,
NMGC filed an unopposed settlement agreement with the NMPRC for an increase of $19 million USD in annual base revenues.
The rates reflect the recovery of increased operating costs and capital investments in pipelines and related infrastructure. The
NMPRC approved the settlement agreement on November 30, 2022.
Weather Normalization Mechanism:
In July 2019, the NMPRC approved changes to the company’s rate design to include a five-year pilot of Weather Normalization
Mechanism. This clause is designed to lower the variability of weather impacts during the October through April heating seasons.
The Weather Normalization Mechanism allows customer rates and company revenue to be more predictable by partially removing
the impact of warmer than usual or colder than usual weather. Weather-related revenue increases or decreases experienced from
October to April are adjusted annually in October of the following heating season.
Integrity Management Programs (“IMP”) Regulatory Asset:
A portion of NMGC’s annual spending on infrastructure is for IMP, or the replacement and update of legacy systems. These programs
are driven both by NMGC integrity management plans and federal and state mandates. In December 2020, NMGC received approval
through its rate case to defer costs through an IMP regulatory asset for certain of its IMP capital investments occurring between
January 1, 2022 and December 31, 2023 and petitioned recovery of the regulatory asset in its rate case filed on December 13, 2021.
On November 30, 2022, the NMPRC issued a Final Order that included approval of recovery of the IMP regulatory asset.
Brunswick Pipeline
Brunswick Pipeline is a 145-kilometre pipeline delivering natural gas from the Saint John LNG import terminal near Saint John,
New Brunswick to markets in the northeastern United States. Brunswick Pipeline entered into a 25-year firm service agreement
commencing in July 2009 with Repsol Energy North America Canada Partnership. The agreement provides for a predetermined
toll increase in the fifth and fifteenth year of the contract. The pipeline is considered a Group II pipeline regulated by the Canada
Energy Regulator (“CER”). The CER Gas Transportation Tariff is filed by Brunswick Pipeline in compliance with the requirements
of the CER Act and sets forth the terms and conditions of the transportation rendered by Brunswick Pipeline.
Other Electric Utilities
BLPC
BLPC is regulated by the Fair Trading Commission (“FTC”), an independent regulator, under the Utilities Regulation (Procedural)
Rules 2003. BLPC is regulated under a cost-of-service model, with rates set to recover prudently incurred costs of providing
electricity service to customers plus an appropriate return on capital invested. BLPC’s approved regulated return on rate base
was 10 per cent for 2022 and 2021.
Licenses:
The Government of Barbados has granted BLPC a franchise to generate, transmit and distribute electricity on the island
until 2028. In 2019, the Government of Barbados passed legislation amending the number of licenses required for the supply
of electricity from a single integrated license which currently exists to multiple licenses for Generation, Transmission and
Distribution, Storage, Dispatch and Sales. In March 2021, BLPC reached commercial agreement with the Government of Barbados
for each of the license types, subject to the passage of implementing legislation. The new licenses are expected to take effect
in 2023 on completion of the legislative process. The Dispatch license will have a term of 5 years with the remaining licenses
having terms ranging from 25-30 years. BLPC anticipates that any increased costs associated with the implementation of the new
multi-licensed structure will be recoverable through BLPC’s regulatory framework. BLPC is awaiting final enactment and will work
towards implementation of the licenses once received.
98
Notes to the Consolidated Financial StatementsEMERA 2022 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.
On October 4, 2021 BLPC submitted a general rate review application to the FTC. The application seeks a rate adjustment and
the implementation of a cost reflective rate structure that will facilitate the changes expected in the newly reformed electricity
market and the country’s transition towards 100 per cent renewable energy generation. The application seeks recovery of capital
investment in plant, equipment and related infrastructure and results in an increase in annual non-fuel revenue of approximately
$23 million USD upon approval. The application includes a request for allowed regulatory ROE of 12.50 per cent on an allowed
equity capital structure of 65 per cent. On September 16, 2022, the FTC granted BLPC interim rate relief, allowing an increase
in base rates of approximately $3 million USD for the remainder of 2022 and approximately $1 million USD per month for
2023. Interim rate relief is effective from September 16, 2022 until the implementation of final rates. The hearing concluded in
October 2022. On February 15, 2023, the FTC issued a decision on the BLPC rate review application which included the following
significant items: an allowed regulatory ROE of 11.75 per cent, an equity capital structure of 55 per cent, a directive to update
the major components of rate base to September 16, 2022, and a directive to establish regulatory liabilities of approximately
$70 million USD related to the self-insurance fund, accumulated depreciation, and taxes. The impacts to BLPC’s rate base and
final rates are not yet determinable. BLPC will seek to clarify aspects of the FTC decision in its compliance filing and is also
considering filing a submission to the FTC for a review of the decision. BLPC expects a decision on final rates from the FTC
in 2023.
Fuel Hedging:
On October 21, 2021, the FTC approved BLPC’s application to implement a fuel hedging program which will be incorporated into
the calculation of the fuel clause adjustment. On November 10, 2021, BLPC requested the FTC review the required 50/50 cost
sharing arrangement between BLPC and customers in relation to the hedging administrative costs, or any gains and losses
associated with the hedging program. A decision is expected from the FTC in 2023.
GBPC
GBPC is regulated by the GBPA. The GBPA has granted GBPC a licensed, regulated and exclusive franchise to produce, transmit
and distribute electricity on the island until 2054. Rates are set to recover prudently incurred costs of providing electricity
service to customers plus an appropriate return on rate base. GBPC’s approved regulated return on rate base was 8.23 per cent
for 2022 (2021 – 8.37 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 will be adjusted monthly, in-line with actual fuel costs.
Base Rates:
There is a fuel pass-through mechanism and tariff review policy with new rates submitted every three years. On January 14,
2022, the GBPA issued its decision on GBPC’s application for rate review that was filed with the GBPA on September 23, 2021.
The decision, which became effective April 1, 2022, allows for an increase in revenues of $3.5 million USD. The new rates include a
regulatory ROE of 12.84 per cent.
Storm Restoration Costs – Hurricane Matthew:
In 2017, as part of the recovery of costs incurred as a result of Hurricane Matthew, the GBPA approved a fixed per kWh fuel
charge and allowed the difference between this and the actual cost of fuel to be applied to the Hurricane Matthew regulatory
asset. As part of its decision on GBPC’s application for rate review, issued January 14, 2022, and effective April 1, 2022, the GBPA
approved the continued amortization of the remaining regulatory asset over the three year period ending December 31, 2024.
99
Notes to the Consolidated Financial StatementsEMERA 2022 ANNUAL REPORT 8. 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
2021
2022
740
501
128
49
$ 682
533
123
44
–
–
$ 1,418
$ 1,382
Equity Income
For the year ended
December 31
2021
2022
$
58
29
21
4
17
$ 129
$
$
54
49
20
4
16
143
Percentage
of
Ownership
2022
31.9
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) Although Emera’s ownership percentage of these entities is relatively low, it is considered to have significant influence over the operating and financial
decisions of these companies through Board representation. Therefore, Emera records its investment in these entities using the equity method.
(3) The investment balance in Bear Swamp is in a credit position primarily as a result of a $179 million distribution received in 2015. Bear Swamp’s credit
investment balance of $95 million (2021 – $104 million) is recorded in Other long-term liabilities on the Consolidated Balance Sheets.
Equity investments include a $9 million difference between the cost and the underlying fair value 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.
9. Other Income, Net
For the
millions of dollars
TECO Guatemala Holdings award (1 )
AFUDC
Other
(1) Refer to note 27 for further detail related to the TECO Guatemala Holdings award.
100
December 31
2022
December 31
2021
$
17
1,517
265
29
$ 1,828
48
$
1,149
130
501
$ 1,828
$
25
1,587
247
31
$ 1,890
50
$
1,189
118
533
$ 1,890
Year ended December 31
2021
2022
$
63
52
30
$ 145
$
$
–
61
32
93
Notes to the Consolidated Financial StatementsEMERA 2022 ANNUAL REPORT 10. Income Taxes
The income tax provision, for the years ended December 31, differs from that computed using the enacted combined Canadian
federal and provincial statutory income tax rate for the following reasons:
millions of dollars
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
Foreign tax rate variance
Amortization of deferred income tax regulatory liabilities
GBPC impairment charge
Tax effect of equity earnings
Tax credits
Other
Income tax expense (recovery)
Effective income tax rate
2022
2021
$ 1,194
29.0%
346
(70)
(44)
(33)
21
(10)
(18)
(7)
$ 185
15%
$
$
555
29.0%
161
(62)
(42)
(33)
–
(16)
(13)
(1)
(6)
(1%)
On August 16, 2022, the United States Inflation Reduction Act (“IRA”) was signed into legislation. The IRA includes numerous tax
incentives for clean energy, such as the extension and modification of existing investment and production tax credits for projects
placed in service through 2024 and introduces new technology-neutral clean energy related tax credits beginning in 2025. During
2022, the Company recorded a $9 million regulatory liability 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
Other
Investment tax credits
United States
Operating loss carryforwards
Canada
United States
Income tax expense (recovery)
2022
2021
$
$
25
8
20
11
120
252
–
(33)
118
2
(7)
(11)
(92)
(121)
$ 185
$
(64)
(49)
(6)
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
2022
$
173
1,063
(42)
$ 1,194
$
$
2021
244
289
22
555
101
Notes to the Consolidated Financial StatementsEMERA 2022 ANNUAL REPORT 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
Regulatory liabilities – cost of removal
Derivative instruments
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
Regulatory assets
Derivative instruments
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
2022
2021
$ 1,207
415
177
45
428
2,272
(312)
$ 1,960
$ 873
375
170
188
434
2,040
(256)
$ 1,784
$ (2,981) $ (2,622)
(78)
(197)
(460)
$ (3,919) $ (3,357)
(219)
(125)
(594)
$
$
237
(2,196)
295
(1,868)
$ (1,959) $ (1,573)
Considering all evidence regarding the utilization of the Company’s deferred income tax assets, it has been determined that
Emera is more likely than not to realize all recorded deferred income tax assets, except for certain loss carryforwards and
unrealized capital losses on long-term debt and investments. A valuation allowance of $312 million has been recorded as at
December 31, 2022 (2021 – $256 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, 2022,
$3.8 billion (2021 – $2.9 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.
Emera’s NOL, capital loss and tax credit carryforwards and their expiration periods as at December 31, 2022 consisted of
the following:
Tax
Carryforwards
Subject to
Valuation
Allowance
Net Tax
Carryforwards
Expiration
Period
$
$
$ 2,372
79
$ 2,082
1,489
415
(977) $ 1,395
–
(79)
2026–2042
Indefinite
– $ 2,082
1,489
415
–
–
2032–Indefinite
2032–Indefinite
2025–2042
$
73
$
(33) $
40
2023–2029
millions of dollars
Canada
NOL
Capital loss
United States
Federal NOL
State NOL
Tax credit
Other
NOL
102
Notes to the Consolidated Financial StatementsEMERA 2022 ANNUAL REPORT
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
Decreases due to settlement with tax authorities
Balance, December 31
2022
28
5
2
(2)
–
33
$
$
2021
30
4
1
(1)
(6)
28
$
$
The total amount of unrecognized tax benefits as at December 31, 2022 was $33 million (2021 – $28 million), which would affect
the effective tax rate if recognized. The total amount of accrued interest with respect to unrecognized tax benefits was $7 million
(2021 – $6 million) with $1 million interest expense recognized in the Consolidated Statements of Income (2021 – nil). 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 (2021 – $62 million), including interest. NSPI has prepaid $55 million
(2021 – $23 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, 2022, the Company’s tax years still open to
examination by taxing authorities include 2005 and subsequent years.
11. Common Stock
Authorized: Unlimited number of non-par value common shares.
Issued and outstanding:
Balance, December 31, 2021
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, 2022
millions of
shares
261.07
4.07
4.21
2022
millions of
dollars
$ 7,242
248
238
millions of
shares
251.43
4.99
3.90
2021
millions of
dollars
$ 6,705
284
215
0.60
269.95
34
$ 7,762
0.75
261.07
38
$ 7,242
(1) As at December 31, 2021, a total of 4,987,123 common shares were issued under Emera’s ATM program at an average price of $57.63 per share for gross
proceeds of $287 million ($284 million net of after-tax issuance costs).
(2) For the year ended December 31, 2022, 4,072,469 common shares were issued under Emera’s ATM program at an average price of $61.31 per share for gross
proceeds of $250 million ($248 million net of after-tax issuance costs).
103
Notes to the Consolidated Financial StatementsEMERA 2022 ANNUAL REPORT On August 12, 2021, Emera renewed its ATM Program that allows the Company to issue up to $600 million of common shares
from treasury to the public from time to time, at the Company’s discretion, at the prevailing market price. The ATM Program was
renewed pursuant to a prospectus supplement to the Company’s short form base shelf prospectus dated August 5, 2021. The
ATM program is expected to remain in effect until September 5, 2023. As at December 31, 2022, an aggregate gross sales limit of
$207 million remains available for issuance under the ATM program.
As at December 31, 2022, the following common shares were reserved for issuance: 6 million (2021 – 6.2 million) under the senior
management stock option plan, 2.7 million (2021 – 3.1 million) under the employee common share purchase plan and 10 million
(2021 – 14.2 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, 2022, Emera is in compliance with this requirement.
12. Earnings Per Share
Basic earnings per share is determined by dividing net income attributable to common shareholders by the weighted average
number of common shares outstanding during the period. Diluted EPS is computed by dividing net income attributable to
common shareholders by the weighted average number of common shares outstanding during the period, adjusted for the
exercise and/or conversion of all potentially dilutive securities. Such dilutive items include Company contributions to the senior
management stock option plan, convertible debentures and shares issued under the DRIP.
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
Weighted average deferred share units outstanding ( 1)
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
2021
2022
$ 945.1
945.1
$ 510.5
510.5
265.5
–
265.5
0.4
265.9
255.9
1.3
257.2
0.4
257.6
$ 3.56
$ 3.55
1.98
$
$ 1.98
(1) Effective February 10, 2022, deferred share units are no longer able to be settled in shares and are therefore no longer included in the calculation of
earnings per common share.
104
Notes to the Consolidated Financial StatementsEMERA 2022 ANNUAL REPORT 13. Accumulated Other Comprehensive Income
The components of AOCI are as follows:
millions of dollars
For the year ended December 31, 2022
Balance, January 1, 2022
Other comprehensive income (loss) before
reclassifications
Amounts reclassified from AOCI
Net current period other comprehensive
income (loss)
Balance, December 31, 2022
For the year ended December 31, 2021
Balance, January 1, 2020
Other comprehensive (loss) income before
reclassifications
Amounts reclassified from AOCI
Net current period other comprehensive
income (loss)
Balance, December 31, 2021
Unrealized
gain (loss) on
translation of
self-sustaining
foreign
operations
Net change in
net investment
hedges
Gains on
derivatives
recognized
as cash flow
hedges
Net change
on available-
for-sale
investments
Net change in
unrecognized
pension
and post-
retirement
benefit costs
Total AOCI
$
10
$
35
$
18
$
(1) $
(37) $
25
629
–
629
$ 639
(97)
–
(97)
$
(62) $
–
(2)
(2)
16
(1)
–
(1)
$
(2) $
–
24
531
22
24
553
(13) $ 578
$
52
$
30
$
1
$
(1) $
(161) $
(79)
(42)
–
5
–
18
(1)
–
–
(42)
10
$
5
35
$
17
18
$
$
–
(1) $
–
124
124
(37) $
(19)
123
104
25
Year ended December 31
2022
2021
The reclassifications out of accumulated other comprehensive income (loss) 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
Interest expense, net
Net change in unrecognized pension and post-retirement benefit costs
Actuarial losses
Amounts reclassified into obligations
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
$
$
$
$
(2) $
(1)
10
15
25
(1)
24
22
$
24
102
126
(2)
$
124
$ 123
105
Notes to the Consolidated Financial StatementsEMERA 2022 ANNUAL REPORT
14. Inventory
As at
millions of dollars
Fuel
Materials
Total
December 31
2022
December 31
2021
$
$
404
365
769
$
255
283
$ 538
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
2022
December 31
2021
December 31
2022
December 31
2021
$
$
186
18
52
256
89
340
429
–
5
5
690
(18)
(276)
(294)
$ 396
296
100
396
$
$
$
146
7
88
241
33
208
241
11
–
11
493
(4)
(188)
(192)
301
195
106
301
$
$
42
1
–
43
77
1,224
1,301
5
23
28
1,372
16
8
–
24
32
818
850
–
–
–
874
(18)
(276)
(294)
$ 1,078
888
190
$ 1,078
(4)
(188)
(192)
$ 682
533
149
$ 682
(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, the 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. As of December 31, 2022, the unrealized gain in AOCI was $16 million, net of
tax (2021 – $18 million, net of tax). For the year ended December 31, 2022, unrealized gains of $2 million (2021 – $1 million) have
been reclassified from AOCI into interest expense. The Company expects $2 million of unrealized gains currently in AOCI to be
reclassified into net income within the next twelve months.
106
Notes to the Consolidated Financial StatementsEMERA 2022 ANNUAL REPORT
REGULATORY DEFERRAL
The Company has recorded the following changes in realized and unrealized gains (losses) with respect to derivatives receiving
regulatory deferral:
For the year ended December 31
millions of dollars
Unrealized gain (loss) in regulatory assets
Unrealized gain (loss) in regulatory liabilities
Realized loss in regulatory assets
Realized gain in regulatory liabilities
Realized (gain) loss in inventory (1 )
Realized (gain) loss in regulated fuel for
generation and purchased power (2)
Total change derivative instruments
Physical
natural gas
purchases
Commodity
swaps and
forwards
$
– $
(69) $
28
–
–
–
343
48
(41)
(121)
(64)
(146)
$
(36) $
14
$
2022
FX
forwards
1
16
–
–
1
–
18
2021
FX
forwards
9
(3)
–
–
5
Physical
natural gas
purchases
Commodity
swaps and
forwards
$
– $
(7) $
88
218
–
(3)
(8)
–
–
–
–
$
88
$
(39)
161
$
5
16
(1) Realized (gains) losses will be recognized in fuel for generation and purchased power when the hedged item is consumed.
(2) Realized (gains) losses on derivative instruments settled and consumed in the period and hedging relationships that have been terminated or the hedged
transaction is no longer probable.
As at December 31, 2022, the Company had the following notional volumes designated for regulatory deferral that are expected
to settle as outlined below:
millions
Physical natural gas purchases:
Natural gas (Mmbtu)
Commodity swaps and forwards purchases:
Natural gas (Mmbtu)
Power (MWh)
FX swaps and forwards:
FX contracts (millions of USD)
Weighted average rate
% of USD requirements
2023
2024–2026
6
18
1
–
12
1
$ 206
1.2832
50%
$
123
1.3064
28%
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 (losses) in net income
Year ended December 31
2021
2022
$
$
17
47
64
$
$
4
(142)
(138)
As at December 31, 2022, 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)
2023
319
492
2
2
2024
92
205
–
–
2025
42
105
–
–
2026
36
6
–
–
2027 and
thereafter
131
19
–
–
107
Notes to the Consolidated Financial StatementsEMERA 2022 ANNUAL REPORT
OTHER DERIVATIVES
As at December 31, 2022, the Company had equity derivatives in place to manage the cash flow risk associated with forecasted
future cash settlements of deferred compensation obligations and FX forwards in place to manage cash flow risk associated with
forecasted USD cash inflows. The equity derivatives hedge the return on 2.8 million shares and extends until December 2023.
The FX forwards have a combined notional amount of $448 million USD and expire throughout 2023, 2024, and 2025.
The Company has recognized the following realized and unrealized gains (losses) with respect to other derivatives:
For the
millions of dollars
Unrealized gain (loss) in OM&G
Unrealized loss in other income, net
Realized gain (loss) in OM&G
Realized gain (loss) in other income, net
Total gains (losses) in net income
2022
Year ended December 31
2021
FX
Forwards
Equity
Derivatives
FX
Forwards
Equity
Derivatives
– $
$
– $
(18)
–
(6)
$
(24) $
(5) $
–
(17)
–
(22) $
(15)
–
18
3
11
–
15
–
$
26
CREDIT RISK
The Company is exposed to credit risk with respect to amounts receivable from customers, energy marketing collateral deposits
and derivative assets. Credit risk is the potential loss from a counterparty’s non-performance under an agreement. The Company
manages credit risk with policies and procedures for counterparty analysis, exposure measurement, and exposure monitoring and
mitigation. Credit assessments are conducted on all new customers and counterparties, and deposits or collateral are requested
on any high-risk accounts.
The Company assesses the potential for credit losses on a regular basis and, where appropriate, maintains provisions. With
respect to counterparties, the Company has implemented procedures to monitor the creditworthiness and credit exposure of
counterparties and to consider default probability in valuing the counterparty positions. The Company monitors counterparties’
credit standing, including those that are experiencing financial problems, have significant swings in default probability rates, have
credit rating changes by external rating agencies, or have changes in ownership. Net liability positions are adjusted based on the
Company’s current default probability. Net asset positions are adjusted based on the counterparty’s current default probability.
The Company assesses credit risk internally for counterparties that are not rated.
As at December 31, 2022, the maximum exposure the Company had to credit risk was $1.9 billion (2021 – $1.3 billion), which
includes 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, 2022 was $386 million (2021 – $341 million), which mitigates the Company’s maximum
credit risk exposure. The Company uses the cash as payment for the amount receivable or returns the deposit/collateral to the
customer/counterparty where it is no longer required by the Company.
The Company enters into commodity master arrangements with its counterparties to manage certain risks, including credit risk
to these counterparties. The Company generally enters into International Swaps and Derivatives Association agreements, North
American Energy Standards Board agreements and, or Edison Electric Institute agreements. The Company believes entering
into such agreements offers protection by creating contractual rights relating to creditworthiness, collateral, non-performance
and default.
As at December 31, 2022, the Company had $131 million (2021 – $114 million) in financial assets, considered to be past due, which
have been outstanding for an average 60 days. The fair value of these financial assets is $114 million (2021 – $93 million), the
difference of which is 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 2022 ANNUAL REPORT CONCENTRATION RISK
The Company’s concentrations of risk consisted of the following:
As at
Receivables, net
Regulated utilities:
Residential
Commercial
Industrial
Other
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, 2022
December 31, 2021
millions of
dollars
% of total
exposure
millions of
dollars
% of total
exposure
$
455
192
121
122
890
125
75
307
507
585
1,982
202
8
186
396
$ 2,378
19%
8%
5%
5%
37%
5%
3%
13%
21%
25%
83%
$ 384
167
54
91
696
66
107
132
305
329
1,330
9%
0%
8%
17%
100%
155
22
124
301
$ 1,631
24%
10%
3%
6%
43%
4%
7%
8%
19%
20%
82%
9%
1%
8%
18%
100%
December 31
2022
December 31
2021
$
$
224
112
$
$
212
100
Collateral is posted in the normal course of business based on the Company’s creditworthiness, including its senior unsecured
credit rating as determined by certain major credit rating agencies. Certain derivatives contain financial assurance provisions
that require collateral to be posted if a material adverse credit-related event occurs. If a material adverse event resulted
in the senior unsecured debt falling below investment grade, the counterparties to such derivatives could request ongoing
full collateralization.
As at December 31, 2022, the total fair value of derivatives in a liability position was $1,078 million (December 31, 2021 –
$682 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. Fair Value Measurements
The Company is required to determine the fair value of all derivatives except those which qualify for the NPNS exemption
(see note 1) and uses a market approach to do so. The three levels of the fair value hierarchy are defined as follows:
Level 1 – Where possible, the Company bases the fair valuation of its financial assets and liabilities on quoted prices in active
markets (“quoted prices”) for identical assets and liabilities.
Level 2 – Where quoted prices for identical assets and liabilities are not available, the valuation of certain contracts must
be based on quoted prices for similar assets and liabilities with an adjustment related to location differences. Also, certain
derivatives are valued using quotes from over-the-counter clearing houses.
109
Notes to the Consolidated Financial StatementsEMERA 2022 ANNUAL REPORT 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 fair
value measurement.
The following tables set out the classification of the methodology used by the Company to fair value its derivatives:
Level 1
Level 2
Level 3
Total
December 31, 2022
$
120
$
–
–
120
9
3
12
–
132
15
–
15
2
51
53
–
5
5
73
59
$
$
48
18
–
66
31
72
103
5
174
9
1
10
28
118
146
23
–
23
179
–
– $ 168
18
52
238
52
52
4
34
38
–
90
–
–
–
1
825
826
–
–
–
826
(736) $
44
109
153
5
396
24
1
25
31
994
1,025
23
5
28
1,078
(682)
$
(5) $
As at
millions of dollars
Assets
Regulatory deferral:
Commodity swaps and forwards
FX forwards
Physical natural gas purchases
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)
110
Notes to the Consolidated Financial StatementsEMERA 2022 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:
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
Total liabilities
Net assets (liabilities)
$
Level 1
Level 2
Level 3
Total
December 31, 2021
$
101
$
41
7
–
48
5
29
34
–
82
5
8
13
5
122
127
140
$
– $
–
88
88
4
12
16
–
104
–
–
–
142
7
88
237
13
40
53
11
301
12
8
20
3
515
518
518
(414) $
12
650
662
682
(381)
$
(58) $
–
–
101
4
(1)
3
11
115
7
–
7
4
13
17
24
91
The change in the fair value of the Level 3 financial assets for the year ended December 31, 2022 was as follows:
millions of dollars
Balance, January 1, 2022
Realized gains included in fuel for generation and purchased power
Unrealized gains included in regulatory liabilities
Total realized and unrealized gains included in non-regulated operating
revenues
Balance, December 31, 2022
Regulatory
Deferral
Physical
natural gas
purchases
$
$
88
(64)
28
–
52
$
$
HFT Derivatives
Power
Natural gas
4
–
–
–
4
$
$
12
–
–
22
34
$
Total
104
(64)
28
22
90
$
The change in the fair value of the Level 3 financial liabilities for the year ended December 31, 2022 was as follows:
millions of dollars
HFT Derivatives
Power
Natural gas
Total
Balance, January 1, 2022
Total realized and unrealized gains (losses) included in non-regulated operating revenues
Balance, December 31, 2022
$
$
3
(2)
1
$
515
310
$ 825
$ 518
308
826
$
111
Notes to the Consolidated Financial StatementsEMERA 2022 ANNUAL REPORT
Significant unobservable inputs used in the fair value measurement of Emera’s natural gas and power derivatives include
third-party sourced pricing for instruments based on illiquid markets. Significant increases (decreases) in any of these inputs in
isolation would result in a significantly lower (higher) fair value measurement. Other unobservable inputs used include internally
developed correlation factors and basis differentials; own credit risk; and discount rates. Internally developed correlations and
basis differentials are reviewed on a quarterly basis based on statistical analysis of the spot markets in the various illiquid term
markets. Discount rates may include a risk premium for those long-term forward contracts with illiquid future price points to
incorporate the inherent uncertainty of these points. Any risk premiums for long-term contracts are evaluated by observing
similar industry practices and in discussion with industry peers.
The Company uses a modelled pricing valuation technique for determining the fair value of Level 3 derivative instruments. The
following table outlines quantitative information about the significant unobservable inputs used in the fair value measurements
categorized within Level 3 of the fair value hierarchy:
As at
millions of dollars
Regulatory deferral – Physical
natural gas purchases and sales
HFT derivatives – Power swaps
and physical contracts
HFT derivatives –
Natural gas swaps, futures,
forwards and physical contracts
Total
Net liability
Fair Value
Assets
Liabilities
Significant
Unobservable Input
Low
High
Weighted
Average (1)
December 31, 2022
$
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
$
90
$
$
826
736
(1) Unobservable inputs were weighted by the relative fair value of the instruments.
As at
millions of dollars
Regulatory deferral – Physical
natural gas purchases and sales
HFT derivatives – Power swaps
and physical contracts
HFT derivatives –
Natural gas swaps, futures,
forwards and physical contracts
Total
Net liability
Assets
Fair Value
Liabilities
Significant
Unobservable Input
Low
High
Weighted
Average (1)
December 31, 2021
$
88
$
4
12
–
3
Third-party pricing
$4.51
$26.09
$9.74
Third-party pricing
$37.05
$213.00
$99.34
515
Third-party pricing
$1.90
$21.53
$8.80
$
104
$
$
518
414
(1) Unobservable inputs were weighted by the relative fair value of the instruments.
Long-term debt is a financial liability not measured at fair value on the Consolidated Balance Sheets. The balance consisted of
the following:
As at
millions of dollars
December 31, 2022
December 31, 2021
Carrying
Amount
Fair Value
Level 1
Level 2
Level 3
Total
$ 16,318
$ 14,658
$ 14,670
$ 16,775
$
$
–
$ 14,284
– $ 16,308
$ 386
$ 467
$ 14,670
$ 16,775
112
Notes to the Consolidated Financial StatementsEMERA 2022 ANNUAL REPORT 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, 2022, the fair value of the Hybrid
Notes was $1.1 billion (2021 – $1.7 billion). An after-tax foreign currency loss of $97 million was recorded in AOCI for the year
ended December 31, 2022 (2021 – $5 million after-tax gain).
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
$157 million for the year ended December 31, 2022 (2021 – $149 million). NSPML is accounted for as an equity investment
and therefore, the corresponding earnings related to this revenue are reflected in Income from equity investments.
• Natural gas transportation capacity purchases from M&NP are reported in the Consolidated Statements of Income.
Purchases from M&NP reported net in Operating revenues, Non-regulated, totalled $9 million for the year ended
December 31, 2022 (2021 – $19 million).
There were no significant receivables or payables between Emera and its associated companies reported on Emera’s Consolidated
Balance Sheets as at December 31, 2022 and at December 31, 2021.
18. Receivables and Other Current Assets
As at
millions of dollars
Customer accounts receivable – billed
Customer accounts receivable – unbilled
Allowance for credit losses
Capitalized transportation capacity (1 )
NMGC gas hedge settlement receivable (2)
Income tax receivable
Prepaid expenses
Other
Total receivables and other current assets
December 31
2022
December 31
2021
$ 1,096
424
(17)
781
162
9
82
360
$ 2,897
$
767
318
(21)
316
–
8
65
280
$ 1,733
(1) Capitalized transportation capacity represents the value of transportation/storage received by EES on asset management agreements at the inception of
the contracts. The asset is amortized over the term of each contract.
(2) Related amount is included in regulatory liabilities for NMGC as gas hedges are part of the PGAC. Refer to note 7.
113
Notes to the Consolidated Financial StatementsEMERA 2022 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 63 years, some of which include options to extend the leases for up to 65 years. These options are
included as part of the lease term when it is considered reasonably certain that they will be exercised.
As at
millions of dollars
Right-of-use asset
Lease liabilities
Current
Long-term
Total lease liabilities
Classification
December 31
2022
December 31
2021
Other long-term assets
$
58
$
Other current liabilities
Other long-term liabilities
3
59
62
$
$
58
3
58
61
The Company has recorded lease expense of $138 million for the year ended December 31, 2022 (2021 – $150 million), of which
$131 million (2021 – $142 million) relates 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
2023
2024
2025
2026
2027
Thereafter
Minimum lease payments
Less imputed interest
Total
$
6
$
6
$
5
$
3
$
3
$
116
$
$
Total
139
(77)
62
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
2021
2022
$
8
$
7
$
1
44
3.98%
$
–
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 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 January 2022, the Company leased a Seacoast pipeline, a 21-mile, 30-inch lateral that is classified as a sales-type
lease. The term of the pipeline lateral lease is 34 years with a net investment of $100 million USD. The lessee of the new 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.
114
Notes to the Consolidated Financial StatementsEMERA 2022 ANNUAL REPORT 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: 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
2022
December 31
2021
$ 1,393
$ 947
(205)
(165)
$ 1,188
183
(733)
$ 782
183
(443)
$ 638
34
604
$
$ 522
19
503
$
As at December 31, 2022, future minimum lease payments to be received for each of the next five years and in aggregate
thereafter are as follows:
millions of dollars
2023
2024
2025
2026
2027
Thereafter
Total
Minimum lease payments to be received
Less: executory costs
Total
$ 90
$ 92
$ 95
$ 94
$
92
$ 930
$ 1,393
(205)
$ 1,188
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
2 to 131
10 to 80
10 to 65
13 to 83
2 to 71
December 31
2022
December 31
2021
$ 13,083
2,731
6,978
5,061
2,723
30,576
(9,574)
21,002
1,994
$ 22,996
$ 11,173
2,532
6,305
4,385
2,473
26,868
(8,739)
18,129
2,224
$ 20,353
(1) SeaCoast owns a 50% undivided ownership interest in a jointly owned 26-mile pipeline lateral located in Florida, which went into service in 2020. At
December 31, 2022, SeaCoast’s share of plant in service was $27 million USD (2021 – $27 million USD), and accumulated depreciation of $1 million USD
(2021 – $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 2022 ANNUAL REPORT 21. Employee Benefit Plans
Emera maintains a number of contributory defined-benefit and defined-contribution pension plans, which cover substantially
all of its employees. In addition, the Company provides non-pension benefits for its retirees. These plans cover employees in
Nova Scotia, New Brunswick, Newfoundland and Labrador, Florida, New Mexico, Barbados, and Grand Bahama Island.
Emera’s net periodic benefit cost included the following:
BENEFIT OBLIGATION AND PLAN ASSETS
The changes in benefit obligation and plan assets, and the funded status for all plans were as follows:
For the
millions of dollars
2022
Year ended December 31
2021
Change in Projected Benefit Obligation (“PBO”) and
Accumulated Post-retirement Benefit Obligation (“APBO”)
Defined benefit
pension plans
Non-pension
benefit plans
Defined benefit
pension plans
Non-pension
benefit plans
Balance, January 1
Service cost
Plan participant contributions
Interest cost
Benefits paid
Actuarial gains
Settlements and curtailments
Foreign currency 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
Foreign currency translation adjustment
Balance, December 31
Funded status, end of year
$
$
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
$ 2,759
43
6
67
(160)
(89)
–
(2)
2,624
$ 339
5
4
8
(27)
(10)
–
(1)
318
51
24
6
(31)
(7)
–
3
46
(197) $
2,605
42
6
(160)
214
–
(5)
2,702
78
$
52
21
4
(27)
2
–
(1)
51
(267)
$
The actuarial gains recognized in the period are primarily due to changes in the discount rate and compensation-related
assumption changes. This was partially offset by losses associated with member experience and indexation.
PLANS WITH PBO/APBO IN EXCESS OF PLAN ASSETS
The aggregate financial position for all pension plans where the PBO or APBO (for post-retirement benefit plans) exceeds the
plan assets for the years ended December 31 is as follows:
2022
2021
Defined benefit
pension plans
Non-pension
benefit plans
Defined benefit
pension plans
Non-pension
benefit plans
$ 221
$
$ 290
1,006
914
$
$
(92) $
–
(221) $
140
35
(105) $
–
(290)
millions of dollars
PBO/APBO
Fair value of plan assets
Funded status
116
Notes to the Consolidated Financial StatementsEMERA 2022 ANNUAL REPORT PLANS WITH ACCUMULATED BENEFIT OBLIGATION (“ABO”) IN EXCESS OF PLAN ASSETS
The ABO for the defined benefit pension plans was $2,080 million as at December 31, 2022 (2021 – $2,507 million). The aggregate
financial position for those plans with an ABO in excess of the plan assets for the years ended December 31 is as follows:
millions of dollars
ABO
Fair value of plan assets
Funded status
2022
2021
Defined benefit
pension plans
Defined benefit
pension plans
$
$
$
111
33
(78) $
133
35
(98)
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
2022
December 31
2021
Defined benefit
pension plans
Non-pension
benefit plans
Defined benefit
pension plans
Non-pension
benefit plans
$
(13) $
(20) $
(7) $
(80)
98
358
(7)
356
(201)
24
22
(1)
(176) $
(100)
185
230
(8)
300
$
$
$
(20)
(270)
23
90
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, 2022
Amortized in current period
Current year addition to AOCI or regulatory assets
Change in FX rate
Balance, December 31, 2022
Non-pension benefits plans
Balance, January 1, 2022
Amortized in current period
Current year addition to AOCI or regulatory assets
Change in FX rate
Balance, December 31, 2022
Regulatory
assets
Actuarial
(gains) losses
$ 192
(21)
147
18
$ 336
$
30
(10)
(5)
–
$
15
$
$
91
(2)
(62)
4
31
$
$
–
–
(10)
–
(10)
117
Notes to the Consolidated Financial StatementsEMERA 2022 ANNUAL REPORT As at
millions of dollars
Actuarial losses (gains)
Deferred income tax expense (recovery)
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
Regulatory assets (liability)
Settlement, curtailments
Total
December
2022
December
2021
Defined benefit
pension plans
Non-pension
benefit plans
Defined benefit
pension plans
Non-pension
benefit plans
$
$
15
7
22
336
358
$
$
(10) $
1
(9)
31
22
30
8
38
192
$ 230
$
$
–
(1)
(1)
91
90
2022
Year ended December 31
2021
Defined benefit
pension plans
Non-pension
benefit plans
Defined benefit
pension plans
Non-pension
benefit plans
$
$
41
80
(144)
8
21
2
8
$
$
4
9
–
–
2
–
15
$
$
43
67
(132)
21
24
–
23
$
$
5
8
(1)
3
2
–
17
The expected return on plan assets is determined based on the market-related value of plan assets of $2,482 million as at
January 1, 2022 (2021 – $2,151 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 5%
35% to 50%
7% to 17%
36% to 60%
Notes to the Consolidated Financial StatementsEMERA 2022 ANNUAL REPORT
Non-Canadian Pension Plans
Asset class
Fixed income
Equities
Target Range at Market
Weighted Average
30% to 50%
50% to 70%
Pension Plan assets are overseen by the respective Management Pension Committees in the sponsoring companies. All pension
investments are in accordance with policies approved by the respective Board of Directors of each sponsoring company.
The following tables set out the classification of the methodology used by the Company to fair value its investments:
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
$
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, 2022
$
$
70
(70)
$
–
–
–
–
–
–
–
–
–
–
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%
87
233
186
–
–
3
68
–
–
–
577
$
NAV
Level 1
Level 2
Total
Percentage
December 31, 2021
$
$
60
(84)
$
–
–
–
–
–
–
–
–
–
–
$
60
(84)
97
366
215
2%
(3)%
4%
14%
8%
5%
4%
–%
3%
–%
35%
28%
100%
97
366
215
–
–
8
86
1
–
–
749
Government
Corporate
Other
Mutual funds
Other
Open-ended investments measured at NAV (1 )
Common collective trusts measured at NAV (2)
Total
–
–
–
–
–
952
750
$ 1,702
$
132
117
3
–
(1)
–
–
251
132
117
11
86
–
952
750
$ 2,702
$
(1) NAV investments are open-ended registered and non-registered mutual funds, collective investment trusts, or pooled funds. NAV’s are calculated at least
monthly and the funds honor subscription and redemption activity regularly.
(2) The common collective trusts are private funds valued at NAV. The NAVs are calculated based on bid prices of the underlying securities. Since the prices are
not published to external sources, NAV is used as a practical expedient. Certain funds invest primarily in equity securities of domestic and foreign issuers
while others invest in long duration U.S. investment grade fixed income assets and seeks to increase return through active management of interest rate and
credit risks. The funds honor subscription and redemption activity regularly.
Refer to note 16 for more information on the fair value hierarchy and inputs used to measure fair value.
119
Notes to the Consolidated Financial StatementsEMERA 2022 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 exceptions to this is the NMGC Retiree Medical
Plan, which is fully funded.
INVESTMENTS IN EMERA
As at December 31, 2022 and 2021, the assets related to the pension funds and post-retirement benefit plans did not hold any
material investments in Emera or its subsidiaries securities. However, as a significant portion of assets for the benefit plan are
held in pooled assets, there may be indirect investments in these securities.
CASH FLOWS
The following table shows the expected cash flows for defined benefit pension and other post-retirement benefit plans:
millions of dollars
Expected employer contributions
2023
Expected benefit payments
2023
2024
2025
2026
2027
2028–2032
Defined benefit
pension plans
Non-pension
benefit plans
$
44
$
20
164
161
168
172
178
919
22
23
23
22
22
105
ASSUMPTIONS
The following table shows the assumptions that have been used in accounting for defined benefit pension and other post-
retirement benefit plans:
(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.
2022
2021
Defined benefit
pension plans
Non-pension
benefit plans
Defined benefit
pension plans
Non-pension
benefit plans
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
3.05%
3.18%
3.31%
–
–
2.49%
2.64%
5.86%
2.89%
–
–
2.81%
2.92%
3.29%
5.09%
3.77%
2042
2.48%
2.51%
–%
3.04%
5.64%
4.35%
2038
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.
120
Notes to the Consolidated Financial StatementsEMERA 2022 ANNUAL REPORT
The discount rate is based on high-quality long-term corporate bonds, with maturities matching the estimated cash flows from
the pension plan.
DEFINED CONTRIBUTION PLAN
Emera also provides a defined contribution pension plan for certain employees. The Company’s contribution for the year ended
December 31, 2022 was $41 million (2021 – $45 million).
22. Goodwill
The change in goodwill for the year ended December 31 is due to the following:
millions of dollars
Balance, January 1
GBPC impairment charge (1 )
Change in FX rate
Balance, December 31
2022
2021
$ 5,696
(73)
389
$ 6,012
$ 5,720
–
(24)
$ 5,696
(1) At the beginning of the period, Emera’s accumulated impairment charges related to GBPC were $30 million.
Goodwill is subject to an annual assessment for impairment at the reporting unit level. The goodwill on Emera’s Consolidated
Balance Sheets at December 31, 2022, primarily relates to TECO Energy. Emera’s reporting units with goodwill are Tampa Electric,
PGS, NMGC, and GBPC.
In 2022, Emera performed a qualitative impairment assessment for Tampa Electric and PGS, concluding that the fair value of
the reporting units exceeded their respective carrying amounts, and as such, no quantitative assessments were performed
and no impairment charges were recognized. For the NMGC reporting unit, Emera elected to bypass a qualitative assessment
and performed a quantitative impairment assessment using a combination of the income approach and market approach. This
assessment estimated that the fair value of the NMGC reporting unit exceeded its carrying amount, including goodwill. As a result
of this assessment, no 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, as this reporting unit is sensitive to changes in assumptions due to limited excess of fair
value over carrying amount, including goodwill. Although the cash flows of GBPC have not changed significantly compared to
previous periods, it was determined that the fair value did not exceed its carrying amount, including goodwill, primarily due to an
increase in discount rates. The discount rate for the reporting unit was negatively impacted by changes in the macro-economic
environment, including the risk-free rate assumption. As a result of this assessment, a goodwill impairment charge of $73 million
was recorded in 2022, reducing the GBPC goodwill balance to nil as at December 31, 2022. This non-cash charge is included in
“Impairment charge” on the Consolidated Statements of Income.
121
Notes to the Consolidated Financial StatementsEMERA 2022 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
Tampa Electric Company (“TEC”)
Advances on term, revolving and accounts receivable facilities
Emera
Non-revolving term facility
Bank indebtedness
TECO Finance
Advances on revolving credit and term facilities
NMGC
Advances on revolving credit facilities
GBPC
Advances on revolving credit facilities
NSPI
Bank indebtedness
Short-term debt
Weighted
average
interest rate
2022
Weighted
average
interest rate
2021
$ 1,380
5.00%
$
945
0.58%
796
–
5.19%
–%
400
6
0.96%
–%
481
5.47%
355
1.20%
59
10
5.15%
5.25%
25
10
–
$ 2,726
–%
1
$ 1,742
1.20%
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
Emera – non-revolving term facility
Emera – non-revolving term facility
TEC – Unsecured non-revolving facility
NMGC – revolving credit facility
GBPC – revolving credit facility
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
2022
2021
2026
2026
2023
2023
2023
2026
on demand
$ 1,084
542
400
400
542
169
18
$ 3,155
$ 1,014
507
400
–
634
158
16
$ 2,729
2,731
4
2,735
1,735
4
1,739
$ 420
$ 990
The weighted average interest rate on outstanding short-term debt at December 31, 2022 was 5.01 per cent (2021 – 0.83 per cent).
122
Notes to the Consolidated Financial StatementsEMERA 2022 ANNUAL REPORT RECENT SIGNIFICANT FINANCING ACTIVITY BY SEGMENT
Florida Electric Utilities
On December 13, 2022, TEC amended its 364-day non-revolving term credit facility to extend the maturity date from
December 16, 2022 to December 13, 2023 and reduced the facility amount from $500 million USD to $400 million USD. There
were no other significant changes in commercial terms from the prior agreement.
Other
On December 16, 2022, Emera amended its $400 million non-revolving term credit facility to extend the maturity from
December 16, 2022 to December 16, 2023. There were no other significant changes in commercial terms from the prior agreement.
On August 2, 2022, Emera entered into a $400 million non-revolving term facility which matures on August 2, 2023. The credit
agreement contains customary representation and warranties, events of default and financial and other covenants and bears
interest at Bankers’ Acceptances or prime rate advances, plus a margin.
24. Other Current Liabilities
As at
millions of dollars
Accrued charges
Nova Scotia Cap-and-Trade Program provision (note 7)
Accrued interest on long-term debt
Pension and post-retirement liabilities (note 21)
Sales and other taxes payable
Income tax payable
Other
December 31
2022
December 31
2021
$
$
174
172
97
33
14
9
80
579
$ 157
–
75
27
6
6
95
$ 366
123
Notes to the Consolidated Financial StatementsEMERA 2022 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
2022
2021
Maturity
2022
2021
Weighted average
interest rate ( 1)
Emera
Bankers acceptances, LIBOR loans
Unsecured fixed rate notes
Fixed to floating subordinated notes (USD) (2)
Emera Finance
Unsecured senior notes (USD)
Tampa Electric (3)
Fixed rate notes and bonds (USD)
PGS
Fixed rate notes and bonds (USD)
NMGC
Fixed rate notes and bonds (USD)
Non-revolving term facility, floating rate
NMGI
Fixed rate notes and bonds (USD)
NSPI
Discount notes
Medium term fixed rate notes
EBP
Senior secured credit facility
ECI
Secured senior notes (USD)
Amortizing fixed rate notes (USD)
Non-revolving term facility, floating rate
Non-revolving term facility, fixed rate
Secured fixed rate senior notes (4)
Variable
2.90%
6.75%
Variable
2.90%
6.75%
2027
2023
2076
$ 403
500
1,625
$ 2,528
$
378
500
1,521
$ 2,399
3.65%
3.65%
2024–2046
$ 3,725
$ 3,487
4.15%
4.15%
2024–2052
$ 4,341
$ 3,683
3.78%
3.78%
2024–2052
$
772
$ 660
3.11%
Variable
3.11%
Variable
2026–2051
2024
$ 521
108
$ 488
101
$
629
$ 589
3.64%
3.64%
2024
$ 203
$
190
Variable
5.14%
Variable
5.14%
2024–2027
2025–2097
$ 881
2,665
$ 3,546
$
376
2,665
$ 3,041
Variable
Variable
2026
$ 249
$
249
Variable
3.97%
Variable
2.05%
3.06%
Variable
3.97%
Variable
2.36%
4.43%
2026
2024–2026
2027
2025–2026
2023–2029
$
86
100
30
91
142
$ 449
$
84
104
28
101
161
$ 478
Adjustments
Fair market value adjustment – TECO Energy acquisition (5)
Debt issuance costs
Amount due within one year
Long-Term Debt
$
2
$
(126)
(574)
3
(121)
(462)
$
(698) $
(580)
$ 15,744
$ 14,196
(1) Weighted average interest rate of fixed rate long-term debt.
(2) In 2022, the Company recognized $110 million in interest expense (2021 – $102 million) related to its fixed to floating subordinated notes.
(3) A substantial part of Tampa Electric’s tangible assets are pledged as collateral to secure its first mortgage bonds. There are currently no bonds outstanding
under Tampa Electric’s first mortgage bond indenture.
(4) Notes are issued and payable in either USD or BBD.
(5) On acquisition of TECO Energy, Emera recorded a fair market value adjustment on the unregulated long-term debt acquired. The fair market value
adjustment is amortized over the remaining term of the debt.
124
Notes to the Consolidated Financial StatementsEMERA 2022 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 )
NSPI – revolving credit facility (1 )
NSPI – non-revolving credit facility
NMGC – 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
2022
2021
June 2027
December 2027
July 2024
March 2024
2023–2032
$ 900
800
400
108
11
$ 2,219
$ 900
600
–
–
27
$ 1,527
1,396
12
$ 1,408
770
124
894
$
$
811
$ 633
(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, 2022
RECENT SIGNIFICANT FINANCING ACTIVITY BY SEGMENT
Florida Electric Utility
On September 15, 2022, TEC repaid a $250 million USD note upon maturity. The note was repaid using existing credit facilities.
On July 12, 2022, TEC completed an issuance of $600 million USD senior notes. The issuance included $300 million USD senior
notes that bear an interest rate of 3.875 per cent with a maturity date of July 12, 2024, and $300 million USD senior notes that
bear an interest rate of 5 per cent with a maturity date of July 15, 2052.
Canadian Electric Utilities
On December 16, 2022, NSPI amended its revolving operating credit facility to extend the maturity date from December 16, 2026
to December 16, 2027 and increase the amount of the facility from $600 million to $800 million. There were no other significant
changes in commercial terms from the prior agreement.
On July 15, 2022, NSPI entered into a $400 million non-revolving term credit facility which matures on July 15, 2024. The credit
facility contains customary representation and warranties, events of default and financial and other covenants, and bears interest
at Bankers’ Acceptances or prime rate advances, plus a margin.
Gas Utilities and Infrastructure
On September 23, 2022, NMGC amended its $80 million USD, unsecured, non-revolving term credit facility to extend the maturity
from September 23, 2022, to March 22, 2024. There were no other changes in commercial terms from the prior agreement.
On June 30, 2022, Brunswick Pipeline amended its non-revolving credit agreement to extend the maturity from June 30, 2025 to
June 30, 2026. There were no other changes in commercial terms from the prior agreement.
Other Electric Utilities
On March 25, 2022, ECI amended its amortizing floating rate notes to extend the maturity from March 25, 2022 to March 25,
2027. There were no other changes in commercial terms from the prior agreement.
125
Notes to the Consolidated Financial StatementsEMERA 2022 ANNUAL REPORT Other
On December 16, 2022, Emera amended its $900 million revolving operating credit facility to extend the maturity date from
June 30, 2026 to June 30, 2027. There were no other significant changes in commercial terms from the prior agreement.
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
Tampa Electric
PGS
NMGC
NMGI
NSPI
EBP
ECI
Total
2023
2024
2025
2026
2027
Thereafter
Total
$ 500
$
– $
–
–
–
–
–
–
–
74
574
$
407
356
51
108
203
398
–
90
$ 1,613
$
– $ 1,625
1,016
$
403
$
–
–
–
–
–
–
–
95
–
125
–
137
262
40
249
85
$ 3,110
$
2,302
3,985
721
426
–
2,500
–
3
$ 9,937
– $ 2,528
3,725
4,341
772
629
203
3,546
249
449
$ 16,442
–
–
–
–
–
483
–
60
946
26. Asset Retirement Obligations
AROs mostly relate to reclamation of land at the thermal, hydro and combustion turbine sites; and the disposal of polychlorinated
biphenyls in transmission and distribution equipment and a pipeline site. Certain hydro, transmission and distribution assets may
have additional AROs that cannot be measured as these assets are expected to be used for an indefinite period and, as a result, a
reasonable estimate of the fair value of any related ARO cannot be made.
The change in ARO for the years ended December 31 is as follows:
millions of dollars
Balance, January 1
Accretion included in depreciation expense
Change in FX rate
Additions
Accretion deferred to regulatory asset (included in PP&E)
Liabilities settled (1)
Revisions in estimated cash flows
Other
Balance, December 31
$
$
2022
174
9
3
1
1
(1)
(13)
–
$
174
$
2021
178
10
(1)
1
(2)
(13)
–
1
174
(1) Tampa Electric produced ash and other by-products, collectively known as CCR’s, at its Big Bend and Polk power stations. The decrease in ARO in 2021 was
due to the closure of CCR management facilities.
126
Notes to the Consolidated Financial StatementsEMERA 2022 ANNUAL REPORT 27. Commitments and Contingencies
A. COMMITMENTS
As at December 31, 2022, contractual commitments (excluding pensions and other post-retirement obligations, long-term debt
and asset retirement obligations) for each of the next five years and in aggregate thereafter consisted of the following:
millions of dollars
Transportation (1)
Purchased power (2)
Fuel, gas supply and storage
Capital projects
Equity investment commitments (3)
Other
2023
$
693
269
1,161
264
240
149
$ 2,776
$
$
2024
516
243
282
89
–
$
2025
423
237
138
4
–
142
$ 1,272
132
$ 934
$
2026
383
228
40
1
–
49
701
2027
Thereafter
Total
$
367
243
5
–
–
$ 2,817
2,145
1
–
–
42
$ 657
189
$ 5,152
$ 5,199
3,365
1,627
358
240
703
$ 11,492
(1) Purchasing commitments for transportation of fuel and transportation capacity on various pipelines. Includes a commitment of $144 million related to a gas
transportation contract between PGS and SeaCoast through 2040.
(2) Annual requirement to purchase electricity production from IPPs or other utilities over varying contract lengths.
(3) Emera has a commitment to make a final equity contribution to the LIL upon its commissioning. Once commissioned, the commercial agreements between
Emera and Nalcor require true ups to finalize the respective investment obligations of the parties in relation to the Maritime Link and LIL.
NSPI has a contractual obligation to pay NSPML for use of the Maritime Link over approximately 38 years from its January 15,
2018 in-service date. In February 2022, the UARB issued its decision and Board Order approving NSPML’s requested rate base of
approximately $1.8 billion. In December 2022, the UARB approved the collection of $164 million from NSPI for the recovery of
Maritime Link costs in 2023. The timing and amounts payable to NSPML for the remainder of the 38-year commitment period are
subject to UARB approval.
Emera has committed to obtain certain transmission rights for Nalcor, if requested, to enable it to transmit energy which is not
otherwise used in Newfoundland and Labrador or Nova Scotia. Nalcor has the right to transmit this energy from Nova Scotia to
New England energy markets effective August 15, 2021, the date the NS Block delivery obligation commenced, and continuing for
50 years. As transmission rights are contracted, the obligations are included within “Other” in the above table.
B. LEGAL PROCEEDINGS
TECO Guatemala Holdings (“TGH”)
Prior to Emera’s acquisition of TECO Energy in 2016, TGH, a wholly owned subsidiary of TECO Energy, divested of its indirect
investment in the Guatemala electricity sector, but retained certain claims against the Republic of Guatemala (“Guatemala”).
In 2013, TGH asserted an arbitration claim against Guatemala with the International Centre for the Settlement of Investment
Disputes (“ICSID”) under the Dominican Republic Central America – United States Free Trade Agreement. The arbitration
concerned TGH’s allegation that Guatemala unfairly set the distribution tariff for a local distribution company which harmed
TGH’s investment in that company. A tribunal established by the ICSID ruled in favour of TGH (the “First Award”) and, in
November 2020, Guatemala made a payment of approximately $38 million USD in full and final satisfaction of the First Award.
On September 23, 2016, TGH had filed a request for resubmission to arbitration seeking damages in addition to those awarded
in the First Award. On May 13, 2020, an ICSID tribunal awarded TGH additional damages and costs against Guatemala of
more than $35 million USD plus interest (the “Second Award”). TGH subsequently requested a reconsideration of the interest
quantum awarded in connection with the Second Award. On October 16, 2020, the tribunal granted TGH’s request for additional
interest. The additional amount was approximately $2 million USD. On February 12, 2021, Guatemala filed an application with
ICSID for annulment of the Second Award. On March 31, 2021, ICSID constituted an ad hoc Committee to oversee the annulment
proceeding. A three-day hearing was held before the ad hoc Committee beginning on July 27, 2022.
On November 28, 2022, TGH and Guatemala entered into a settlement agreement with respect to the Second Award. Pursuant
to the settlement agreement, on December 15, 2022, Guatemala paid TGH $46 million USD and the parties agreed to settle all
outstanding disputes, concluding this matter. This amount was recognized in “Other Income, net” on the Consolidated Statements
of Income.
127
Notes to the Consolidated Financial StatementsEMERA 2022 ANNUAL REPORT Superfund and Former Manufactured Gas Plant Sites
TEC, through its Tampa Electric and PGS divisions, is a potentially responsible party (“PRP”) for certain superfund sites and,
through its PGS division, for certain former manufactured gas plant sites. While the joint and several liability associated with
these sites presents the potential for significant response costs, as at December 31, 2022, TEC estimated its financial liability
to be $17 million ($13 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 TEC. The estimates to perform
the work are based on TEC’s experience with similar work, adjusted for site-specific conditions and agreements with the
respective governmental agencies. The estimates are made in current dollars, are not discounted and do not assume any
insurance recoveries.
In instances where other PRPs are involved, most of those PRPs are believed to be currently credit-worthy and are likely to
continue to be credit-worthy for the duration of the remediation work. However, in those instances that they are not, TEC could
be liable for more than TEC’s actual percentage of the remediation costs. Other factors that could impact these estimates include
additional testing and investigation which could expand the scope of the cleanup activities, additional liability that might arise
from the cleanup activities themselves or changes in laws or regulations that could require additional remediation. Under current
regulations, these costs are recoverable through customer rates established in base rate proceedings.
Other Legal Proceedings
Emera and its subsidiaries may, from time to time, be involved in other legal proceedings, claims and litigation that arise in the
ordinary course of business which the Company believes would not reasonably be expected to have a material adverse effect on
the financial condition of the Company.
C. PRINCIPAL FINANCIAL RISKS AND UNCERTAINTIES
Emera believes the following principal financial risks could materially affect the Company in the normal course of business.
Risks associated with derivative instruments and fair value measurements are discussed in note 15 and note 16.
Sound risk management is an essential discipline for running the business efficiently and pursuing the Company’s strategy
successfully. Emera has an enterprise-wide risk management process, overseen by its Enterprise Risk Management Committee
(“ERMC”) and monitored by the Board of Directors, to ensure an effective, consistent and coherent approach to risk management.
The Board of Directors established a Risk and Sustainability Committee (’RSC”) in September 2021. The RSC’s mandate includes
oversight of the Company’s Enterprise Risk Management framework, including the identification, assessment, monitoring and
management of enterprise risks. It also includes oversight of the Company’s approach to sustainability and its performance
relative to its sustainability objectives.
Regulatory and Political Risk
The Company’s rate-regulated subsidiaries and certain investments subject to significant influence are subject to risk of
the recovery of costs and investments. Regulatory and political risk can include changes in regulatory frameworks, shifts in
government policy, legislative changes, and regulatory decisions.
As cost-of-service utilities with an obligation to serve customers, Emera’s utilities operate under formal regulatory frameworks,
and must obtain regulatory approval to change or add rates and/or riders. Emera also holds investments in entities in which it
has significant influence, and which are subject to regulatory and political risk including NSPML, LIL, and M&NP. As a regulated
Group II pipeline, the tolls of Brunswick Pipeline are regulated by the CER on a complaint basis, as opposed to the regulatory
approval process described above. In the absence of a complaint, the CER does not normally undertake a detailed examination
of Brunswick Pipeline’s tolls, which are subject to a firm service agreement expiring in 2034, with Repsol Energy North America
Canada Partnership. The agreement provides for a predetermined toll increase in the fifth and fifteenth year of the contract.
128
Notes to the Consolidated Financial StatementsEMERA 2022 ANNUAL REPORT Regulators administer legislation covering material aspects of the utilities’ businesses, including customer rates and/or riders,
the underlying allowed ROEs, deemed capital structures, capital investment, the terms and conditions for the provision of service,
performance standards, and affiliate transactions. Costs and investments can be recovered upon approval by the respective
regulator as an adjustment to rates and/or riders, which normally requires a public hearing process or may be mandated by other
governmental bodies. During public hearing processes, consultants and customer representatives scrutinize the costs, actions
and plans of these rate-regulated companies, and their respective regulators determine whether to allow recovery and to adjust
rates based upon the evidence and any contrary evidence from other parties. In some circumstances, other government bodies
may influence the setting of rates. Regulatory decisions, legislative changes, and prolonged delays in the recovery of costs or
regulatory assets could result in decreased rate affordability for customers and could materially affect Emera and its utilities.
Emera’s utilities generally manage this risk through transparent regulatory disclosure, ongoing stakeholder and government
consultation and multi-party engagement on aspects such as utility operations, regulatory audits, rate filings and capital
plans. The subsidiaries employ a collaborative regulatory approach through technical conferences and, where appropriate,
negotiated settlements.
Changes in government and shifts in government policy and legislation can impact the commercial and regulatory frameworks
under which Emera and its subsidiaries operate. This includes initiatives regarding deregulation or restructuring of the energy
industry. Deregulation or restructuring of the energy industry may result in increased competition and unrecovered costs that
could adversely affect operations, net income and cash flows. State and local policies in some United States jurisdictions have
sought to prevent or limit the ability of utilities to provide customers the choice to use natural gas while in other jurisdictions
policies have been adopted to prevent limitations on the use of natural gas. Changes in applicable state or local laws and
regulations, including electrification legislation, could adversely impact PGS and NMGC.
Emera cannot predict future legislative, policy, or regulatory changes, whether caused by economic, political or other factors,
or its ability to respond in an effective and timely manner or the resulting compliance costs. Government interference in the
regulatory process can undermine regulatory stability, predictability, and independence, and could have a material adverse effect
on the Company.
Foreign Exchange Risk
The Company is exposed to foreign currency exchange rate changes. Emera operates internationally, with an increasing amount
of the Company’s net income earned outside of Canada. As such, Emera is exposed to movements in exchange rates between the
CAD and, particularly, the USD, which could positively or adversely affect results.
Consistent with the Company’s risk management policies, Emera manages currency risks through matching United States
denominated debt to finance its United States operations and may use foreign currency derivative instruments to hedge specific
transactions and earnings exposure. The Company may enter FX forward and swap contracts to limit exposure on certain foreign
currency transactions such as fuel purchases, revenue streams and capital expenditures, and on net income earned outside of
Canada. The regulatory framework for the Company’s rate-regulated subsidiaries permits the recovery of prudently incurred
costs, including FX.
The Company does not utilize derivative financial instruments for foreign currency trading or speculative purposes or to hedge
the value of its investments in foreign subsidiaries. Exchange gains and losses on net investments in foreign subsidiaries do not
impact net income as they are reported in AOCI.
Liquidity and Capital Market Risk
Liquidity risk relates to Emera’s ability to ensure sufficient funds are available to meet its financial obligations. Emera manages
this risk by forecasting cash requirements on a continuous basis to determine whether sufficient funds are available. Liquidity
and capital needs could be financed through internally generated cash flows, asset sales, short-term credit facilities, and ongoing
access to capital markets.
Emera’s access to capital and cost of borrowing is subject to several risk factors, including financial market conditions, market
disruptions, and ratings assigned by credit rating agencies. Disruptions in capital markets could prevent Emera from issuing new
securities or cause the Company to issue securities with less than preferred terms and conditions. Emera’s growth plan requires
significant capital investments in PP&E and the risk associated with changes in interest rates could have an adverse effect on the
cost of financing. The Company’s future access to capital and cost of borrowing may be impacted by various market disruptions.
The inability to access cost-effective capital could have a material impact on Emera’s ability to fund its growth plan.
129
Notes to the Consolidated Financial StatementsEMERA 2022 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 the legislative environment,
political interference in the regulatory process, the ability to recover costs and earn returns, diversification, leverage, liquidity
and increased exposure to climate change-related impacts, including increased frequency and severity of hurricanes and other
severe weather events. A decrease in a credit rating could result in higher interest rates in future financings, increased borrowing
costs under certain existing credit facilities, limit access to the commercial paper market or limit the availability of adequate
credit support for subsidiary operations. For certain derivative instruments, if the credit ratings of the Company were reduced
below investment grade, the full value of the net liability of these positions could be required to be posted as collateral. Emera
manages these risks by actively monitoring and managing key financial metrics with the objective of sustaining investment grade
credit ratings.
The Company has exposure to its own common share price through the issuance of various forms of stock-based compensation,
which affect earnings through revaluation of the outstanding units every period. The Company uses equity derivatives to reduce
the earnings volatility derived from stock-based compensation.
General Economic Risk
The Company has exposure to the macro-economic conditions in North America and in other geographic regions in which Emera
operates. Like most utilities, economic factors such as consumer income, employment and housing affect demand for electricity
and natural gas, and in turn the Company’s financial results. Adverse changes in general economic conditions and inflation
may impact the ability of customers to afford rate increases arising from increases to fuel, operating, capital, environmental
compliance, and other costs, and therefore could materially affect Emera and its utilities. This may also result in higher credit and
counterparty risk, adverse shifts in government policy and legislation, and/or increased risk to full and timely recovery of costs
and regulatory assets.
Interest Rate Risk
Emera utilizes a combination of fixed and floating rate debt financing for operations and capital expenditures, resulting in an
exposure to interest rate risk. Emera seeks to manage interest rate risk through a portfolio approach that includes the use of
fixed and floating rate debt with staggered maturities. The Company will, from time to time, issue long-term debt or enter interest
rate hedging contracts to limit its exposure to fluctuations in floating interest rate debt.
For Emera’s regulated subsidiaries, the cost of debt is a component of rates and prudently incurred debt costs are recovered
from customers. Regulatory ROE will generally follow the direction of interest rates, such that regulatory ROE’s are likely to fall
in times of reducing interest rates and rise in times of increasing interest rates, albeit not directly and generally with a lag period
reflecting the regulatory process. Rising interest rates may also negatively affect the economic viability of project development
and acquisition initiatives.
As with most other utilities and other similar yield-returning investments, Emera’s share price may be affected by changes in
interest rates and could underperform the market in an environment of rising interest rates.
Inflation Risk
The Company may be exposed to changes in inflation that may result in increased operating and maintenance costs, capital
investment, and fuel costs compared to the revenues provided by customer rates. Emera’s utilities have budgeting and
forecasting processes to identify inflationary risk factors and measure operating performance, as well as collective bargaining
agreements that mitigate the short-term impact of inflation on labour costs.
Commodity Price Risk
The Company’s utility fuel supply is subject to commodity price risk. In addition, Emera Energy is subject to commodity price risk
through its portfolio of commodity contracts and arrangements.
The Company manages this risk through established processes and practices to identify, monitor, report and mitigate these risks.
These include the Company’s commercial arrangements, such as the combination of supply and purchase agreements, asset
management agreements, pipeline transportation agreements and financial hedging instruments. In addition, its credit policies,
counterparty credit assessments, market and credit position reporting, and other risk management and reporting practices, are
also used to manage and mitigate this risk.
130
Notes to the Consolidated Financial StatementsEMERA 2022 ANNUAL REPORT Regulated Utilities
The Company’s utility fuel supply is exposed to broader global conditions, which may include impacts on delivery reliability and
price, despite contracted terms. Supply and demand dynamics in fuel markets can be affected by a wide range of factors which
are difficult to predict and may change rapidly, including but not limited to currency fluctuations, changes in global economic
conditions, natural disasters, transportation or production disruptions, and geo-political risks such as political instability, conflicts,
changes to international trade agreements, trade sanctions or embargos. The Company seeks to manage this risk using financial
hedging instruments and physical contracts and through contractual protection with counterparties, where applicable.
The majority of Emera’s regulated electric and gas utilities have adopted and implemented fuel adjustment mechanisms and
purchased gas adjustment mechanisms respectively, which has further helped manage commodity price risk, as the regulatory
framework for the Company’s rate-regulated subsidiaries permits the recovery of prudently incurred fuel and gas costs. There
is no assurance that such mechanisms and regulatory frameworks will continue to exist in the future. Prolonged and substantial
increases in fuel prices could result in decreased rate affordability, increased risk of recovery of costs or regulatory assets, and/or
negative impacts on customer consumption patterns and sales.
Emera Energy Marketing and Trading
Emera Energy has employed further measures to manage commodity risk. The majority of Emera Energy’s portfolio of electricity
and gas marketing and trading contracts and, in particular, its natural gas asset management arrangements, are contracted on
a back-to-back basis, avoiding any material long or short commodity positions. However, the portfolio is subject to commodity
price risk, particularly with respect to basis point differentials between relevant markets in the event of an operational issue or
counterparty default. Changes in commodity prices can also result in increased collateral requirements associated with physical
contracts and financial hedges, resulting in higher liquidity requirements and increased costs to the business.
To measure commodity price risk exposure, Emera Energy employs a number of controls and processes, including an estimated
VaR analysis of its exposures. The VaR amount represents an estimate of the potential change in fair value that could occur from
changes in Emera Energy’s portfolio or changes in market factors within a given confidence level, if an instrument or portfolio
is held for a specified time period. The VaR calculation is used to quantify exposure to market risk associated with physical
commodities, primarily natural gas and power positions.
Income Tax Risk
The computation of the Company’s provision for income taxes is impacted by changes in tax legislation in Canada, the United
States and the Caribbean. Any such changes could affect the Company’s future earnings, cash flows, and financial position.
The value of Emera’s existing deferred tax assets and liabilities are determined by existing tax laws and could be negatively
impacted by changes in laws. Emera monitors the status of existing tax laws to ensure that changes impacting the Company are
appropriately reflected in the Company’s tax compliance filings and financial results.
D. GUARANTEES AND LETTERS OF CREDIT
Emera has guarantees and letters of credit on behalf of third parties outstanding. The following significant guarantees and letters
of credit are not included within the Consolidated Balance Sheets as at December 31, 2022:
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.
TECO Energy issued a guarantee in connection with SeaCoast’s performance obligations under a firm service agreement, which
expires on December 31, 2055, subject to two extension terms at the option of the counterparty with a final expiration date of
December 31, 2071. The guarantee is for a maximum potential amount of $13 million USD if SeaCoast fails to pay or perform
under the firm service agreement. In the event that TECO Energy’s long-term senior unsecured credit ratings are downgraded
below investment grade by Moody’s or S&P, TECO Energy would need to provide either a substitute guarantee from an affiliate
with an investment grade credit rating or a letter of credit or cash deposit of $13 million USD.
Emera Inc. has issued a guarantee of up to $35 million USD relating to outstanding notes of GBPC. The guarantee for the notes
will expire in May 2023.
131
Notes to the Consolidated Financial StatementsEMERA 2022 ANNUAL REPORT Emera Inc. has issued a guarantee of $66 million USD relating to outstanding notes of ECI. This guarantee will automatically
terminate on the date upon which the obligations have been repaid in full.
NSPI has issued guarantees on behalf of its subsidiary, NS Power Energy Marketing Incorporated (“NSPEMI”), in the amount of
$119 million USD (2021 – $118 million USD) with terms of varying lengths.
The Company has standby letters of credit and surety bonds in the amount of $145 million USD (December 31, 2020 – $148 million
USD) to third parties that have extended credit to Emera and its subsidiaries. These letters of credit and surety bonds typically
have a one-year term and are renewed annually as required.
Emera Inc., on behalf of NSPI, has a standby letter of credit to secure obligations under a supplementary retirement plan. The
expiry date of this letter of credit was extended to June 2023. The amount committed as at December 31, 2022 was $63 million
(December 31, 2021 – $64 million).
Collaborative Arrangements
For the years ended December 31, 2022 and 2021, the Company has identified the following material collaborative arrangements:
Through NSPI, the Company is a participant in three wind energy projects in Nova Scotia. The percentage ownership of the wind
project assets is based on the relative value of each party’s project assets by the total project assets. NSPI has power purchase
arrangements to purchase the entire net output of the projects and, therefore, NSPI’s portion of the revenues are recorded
net within regulated fuel for generation and purchased power. NSPI’s portion of operating expenses is recorded in OM&G. In
2022, NSPI recognized $12 million net expense (2021 – $18 million) in “Regulated fuel for generation and purchased power” and
$3 million (2021 – $3 million) in OM&G.
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, 2022
December 31, 2021
$ 0.5456
Floating
$ 1.1802
$ 1.1250
$ 1.0505
$ 1.2250
$ 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 2022 ANNUAL REPORT Characteristics of the First Preferred Shares:
First Preferred Shares (1) (2)
Fixed rate reset (3) (4)
Series A
Series C
Series F
Minimum rate reset (3) (4)
Series B
Series H
Series J
Perpetual fixed rate
Series E (5)
Series L (6)
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
1.1802
1.0505
Floating
1.2250
1.0625
1.1250
1.1500
1.84
2.65
2.63
1.84
4.90
4.25
August 15, 2025
August 15, 2023
February 15, 2025
August 15, 2025
August 15, 2023
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, 2023, February 15, 2025 and August 15, 2023,
respectively. The reset dividend yield for Series I equals the Government of Treasury Bill Rate on the applicable reset date, plus 2.54 per cent.
(5) First Preferred Shares, Series E are redeemable at $25.00 per share.
(6) 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 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
Domlec (1)
(1) On March 31, 2022, Emera disposed its interest in Domlec. For further details, refer to note 4.
December 31
2022
December 31
2021
$
$
14
–
$
14
$
14
20
34
133
Notes to the Consolidated Financial StatementsEMERA 2022 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
2022
2021
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
2021
2022
$
(214) $
(636)
423
193
(84)
(364)
289
7
$
(234) $
(152)
(1)
Includes $(162) million related to the January 2023 settlement of NMGC gas hedges. Offsetting regulatory liability is included in operating cash flow before
working capital resulting in no impact to net cash provided by operating activities.
(2) Includes $172 million related to the Nova Scotia Cap-and-Trade program. For further detail, refer to note 7. 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.
Supplemental disclosure of cash paid (received):
Interest
Income taxes
Supplemental disclosure of non-cash activities:
Common share dividends reinvested
Reclassification of long-term debt to short-term debt
Decrease in accrued capital expenditures
Supplemental disclosure of operating activities:
Net change in short-term regulatory assets and liabilities
31. Stock-Based Compensation
$ 699
67
$
$ 603
24
$
$
$
$
$
237
500
$
(13) $
214
–
(45)
$
(157) $
(108)
EMPLOYEE COMMON SHARE PURCHASE PLAN AND COMMON SHAREHOLDERS DIVIDEND
REINVESTMENT AND SHARE PURCHASE PLAN
Eligible employees may participate in Emera’s Employee Common Share Purchase Plan. As of December 31, 2022, the plan allows
employees to make cash contributions of a minimum of $25 to a maximum of $20,000 CAD or $15,000 USD per year for the
purpose of purchasing common shares of Emera. The Company also contributes 20 per cent of the employees’ contributions to
the plan.
The plan allows the reinvestment of dividends for all participants except for where it is prohibited by law. The maximum
aggregate number of Emera common shares reserved for issuance under this plan is 7 million common shares. As at
December 31, 2022, Emera is in compliance with this requirement.
134
Notes to the Consolidated Financial StatementsEMERA 2022 ANNUAL REPORT
Compensation cost for shares issued under the Employee Common Share Purchase Plan for the year ended December 31, 2022
was $3 million (2021 – $3 million) and is included in OM&G on the Consolidated Statements of Income.
The Company also has a Common Shareholders Dividend Reinvestment and Share Purchase Plan (“Dividend Reinvestment
Plan”), which provides an opportunity for shareholders to reinvest dividends and purchase common shares. This plan provides
for a discount of up to 5 per cent from the average market price of Emera’s common shares for common shares purchased in
connection with the reinvestment of cash dividends. The discount was 2 per cent in 2022.
STOCK-BASED COMPENSATION PLANS
Stock Option Plan
The Company has a stock option plan that grants options to senior management of the Company for a maximum term of
10 years. The option price of the stock options is the closing price of the Company’s common shares on the Toronto Stock
Exchange on the last business day on which such shares were traded before the date on which the option is granted. The
maximum aggregate number of shares issuable under this plan is 14.7 million shares. As at December 31, 2022, Emera is in
compliance with this requirement.
Stock options granted in 2021 and prior vest in 25 per cent increments on the first, second, third and fourth anniversaries of
the date of the grant. Stock options granted in 2022 vest in 20 per cent increments on the first, second, third, fourth and fifth
anniversaries of the date of the grant. If an option is not exercised within 10 years, it expires and the optionee loses all rights
thereunder. The holder of the option has no rights as a shareholder until the option is exercised and shares have been issued.
The total number of stocks to be optioned to any optionee shall not exceed five per cent of the issued and outstanding common
stocks on the date the option is granted.
For stock options granted in 2021 and prior, unless a stock option has expired, vested options may be exercised within the
27 months 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. Commencing with the 2022 stock option grant,
vested options may be exercised during the full term of the option following the option holders date of retirement, six months
following a termination without just cause or death, and within sixty days following the date of termination for just cause or
resignation. If stock options are not exercised within such time, they expire.
The Company uses the Black-Scholes valuation model to estimate the compensation expense related to its stock-based
compensation and recognizes the expense over the vesting period on a straight-line basis.
The following table shows the weighted average fair values per stock option along with the assumptions incorporated into the
valuation models for options granted, for the year-ended December 31:
Weighted average fair value per option
Expected term (1)
Risk-free interest rate (2)
Expected dividend yield (3)
Expected volatility (4)
2022
2021
$
5.35
5 years
1.79%
4.55%
18.87%
$
3.63
5 years
0.60%
5.00%
19.14%
(1) The expected term of the option awards is calculated based on historical exercise behaviour and represents the period of time that the options are expected
to be outstanding.
(2) Based on the Bank of Canada five-year government bond yields.
(3) Incorporates current dividend rates and historical dividend increase patterns.
(4) Estimated using the five-year historical volatility.
135
Notes to the Consolidated Financial StatementsEMERA 2022 ANNUAL REPORT The following table summarizes stock option information for 2022:
Outstanding as at December 31, 2021
Granted
Exercised
Vested
Options outstanding December 31, 2022
Total Options
Non-Vested Options (1)
Weighted
Average
Exercise Price
per Share
Number of
Options
Number of
Options
Weighted
Average Grant
Date Fair Value
2,590,304
467,100
(203,525)
N/A
$ 48.48
58.26
43.87
N/A
$
1,452,475
467,100
N/A
(571,175)
2,853,879
$ 50.41
1,348,400
$
3.18
5.35
N/A
2.83
4.08
Options exercisable December 31, 2022 (2) (3)
1,505,479
$ 46.59
(1) As at December 31, 2022, there was $4 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 (2021 – $3 million, 3 years).
(2) As at December 31, 2022, the weighted average remaining term of vested options was 5 years with an aggregate intrinsic value of $10 million (2021 –
6 years, $21 million).
(3) As at December 31, 2022, the fair value of options that vested in the year was $2 million (2021 – $1 million).
Compensation cost recognized for stock options for the year ended December 31, 2022 was $2 million (2021 – $2 million), which is
included in OM&G on the Consolidated Statements of Income.
As at December 31, 2022, cash received from option exercises was $9 million (2021 – $14 million). The total intrinsic value of
options exercised for the year ended December 31, 2022 was $4 million (2021 – $6 million). The range of exercise prices for the
options outstanding as at December 31, 2022 was $32.35 to $60.03 (2021 – $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 2022 ANNUAL REPORT A summary of the activity related to employee and director DSUs for the year ended December 31, 2022 is presented in the
following table:
Outstanding as at December 31, 2021
Granted including DRIP
Exercised
Outstanding and exercisable as at December 31, 2022
Employee
DSU
Weighted
Average Grant
Date Fair Value
Director
DSU
Weighted
Average Grant
Date Fair Value
610,601
76,252
(59,630)
627,223
$ 39.22
52.42
31.57
$ 41.55
614,365
104,465
(54,572)
664,258
$ 43.80
57.89
46.04
$ 45.83
Compensation cost recovery recognized for employee and director DSU’s for the year ended December 31, 2022 was $6 million
(2021 – $9 million expense). Tax expense related to this compensation cost recovery for share units realized for the year ended
December 31, 2022 was $2 million (2021 – $3 million tax recovery). The aggregate intrinsic value of the outstanding shares for
the year ended December 31, 2022 for employees was $33 million (2021 – $39 million). The aggregate intrinsic value of the
outstanding shares for the year ended December 31, 2022 for directors was $34 million (2021 – $39 million). Cash payments made
during the year ended December 31, 2021 associated with the DSU plan was $8 million (2021 – $11 million).
Performance Share Unit Plan
Under the PSU plan, certain executive and senior employees are eligible for long-term incentives payable through the PSU plan.
PSUs are granted annually for three-year overlapping performance cycles, resulting in a cash payment. PSUs are granted based
on the average of Emera’s stock closing price for the fifty trading days prior to the effective grant date. Dividend equivalents are
awarded and paid in the form of additional PSUs. The PSU value varies according to the Emera common share market price and
corporate performance.
PSUs vest at the end of the three-year cycle and the payouts will be calculated and approved by 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.
A summary of the activity related to employee PSUs for the year ended December 31, 2022 is presented in the following table:
Outstanding as at December 31, 2021
Granted including DRIP
Exercised
Forfeited
Outstanding as at December 31, 2022
Employee
PSU
951,935
242,462
(357,960)
(145,991)
690,446
Weighted
Average Grant
Date Fair Value
$ 48.60
59.30
42.85
44.28
$ 56.24
Aggregate
Intrinsic Value
$
66
$
40
Compensation cost recognized for the PSU plan for the year ended December 31, 2022 was $18 million (2021 – $12 million).
Tax benefits related to this compensation cost for share units realized for the year ended December 31, 2022 were $5 million
(2021 – $3 million). Cash payments made during the year ended December 31, 2021 associated with the PSU plan was $24 million
(2021 – $29 million).
Restricted Share Unit Plan
Under the RSU plan, certain executive and senior employees are eligible for long-term incentives payable through the RSU plan.
RSUs are granted annually for three-year overlapping performance cycles, resulting in a cash payment. RSUs are granted based
on the average of Emera’s stock closing price for the fifty trading days prior to the effective grant date. Dividend equivalents are
awarded and paid in the form of additional RSUs. The RSU value varies according to the Emera common share market price.
RSUs vest at the end of the three-year cycle and the payouts will be calculated and approved by 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.
137
Notes to the Consolidated Financial StatementsEMERA 2022 ANNUAL REPORT A summary of the activity related to employee RSUs for the year ended December 31, 2022 is presented in the following table:
Outstanding as at December 31, 2021
Granted including DRIP
Exercised
Forfeited
Outstanding as at December 31, 2022
Employee
RSU
Weighted
Average Grant
Date Fair Value
343,952
180,426
(134)
(15,776)
508,468
$ 54.64
59.30
54.63
56.08
$ 56.25
Aggregate
Intrinsic Value
$
24
$
30
Compensation cost recognized for the RSU plan for the year ended December 31, 2022 was $9 million (2021 – $8 million). Tax
benefits related to this compensation cost for share units realized for the year ended December 31, 2022 were $2 million (2021 –
$2 million). Cash payments made during the year ended December 31, 2022 associated with the RSU plan was nil (2021 – nil).
32. Variable Interest Entities
Emera holds a variable interest in NSPML, a VIE for which it was determined that Emera is not the primary beneficiary since it
does not have the controlling financial interest of NSPML. When the critical milestones were achieved, Nalcor Energy was deemed
the primary beneficiary of the asset for financial reporting purposes as it has authority over the majority of the direct activities
that are expected to most significantly impact the economic performance of the Maritime Link. Thus, Emera began recording the
Maritime Link as an equity investment.
BLPC has established a Self-Insurance Fund (“SIF”), primarily for the purpose of building a fund to cover risk against damage and
consequential loss to certain generating, transmission and distribution systems. ECI holds a variable interest in the SIF for which
it was determined that ECI was the primary beneficiary and, accordingly, the SIF must be consolidated by ECI. In its determination
that ECI controls the SIF, management considered that, in substance, the activities of the SIF are being conducted on behalf of
ECI’s subsidiary BLPC and BLPC, alone, obtains the benefits from the SIF’s operations. Additionally, because ECI, through BLPC,
has rights to all the benefits of the SIF, it is also exposed to the risks related to the activities of the SIF. Any withdrawal of SIF fund
assets by the Company would be subject to existing regulations. Emera’s consolidated VIE in the SIF is recorded as “Other long-
term assets”, “Restricted cash” and “Regulatory liabilities” on the Consolidated Balance Sheets. Amounts included in restricted
cash represent the cash portion of funds required to be set aside for the BLPC SIF.
The Company has identified certain long-term purchase power agreements that meet the definition of variable interests as
the Company has to purchase all or a majority of the electricity generation at a fixed price. However, it was determined that the
Company was not the primary beneficiary since it lacked the power to direct the activities of the entity, including the ability to
operate the generating facilities and make management decisions.
The following table provides information about Emera’s portion of material unconsolidated VIEs:
As at
millions of dollars
Unconsolidated VIEs in which Emera has variable interests
NSPML (equity accounted)
33. Comparative Information
December 31, 2022
December 31, 2021
Total Assets
Maximum
Exposure to
Loss
Total Assets
Maximum
Exposure to
Loss
$
501
$
6
$
533
$
11
These financial statements contain certain reclassifications of prior period amounts to be consistent with the current period
presentation, with no effect on net income.
34. Subsequent Events
These financial statements and notes reflect the Company’s evaluation of events occurring subsequent to the balance sheet date
through February 23, 2023, the date the financial statements were issued.
138
Notes to the Consolidated Financial StatementsEMERA 2022 ANNUAL REPORT Emera Leadership and Board
As of March 31, 2023
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
Ian Robertson
Oakville, Ontario
Andrea Rosen
Toronto, Ontario
Richard Sergel
Boston, Massachusetts
Karen Sheriff
Picton, Ontario
Jochen Tilk
Toronto, Ontario
139
EMERA 2022 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 2022 Annual
Report, is available on our website:
www.emera.com
Transfer Agent
TSX Trust Company
P.O. Box 2082, Station C
Halifax, NS 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
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 through the
System for Electronic Document Analysis
and Retrieval (SEDAR).
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: 269,944,308
(as of December 31, 2022)
Dividends Paid in 2022
Emera Inc. paid common share dividends
of $0.6625 per quarter in Q1, Q2 and Q3
(annualized rate of $2.65 per common
share) and $0.69 in Q4 (annualized
rate of $2.76 per common share), for an
effective annual common share dividend
rate of $2.6775 per common share.
Dividend Payments
in 2023
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
$0.69, a Series A First Preferred Share
dividend of $0.1364, a Series B First
Preferred Share dividend of $0.3570, a
Series C First Preferred Share dividend
of $0.29506, 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 $0.30625, 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, 2023.
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 2022,
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 2023. Year-end results for
2022 were released in February 2023.
Emera is represented in the TSX
Composite, TSX Capped Utilities, TSX60
and select MSCI and FTSE World indexes.
140
EMERA 2022 ANNUAL REPORT Our Operating Companies
As of March 31, 2023
TAMPA ELECTRIC
Vertically integrated electric utility
serving about 830,000 customers in
west central Florida.
NOVA SCOTIA POWER
Vertically integrated electric utility
serving approximately 540,000
customers in Nova Scotia.
PEOPLES GAS
Natural gas utility serving 470,000
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.
EMERA TECHNOLOGIES
A technology company focused
on finding new, innovative ways to
deliver renewable and resilient energy
to customers.
www.emera.com
SEE REVERSE FOR A FULL LIST OF OUR OPERATIONS
www.emera.com