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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM
40-F
 
REGISTRATION STATEMENT
 
PURSUANT TO SECTION 12 OF THE SECURITIES EXCHANGE ACT OF 1934
 
 
ANNUAL REPORT PURSUANT TO SECTION 13(a) OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended
December 31, 2023
Commission File Number
000-54516
EMERA INCORPORATED
(Exact name of Registrant as specified in its charter)
Nova Scotia, Canada
(Province or other jurisdiction of incorporation or organization)
4911
(Primary Standard Industrial Classification Code Number (if applicable))
Not applicable
(I.R.S. Employer Identification Number (if applicable))
5151 Terminal Road
 
Halifax
,
Nova Scotia
,
Canada
B3J 1A1
Telephone: (
902
)
428-6096
(Address and telephone number of Registrant’s principal executive offices)
Emera US Finance LP
c/o Corporation Service Company
251 Little Falls Drive
Wilmington
,
Delaware
 
19808
 
Telephone: (
302
)
636-5401
 
(Name, address (including zip code) and telephone number (including area code)
 
of agent for service in the United States)
Securities registered or to be registered pursuant to Section 12(b) of the Act:
 
Not applicable.
Securities registered or to be registered pursuant to Section 12(g) of the Act:
 
Not applicable.
Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act: Not applicable.
For annual reports, indicate by check mark the information filed with this Form:
 
Annual information form
 
Audited annual financial statements
Number of outstanding shares of each of the issuer’s classes of
capital or common stock as of December 31, 2023:
284,117,511
 
Common Shares
4,866,814
 
Series A First Preferred Shares
1,133,186
 
Series B First Preferred Shares
10,000,000
 
Series C First Preferred Shares
5,000,000
 
Series E First Preferred Shares
8,000,000
 
Series F First Preferred Shares
12,000,000
 
Series H First Preferred Shares
8,000,000
 
Series J First Preferred Shares
9,000,000
 
Series L First Preferred Shares
Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange
Act during the
 
preceding 12 months
 
(or for such
 
shorter period that
 
the Registrant was
 
required to file
 
such reports) and
 
(2) has
been subject to such filing requirements for the past 90 days.
Yes
 
No
 
Indicate by
 
check mark
 
whether the
 
registrant has
 
submitted electronically
 
and posted
 
on its
 
corporate Web
 
site, if
 
any,
 
every
Interactive Data File required to be submitted
 
and posted pursuant to Rule 405 of
 
Regulation S-T (§232.405 of this chapter) during
the preceding 12 months (or for such shorter period that the Registrant was required to submit and post such files).
Yes
 
 
No
 
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the
registrant included in the filing reflect the correction of an error to previously issued financial statements.
 
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-
based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to
§ 240.10D-1(b).
 
 
Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 12b-2 of the Exchange Act.
Emerging growth company
 
If an emerging growth company that prepares is
 
financial statements in accordance with U.S. GAAP, indicate by check mark if the
registrant
 
has
 
elected
 
not
 
to
 
use
 
the
 
extended
 
transition
 
period
 
for
 
complying
 
with
 
any
 
new
 
or
 
revised
 
financial
 
accounting
standards
 
provided pursuant to Section 13(a) of the Exchange Act.
 
 
The term “new
 
or revised financial accounting
 
standard” refers to any
 
update issued by the
 
Financial Accounting Standards
 
Board
to its Accounting Standards Codification after April 5, 2012.
Indicate
 
by
 
check
 
mark
 
whether
 
the
 
registrant
 
has
 
filed
 
a
 
report
 
on
 
and
 
attestation
 
to
 
its
 
management’s
 
assessment
 
of
 
the
effectiveness of its
 
internal control over financial
 
reporting under Section 404(b)
 
of the Sarbanes-Oxley Act
 
(15 U.S.C. 7262(b))
by the registered public accounting firm that prepared or issued its audit report.
 
 
Certifications and Disclosure Regarding Controls and Procedures.
(a)
 
Certifications regarding controls and procedures. See Exhibits 99.5 and 99.6.
(b)
 
Evaluation of disclosure controls and procedures. As of December 31,
2023
, an evaluation of the
effectiveness of the Registrant’s “disclosure controls and procedures” (as such term is defined in Rules 13a-
15(e) and 15d-15(e) of the United States Securities Exchange Act of 1934, as amended (the “Exchange
Act”)), was carried out by the Registrant’s Chief Executive Officer (“CEO”) and Chief Financial Officer
(“CFO”). Based on that evaluation, the CEO and CFO have concluded that as of such date the Registrant’s
disclosure controls and procedures are effective to provide a reasonable level of assurance that information
required to be disclosed by the Registrant in reports that it files or submits under the Exchange Act is
recorded, processed, summarized and reported within the time periods specified in the United States
Securities and Exchange Commission’s (the “Commission”) rules and forms.
It should be noted that while the CEO and CFO believe that the Registrant’s disclosure controls and
procedures provide a reasonable level of assurance that they are effective, they do not expect the disclosure
controls and procedures or internal control over financial reporting to be capable of preventing all errors
and fraud. A control system, no matter how well conceived or operated, can provide only reasonable, not
absolute, assurance that the objectives of the control system are met.
(c)
 
Management’s annual report on internal control over financial reporting.
 
The Registrant's management is
responsible for establishing and maintaining adequate internal control over financial reporting. The
Registrant'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. The Registrant's management, including the CEO and CFO, evaluated the
design and effectiveness of the Registrant's internal control over financial reporting as at December 31,
2023 and concluded that the Registrant's internal control over financial reporting is effective as at
December 31,
2023
.
(d)
 
Attestation report of the registered public accounting firm.
 
This annual report does not include an
attestation report of the Registrant’s registered public accounting firm regarding internal control over
financial reporting.
 
(e)
 
Changes in internal control over financial reporting. There were no changes in the Registrant’s internal
control over financial reporting during the fiscal year ended December 31,
2023
, that have materially
affected, or are reasonably likely to materially affect, the Registrant’s internal control over financial
reporting.
Audit Committee Financial Expert.
 
The Registrant’s board of directors (the “Board”) has determined that five
audit committee financial experts serve on its Audit Committee. The audit committee financial experts are Paula Y.
Gold-Williams, Kent M. Harvey, B. Lynn
 
Loewen, Ian E. Robertson, and Andrea S. Rosen. The Board has
determined that Paula Y.
 
Gold-Williams, Kent M. Harvey, B. Lynn
 
Loewen, Ian E. Robertson, and Andrea S. Rosen
are independent within the meaning of the listing standards of the New York Stock Exchange. Information
concerning the relevant experience of Paula Y.
 
Gold-Williams, Kent M. Harvey, B. Lynn
 
Loewen, Ian E. Robertson,
and Andrea S. Rosen is included in their biographical information contained in the Registrant’s Annual Information
Form for the fiscal year ended December 31,
2023
, filed as Exhibit 99.1 hereto (the “Annual Information Form”).
The Commission has indicated that the designation of a person as an audit committee financial expert does not make
such person an “expert” for any purpose, impose any duties, obligations or liability on such person that are greater
than those imposed on members of the audit committee and board of directors who do not carry this designation, or
affect the duties, obligations or liability of any other member of the audit committee or board of directors.
Code of Ethics.
 
The Emera Code of Conduct was revised and became effective on October 1,
2023
 
(the “Code”) and
applies to all directors, officers and employees of the Registrant, including the CEO and CFO. Since the adoption of
the Code, there have not been any waivers, including implied waivers, from any provision of the Code. A copy of
the Code can be found on Emera’s internet website at the following address: https://www.emera.com/about-us/who-
we-are/code-of-conduct.
 
 
 
 
The Code was furnished to the Commission on November 24, 2023 as Exhibit 99.1 to a report on Form 6-K and is
incorporated by reference herein as Exhibit 99.9.
Principal Accountant Fees and Services.
 
The information provided under the headings “Audit Committee—Audit
and Non-Audit Services Pre-Approval Process” and “Audit Committee—Auditors’ Fees” contained in the
Registrant’s Annual Information Form. The Registrant’s Audit Committee approved all of the Audit-Related and
Tax services provided by Ernst & Young
 
LLP in
2023
 
and none were approved pursuant to the de minimis exception
provided by Section (c)(7)(i)(C) of Rule 2-01 of Regulation S-X.
In connection with the Commission’s adoption of amendments to finalize the implementation of disclosure and
submission requirements on December 2, 2021, pursuant to Release No. 34-93701, the Registrant hereby affirms
that
 
Ernst & Young LLP (PCAOB ID:
1263
) delivered an audit opinion relating to the Registrant’s Financial
Statements (as defined below) contained in the Annual Information Form, and such audit opinion was issued in
Halifax, Nova Scotia, Canada.
Liquidity and Capital Resources
The information provided under the headings (a) “Off-Balance Sheet Arrangements” and (b) “Contractual
Obligations” contained in the Registrant’s Management’s Discussion and Analysis dated
February 26, 2024
 
for the
year ended December 31,
2023
, filed as Exhibit 99.2 hereto (the “MD&A”) and with respect to clause (a) the
information provided at note 27 (“D. Guarantees and Letters of Credit”) and note 32 (“Variable Interest Entities”),
and with respect to clause (b) note 27 (“A. Commitments”) and note 25 (“Long-Term Debt”), to the Audited
Consolidated Financial Statements as at and for the years ended December 31,
2023
 
and December 31,
2022
, filed as
Exhibit 99.3 hereto (the “Financial Statements”), are incorporated by reference herein.
Identification of the Audit Committee.
 
The information provided under the heading “Audit Committee” contained
in the Annual Information Form is incorporated by reference herein.
Mine Safety Disclosure.
 
Neither the Registrant nor any of its subsidiaries is the “operator” of any “coal or other
mine”, as those terms are defined in section 3 of the Federal Mine Safety and Health Act of 1977 (30 U.S.C. 802),
that is subject to the provisions of such Act (30 U.S.C. 801 et seq.). Therefore, the provisions of Section 1503(a) of
the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 16 of General Instruction B to Form 40-
F requiring disclosure concerning mine safety violations and other regulatory matters do not apply to the
 
Registrant
or any of its subsidiaries.
EXHIBIT INDEX
Exhibit
Number
Description
99.1
99.2
99.3
99.4
99.5
99.6
UNDERTAKING
 
AND CONSENT TO SERVICE OF PROCESS
The Registrant undertakes to make available, in person or by telephone, representatives to respond to inquiries made
by the Commission staff, and to furnish promptly, when requested to do so by the Commission staff, information
relating to the securities in relation to which the obligation to file an annual report on Form 40-F arises or
transactions in said securities.
The Registrant has previously filed a Form F-X in connection with the class of securities in relation to which the
obligation to file this report arises.
Any change to the name or address of a Registrant’s agent for service shall be communicated promptly to the
Commission by amendment to Form F-X referencing the file number of the Registrant.
 
 
SIGNATURES
Pursuant to the requirements of the Exchange Act, the Registrant certifies that it meets all of the requirements for
filing on Form 40-F and has duly caused this annual report to be signed on its behalf by the undersigned, thereto
duly authorized.
DATED
 
this 26
th
day of February, 2024.
EMERA
INCORPORATED
By:
 
/s/ Scott C. Balfour
Name:
 
Scott C. Balfour
Title:
 
President & Chief
Executive Officer

Exhibit 99.1

 

 

LOGO

Emera Incorporated

Annual Information Form

For the year ended December 31, 2023

February 26, 2024


ANNUAL INFORMATION FORM

For the year ended December 31, 2023

Dated: February 26, 2024

TABLE OF CONTENTS

 

PRESENTATION OF INFORMATION

     4  

CAUTIONARY NOTE REGARDING FORWARD-LOOKING INFORMATION

     4  

CORPORATE STRUCTURE

     5  

Name and Incorporation

     5  

Amended Articles of Association

     6  

Intercorporate Relationships

     6  

INTRODUCTION

     6  

DESCRIPTION OF THE BUSINESS

     8  

Business Segments

     8  

Florida Electric Utility

     8  

Canadian Electric Utilities

     11  

Gas Utilities and Infrastructure

     14  

Other Electric Utilities

     16  

Other

     18  

GENERAL DEVELOPMENT OF THE BUSINESS

     19  

Florida Electric Utility

     19  

Canadian Electric Utilities

     21  

Gas Utilities and Infrastructure

     25  

Other Electric Utilities

     26  

USGAAP – Exemptive Relief

     27  

Financing Activity

     27  

RISK FACTORS

     29  

CAPITAL STRUCTURE

     29  

Common Shares

     29  

Emera First Preferred Shares

     30  

Emera Second Preferred Shares

     30  

Share Ownership Restrictions

     30  

CREDIT RATINGS

     31  

DIVIDENDS

     33  

MARKET FOR SECURITIES

     34  

Trading Price and Volume

     34  

At-The-Market Equity Program

     34  

DIRECTORS AND OFFICERS

     35  

Directors

     35  

Officers

     37  

 

Emera Incorporated – 2023 Annual Information Form    2


AUDIT COMMITTEE

     38  

Audit and Non-Audit Services Pre-Approval Process

     39  

Auditors’ Fees

     40  

CERTAIN PROCEEDINGS

     40  

CONFLICTS OF INTEREST

     40  

LEGAL PROCEEDINGS AND REGULATORY ACTIONS

     41  

NO INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

     41  

MATERIAL CONTRACTS

     41  

TRANSFER AGENT AND REGISTRAR

     41  

EXPERTS

     41  

ADDITIONAL INFORMATION

     41  

APPENDIX “A” - DEFINITIONS OF CERTAIN TERMS

     42  

APPENDIX “B” – SUMMARY OF TERMS AND CONDITIONS OF AUTHORIZED SERIES OF FIRST PREFERRED SHARES

     46  

APPENDIX “C” - MONTHLY TRADING VOLUME AND HIGH AND LOW PRICE FOR EMERA’S SECURITIES IN 2023

     49  

APPENDIX “D” - EMERA INCORPORATED AUDIT COMMITTEE CHARTER

     50  

 

Emera Incorporated – 2023 Annual Information Form    3


PRESENTATION OF INFORMATION

Unless otherwise noted, the information contained in this Annual Information Form (“AIF”) is given at or for the year ended December 31, 2023. Amounts are expressed in Canadian dollars unless otherwise indicated. All financial information presented in millions of Canadian dollars is rounded to the nearest million unless otherwise stated. Unless otherwise indicated, all financial information is presented in accordance with United States’ generally accepted accounting principles (“USGAAP”). Emera Incorporated (“Emera” or “the Company”) uses Adjusted Net Income Attributable to Common Shareholders (“adjusted net income”) as a financial performance measure, which is not a defined financial measure according to USGAAP and does not have standardized meanings prescribed by USGAAP. For further information on the non-GAAP financial measure, adjusted net income, including a full description of the measure and a reconciliation to the nearest USGAAP measure, please refer to the Company’s MD&A section entitled “Non-GAAP Financial Measures and Ratios”, which is incorporated herein by reference, a copy of which is available electronically under Emera’s profile on SEDAR+ at www.sedarplus.ca.

Certain capitalized terms used herein, and not otherwise defined herein, are defined under “Definitions of Certain Terms”, attached to this AIF as Appendix “A”. References to “including”, “include”, or “includes” means “including (or includes) but is not limited to” and shall not be construed to limit any general statement preceding it to the specific or similar items or matters immediately following it.

This AIF provides material information about the business and operations of Emera. The “Enterprise Risk and Risk Management” section of the Company’s MD&A is incorporated herein by reference and can be found on SEDAR+ at www.sedarplus.ca.

CAUTIONARY NOTE REGARDING FORWARD-LOOKING INFORMATION

This AIF, including the documents incorporated herein by reference, contains “forward-looking information” and “forward-looking statements” within the meaning of applicable securities laws (collectively, “forward-looking information”). 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. References to “Emera” in this section include references to the subsidiaries of Emera.

The forward-looking information in this AIF, including the documents incorporated herein by reference, includes statements which reflect the current view of Emera’s management with respect to Emera’s objectives, plans, financial and operating performance, carbon dioxide emissions reduction goals, business prospects and opportunities. 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(s) at which, such events, performance or results will be achieved. All such forward-looking information in this AIF is provided pursuant to safe harbour provisions contained in applicable securities laws.

The forward-looking information in this AIF, including the documents incorporated herein by reference, includes, but is not limited to, statements regarding: Emera’s revenue, earnings and cash flow; the growth and diversification of Emera’s business and earnings base; future annual net income and dividend growth; expansion of Emera’s business; the expected compliance by Emera with the regulation of its operations; the expected timing of regulatory decisions; forecasted capital investments; the nature, timing and costs associated with certain capital projects; the expected impact on Emera of challenges in the global economy; estimated energy consumption rates; expectations related to annual operating cash flows; the expectation that Emera will continue to have reasonable access to capital in the near to medium term; expected debt maturities, repayments and renewals; expectations about increases in interest expense and/or fees associated with debt securities and credit facilities; no material adverse credit rating actions expected in the near term; the successful development of relationships with various stakeholders, the impact of currency fluctuations; expected changes in electricity rates; and the impacts of planned investment by the industry of gas transportation infrastructure within the United States.

 

Emera Incorporated – 2023 Annual Information Form    4


The forecasts and projections that make up the forward-looking information are based on reasonable assumptions which include, but are not limited to: the receipt of applicable regulatory approvals and requested rate decisions; no significant operational disruptions or environmental liability due to a catastrophic event or environmental upset caused by severe weather or global climate change, other acts of nature or other major events; seasonal weather patterns remaining stable; no significant cyber or physical attacks or disruptions to Emera’s systems; the continued ability to maintain transmission and distribution systems to ensure their continued performance; continued investment in solar, wind and hydro generation; continued natural gas activity; no severe and/or prolonged downturn in economic conditions; sufficient liquidity and capital resources; the continued ability to hedge exposures to fluctuations in interest rates, foreign exchange rates and commodity prices; no significant variability in interest rates; expectations regarding the nature, timing and costs of capital investments of Emera and its subsidiaries; expectations regarding rate base growth; the continued competitiveness of electricity pricing when compared with other alternative sources of energy; the continued availability of commodity supply; the absence of significant changes in government energy plans and environmental laws and regulations that may materially affect Emera’s operations and cash flows; maintenance of adequate insurance coverage; the ability to obtain and maintain licenses and permits; no material decrease in market energy sales prices; favourable labour relations; and sufficient human resources to deliver service and execute Emera’s capital investment plan.

The forward-looking information 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, but are not limited to: regulatory and political risk; operating and maintenance risks; changes in economic conditions; commodity price and availability risk; liquidity and capital market risk; changes in credit ratings; future dividend growth; timing and costs associated with certain capital investments; expected impacts on Emera of challenges in the global economy; estimated energy consumption rates; maintenance of adequate insurance coverage; changes in customer energy usage patterns; developments in technology that could reduce demand for electricity; global climate change; weather risk, including higher frequency and severity of weather events; risk of wildfires; unanticipated maintenance and other expenditures; system operating and maintenance risk; derivative financial instruments and hedging; interest rate risk; inflation risk; counterparty risk; disruption of fuel supply; country risks; supply chain risk; environmental risks; foreign exchange (“FX”); regulatory and government decisions, including changes to environmental legislation, financial reporting and tax legislation; risks associated with pension plan performance and funding requirements; loss of service area; risk of failure of information technology infrastructure and cybersecurity risks; uncertainties associated with infectious diseases, pandemics and similar public health threats; market energy sales prices; labour relations; and availability of labour and management resources.

Readers are cautioned not to place undue reliance on 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 AIF and in the documents incorporated herein by reference 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.

CORPORATE STRUCTURE

Name and Incorporation

Emera was incorporated on July 23, 1998 pursuant to the Companies Act (Nova Scotia). The Reorganization Act and the Privatization Act require the Company’s Articles of Association (the “Articles”) to contain provisions specifying that the head office and the principal executive offices of the Company are to be situated in the Province of Nova Scotia. The current address of the Company’s registered office, head office and principal executive offices is Emera Place, 5151 Terminal Road, Halifax, Nova Scotia, Canada, B3J 1A1.

 

Emera Incorporated – 2023 Annual Information Form    5


Amended Articles of Association

On April 12, 2019, amendments to the Privatization Act and the Reorganization Act were enacted, removing the legislative restriction preventing non-Canadian residents from holding more than 25 per cent of Emera voting shares, in aggregate. These legislative amendments did not alter the existing 15 per cent individual share ownership restriction, as described below in the section entitled “Capital Structure – Share Ownership Restrictions”. The Board approved amendments to the Company’s Articles and on July 11, 2019, shareholders passed a special resolution to amend the Articles to remove this non-Canadian resident ownership restriction. For more information on these amendments to the Articles, please refer to Emera’s Management Information Circular dated May 31, 2019 distributed in connection with a special meeting of shareholders held on July 11, 2019, a copy of which is available electronically under Emera’s profile on SEDAR+ at www.sedarplus.ca.

Intercorporate Relationships

The following table sets forth the relationships among the Company and its principal subsidiaries, the percentage of votes attaching to all voting securities of its respective subsidiaries beneficially owned, or controlled or directed, directly or indirectly, by the Company, as well as their respective jurisdictions of incorporation, continuance, formation or organization. This table excludes certain subsidiaries, the assets and revenues of which did not individually exceed 10 per cent, or in the aggregate exceed 20 per cent, of the total consolidated assets or total consolidated revenues of the Company as at December 31, 2023.

 

 Subsidiaries   

 Percentage Ownership 

(%)

    Jurisdiction       

Tampa Electric Company1

   100    Florida       

Nova Scotia Power

   100    Nova Scotia     

Peoples Gas System1

   100    Florida     

New Mexico Gas Company

   100    Delaware     

 

  (1)

Tampa Electric Company has historically included both its regulated electric and gas utilities, namely the Tampa Electric Division and the Peoples Gas System Division. Effective January 1, 2023, PGS ceased to be a division of TEC and the gas utility was reorganized, resulting in a separate legal entity called Peoples Gas System, Inc. (existing under the laws of the State of Florida, and a wholly-owned direct subsidiary of TECO Gas Operations, Inc.

INTRODUCTION

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 investments in rate-regulated businesses are located in Florida with other investments in Nova Scotia, New Mexico and the Caribbean. Emera’s portfolio of regulated utilities provides reliable earnings, cash flow and dividends. Earnings opportunities in regulated utilities are generally driven by the magnitude of net investment in the utility (known as “rate base”), and the amount of equity in the capital structure and the ROE as approved through regulation. Earnings are also affected by sales volumes and operating expenses.

Emera’s capital investment plan is approximately $9 billion over the 2024 through 2026 period with approximately $2 billion of additional potential capital investments over the same period. The capital investment plan and additional potential capital result in an anticipated compound annual rate base growth in the range of approximately 7 per cent to 8 per cent through 2026. The capital investment plan includes significant investments across the portfolio in renewable and cleaner generation, reliability and system integrity investments, infrastructure modernization, infrastructure expansion to meet the needs of new and existing customers, and technologies to better support the business and customer experiences. It is

 

Emera Incorporated – 2023 Annual Information Form    6


anticipated that approximately 75 per cent of Emera’s $9 billion capital investment plan over the 2024 through 2026 period will be made in Florida.

Emera’s capital investment plan is being funded primarily through internally generated cash flows, debt raised at the operating company level consistent with regulated capital structures, equity, and select asset sales. Generally, equity requirements in support of the Company’s capital investment plan are expected to be funded through the issuance of preferred equity and the issuance of common equity through Emera’s DRIP and ATM Program. Maintaining investment-grade credit ratings is a priority of the Company.

Emera has provided annual dividend growth guidance of four to five per cent through 2026. The Company targets a long-term dividend payout ratio of adjusted net income of 70 to 75 per cent and, while the payout ratio is likely to exceed that target through and beyond the forecast period, it is expected to return to that range over time. For further information on the non-GAAP measure “Dividend Payout Ratio of Adjusted Net Income”, refer to the “Non-GAAP Financial Measures and Ratios” section of the MD&A, which is hereby incorporated by reference, a copy of which is available electronically under Emera’s profile on SEDAR+ at www.sedarplus.ca.

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 CAD. Emera may hedge both transactional and translational exposure. These impacts, as well as the timing of capital investments and other factors, mean results in any one quarter are not necessarily indicative of results in any other quarter, or for the year as a whole.

Energy markets worldwide are experiencing significant change and Emera is well-positioned to continue to respond to shifting customer demands and meet the challenges of digitization, decarbonization and decentralized generation, within complex regulatory environments.

Customers depend on energy and are looking for more choice, better control, and greater reliability. The costs of decentralized generation and storage have become more competitive and advancing technologies are transforming how utilities operate and interact with customers. Concurrently, climate change and the increased frequency of extreme weather events are shaping government energy policy. This is also creating a need to replace aging infrastructure and make investments to protect and harden energy systems to deliver energy reliability and system resiliency. These factors combined with inflation, higher interest rates and higher cost of capital place increased pressure on energy costs, and thus customer rates, at a time when affordability is a challenge.

Emera’s strategy is to invest in the energy future, including infrastructure renewal, centered on delivering value for customers, and in doing so creating value for shareholders. This includes:

 

   

investing in cleaner and renewable sources of energy, in the related transmission assets, and in energy storage needed to support intermittent renewables;

 

   

supporting increasing demand from customers and the ongoing electrification of other sectors;

 

   

improving system reliability and resiliency, including replacing aging infrastructure and expanding systems to service new customers; and

 

   

investing in new internal and customer-facing technologies for improved cost efficiency and better customer experiences.

Building on its decarbonization progress, Emera is continuing its efforts by establishing clear carbon reduction goals and a vision to achieve net-zero carbon dioxide emissions by 2050.

This vision is inspired by Emera’s strong track record, the Company’s experienced team, and a visible path to Emera’s interim carbon goals. With existing technologies and resources, and subject to supportive government and regulatory decisions, Emera is working to achieve the following goals compared to corresponding 2005 levels:

 

Emera Incorporated – 2023 Annual Information Form    7


   

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.

DESCRIPTION OF THE BUSINESS

Business Segments

Emera’s reportable segments are:

 

   

Florida Electric Utility, which consists of TEC;

 

   

Canadian Electric Utilities, which includes NSPI and ENL, a holding company with equity interests in NSPML (100 per cent) and the LIL (31 per cent);

 

   

Gas Utilities and Infrastructure, which includes PGS, NMGC, Emera Brunswick Pipeline Company, SeaCoast and an equity interest in M&NP (12.9 per cent);

 

   

Other Electric Utilities, which includes ECI, a holding company with regulated electric utilities which include BLPC, GBPC and an equity interest in Lucelec (19.5 per cent); and

 

   

Other, which includes Emera Energy, Block Energy and corporate holding, financing companies and certain other investments.

General

Emera and its subsidiaries had 7,366 employees as at December 31, 2023, approximately 30 per cent of whom are unionized.

Operations by Segment

The following sections describe the operations included in each of the Company’s reportable segments.

Florida Electric Utility

Florida Electric Utility consists of TEC, a vertically integrated regulated electric utility engaged in the generation, transmission and distribution of electricity, serving customers in West Central Florida. TEC has $12 billion USD of assets, approximately 840,000 customers and 2,546 employees as at December 31, 2023.

TEC is regulated by the FPSC and is also subject to regulation by the FERC. The FPSC sets rates at a level that allows utilities such as TEC to collect total revenues or revenue requirements equal to their cost of providing service, plus an appropriate return on invested capital. Base rates are determined in FPSC rate setting hearings which occur at the initiative of TEC, the FPSC or other interested parties.

TEC’s approved regulated ROE range is 9.25 per cent to 11.25 per cent, based on an allowed equity capital structure of 54 per cent. An ROE of 10.20 per cent is used for the calculation of the return on investments for clauses.

 

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For further details on TEC’s regulatory environment, base rates and recovery mechanisms, refer to Note 6, Regulatory Assets and Liabilities, in the Audited Financial Statements, which are hereby incorporated by reference, a copy of which is available electronically under Emera’s profile on SEDAR+ at www.sedarplus.ca.

Market and Sales

 

TEC Revenue and Sales Volumes by Customer Class
       Electric Revenues (%)       GWh Electric Sales Volumes  (%) 
For the year ended December 31     2023       2022       2023       2022  

Residential

  64.9   54.7   49.0   48.4

Commercial

  30.4   26.4   30.7   30.2

Industrial

  7.7   7.0   9.9   10.1

Other

  (3.0)1   11.9   10.4   11.3

Total

  100.0   100.0   100.0   100.0

 

  (1)

Other includes regulatory deferrals related to clauses, sales to public authorities, off-system sales to other utilities.

Energy Sources and Generation

As at December 31, 2023, TEC owns 6,433 MW of generating capacity, of which 74 per cent is natural gas fired, 19 per cent is solar and 7 per cent is coal. TEC owns 2,192 kilometres of transmission facilities and 20,299 kilometres of distribution facilities. TEC meets the planning criteria for reserve capacity established by the FPSC, which is a 20 per cent reserve margin over firm peak demand.

System Operations

TEC’s Energy Control Center co-ordinates and controls the electric generation, transmission and distribution facilities. The Energy Control Center is linked to the generating stations and other key facilities through the Supervisory Control and Data Acquisition system, a communication network used by system operators for remote monitoring and control of the power system assets.

Through interconnection agreements with our neighboring electric utilities within the Florida Region, TEC’s system has access to other regional power systems and the rest of the interconnected North American electric bulk power system. The interconnection of power systems enhances the cost effectiveness, reserve capacity and reliability of participating power systems. As a member of the Florida Reserve Sharing Group, TEC has immediate access to reserve generating capacity from all other group members.

Contribution to Consolidated Net Income

Florida Electric Utility’s contribution to consolidated net income was $466 million USD in 2023 (2022 – $458 million USD).

Seasonal Nature

Electric sales volumes are primarily driven by general economic conditions, population and weather. Residential and commercial electricity sales are seasonal. In Florida, Q3 is the strongest period for electricity sales, reflecting warmer weather and cooling demand.

Capital Investments

In 2023, capital investments, including AFUDC, in the Florida Electric Utility segment were $1.3 billion USD (2022 – $1.1 billion USD). In 2024, capital investment is expected to be approximately $1.3 billion USD, including AFUDC. Capital projects include solar investments, grid modernization, storm hardening investments and other infrastructure investments.

 

Emera Incorporated – 2023 Annual Information Form    9


Environmental Considerations

TEC has significant environmental considerations. TEC operates stationary sources with air emissions regulated by the Clean Air Act. Its operations are also impacted by provisions in the Clean Water Act and federal and state legislative initiatives on environmental matters.

Hazardous Air Pollutants

All of TEC’s conventional coal-fired units are already equipped with electrostatic precipitators, scrubbers and selective catalytic reduction systems, and the Polk Unit 1 integrated gasification combined-cycle unit emissions are minimized in the gasification process. Therefore, TEC has minimized the impact of the EPA’s current Mercury Air Toxics Standards (“MATS”) and has demonstrated compliance on all applicable units with the most stringent “Low Emitting Electric Generating Unit” classification for the EPA’s current MATS with nominal additional capital investment.

Carbon Reductions and GHG

In June 2019, the EPA released a final rule, named the Affordable Clean Energy (“ACE”) rule, to establish emission guidelines for states to address GHG emissions from existing coal-fired electric generating units (“EGUs”). EPA released a proposed rule establishing CO2 emission standards for new and existing fossil fuel-fired power plants. As proposed under Section 111 of the Clean Air Act, the New Source Performance Standards and Best System of Emission Reduction guidelines would require affected electric generating units to achieve CO2 emission limits thorough the implementation of carbon capture and sequestration, or low-GHG hydrogen co-firing. The proposed rule also repeals the ACE rule promulgated under the Trump Administration. TEC expects one or more units to be subject to the rule, if finalized in its current form.

TEC expects that the costs to comply with new environmental regulations would be eligible for recovery through the ECRC. If approved as prudent, the costs required to comply with CO2 emissions reductions would be reflected in customers’ bills. If the regulation allowing cost recovery is changed and the cost of compliance is not recovered through the ECRC, TEC could seek to recover those costs through a base-rate proceeding.

Ozone

On December 31, 2020, the EPA published a final rule to retain the national ambient air quality standards (“NAAQS”) for photochemical oxidants including ozone, originally adopted in 2012. Under the Clean Air Act, the EPA is required to review the NAAQS every five years and, if appropriate, revise it. The EPA has announced that the NAAQS is currently under review, which could result in revisions to the standard affecting compliance in TEC’s service territory. The impact of this potential new standard on the operations of TEC will depend on the standard that is ultimately adopted and on the outcome of any related litigation or other developments.

Water Supply and Quality

The EPA’s final rule under 316(b) of the Clean Water Act (effective October 2014) addresses perceived impacts to aquatic life by cooling water intakes and is applicable to TEC’s Bayside and Big Bend Power Stations. Polk Power Station is not covered by this rule since it does not operate an intake on waters of the U.S. TEC has two ongoing projects (one for Bayside and one for Big Bend) that require compliance with the rule. The Florida Department of Environmental Protection (“FDEP”) agreed with TEC’s proposed plan for Bayside and TEC began a multi-year construction project to install new fish-friendly modified traveling screens and a fish return in 2022. Compliance study elements have been completed and submitted for Bayside. TEC is negotiating an alternative schedule for a portion of the compliance requirements with the Big Bend modernization project, with the remainder of the compliance requirements to be determined and completed at a later date. The full impact of the regulations on TEC will depend on the outcome of subsequent legal proceedings challenging the rule, the results of the study elements performed as part of the rules’ implementation, and the actual requirements established by FDEP.

 

Emera Incorporated – 2023 Annual Information Form    10


The final EPA rule for existing steam electric effluent limit guidelines (“ELGs”) became effective January 4, 2016 and establishes limits for certain wastewater discharges. The ELGs are expected to be incorporated into National Pollutant Discharge Elimination System (“NPDES”) permit renewals for Big Bend Station and Polk Power Station to achieve compliance as soon as possible after November 1, 2018, but no later than December 31, 2023. The EPA proposed a new rule in March 2023 to strengthen discharge limits that is expected to be finalized in 2024.

The preliminary draft of the NPDES Permit for Big Bend stated that effluent limitations for total recoverable arsenic, mercury, and selenium and total nitrate/nitrite for flue gas desulfurization wastewater are applicable no later than December 31, 2023. Big Bend completed construction of a deep injection well system in December 2023 for disposal of various wastewaters. The effluent limitations do not apply to Polk Power Station.

Superfund and Former Manufactured Gas Plant Sites

Previously, TEC had been a potentially responsible party (“PRP”) for certain superfund sites through its Tampa Electric and former PGS divisions, as well as for certain former manufactured gas plant sites through its PGS division. As a result of the separation of the PGS division into a separate legal entity, PGS is also now a PRP for those sites (in addition to third party PRPs for certain sites). For further details, refer to Note 27, Commitments and Contingencies – Legal Proceedings - Superfund and Former Manufactured Gas Plant Sites, in the Audited Financial Statements, which is hereby incorporated by reference, a copy of which is available electronically under Emera’s profile on SEDAR+ at www.sedarplus.ca.

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 a 100 per cent equity investment in NSPML and a 31 per cent equity investment in LIL: two transmission investments related to the development of an 824 MW hydroelectric generating facility at Muskrat Falls hydroelectric project (“Muskrat Falls”) on the Lower Churchill River in Labrador.

NSPI

NSPI is the primary electricity supplier in Nova Scotia, providing electricity generation, transmission and distribution services to approximately 549,000 customers with $7.2 billion in assets and 2,179 employees as at December 31, 2023.

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.

NSPI has a FAM, approved by the UARB, allowing NSPI to recover fluctuating fuel and certain fuel-related costs from customers through regularly scheduled fuel rate adjustments. Differences between prudently incurred fuel costs and amounts recovered from customers through electricity rates in a year are deferred to a FAM regulatory asset or liability and recovered from or returned to customers in subsequent periods.

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.

For further details on NSPI’s regulatory environment and recovery mechanisms, refer to Note 6, Regulatory Assets and Liabilities, in the Audited Financial Statements, which are hereby incorporated by reference, a copy of which is available electronically under Emera’s profile on SEDAR+ at www.sedarplus.ca.

 

Emera Incorporated – 2023 Annual Information Form    11


Market and Sales

 

                                                                                                               
NSPI Revenue and Electricity Sales Volumes by Customer Class
      Electric Revenues (%)     GWh Electric  Sales Volumes (%) 
For the year ended December 31    2023     2022    2023   2022
Residential   55.7   50.8   47.8   46.1
Commercial   28.4   26.0   29.2   28.8
Industrial   13.4   21.5   20.7   23.7
Other   2.5   1.7   2.3   1.4
Total   100.0   100.0   100.0   100.0

Energy Sources and Generation

NSPI owns 2,422 MW of generating capacity, of which 44 per cent is coal and/or oil-fired, 28 per cent is natural gas and/or oil, 19 per cent is hydro, wind, or solar, 7 per cent is petroleum coke and 2 per cent is biomass-fueled generation. In addition, NSPI has contracts to purchase renewable energy from IPPs, and COMFIT participants, which own 532 MW of capacity. NSPI also has rights to 153 MW of Maritime Link capacity, representing Nalcor’s NS Block delivery obligations, as discussed below.

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. 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.

System Operations

NSPI’s Control Center Operations co-ordinates and controls the electric generation, transmission and distribution facilities with the goal of providing safe, reliable and efficient electricity supply while adhering to applicable environmental requirements and regulations. The Control Center is linked to the generating stations and other key facilities through the Supervisory Control and Data Acquisition system, a software applicaction used by system operators for remote monitoring and control of the power system assets via the company’s telecommunication networks.

Through interconnection agreements with NB Power and with Newfoundland and Labrador Hydro, NSPI’s system has access to other regional power systems and the interconnected North American bulk electric system. The interconnection of power systems enhances the cost effectiveness, reserve capacity and reliability of participating power systems. The interconnection agreements also provide participating utilities with a source of reserve power, subject to availability, transmission line capacity and the requirements of the supplier.

NSPI is a member of the NPCC, a body whose primary role is promoting the reliability of the interconnected power systems throughout the Northeastern United States and Eastern Canada (Nova Scotia, New Brunswick, Quebec, Ontario) under the regulatory authority of NERC. NERC and NPCC reliability standards and criteria are approved for enforcement in Nova Scotia by the UARB. NSPI complies with NPCC criteria and NERC standards for the design, planning and operation of NSPI’s portion of the interconnected bulk electric system.

Transmission and Distribution

NSPI transmits and distributes electricity from its generating stations to its customers. NSPI’s transmission system consists of approximately 5,000 km of transmission facilities. The distribution system consists of approximately 28,000 km of distribution facilities, which includes distribution supply substations.

 

Emera Incorporated – 2023 Annual Information Form    12


ENL

NSPML

Equity earnings from the Maritime Link are dependent on the approved ROE and operational performance of NSPML. NSPML’s approved regulated ROE range is 8.75 per cent to 9.25 per cent, based on an actual five-quarter average regulated common equity component of up to 30 per cent.

The Maritime Link assets entered service on January 15, 2018, enabling the transmission of energy between Newfoundland and Nova Scotia, improved reliability and ancillary benefits, supporting the efficiency and reliability of energy in both provinces. Nalcor’s NS Block delivery obligations commenced on August 15, 2021, and the NS Block will be delivered over the next 35 years pursuant to the project agreements.

LIL

ENL is a limited partner with Nalcor in LIL. Construction of the LIL is complete and the Newfoundland Electrical System Operator confirmed the asset to be operating suitably to support reliable system operation and full functionality at 700MW, which was validated by the Government of Canada’s Independent Engineer issuing its Commissioning Certificate on April 13, 2023.

Upon issuance of the Commissioning Certificate, AFUDC equity earnings ceased and cash equity earnings and return of equity to Emera commenced. The first distribution was received from the LIL partnership in Q4 2023.

Equity earnings from the LIL investment are based upon the book value of the equity investment and the approved ROE. Emera’s current equity investment is $747 million, comprised of $410 million in equity contribution and $337 million of accumulated equity earnings. Emera’s total equity contribution in the LIL, excluding accumulated equity earnings, is estimated to be approximately $650 million once the final costing has been confirmed by Nalcor to determine the amount of the remaining investment.

Contribution to Consolidated Net Income and Adjusted Net Income

Canadian Electric Utilities’ contribution to consolidated net income was $247 million in 2023 (2022 - $215 million). Canadian Electric Utilities’ contribution to Emera’s consolidated adjusted net income was $247 million in 2023 (2022 - $222 million). For a reconciliation of Canadian Electric Utilities’ adjusted net income to consolidated net income, refer to the “Non-GAAP Financial Measures and Ratios” and “Financial Highlights – Canadian Electric Utilities” sections of Emera’s MD&A, which is incorporated herein by reference, a copy of which is available electronically under Emera’s profile on SEDAR+ at www.sedarplus.ca.

Seasonal Nature

Electric sales volumes are primarily driven by weather, number of customers, general economic conditions, and demand side management activities. Residential and commercial electricity sales are seasonal in Nova Scotia, with Q1 historically generating the highest sales, reflecting colder weather and fewer daylight hours in the winter season.

Capital Investment

NSPI

NSPI’s capital investments in 2023 were $451 million (2022 – $540 million), including AFUDC. In 2024, NSPI expects to invest $435 million, including AFUDC, primarily in capital projects to support power system reliability and reliable service for customers.

 

Emera Incorporated – 2023 Annual Information Form    13


NSPML

NSPML does not anticipate any significant capital investment in 2024.

Environmental Considerations

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 reductions 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 of the MD&A, which is hereby incorporated by reference, a copy of which is available electronically under Emera’s profile on SEDAR+ at www.sedarplus.ca.

Other Environmental Legislation and Regulations

There have been several recent environmental developments at both the federal and provincial levels, as described below in the “General Development of the Business – Canadian Electric Utilities - NSPI” section. For additional information on environmental regulations affecting NSPI, see also NSPI’s 2023 Annual Information Form, a copy of which is available electronically under NSPI’s profile on SEDAR+ at www.sedarplus.ca.

Gas Utilities and Infrastructure

Gas Utilities and Infrastructure includes PGS, NMGC, SeaCoast, Brunswick Pipeline and Emera’s equity investment in M&NP. PGS is a regulated gas distribution utility engaged in the purchase, distribution and sale of natural gas serving customers in Florida. NMGC is an intrastate regulated gas distribution utility engaged in the purchase, transmission, distribution and sale of natural gas serving customers in New Mexico. SeaCoast is a regulated intrastate natural gas transmission company offering services in Florida. Brunswick Pipeline is a regulated 145-kilometre pipeline delivering re-gasified liquefied natural gas from Saint John, New Brunswick, to markets in the northeastern United States.

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 on which NMGC has transportation capacity and NMGC’s intrastate transmission and distribution system for delivery to customers.

Market and sales

 

                                                                                                               
PGS, NMGC and SeaCoast Revenue and Sales Volumes by Customer Class
      Gas Revenues (%)    Therms Gas Sales  Volumes (%) 
For the year ended December 31   2023   2022   2023   2022
Residential   50.3   49.2   13.2   14.4
Commercial   29.5   28.3   26.8   28.7
Industrial   6.5   5.1   51.5   49.1
Other   13.7   17.4   8.5   7.8
Total   100.0   100.0   100.0   100.0

 

Emera Incorporated – 2023 Annual Information Form    14


PGS

As at December 31, 2023, PGS serves approximately 490,000 customers with $2.8 billion USD in assets and 767 employees. The PGS system includes approximately 24,300 kilometres of natural gas mains and 13,500 kilometres of service lines. Natural gas throughput (the amount of gas delivered to its customers, including transportation-only service) was 2 billion therms in 2023.

PGS is regulated by the FPSC. Rates are set at a level that allow the utilities to collect total revenues or revenue requirements equal to their cost to provide service, plus an appropriate return on invested capital.

Beginning in 2024, the approved ROE range for PGS is 9.15 per cent to 11.15 per cent (2023 – 8.9 per cent to 11.0 per cent), based on an allowed equity capital structure of 54.7 per cent (2023 – 54.7 per cent). An ROE of 10.15 per cent (2023 – 9.9 per cent) is used for the calculation of return on investments recovered through cost recovery clauses.

For further details on PGS’ regulatory environment and recovery mechanisms, refer to Note 6, Regulatory Assets and Liabilities, in the Audited Financial Statements, which are hereby incorporated by reference, a copy of which is available electronically under Emera’s profile on SEDAR+ at www.sedarplus.ca.

NMGC

As at December 31, 2023, NMGC serves approximately 540,000 customers with $1.8 billion USD in assets and 725 employees. NMGC’s system includes 2,408 km of transmission lines and 17,657 km of distribution lines. Annual natural gas throughput was 1 billion therms in 2023.

NMGC is subject to regulation by the NMPRC. Rates are set 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 is 9.375 per cent on an allowed equity capital structure of 52 per cent.

For further details on NMGC’s regulatory environment and recovery mechanisms, refer to Note 6, Regulatory Assets and Liabilities, in the Audited Financial Statements, which are hereby incorporated by reference, a copy of which is available electronically under Emera’s profile on SEDAR+ at www.sedarplus.ca.

EBPC

EBPC owns Brunswick Pipeline, a regulated 145-km pipeline delivering re-gasified liquefied natural gas from the Saint John LNG import terminal near Saint John, New Brunswick to markets in the Northeastern United States. The pipeline travels through southwest New Brunswick and connects with M&NP at the Canada/U.S. border near Baileyville, Maine.

Since its commissioning in July 2009, the pipeline has been used solely to transport natural gas for RENAC under a 25-year firm service agreement, which expires in 2034. Brunswick Pipeline is regulated by the CER, which has classified it as a Group II pipeline. As a regulated Group II pipeline, the tolls of Brunswick Pipeline are regulated by the CER on a complaint basis, as opposed to a regulatory approval process. 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 with RENAC, as noted above. The firm service agreement provides for a predetermined toll increase in the fifth and fifteenth year of the contract.

Economic Dependence

Brunswick Pipeline has a 25-year firm service agreement with RENAC, which expires in 2034. The risk of non-payment is mitigated as Repsol, the parent company of RENAC, has provided EBPC with a guarantee for all RENAC’s payment obligations under the firm service agreement.

 

Emera Incorporated – 2023 Annual Information Form    15


M&NP

Emera owns a 12.9 per cent interest in M&NP, which is a 1,400 km pipeline that transports natural gas throughout markets in Atlantic Canada and the Northeastern United States.

Contribution to Consolidated Net Income

Gas Utilities and Infrastructure’s contribution to consolidated net income was $158 million USD in 2023 (2022 – $170 million USD).

Seasonal Nature

Gas sales volumes are primarily driven by general economic conditions, population and weather. Residential and commercial gas sales are seasonal. In Florida and New Mexico, Q1 is the strongest period for gas sales due to colder weather and heating demand.

Capital Investment

Capital investments, including AFUDC, in the Gas Utilities and Infrastructure segment in 2023 were $495 million USD (2022 - $436 million USD). In 2024, capital investment is expected to be approximately $465 million USD, including AFUDC. PGS and NMGC will make investments to maintain the reliability of their systems and support customer growth.

Environmental Considerations

PGS’s operations are subject to federal, state and local statutes, rules and regulations relating to the discharge of materials into the environment and the protection of the environment that generally require monitoring, permitting and ongoing expenditures. Previously, TEC had been a potentially responsible party (“PRP”) for certain superfund sites through its Tampa Electric and former PGS divisions, as well as for certain former manufactured gas plant sites through its PGS division. As a result of the separation of the PGS division into a separate legal entity, Peoples Gas System, Inc. is also now a PRP for those sites (in addition to third party PRPs for certain sites). For further details, refer to Note 27, Commitments and Contingencies – Legal Proceedings - Superfund and Former Manufactured Gas Plant Sites, in the Audited Financial Statements, which is hereby incorporated by reference, a copy of which is available electronically under Emera’s profile on SEDAR+ at www.sedarplus.ca.

Brunswick Pipeline is subject to both federal and provincial environmental regulations. Brunswick Pipeline has comprehensive integrity, safety and environmental programs in place, including an integrated management system to ensure compliance and continuous improvement of its integrity, safety and environmental programs. Brunswick Pipeline also conducts regularly scheduled physical inspections of the pipeline and its right-of-way.

Other Electric Utilities

Other Electric Utilities includes 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 equity investment in Lucelec on the island of St. Lucia.

Market and Sales

Other Electric Utilities operating revenues for 2023 were $390 million USD (2022 – $398 million USD) and electric sales volumes were 1,260 GWh (2022 –1,239 GWh).

 

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BLPC

As at December 31, 2023, BLPC serves approximately 134,000 customers with $517 million USD of assets and a workforce of 414 employees. BLPC owns 243 MW of generating capacity, of which 96 per cent is oil-fired and 4 per cent is solar. BLPC’s transmission system consists of 188 km of transmission lines, including major substations connected to the transmission and distribution system. The distribution system consists of 3,839 km of distribution lines which includes distribution supply substations.

BLPC currently operates pursuant to a single integrated license to generate, transmit and distribute electricity on the island of Barbados until 2028. In 2019, the Government of Barbados passed legislation requiring multiple licenses for the supply of electricity. In 2021, BLPC reached commercial agreement with the Government of Barbados for each of the license types, subject to the passage of implementing legislation.The timing of the final enactment is unknown at this time, but BLPC will work towards the implementation of the licenses once enacted.

BLPC is regulated by the FTC. Rates are set to recover prudently incurred costs of providing electricity service to customers plus an appropriate return on capital invested. BLPC’s approved regulated return on rate base is 10 per cent.

GBPC

As at December 31, 2023, GBPC serves approximately 19,000 customers, with $334 million USD of assets and a workforce of 205 employees. GBPC owns 98 MW of oil-fired generation, approximately 90 kilometres of transmission facilities and 994 kilometers of distribution facilities.

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. GBPC’s approved regulatory return on rate base is 8.52 per cent for 2024 (2023 – 8.32 per cent). For further details on GBPC’s regulatory environment and recovery mechanisms, refer to Note 6, Regulatory Assets and Liabilities, in the Audited Financial Statements, which is hereby incorporated by reference, a copy of which is available electronically under Emera’s profile on SEDAR+ at www.sedarplus.ca.

System Operation

BLPC and GBPC have system control centres that co-ordinate and control their electric generation and transmission facilities with the goal of providing a reliable and secure electricity supply while maintaining economy of operations. The generation and transmission system control centres are linked to their generating stations and other key parts of their systems by the “Supervisory Control and Data Acquisition” systems, with fibre optic, voice and data communications networks.

Transmission and Distribution

BLPC and GBPC transmit and distribute electricity from their generating stations to their customers.

Contribution to Consolidated Net Income and Adjusted Net Income

Other Electric Utilities’ contribution to consolidated net income was $28 million USD in 2023 (2022 – a loss of $35 million USD). Other Electric Utilities’ contribution to consolidated adjusted net income was $26 million USD in 2023 (2022 – $23 million USD). For a reconciliation of Other Electric Utilities adjusted net income to consolidated net income, refer to the “Non-GAAP Financial Measures and Ratios” and “Financial Highlights – Other Electric Utilities” sections of Emera’s MD&A, which is incorporated herein by reference, a copy of which is available electronically under Emera’s profile on SEDAR+ at www.sedarplus.ca.

 

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Seasonal Nature

Electricity sales and related generation varies significantly over the year in the Caribbean; Q3 is typically the strongest period, reflecting warmer weather. Grand Bahama is also particularly prone to tropical storm and hurricane impacts during Q3.

Capital Investment

Other Electric Utilities capital investments (including AFUDC) for 2023 were $47 million USD (2022 – $48 million USD). In 2024, capital investment is expected to be approximately $80 million USD, primarily in more efficient and cleaner sources of generation, including renewables and battery storage.

Environmental Considerations

Emera’s Caribbean utilities have implemented formal health & safety and environmental and management systems to assist in safeguarding the health and safety of its employees, contractors and customers while ensuring protection of the environment.

Other

The Other segment includes those business operations that in a normal year are below the required threshold for reporting as separate segments; and corporate expense and revenue items that are not directly allocated to the operations of Emera’s subsidiaries and investments.

Business operations in the Other segment include Emera Energy and Block Energy. Emera Energy consists of EES, a wholly owned physical energy marketing and trading business and an equity investment in a 50 per cent joint venture ownership of Bear Swamp, a 660 MW pumped storage hydroelectric facility in northwestern Massachusetts. Block Energy is a wholly owned technology company focused on finding ways to deliver renewable and resilient energy to customers.

Corporate items included in the Other segment are certain corporate-wide functions including executive management, strategic planning, treasury services, legal, financial reporting, tax planning, corporate business development, corporate governance, investor relations, risk management, insurance, acquisition and disposition related costs, gains or losses on select assets sales, and corporate human resource activities. It includes interest revenue on intercompany financings and interest expense on corporate debt in both Canada and the U.S. It also includes costs associated with corporate activities that are not directly allocated to the operations of Emera’s subsidiaries and investments.

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 and credit exposure. EES purchases and sells physical natural gas and electricity, the related transportation and transmission capacity rights, and provides related 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.

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

 

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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.

Contribution to Consolidated Net Income and Adjusted Net Income

Other’s contribution to consolidated net income was a loss of $147 million in 2023 (2022 – loss of $39 million). Other’s contribution to consolidated adjusted net income was a loss of $314 million in 2023 (2022 – loss of $218 million). For further information on the non-GAAP measure adjusted net income, refer to the “Non-GAAP Financial Measures and Ratios” and “Financial Highlights – Other” sections of the MD&A, which is hereby incorporated by reference, a copy of which is available electronically under Emera’s profile on SEDAR+ at www.sedarplus.ca.

Capital Investment

In 2024, capital investment in the Other segment is not expected to be significant.

GENERAL DEVELOPMENT OF THE BUSINESS

Three Year History and Changes Expected in 2024

The following discussion summarizes key developments in Emera’s business and operations over the last three completed financial years and changes that are expected to occur during the current financial year.

Florida Electric Utility

Base Rates

On August 6, 2021, TEC filed with the FPSC a joint motion for approval of a settlement agreement by TEC and the intervenors in relation to its rate case filed with the FPSC in April 2021. On October 21, 2021, the FPSC approved a settlement agreement filed by TEC. The settlement agreement allows for an increase 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.

On August 16, 2022, the FPSC approved TEC’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.

On August 16, 2023, TEC filed a petition to implement the 2024 Generation Base Rate Adjustment provisions pursuant to the 2021 rate case settlement agreement. Inclusive of TEC’s ROE adjustment, the increase of $22 million USD was approved by the FPSC on November 17, 2023.

On February 1, 2024, TEC notified the FPSC of its intent to seek a base rate increase effective January 2025, reflecting a revenue requirement increase of approximately $290 to $320 million USD and additional adjustments of approximately $100 million USD and $70 million USD for 2026 and 2027, respectively. TEC’s proposed rates include recovery of solar generation projects, energy storage capacity, a more resilient and modernized energy control center, and numerous other resiliency and reliability projects. The filing range amounts are estimates until TEC files its detailed case in April 2024. The FPSC is scheduled to hear the case in Q3 2024 with a decision expected by the end of 2024.

 

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Fuel Recovery

The mid-course fuel adjustment requested by TEC on July 19, 2021, was approved on August 3, 2021. The rate increase, effective with September 2021 customer bills, covered higher fuel and capacity costs of $83 million USD, and was spread over customer bills from September through December 2021.

The mid-course fuel adjustment requested by TEC on January 19, 2022, was approved on March 1, 2022. The rate increase, effective with the first billing cycle in April 2022, covered higher fuel and capacity costs of $169 million USD, and was spread over customer bills from April 1, 2022 through December 2022.

On January 23, 2023, TEC requested an adjustment to its fuel charges to recover the 2022 fuel under-recovery of $518 million USD over a period of 21 months. The request also included an adjustment to 2023 projected fuel costs to reflect the reduction in natural gas prices since September 2022 for a projected reduction of $170 million USD for the balance of 2023. The changes were approved by the FPSC on March 7, 2023, and were effective beginning on April 1, 2023.

Solar Projects

During 2017 to 2021, TEC invested $850 million USD in 600 MW of utility-scale solar photovoltaic projects, which is recoverable through FPSC-approved 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.

Big Bend Modernization Project

TEC 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, TEC retired the Unit 1 components that will not be used in the modernized plant in 2020 and Big Bend Unit 2 in 2021. TEC retired Big Bend Unit 3 in 2023 as it is in the best interest of the customers from an economic, environmental risk and operational perspective. On December 31, 2021, the remaining costs of the retired Big Bend coal generation assets, Units 1 through 3, of $636 million USD and $267 million USD in accumulated depreciation were reclassified to a regulatory asset on the balance sheet.

TEC’s 2021 settlement agreement provides 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 were recovered as part of the 2023 subsequent year adjustment. The settlement agreement also includes a new charge to recover the remaining costs of the retired Big Bend coal generation assets, Units 1 through 3, which are spread over 15 years, effective January 1, 2022. This recovery mechanism is authorized by and survives the term of the settlement agreement approved by the FPSC in 2021.

Storm Reserve

In September 2022, TEC was impacted by Hurricane Ian with $119 million USD of restoration costs charged against TEC’s FPSC approved storm reserve. Total restoration costs charged to the storm reserve exceeded the reserve balance and have been deferred as a regulatory asset for future recovery.

On January 23, 2023, TEC petitioned the FPSC for recovery of the storm reserve regulatory asset and the replenishment of the balance in the storm reserve to the approved storm reserve level of $56 million USD, for a total of $131 million USD. The storm cost recovery surcharge was approved by the FPSC on March 7, 2023, and TEC began applying the surcharge in April 2023. Subsequently, on November 9, 2023, the

 

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FPSC approved TEC’s petition, filed on August 16, 2023, to update the total storm cost collection to $134 million USD. It also changed the collection of the expected remaining balance of $29 million USD as of December 31, 2023, from over the first three months of 2024 to over the 12 months of 2024. The storm recovery is subject to review of the underlying costs for prudency and accuracy by the FPSC.

In Q3 2023, TEC was impacted by Hurricane Idalia. The related storm restoration costs were approximately $35 million USD, which were charged to the storm reserve regulatory asset, resulting in minimal impact to earnings. TEC will determine the timing of the request for recovery of Hurricane Idalia costs at a future time.

Storm Protection Cost Recovery Clause and Settlement Agreement

The Storm Protection Plan (“SPP”) Cost Recovery Clause provides a process for Florida investor-owned utilities, including TEC, to recover transmission and distribution storm hardening costs for incremental activities not already included in base rates. Differences between prudently incurred clause-recoverable costs and amounts recovered from customers through electricity rates in a year are deferred and recovered from or returned to customers in a subsequent year. A settlement agreement was approved on August 10, 2020, and TEC’s cost recovery began in January 2021. The previously approved plan addressed the years 2020 through 2022, and in April 2022 TEC submitted a new plan to determine cost recovery in 2023, 2024 and 2025. On October 4, 2022, the FPSC approved TEC’s current SPP for those years.

For more information, refer to the “Regulatory Environments and Updates – Florida Electric Utility” section of Note 6, Regulatory Assets and Liabilities, in the Audited Financial Statements, which is hereby incorporated by reference, a copy of which is available electronically under Emera’s profile on SEDAR+ at www.sedarplus.ca

Canadian Electric Utilities

NSPI

General Rate Application

On February 2, 2023, the UARB approved the General Rate Application Settlement Agreement between NSPI, key customer representatives and participating interest groups. This resulted in average customer rate increases of 6.9 per cent effective on February 2, 2023, and further average increase of 6.5 per cent on January 1, 2024, with any under or over-recovery of fuel costs addressed through the UARB’s established FAM process. It also established a storm rider and a demand-side management rider. On March 27, 2023 the UARB issued a final order approving the electricity rates effective on February 2, 2023.

Fuel Recovery

For the period of 2020 through 2022, NSPI operated under a three-year fuel stability plan with no fuel rate adjustments related to the under-recovery of fuel and fuel-related costs in the period.

On January 29, 2024, NSPI applied to the UARB for approval of a structure that would begin to recover the outstanding FAM balance. As part of the application, NSPI requested approval for the sale of $117 million of the FAM regulatory asset to Invest Nova Scotia, a provincial Crown corporation, with the proceeds paid to NSPI upon approval. NSPI has requested approval to collect from customers the amortization and financing costs of $117 million on behalf of Invest Nova Scotia over a 10-year period, and remit those amounts to Invest Nova Scotia as collected, reducing short-term customer rate increases relative to the currently established FAM process. If approved, this portion of the FAM regulatory asset would be removed from the Consolidated Balance Sheets and NSPI would collect the balance on behalf of Invest Nova Scotia in NSPI rates beginning in 2024. A decision is expected in the first half of 2024. It is anticipated that NSPI will apply to the UARB later in 2024 to collect additional under-recovered fuel amounts in 2025 or future periods, subject to the approval of the UARB.

 

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Extra Large Industrial Active Demand Tariff

On July 5, 2023, NSPI received approval from the UARB to change the methodology in which fuel cost recovery from an industrial customer is calculated. Due to significant volatility in commodity prices in 2022, the previous methodology did not result in a reasonable determination of the fuel cost to serve this customer. The change in methodology, effective January 1, 2022, results in a shifting of fuel costs from this industrial customer to the FAM. This adjustment was recorded in Q2 2023 resulting in a $51 million increase to the FAM regulatory asset and an offsetting decrease to unbilled revenue within Receivables and other current assets. This adjustment had minimal impact on earnings.

Hurricane Fiona

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 km per hour and peak gusts of approximately 180 km 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 $120 million, of which $96 million was capitalized to “PP&E” and $24 million deferred to “Other long-term assets” for future amortization, subject to UARB approval.

On October 31, 2023, NSPI submitted an application to the UARB to defer $24 million in incremental operating costs incurred during Hurricane Fiona storm restoration efforts in September 2022. NSPI is seeking amortization of the costs over a period to be approved by the UARB during a future rate setting process. At December 31, 2023 the $24 million is deferred to “Other long-term assets”, pending UARB approval.

Post-Tropical Storm Lee

On September 16, 2023, Nova Scotia was struck by post-tropical storm Lee and as a result, approximately 280,000 customers lost power. The total cost of storm restoration was $19 million, with $9 million charged to OM&G, $5 million capitalized to PP&E and $5 million deferred to the UARB approved storm rider. The storm rider for each of 2023, 2024, and 2025 allows NSPI to apply to the UARB for deferral and recovery of expenses if major storm restoration expenses exceed approximately $10 million in any given year. The application for deferral of the storm rider is made in the year following the year of the incurred costs, with recovery beginning in the year after the application.

Regulatory Matters – General

For more information, refer to the “Regulatory Environments and Updates – Canadian Electric Utilities – NSPI” section of Note 6, Regulatory Assets and Liabilities, in the Audited Financial Statements, which is hereby incorporated by reference, a copy of which is available electronically under Emera’s profile on SEDAR+ at www.sedarplus.ca.

Environmental Legislation and Regulations

Greenhouse Gas Emissions

On June 29, 2021, the federal government enacted Bill C-12 “Canadian Net-Zero Emissions Accountability Act” with the objective of attaining net-zero emissions by 2050.

On July 9, 2021, the Nova Scotia provincial government amended the Renewable Electricity Regulations, mandating that 80 per cent of electric sales be generated from renewable sources by 2030.

On August 5, 2021, the federal government issued an update to the Pan-Canadian Framework on Clean Growth and Climate Change under the “Greenhouse Gas Pollution Pricing Act”. This update (the “Federal Benchmark”) applies to the 2023 through 2030 period and puts in place the legal mechanism for increasing the carbon tax in Canada by $15 per tonne annually and reaching $170 per tonne by 2030. It also outlines

 

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the minimum compliance criteria for recognizing systems like the Nova Scotia Cap-and-Trade Program to be considered equivalent to the Federal Benchmark.

On November 5, 2021, the Nova Scotia provincial government enacted Bill 57, “Environmental Goals and Climate Change Reduction Act,” which signals the provincial government’s intent to implement several climate change related goals and greenhouse gas reduction targets, many of which overlap with and replace provisions of pre-existing acts. The legislation also introduces a goal to phase out coal-fired electricity generation in Nova Scotia by 2030. Subsequent provincial regulations will be required to detail how these goals and targets will be achieved.

In March 2022 the federal government issued their 2030 Emission Reduction Plan required under the Canadian Net-Zero Emissions Accountability Act. The Emission Reduction Plan acknowledges the federal and provincial emission reduction goals and programs currently legislated and also signals the intention for implementation of further emission reduction goals, including the federal intention of attaining a net-zero electricity grid by 2035. Subsequent regulations will be required to detail how this goal will be achieved.

Clean Electricity Solutions Task Force

The Clean Electricity Solutions Task Force (the “Task Force”) was created by the Province in April 2023 to advise the provincial government on Nova Scotia’s transition away from coal to more renewable sources of energy. On February 23, 2024, the Task Force released its report and recommendations, based on engagement with stakeholders, including NSPI. The Task Force report focuses on findings related to system operations, regulatory oversight, reliability, transmission and affordability. The Task Force announced a number of recommendations including a strengthening of the authority and independence of the regulator and the establishment of an independent system operator in order to support the continuing transition to clean energy and the achievement of federal and provincial clean energy goals and legislation. The Province announced they intend to accept these recommendations and will table enabling legislation in its upcoming session which starts February 27, 2024.

Nova Scotia Renewable Electricity Regulations

Under the provincially legislated RER , starting in 2020, 40 per cent of electric sales must be generated from renewable sources. NSPI met this target in 2023, with 43 per cent of NSPI’s electric sales coming form renewable sources, subject to a compliance filing.

Due to the delay of NSPI receiving energy form the NS Block, the Province provided NSPI with an alternative compliance plan that required 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.

On April 6, 2023, the Province levied a $10 million penalty on NSPI for non-compliance with the RER compliance period ending in 2022. The penalty was recorded in OM&G on the Consolidated Statements of Income. On May 26, 2023, NSPI initiated an appeal of the penalty through a proceeding with the UARB, as permitted under the RER. On October 12, 2023, the UARB decided that it will hear the appeal by giving due deference to the Province’s decision but permitting the filing of new evidence to support the parties’ positions. The hearing for the matter is scheduled for June 2024 and a decision is expected before the end of 2024.

Carbon Pricing Regulations

In November 2022, the Province enacted amendments to the Environment Act which provided the framework for Nova Scotia to implement an OBPS to comply with the Government of Canada’s 2023 through 2030 carbon pollution pricing regulations effective January 1, 2023. The Government of Canada approved the Province’s proposed system, however the OBPS will be subject to an interim review by the Government of Canada of the standards effective for 2026. The final Output-Based Pricing System

 

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Reporting and Compliance Regulations were prescribed by Order in Council dated January 30, 2024. The OBPS GHG emissions performance standards for large industrial GHG emitters that vary by fuel type. GHG emissions in excess of the prescribed intensity standards will be subject to a carbon price that starts at $65 per tonne in 2023 and will increase by $15 per tonne annually, reaching $170 per tonne by 2030. NSPI’s regulatory framework provides for the recovery of costs prudently incurred to comply with carbon pricing programs pursuant to NSPI’s FAM.

Nova Scotia Cap-and-Trade Program Regulations

NSPI was a participant in the Nova Scotia Cap-and-Trade Program and was subject to the 2019 through 2022 compliance period. On March 16, 2023, the Province provided NSPI with emissions allowances sufficient to achieve compliance for the 2019 through 2022 compliance period. As such, compliance costs accrued of $166 million were reversed in Q1 2023. The credits NSPI purchased from provincial auctions in the amount of $6 million were not refunded and no further costs were incurred to achieve compliance with the Nova Scotia Cap-and-Trade Program.

Other Legislation

Electricity Act Amendment

On November 9, 2023, the Province enacted amendments in the Electricity Act which permit the Governor in Council to approve energy storage projects proposed by a public utility and owned wholly or in majority by the public utility if the project is in the best interest of ratepayers. Further, the amendments to the Electricity Act expand the ability of the Province to require NSPI to enter into power purchase agreements with renewable generation facilities by further empowering the Province to require NSPI to enter into an agreement for the sale of the electricity to specified customers. This allows specified customers to buy renewable electricity from specified producers, with NSPI managing the transmission and sale of the energy. On December 21, 2023, the Governor in Council enacted regulations which directed NSPI to install three 50 MW four-hour duration grid-scale batteries as part of the regulated assets of NSPI.

Performance Standards Penalty Amendment

On April 12, 2023, the Province enacted amendments to the Public Utilities Act which increased the cumulative total of administrative penalties that could be levied by the UARB against NSPI for non-compliance with current and future performance standards in a calendar year from $1 million to $25 million. Any administrative penalties levied against NSPI must be credited to customers and NSPI cannot recover administrative penalties imposed through rates.

ENL

Maritime Link Project

On August 9, 2021, NSPML filed a final capital cost application with the UARB seeking approval to recover capital costs associated with the Maritime Link and approval of NSPML’s 2022 assessment. In December 2021, NSPML obtained an interim decision from the UARB approving interim rates beginning January 1, 2022, until receipt of the UARB’s decision on the application.

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, release of which was contingent on receiving in that month at least 90 per cent of NS Block deliveries, including supplemental Energy deliveries.

 

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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, subject to a monthly holdback of up to $2 million, which will increase to $4 million beginning December 2023, as discussed below.

On October 4, 2023 and January 31, 2024, the UARB issued decisions providing clarification on remaining aspects of the Maritime Link holdback mechanism primarily relating to release of past and future holdback amounts and requirements to end the holdback mechanism. In these decisions, the UARB agreed with the Company’s submission that $12 million ($8 million related to 2022 and $4 million relating to 2023) of the previously recorded holdback remain credited to NSPI’s FAM, with the remainder released to NSPML and recorded in Emera’s “Income from equity investments”. NSPML did not record any additional holdback in Q4 2023. The UARB also confirmed that the holdback mechanism will cease once 90 per cent of NS Block deliveries are achieved for 12 consecutive months (subject to potential relief for planned outages or exceptional circumstances) and the net outstanding balance of previously underdelivered NS Block energy is less than 10 per cent of the contracted annual amount. In addition, the UARB increased the monthly holdback amount from $2 million to $4 million beginning December 1, 2023. NSPML expects to file an application to terminate the holdback in 2024.

On December 21, 2023, NSPML received approval to collect up to $164 million from NSPI for the recovery of costs associated with the Maritime Link in 2024; subject to a holdback of up to $4 million a month, as discussed above.

Gas Utilities and Infrastructure

PGS

Base Rates

On November 19, 2020, the FPSC approved a settlement agreement filed by PGS. The settlement agreement allowed 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 provided PGS the ability to reverse a total of $34 million USD of accumulated depreciation through 2023. PGS reversed $20 million USD of accumulated depreciation in 2023 and $14 million USD in 2022.

On April 4, 2023, PGS filed a rate case with the FPSC and a hearing for the matter was held in September 2023. On November 9, 2023, the FPSC approved a $118 million USD increase to base revenues which includes $11 million USD transferred from the cast iron and bare steel replacement rider, for a net incremental increase to base revenues of $107 million USD. This reflects a 10.15 per cent midpoint ROE with an allowed equity capital structure of 54.7 per cent. A final order was issued on December 27, 2023, with the new rates effective January 2024.

NMGC

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.

On September 14, 2023, NMGC filed a rate case with the NMPRC for new base rates to become effective Q4 2024. NMGC requested $49 million USD in annual base revenues primarily as a result of increased operating costs and capital investments in pipeline projects and related infrastructure. The rate case includes a requested ROE of 10.5 per cent. A final order from the NMPRC is expected in Q3 2024.

 

Emera Incorporated – 2023 Annual Information Form    25


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. 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 from July 1, 2021, to December 31, 2023.

For more information, refer to the “Regulatory Environments and Updates – Gas Utilities and Infrastructure” section of Note 6, Regulatory Assets and Liabilities, in the Audited Financial Statements, which is hereby incorporated by reference, a copy of which is available electronically under Emera’s profile on SEDAR+ at www.sedarplus.ca.

Other Electric Utilities

BLPC

General Rate Review

In 2021 BLPC submitted a general rate review application to the FTC. In September 2022, the FTC granted BLPC interim rate relief, allowing an increase in base rates of approximately $1 million USD per month. On February 15, 2023, the FTC issued a decision on the application which included the following significant items: an allowed regulatory ROE of 11.75 per cent, an equity capital structure of 55 per cent, a directive to update the major components of rate base to September 16, 2022, and a directive to establish regulatory liabilities related to the self-insurance fund of $50 million USD, prior year benefits recognized on remeasurement of deferred income taxes of $5 million USD, and accumulated depreciation of $16 million USD. On March 7, 2023, BLPC filed a Motion for Review and Variation (the “Motion”) and applied for a stay of the FTC’s decision, which was subsequently granted. On November 20, 2023, the FTC issued their decision dismissing the Motion. Interim rates continue to be in effect through to a date to be determined in a final decision and order.

On December 1, 2023, BLPC appealed certain aspects of the FTC’s February 15 and November 20, 2023, decisions to the Supreme Court of Barbados in the High Court of Justice (the “Court”) and requested that they be stayed. On December 11, 2023, the Court granted the stay. BLPC’s position is that the FTC made errors of law and jurisdiction in their decisions and believes the success of the appeal is probable, and as a result, the adjustments to BLPC’s final rates and rate base, including any adjustments to regulatory assets and liabilities, have not been recorded at this time. Management does not expect the final decision and order to have a material impact on adjusted net income.

Clean Energy Transition Program (“CETP”)

On May 31, 2023, the FTC approved BLPC’s application to establish an alternative cost recovery mechanism to recover prudently incurred costs associated with its CETP (the “Decision”). The mechanism is intended to facilitate the timely recovery between rate cases of costs associated with approved renewable energy assets. BLPC will be required to submit an individual application for the recovery of costs of each asset through the cost recovery mechanism, meeting the minimum criteria as set out in the Decision. On October 5, 2023, BLPC applied to the FTC to recover the costs of a battery storage system through the CETP.

 

Emera Incorporated – 2023 Annual Information Form    26


GBPC

Base Rates

On January 14, 2022, the GBPA issued its decision on GBPC’s application for rate review that was filed with the GBPA on September 23, 2021. The decision, which became effective April 1, 2022, allows for an increase in revenues of $3.5 million USD. The rates include a regulatory ROE of 12.84 per cent.

Fuel Recovery

Effective November 1, 2022, GBPC’s fuel pass through charge was increased due to an increase in global oil prices impacting the unhedged fuel cost. In 2023 the fuel pass through charge was adjusted monthly, in-line with actual fuel costs.

Storm Restoration Costs – Hurricane Matthew

As part of the recovery of costs incurred as a result of Hurricane Matthew in 2016, the GBPA approved a fixed per kWh fuel charge and allowed the difference between this and the actual cost of fuel to be applied to the Hurricane Matthew regulatory asset. As part of its decision on GBPC’s application for rate review, issued January 14, 2022, and effective April 1, 2022, the GBPA approved the continued amortization of the remaining regulatory asset over the three year period ending December 31, 2024.

For more information, refer to the “Regulatory Environments and Updates – Other Electric Utilities” section of Note 6, Regulatory Assets and Liabilities, in the Audited Financial Statements, which is hereby incorporated by reference, a copy of which is available electronically under Emera’s profile on SEDAR+ at www.sedarplus.ca.

USGAAP – Exemptive Relief

On January 28, 2021, the International Accounting Standards Board (“IASB”) published an Exposure Draft: Regulatory Assets and Regulatory Liabilities, which proposes the accounting model under which a company subject to rate regulation that meets the scope criteria would recognize regulatory assets and liabilities. The proposed effective date is annual reporting periods beginning on or after a date 18-24 months from the date of publication of the standard. 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 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.

The Company will continue to monitor the development of the Mandatory Rate-regulated Standard and assess the impact on the existing Exemptive Relief.

Financing Activity

At-The-Market Equity Program

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

 

Emera Incorporated – 2023 Annual Information Form    27


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.

During 2021, approximately 4.99 million common shares were issued under the 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). As at December 31, 2021, an aggregate gross sales limit of $457 million remained available for issuance under the ATM Program.

During 2022, approximately 4.07 million common shares were issued under the 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, which expired on September 5, 2023.

On November 14, 2023, 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 dated November 14, 2023 to the Company’s short form base shelf prospectus dated October 3, 2023. The ATM program is expected to remain in effect until November 4, 2025.

During 2023, approximately 8.29 million common shares were issued under the ATM Program at an average price of $48.27 per share for gross proceeds of $400 million ($397 million net of after-tax issuance costs) and an aggregate gross sales limit of $200 million remained available for issuance under the ATM Program.

During 2024, up to and including February 26, 2024, no common shares were issued under the ATM Program and an aggregate gross sales limit of $200 million remains available for issuance under the ATM Program.

Preferred Share Issuances

On April 6, 2021, Emera issued 8 million Series J First Preferred Shares at $25.00 per share at an initial dividend rate of 4.25 per cent. The aggregate gross and net proceeds from the offering were $200 million and $196 million, respectively. The net proceeds of the preferred share offering were used for general corporate purposes.

On September 24, 2021, Emera issued 9 million Series L First Preferred Shares, at $25.00 per share at an annual yield of 4.60 per cent. The aggregate gross and net proceeds from the offering were $225 million and $222 million, respectively. The net proceeds of the preferred share offering were used for general corporate purposes.

On July 6, 2023, Emera announced it would not redeem the 10 million outstanding Series C First Preferred Shares. The holders of the Series C First Preferred Shares had the right, at their option, to convert all or any of their Series C First Preferred Shares, on a one-for-one basis, into Series D First Preferred Shares on August 15, 2023 or to continue to hold their Series C First Preferred Shares. On August 4, 2023, Emera announced after having taken into account all conversion notices received from holders, no Series C First Preferred Shares would be converted into Series D First Preferred Shares.

On July 6, 2023, Emera announced it would not redeem the 12 million outstanding Series H First Preferred Shares. The holders of the Series H First Preferred Shares had the right, at their option, to convert all or any of their Series H First Preferred Shares, on a one-for-one basis, into Series I First Preferred Shares on August 15, 2023 or to continue to hold their Series H First Preferred Shares. On August 4, 2023, Emera

 

Emera Incorporated – 2023 Annual Information Form    28


announced after having taken into account all conversion notices received from holders, no Series H First Preferred Shares would be converted into Series I First Preferred Shares.

Senior Notes

On June 4, 2021, Emera US Finance LP completed an issuance of $750 million USD senior notes. The issuance included $450 million USD senior notes that bear interest at a rate of 2.64 per cent with a maturity date of June 15, 2031 and $300 million USD senior notes that bear interest at a rate of 0.83 per cent with a maturity date of June 15, 2024. The USD senior notes are guaranteed by Emera and Emera US Holdings Inc., a wholly owned Emera subsidiary.

From the $750 million USD senior notes issuance discussed above, on June 15, 2021, Emera US Finance LP repaid its previously outstanding $750 million USD senior notes on maturity.

On May 2, 2023, Emera issued $500 million in senior unsecured notes that bear interest at 4.84 per cent with a maturity date of May 2, 2030. The proceeds were used to repay Emera’s $500 million unsecured fixed rate notes, which matured in June 2023.

For more information on financing activities for Emera and its subsidiaries, please refer to the “Liquidity and Capital Resources” section of Emera’s MD&A, which is hereby incorporated by reference, a copy of which is available electronically under Emera’s profile on SEDAR+ at www.sedarplus.ca.

RISK FACTORS

For Emera’s risk factors, refer to the “Enterprise Risk and Risk Management” section of the MD&A and the “Principal Financial Risks and Uncertainties” section of Note 27, Commitments and Contingencies, to the Audited Financial Statements, which are each incorporated herein by reference, copies of which are available electronically under Emera’s profile on SEDAR+ at www.sedarplus.ca.

CAPITAL STRUCTURE

The authorized capital of Emera consists of an unlimited number of common shares, an unlimited number of first preferred shares and an unlimited number of second preferred shares. Each class of preferred shares is issuable in series.

As at December 31, 2023, 284,117,511 common shares, 4,866,814 Series A First Preferred Shares, 1,133,186 Series B First Preferred Shares, 10,000,000 Series C First Preferred Shares, 5,000,000 Series E First Preferred Shares, 8,000,000 Series F First Preferred Shares, 12,000,000 Series H First Preferred Shares, 8,000,000 Series J First Preferred Shares, 9,000,000 Series L First Preferred Shares, 2,200,525 Barbados DRs and 1,814,135 Bahamas DRs were issued and outstanding.

Common Shares

The holders of common shares are entitled to receive notice of and to attend all annual and special meetings of the shareholders of Emera, other than separate meetings of holders of any other class or series of shares, and to one vote in respect of each common share held at such meetings.

The holders of common shares are entitled to dividends on a pro rata basis, as and when declared by the Board. Subject to the rights of the holders of the first preferred shares and second preferred shares, if any, who are entitled to receive dividends in priority to the holders of the common shares, the Board may declare dividends on the common shares to the exclusion of any other class of shares of Emera.

On the liquidation, dissolution or winding-up of Emera, holders of common shares are entitled to participate rateably in any distribution of assets of Emera, subject to the rights of holders of first preferred shares and

 

Emera Incorporated – 2023 Annual Information Form    29


second preferred shares, if any, who are entitled to receive the assets of the Company on such a distribution in priority to the holders of the common shares.

There are no pre-emptive, redemption, purchase or conversion rights attaching to the common shares. The foregoing description is subject to the “Share Ownership Restrictions” section below.

Emera First Preferred Shares

The first preferred shares of each series rank on 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 will be entitled, for only as long as the dividends remain in arrears, 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.

The first preferred shares of each series are not redeemable at the option of their holders. For a summary of the terms and conditions of the Company’s authorized First Preferred Shares as of December 31, 2023, refer to Appendix “B” of this AIF.

Emera Second Preferred Shares

The second preferred shares have special rights, privileges, restrictions and conditions substantially similar to the first preferred shares, except that the second preferred shares rank junior to the first preferred shares with respect to the payment of dividends, repayment of capital and the distribution of assets of Emera in the event of liquidation, dissolution or winding-up of Emera. As at December 31, 2023, Emera had not issued any second preferred shares.

Share Ownership Restrictions

As required by the Reorganization Act and pursuant to the Privatization Act, the Articles of Emera provide that no person, together with associates thereof, may subscribe for, have transferred to that person, hold, beneficially own or control, directly or indirectly, otherwise than by way of security only, or vote, in the aggregate, voting shares of Emera to which are attached more than 15 per cent of the votes attached to all outstanding voting shares of Emera.

The common shares, and in certain circumstances the Series A First Preferred Shares, Series B First Preferred Shares, Series C First Preferred Shares, Series E First Preferred Shares, Series F First Preferred Shares, Series H First Preferred Shares, Series J First Preferred Shares and Series L First Preferred Shares are considered to be voting shares for purposes of the constraints on share ownership.

Emera’s Articles contain provisions for the enforcement of these constraints on share ownership including provisions for suspension of voting rights, forfeiture of dividends, prohibitions of share transfer and issuance, compulsory sale of shares and redemption, and suspension of other shareholder rights. The Board may require shareholders to furnish statutory declarations as to matters relevant to enforcement of the restrictions.

 

Emera Incorporated – 2023 Annual Information Form    30


CREDIT RATINGS

Emera has the following credit ratings by the Rating Agencies:

 

         Moody’s          S&P          Fitch   

Corporate

   Baa3    BBB    BBB

Outlook

   Negative    Negative    Negative

Senior unsecured debt program

   Baa3    BBB-    BBB

Hybrid Notes

   Ba2    BB+    BB+

First Preferred Shares

   N/A    P-3 (high)    BB+

Ratings are intended to provide investors with an independent measure of the credit quality of an issue of securities and are indicators of the likelihood of the payment capacity and willingness of an issuer to meet its financial commitment in accordance with the terms of the obligation. The credit ratings assigned by the Rating Agencies are not recommendations to buy, sell, or hold securities in as much as such ratings are not a comment upon the market price of the securities or their stability for a particular investor. The credit ratings assigned to the securities may not reflect the potential impact of all risks on the value of the securities. There is no assurance that any rating will remain in effect for any given period of time or that any rating will not be revised or withdrawn entirely by a Rating Agency in the future if in its judgment circumstances so warrant.

Moody’s

Moody’s credit ratings are on a long-term debt rating scale that ranges from Aaa to C, representing the range from highest to lowest quality of such rated securities. The rating of Baa3 obtained from Moody’s in respect of the senior unsecured debt is the fourth highest of nine available rating categories and indicates that the obligations are subject to moderate credit risk. As such, they are considered medium-grade and may possess speculative characteristics. The rating of Ba2 from Moody’s in respect of the Hybrid Notes is characterized as having speculative elements and being subject to substantial credit risk. It is the fifth highest of nine available rating categories. Moody’s appends numerical modifiers 1, 2 and 3 to each generic rating classification from Aa through Caa. The modifier 1 indicates that the obligation ranks in the higher end of its generic rating category; the modifier 2 indicates a mid-range ranking; and the modifier 3 indicates a ranking in the lower end of that generic rating category.

S&P

S&P’s credit ratings are on a long-term debt scale that ranges from AAA to D, representing the range from highest to lowest quality of such rated securities. The issuer rating of BBB obtained from S&P in respect of the corporate rating indicates that the issuer has adequate capacity to meet its financial commitments. The issue rating of BBB- from S&P in respect of the senior unsecured debt indicates that the obligations exhibit adequate protection parameters. The issue rating of BB+ from S&P in respect of the Hybrid Notes indicates that the obligations exhibit adequate projection parameters in the near term however the obligor may not have the capacity to meet its obligations in the long term. The issue and issuer ratings of BBB and BB are the fourth and fifth highest, respectively, of ten available ratings categories and the addition of either a “(+)” or a “(-)” designation after a rating indicates the relative standing within a particular category. In each case, however, adverse economic conditions or changing circumstances are more likely to lead to weakened capacity of the obligor to meet its financial commitments on the obligation.

A P-3 (high) rating with respect to Emera’s issued and outstanding First Preferred Shares is the third highest of the eight standard categories of ratings utilized by S&P for preferred shares.

Fitch

Fitch’s credit ratings are on a long-term debt scale that ranges from AAA to D, representing the range from highest to lowest quality of such rated securities. The rating of BBB obtained from Fitch in respect of the senior unsecured debt is the fourth highest of nine available rating categories and indicates that the issuer has adequate capacity to meet its financial commitments. The rating of BB from Fitch in respect of the

 

Emera Incorporated – 2023 Annual Information Form    31


Hybrid Notes is characterized as having elevated default risk however business or financial flexibility exists that support servicing the financial commitments. The BB rating from Fitch is the fifth highest of nine available ratings categories and the addition of either a “(+)” or a “(-)” designation after a rating indicates the relative standing within a particular category. In each case, however, adverse economic conditions or changing circumstances are more likely to lead to weakened capacity of the obligor to meet its financial commitments on the obligation.

Emera has made, or will make, payments in the ordinary course to the Rating Agencies in connection with the assignment of ratings on both Emera and its securities. In addition, Emera has made customary payments in respect of certain subscription services provided to Emera by the Rating Agencies during the last two years.

For further information on the credit ratings of Emera and its subsidiaries, refer to the “Credit Ratings” section of the MD&A, which is hereby incorporated by reference, a copy of which is available electronically under Emera’s profile on SEDAR+ at www.sedarplus.ca.

 

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DIVIDENDS

Any dividend payments will be at the Board’s discretion based upon earnings and capital requirements and any other factors as the Board may consider relevant. On September 20, 2023 Emera extended its annual dividend growth rate target of four to five per cent through 2026. The Company targets a long-term dividend payout ratio 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 maintains the Dividend Reinvestment Plan, which provides an opportunity for shareholders to reinvest dividends and to participate in optional cash contributions for the purpose of purchasing common shares. This plan provides for a discount of up to 5 per cent from the average market price of Emera’s common shares for common shares purchased in connection with the reinvestment of cash dividends. The discount was 2 per cent in 2023.

The Board approved the payment of the following dividends during the last three completed fiscal years, as summarized in the following table:

 

       
Class of Shares      2023        2022        2021  
       

Common Shares(1), (2), (3)

       $2.7875           $2.6775           $2.5750   
       

Series A First Preferred Shares(4)

       $0.5456           $0.5456           $0.5456   
       

Series B First Preferred Shares

       $1.5583           $0.6869           $0.4873   
       

Series C First Preferred Shares(5)

       $1.2873           $1.1802           $1.1802   
       

Series E First Preferred Shares

       $1.1250           $1.1250           $1.1250   
       

Series F First Preferred Shares(6)

       $1.0505           $1.0505           $1.0505   
       

Series H First Preferred Shares(7)

       $1.3140           $1.2250           $1.2250   
       

Series J First Preferred Shares(8)

       $1.0625           $1.0625           $0.6470   
       

Series L First Preferred Shares(9)

       $1.1500           $1.1500           $0.1638   

 

  (1)

On September 24, 2021, Emera approved an increase in the annual common share dividend rate from $2.55 to $2.65. The first payment was effective November 15, 2021.

 

 

  (2)

On September 22, 2022, Emera approved an increase in the annual common share dividend rate from $2.65 to $2.76. The first payment was effective November 15, 2022.

 

 

  (3)

On September 20, 2023, Emera approved an increase in the annual common share dividend rate from $2.76 to $2.87. The first payment was effective November 15, 2023.

 

 

  (4)

The Series A First Preferred Shares annual dividend rate was reset from $0.6388 to $0.5456 for the five year period commencing August 15, 2020 and ending on (and inclusive of) August 14, 2025.

 

 

  (5)

The Series C First Preferred Shares annual dividend rate was reset from $1.18024 to $1.60852 for the five year period commencing August 15, 2023 and ending on (and inclusive of) August 14, 2028.

 

 

  (6)

The Series F First Preferred Shares annual dividend rate was reset from $1.0625 to $1.0505 for the five year period commencing February 15, 2020 and ending on (and inclusive of) February 14, 2025.

 

 

  (7)

The Series H First Preferred Shares annual dividend rate was reset from $1.2250 to $1.5810 for the five year period commencing August 15, 2023 and ending on (and inclusive of) August 14, 2028..

 

 

  (8)

The Series J First Preferred Shares with an annual dividend rate of $1.0625 (per share) were issued April 6, 2021.

 

 

  (9)

The Series L First Preferred Shares with an annual dividend rate of $1.150 (per share) were issued September 24, 2021.

 

Pursuant to the Income Tax Act (Canada) and corresponding provincial legislation, all dividends paid on Emera’s common shares and first preferred shares qualify as eligible dividends.

 

Emera Incorporated – 2023 Annual Information Form    33


MARKET FOR SECURITIES

Trading Price and Volume

Emera’s common shares, Series A First Preferred Shares, Series B First Preferred Shares, Series C First Preferred Shares, Series E First Preferred Shares, Series F First Preferred Shares, Series H First Preferred Shares, Series J First Preferred Shares and Series L First Preferred Shares are listed and posted for trading on the TSX under the symbols “EMA”, “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”, respectively. The Barbados DRs are listed on the BSE under the symbol EMABDR. The Bahamas DRs are listed on the BISX under the symbol EMAB. The trading volume and high and low price for Emera’s securities for each month of 2023 are set out In Appendix “C” of this AIF.

At-The-Market Equity Program

On November 14, 2023, 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 dated November 14, 2023 to the Company’s short form base shelf prospectus dated October 3, 2023. The ATM program is expected to remain in effect until November 4, 2025, unless terminated prior to such date by the Company or otherwise in accordance with the terms of the equity distribution agreement. As at December 31, 2023, an aggregate gross sales limit of approximately $200 million remains available for issuance under the ATM program. For more information on the ATM Program, refer to “General Development of the Business – Financing Activity – At-The-Market Equity Program” above.

 

Emera Incorporated – 2023 Annual Information Form    34


DIRECTORS AND OFFICERS

Directors

The following information is provided for each Director of Emera as at December 31, 2023(1):

 

     
Name, Residence, Principal Occupations During the Past Five Years    Director
Since(2)
  Committees(3)    

M. Jacqueline Sheppard (Chair), Calgary, Alberta, Canada

Chair of the Board since May 2014. Director of Suncor Energy Inc., a Canadian integrated energy company and of ARC Resources Ltd., a publicly traded Canadian energy company. Former Director of Alberta Investment Management Corporation (AIMCo), an institutional investment manager.(1) Former Executive Vice President, Corporate and Legal of Talisman Energy Inc. Founder and former Lead Director of Black Swan Energy Inc., an Alberta upstream energy company, which was sold in July 2021. Former Director of Cairn Energy PLC, a publicly traded UK-based international upstream company, as well as former director of the general partner of Pacific Northwest LNG LP and Chair of the Research and Development Corporation of the Province of Newfoundland and Labrador, a provincial Crown corporation, until June 2014.

   2009   (4)  

Scott C. Balfour, Halifax, Nova Scotia, Canada

A Director and President and Chief Executive Officer of Emera since March 29, 2018. Mr. Balfour is a Director of many Emera subsidiaries, including being Chair of Tampa Electric Company and Nova Scotia Power Inc. He is a former director of Martinrea International Inc. He was Chief Operating Officer from 2016 to 2018 and was Executive Vice President and Chief Financial Officer of Emera from April 2012 to March 2016. From 1994 to 2011 he was Chief Financial Officer and then President of Aecon Group Inc., a Canadian publicly traded construction and infrastructure development company. He is also past Chair of the Ontario Energy Association.

   2018   (5)  

James V, Bertram Calgary, Alberta, Canada

Chair of the Board, Keyera Corporation. Formerly President, and Chief Executive Officer of Keyera from its inception in 1998 until 2015, when he became Executive Chair. Previously Vice President – Marketing for the worldwide operations of Gulf Canada. Director of Methanex Corporation, the world’s largest producer and supplier of methanol to major international markets.

   2018  

Chair of HSEC and Member of MRCC

 

Henry E. Demone, Lunenburg, Nova Scotia, Canada

Former Chair of High Liner Foods, the leading North American processor and marketer of value-added frozen seafood. Mr. Demone was President of High Liner Foods since 1989 and its President and Chief Executive Officer from 1992 to May 2015. He was interim Chief Executive Officer of High Liner Foods from August 2017 until April 2018. A Director of Saputo Inc.

   2014  

Chair of MRCC and Member of

NCGC

 

Paula Y. Gold-Williams, San Antonio, Texas, U.S.

Former President and CEO of CPS Energy, a fully integrated electric and natural gas municipal utility based in San Antonio, Texas. Currently serves as the Co-Chair of the Keystone Policy Center, having been a member of both the Policy Center and its Energy Board since 2016. Former .Board member and Treasurer of EPIcenter, an innovation think tank; incubator and accelerator; and strategic advisory organizationEnergy Pillar Co-Chair of Dentons’ Global Smart Cities & Communities Initiatives and Think Tank. Advisory Board Serves on the US Secretary of Energy’s Advisory Board. A Director of ReNew Energy Global Plc, a renewable energy company based in India.

   2022  

Member of AC and HSEC

 

Kent M. Harvey, New York, New York, U.S.

Former Chief Financial Officer for PG&E Corporation, an energy-based holding company, and the parent of Pacific Gas and Electric Company, one of the largest combined natural gas and electric energy companies in the United States.

   2017  

Chair of AC and Member of HSEC

 

 

Emera Incorporated – 2023 Annual Information Form    35


B. Lynn Loewen, FCPA, FCA, Westmount, Quebec, Canada

Former President of Minogue Medical Inc., a Canadian supplier of innovative medical technologies, supplies and equipment. Former President of Expertech Network Installation Inc., a Canadian network infrastructure service provider, from 2008 to 2011. Member of the Board of Directors of National Bank of Canada, a Canadian Chartered Bank, Chair of its Audit Committee and member of its Technology Comittee. Former member of the Board of Directors of Xplore Inc., a Canadian broadband service provider, and a member of its Audit Committee from 2021 to 2023. Former member of the Public Sector Pension Investment Board, serving on the Audit and Conflicts Committee and as Audit Committee Chair. Chancellor of Mount Allison University and a member of the Executive Committee and Chair of its Nominating and Governance Committee since 2018. Member of the Board of Regents from 1998 to 2008, serving as Chair from 2007-2008.

   2013  

Member of AC, HSEC and RSC

 

Ian E. Robertson, Oakville, Ontario, Canada

A principal of the Northern Genesis Capital Group, an investment group focused on identifying and acquiring energy transition businesses which demonstrate strong sustainability and Environmental, Social and Governance (ESG) alignment. Former CEO of Algonquin Power & Utilities Corp. (Algonquin Power). Former member of the Board of Directors of Northern Genesis Acquisition Corp., Northern Genesis Acquisition Corp. II and Northern Genesis Acquisition Corp. III. Former Director of Embark Technology, Inc., an autonomous vehicle company,Largo Resources Ltd., Algonquin Power and Atlantica Sustainable Infrastructure plc.

   2022  

Member of AC and RSC

 

Andrea S. Rosen, Toronto, Ontario, Canada

Former Vice-Chair of TD Bank Financial Group and President of TD Canada Trust. Director of Manulife Financial Corporation, a Canadian multinational insurance company and financial services provider; Ceridian HCM Holding Inc., a global human capital management software company and Element Fleet Management Corp., a global fleet management company, providing services and financing for commercial vehicle fleets. Former Director of Alberta Investment Management Corporation (“AIMCo.”). Former Director of Hiscox Ltd., a Bermuda-incorporated specialty insurer listed on the London Stock Exchange.

   2007  

Chair of NCGC and Member of AC

 

Karen H. Sheriff, Picton, Ontario, Canada

Ms. Sheriff is past President and CEO of Q9 Networks Inc., and prior to that, President and CEO of Bell Aliant, Inc., from 2008 to 2014. She held senior leadership positions for more than nine years with BCE Inc. and currently serves on the BCE Inc. Board of Directors. She spent over 10 years at United Airlines in the areas of marketing, strategy, human resources, and finance. She is a former member of the Board of Directors of CPP Investments and WestJet Airlines Ltd.

   2021  

Member of MRCC, RSC and NCGC

 

Jochen E. Tilk, Toronto, Ontario, Canada

Former Executive Chair of Nutrien Ltd., a Canadian global supplier of agricultural products and services based in Saskatoon, Saskatchewan. Former President and Chief Executive Officer of Potash Corporation of Saskatchewan. Previously President and Chief Executive Officer of Inmet Mining Corporation, a Canadian-based, international metals company. Mr. Tilk is a director of AngloGold Ashanti Limited, a publicly listed international gold mining company, headquartered in Johannesburg, South Africa. He is also Vice-Chair of the Princess Margaret Cancer Foundation, a not-for-profit organization. He is the former Chair of the board of directors of Canpotex Limited. Former Director of the Fertilizer Institute and the International Fertilizer Association.

   2018  

Chair of RSC and Member of MRCC and NCGC

 

 

  (1)

Effective January 1, 2023, Ms. Sheppard retired from the AIMCo Board of Directors.

 

  (2)

Denotes the year the individual became a Director of Emera. Directors are elected for a one year term which expires at the termination of Emera’s annual general meeting;

 

  (3)

Audit Committee (AC), Health, Safety and Environment Committee (HSEC), Management Resources and Compensation Committee (MRCC), Nominating and Corporate Governance Committee (NCGC), and Risk and Sustainability Committee (RSC);

 

  (4)

Ms. Sheppard is not a member of any committee but attends all committee meetings as Chair of the Board;

 

  (5)

Mr. Balfour is not a member of any committee as he is the President and Chief Executive Officer of the Company but attends all committee meetings.

 

Emera Incorporated – 2023 Annual Information Form    36


Officers

The Officers of Emera as at December 31, 2023 were as follows:

 

   
Name and Residence    Principal Occupations During the Past Five Years

Scott C. Balfour

President and Chief Executive Officer

Halifax, Nova Scotia, Canada

  

A Director and President and Chief Executive Officer of Emera since March 29, 2018.(1)

Gregory W. Blunden, FCPA

Chief Financial Officer

Halifax, Nova Scotia, Canada

  

Chief Financial Officer of Emera since March 2016.

Karen E. Hutt

Executive Vice-President, Business Development and Strategy

Halifax, Nova Scotia, Canada

  

Executive Vice-President, Business Development and Strategy of Emera since October 21, 2019. Previously, President and Chief Executive Officer of NSPI since August 2016.

Bruce A. Marchand

Chief Risk and Sustainability Officer Halifax, Nova Scotia, Canada

  

Chief Risk and Sustainability Officer of Emera since June 30, 2022. Prior to this Chief Legal and Compliance Officer of Emera and NSPI since December 1, 2014 and Chief Legal Officer of Emera and NSPI since January 2012.

R. Michael Roberts

Chief Human Resources Officer

Halifax, Nova Scotia, Canada

  

Chief Human Resources Officer of Emera and NSPI since December 1, 2014.

Daniel P. Muldoon

Executive Vice-President Project Development and Operations Support

Halifax, Nova Scotia, Canada

  

Executive Vice-President Project Development and Operations Support of Emera. Chair of the Boards of ENL, EBPC, Emera Technologies LLC and NMGC and Block Energy, LLC. Former Director of Emera Maine from August 2013 until March 2020. Director of TEC and NSPML. Formerly Executive Vice-President, Major Renewables and Alternative Energy since May 2014.

Michael R. Barrett

Executive Vice-President and General Counsel

Halifax, Nova Scotia, Canada

  

Executive Vice-President and General Counsel of Emera since July 1, 2022. Prior to this, General Counsel of Emera since November 20, 2017. Prior to joining Emera, Senior Partner and head of the power and climate change practice groups at Bennett Jones LLP in Toronto.

Brian C. Curry

Corporate Secretary

Halifax, Nova Scotia, Canada

  

Corporate Secretary of Emera since November 16, 2023 (2) and prior to that Associate Corporate Secretary, Emera. Former Senior Director Regulatory and Corporate Secretary, NSPI from February 2021 to February 2023, Senior Regulaory Counsel and Corporate Secretary, NSPI from January 1, 2020 to February 2021 and Regulatory Counsel from January 2015 to January 2020.

 

  (1)

Mr. Balfour’s principal occupations during the past five years are described above in the Directors table.

 

  (2)

Effective November 16, 2023, Mr. Brian C. Curry succeeded Mr. Stephen D. Aftanas as Corpoate Secretary. Effective January 31, 2024, Mr. Aftanas retired from Emera and various subsidiaries and/or subsidiary boards.

As at December 31, 2023, the Directors and Officers, in total, beneficially owned or controlled, directly or indirectly, 184,256 common shares or less than 1 per cent of the issued and outstanding common shares of Emera.

 

Emera Incorporated – 2023 Annual Information Form    37


AUDIT COMMITTEE

The Audit Committee of Emera is composed of the following five members, all of whom are independent Directors: Kent M. Harvey (Chair), Paula Gold-Williams, B. Lynn Loewen, Ian E. Robertsonand Andrea S. Rosen. The responsibilities and duties of the Audit Committee are set out in the Audit Committee’s Charter, a copy of which is attached as Appendix “D” to this AIF.

The Board believes that the composition of the Audit Committee reflects a high level of financial literacy and experience. Each member of the Audit Committee has been determined by the Board to be “financially literate” as such term is defined under Canadian securities laws. The Board has made these determinations based on the education and breadth and depth of experience of each member of the Audit Committee. The following is a description of the education and experience of each member of the Audit Committee that is relevant to the performance of his or her responsibilities as a member of the Audit Committee:

Kent M. Harvey, Committee Chair

Former Chief Financial Officer for PG&E Corporation, an energy-based holding company headquartered in San Francisco. PG&E Corporation is the parent company of Pacific Gas and Electric Company, one of the largest combined natural gas and electric energy companies in the United States. In over 33 years with PG&E Corporation, Mr. Harvey held progressively senior roles before he retired in 2016, including Senior Vice President and Chief Financial Officer 2009 to 2015, Senior Vice President, Chief Risk and Audit Officer 2005 to 2009. He was Senior Vice President, Chief Financial Officer and Treasurer with Pacific Gas and Electric Company, a subsidiary of PG&E Corporation, from 2000 to 2005. He holds a Bachelor’s degree in Economics and a Master’s degree in Engineering, both from Stanford University.

Paula Y. Gold-Williams

She is the former President and CEO of CPS Energy, a fully integrated electric and natural gas municipal utility based in San Antonio, Texas. Ms. Gold-Williams served in positions of increasing responsibility at CPS Energy before becoming CEO in 2015. She held multiple other positions during her 17-year career at CPS Energy, including Group EVP – Financial & Administrative Services, CFO and Treasurer. Co-Chair of the Keystone Policy Center, having been a member of both the Policy Center and its Energy Board since 2016. Former Board member and Treasurer of EPIcenter, an innovation think tank; incubator and accelerator; and strategic advisory organization. She also serves on the US Secretary of Energy’s Advisory Board (“SEAB”) and is a member of the board of directors of ReNew Energy Global Plc, a renewable energy company based in India. Formerly, First Vice Chair of the Electric Power Resource Institute (EPRI); a member and designated Chair Pro Tem of the Federal Reserve Bank of Dallas’ San Antonio Branch; and a past-Chair of the San Antonio Chamber of Commerce. She holds an Associate Degree in Fine Arts from San Antonio College and a BBA in accounting from St. Mary’s University. She earned a Finance and Accounting MBA from Regis University in Denver, Colorado. She is a Certified Public Accountant and a Chartered Global Management Accountant.

B. Lynn Loewen, FCPA, FCA

Former President of Minogue Medical Inc., a Canadian supplier of innovative medical technologies, supplies and equipment. From 2008 to 2011, she was President of Expertech Network Installation Inc., a Canadian network infrastructure service provider and also held key positions with Bell Canada Enterprises, as Vice President of Finance Operations and Vice President of Financial Controls. Earlier in her career, she was with Air Canada Jazz where she held positions of increasing responsibility, including Vice President of Corporate Services and Chief Financial Officer. She is a member of the Board of Directors of National Bank of Canada, a Canadian Chartered Bank, Chair of its Audit Committee and member of its Technology Comittee. She was a member of the Board of Directors of Xplore Inc., a Canadian broadband service provider, and a member of its Audit Committee from 2021 to 2023. She is also a former member of the Public Sector Pension Investment Board where she served on the Audit and Conflicts Committee and as Audit Committee Chair. Chancellor of Mount Allison University and a member of the Executive Committee and Chair of its Nominating and Governance Committee since 2018. She was a member of the Board of Regents from 1998 to 2008, serving as Chair from 2007-2008. She holds a Bachelor of Commerce

 

Emera Incorporated – 2023 Annual Information Form    38


from Mount Allison University. Fellow of the Chartered Professional Accountants and has received the Institute of Corporate Directors, Directors Designation.

Ian E. Robertson

A principal of the Northern Genesis Capital Group, an investment group focused on identifying and acquiring energy transition businesses which demonstrate strong sustainability and Environmental, Social and Governance (ESG) alignment. Former CEO of Algonquin Power & Utilities Corp. (Algonquin Power), a publicly traded, diversified international generation, transmission, and distribution utility. Founder and principal of Algonquin Power Corporation Inc., a private independent power developer formed in 1988 and predecessor organization to Algonquin Power. Over 30 years of experience in the development of electric power generating projects and the operation of diversified regulated utilities. Former Member of the Board of Directors of Northern Genesis Acquisition Corp., Northern Genesis Acquisition Corp. II and Northern Genesis Acquisition Corp. III and a former Director of Embark Technology, Inc., an autonomous vehicle company,Largo Resources Ltd., Algonquin Power and Atlantica Sustainable Infrastructure plc. Mr. Robertson is an electrical engineer and holds a Professional Engineering designation through his Bachelor of Applied Science degree awarded by the University of Waterloo. He earned a Master of Business Administration degree from York University’s Schulich School of Business. He holds a Chartered Financial Analyst designation, as well as a global professional Master of Laws degree from the University of Toronto. He received a Chartered Director designation from the Directors College of McMaster University. Mr. Robertson is a former member of the board of directors of the American Gas Association.

Andrea S. Rosen

Vice-Chair of TD Bank Financial Group and President, TD Canada Trust from 2002 to 2005. Prior to this, Executive Vice President of TD Commercial Banking and Vice Chair TD Securities. Before joining TD Bank, was Vice President of Varity Corporation from 1991 to 1994 and worked at Wood Gundy Inc. (later CIBC-Wood Gundy) in a variety of roles from 1981 to 1990, eventually becoming Vice President and Director. Holds a Bachelor of Laws from Osgoode Hall Law School and a Masters of Business Administration from the Schulich School of Business at York University. She received a Bachelor of Arts from Yale University. Ms. Rosen is a Director and member of the Audit Committee of Ceridian HCM Holding Inc., a global human capital management software company, and Director and member of the Audit Committee of Manulife Financial Corporation, an issuer listed on The Toronto Stock Exchange, New York Stock Exchange, The Stock Exchange of Hong Kong, and the Philippine Stock Exchange. She is a Director of Element Fleet Management Corp., a global fleet management company. Former Director and member of the Audit Committee of Hiscox Ltd., a Bermuda-incorporated specialty insurer listed on the London Stock Exchange, and former Director of Alberta Investment Management Corporation (“AIMCo.”). Former member of the Board of Directors of the Institute of Corporate Directors.

Audit and Non-Audit Services Pre-Approval Process

The Audit Committee is responsible for the oversight of the work of the external auditors. As part of this responsibility, the Audit Committee is required to pre-approve the audit and non-audit services performed by the external auditors in order to assure that they do not impair the external auditors’ independence from the Company. Accordingly, the Audit Committee has adopted an Audit and Non-Audit Pre-Approval Policy, which sets forth the procedures and the conditions pursuant to which services proposed to be performed by the external auditors may be pre-approved.

Unless a type of service has received the pre-approval of the Audit Committee, it will require specific approval by the Audit Committee if it is to be provided by the external auditors. Any proposed services exceeding the pre-approved cost levels will also require specific approval by the Audit Committee.

 

Emera Incorporated – 2023 Annual Information Form    39


Auditors’ Fees

The aggregate fees billed by Ernst & Young LLP, the Company’s external auditors, during the fiscal years ended December 31, 2023 and 2022 respectively, were as follows:

 

 Service Fee      2023 ($)          2022 ($)    

Audit Fees

             $ 3,910,266                  $ 2,018,989    

Audit-Related Fees (1)

       174,410            19,600    

Tax Fees (2)

       39,450            337,999    

All Other Fees

       75,000            —    

Total

             $ 4,199,126                  $ 2,376,588    

 

  (1)

Audit-related fees for Emera relate to fees associated with agreed upon procedures over rate-case filings and the audit of pension plans.

 

  (2)

Tax fees for Emera relate to tax compliance services and general tax consulting advice on various matters.

CERTAIN PROCEEDINGS

To the knowledge of Emera, none of the Directors or Officers of the Company:

 

(1)

are, as at the date of this AIF, or have been, within ten years before the date of this AIF, a director, chief executive officer or chief financial officer of any company that:

 

  (a)

was subject to an Order that was issued while the Director or Officer was acting in the capacity as director, chief executive officer or chief financial officer; or

 

  (b)

was subject to an Order that was issued after the Director or Officer ceased to be a director, chief executive officer or chief financial officer and which resulted from an event that occurred while that person was acting in the capacity as director, chief executive officer of chief financial officer;

 

(2)

are, as at the date of this AIF, or have been within ten years before the date of this AIF, a director or executive officer of any company that, while that person was acting in that capacity, or within a year of that person ceasing to act in that capacity, became bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency or was subject to or instituted any proceedings, arrangements or compromise with creditors or had a receiver, receiver manager or trustee appointed to hold its assets;

 

(3)

have, within the ten years before the date of this AIF, become bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency, or become subject to or instituted any proceedings, arrangement or compromise with creditors, or had a receiver, receiver manager or trustee appointed to hold the assets of the proposed nominee; or

 

(4)

have been subject to any penalties or sanctions imposed by a court relating to securities legislation or by a securities regulatory body or has entered in a settlement agreement with a securities regulatory body, or is subject to any penalties or sanctions imposed by a court or regulatory body that would likely be considered important to a reasonable investor making an investment decision.

CONFLICTS OF INTEREST

There are no existing or potential material conflicts of interest between Emera or any of its subsidiaries and any Director or Officer of Emera or any of its subsidiaries.

 

Emera Incorporated – 2023 Annual Information Form    40


LEGAL PROCEEDINGS AND REGULATORY ACTIONS

To the knowledge of Emera, there are no legal proceedings that individually or together could potentially involve claims against Emera or its subsidiaries for damages totaling 10 per cent or more of the current assets of Emera, exclusive of interest and costs.

During Emera’s most recently completed financial year, there have been no (a) penalties or sanctions imposed against Emera by a court relating to securities legislation or by a securities regulatory authority, (b) other penalties or sanctions imposed by a court or regulatory body against Emera that would likely be considered important to a reasonable investor in making an investment decision, and (c) settlement agreements entered into by Emera before a court relating to securities legislation or with a securities regulatory authority.

NO INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

None of the following persons or companies, namely (a) a Director or Officer of Emera, (b) a person or company that is the direct or indirect beneficial owner of, or who exercises control or direction over, more than 10 per cent of any class or series of Emera’s outstanding voting securities, or (c) an associate or affiliate of any person or company named in (a) or (b), had a material interest in any transaction involving Emera within Emera’s last three completed financial years or during the current financial year that has materially affected or is reasonably expected to materially affect Emera.

MATERIAL CONTRACTS

Emera did not enter into any material contracts outside the ordinary course of business during the year ended December 31, 2023, nor has it entered into any material contracts outside the ordinary course of business prior to the year ended December 31, 2023 that are still in effect as at the date of this AIF.

TRANSFER AGENT AND REGISTRAR

TSX Trust Company acts as Emera’s transfer agent and registrar for Emera’s common shares and first preferred shares. Registers for the registration and transfer of these securities of Emera are kept at TSX Trust Company’s principal offices in Halifax, Montreal and Toronto.

EXPERTS

Ernst & Young LLP are the external auditors of Emera. Ernst & Young LLP report that they are independent in the context of the CPA Code of Professional Conduct of the Chartered Professional Accountants of Nova Scotia and are in compliance with Rule 3520 of the Public Company Accounting Oversight Board (United States).

ADDITIONAL INFORMATION

Additional information relating to Emera may be found on SEDAR+ at www.sedarplus.ca or upon request to the Corporate Secretary, Emera Incorporated, P.O. Box 910, Halifax, N.S., B3J 2W5, telephone (902) 428-6096 or fax (902) 428-6171. Additional information, including Directors’ and Officers’ remuneration and indebtedness, principal holders of Emera’s securities and securities authorized for issuance under equity compensation plans, is contained in Emera’s information circular for the most recent annual meeting of Emera’s common shareholders. Additional financial information is provided in Emera’s Audited Financial Statements and MD&A.

At any time, Emera will provide to any person upon request to the Corporate Secretary, a copy of the Emera Code of Conduct. Alternatively, a copy of the Emera Code of Conduct is available electronically under Emera’s profile on SEDAR+ at www.sedarplus.ca and on its corporate website at www.emera.com.

 

Emera Incorporated – 2023 Annual Information Form    41


APPENDIX “A” - Definitions of Certain Terms

 

For convenience, certain terms used throughout this AIF shall have the following meanings:

adjusted net income has the meaning ascribed to it in the “Non-GAAP Financial Measures and Ratios” section of the MD&A, which is incorporated herein by reference, a copy of which is available electronically under Emera’s profile on SEDAR+ at www.sedarplus.ca;

“AFUDC” means allowance for funds used during construction and represents the cost of financing regulated construction projects and is capitalized to the cost of property, plant and equipment, where permitted by the regulator;

“AIF” or “Annual Information Form” means this 2023 Annual Information Form of Emera;

“Atlantic Canada” means the region of Canada consisting of the Provinces of New Brunswick, Newfoundland and Labrador, Nova Scotia and Prince Edward Island;

“ATM Program” means an at-the-market distribution program allowing Emera to issue common shares from treasury at the prevailing market price.

“Audited Financial Statements” means the audited consolidated financial statements of Emera as at and for the years ended December 31, 2023 and December 31, 2022, together with the auditors’ report thereon, a copy of which is available electronically under Emera’s profile on SEDAR+ at www.sedarplus.ca;

“Bahamas DRs” means the DRs listed on BISX;

“Barbados DRs” means the DRs listed on the BSE;

“BBD” means Barbadian dollars;

“BISX” means The Bahamas International Securities Exchange;

“Bear Swamp” means Bear Swamp Power Company, LLC, a 633 MW pumped storage hydroelectric company incorporated under the laws of the State of Delaware in which Emera indirectly holds a 50 per cent interest;

“Block Energy” means Block Energy LLC, formerly Emera Technologies LLC, a wholly-owned subsidiary of Emera existing under the laws of the State of Florida.

“BLPC” means Barbados Light & Power Company Limited, a vertically integrated electric utility company incorporated under the laws of Barbados and a wholly-owned, direct subsidiary of ECI;

“Board” means the Board of Directors of Emera;

“Brooklyn Energy” means Brooklyn Power Corporation, a 30 MW biomass co-generation company incorporated under the laws of the Province of Nova Scotia and a wholly-owned direct subsidiary of Emera;

“Brunswick Pipeline” means the pipeline delivering re-gasified natural gas from the Saint John LNG gas terminal near Saint John, New Brunswick to markets in the Northeastern United States, which is owned directly by EBPC;

“BSD” means Bahamian dollars;

“BSE” means the Barbados Stock Exchange;

“CAD” means Canadian dollars;

“CAIR” means the Clean Air Interstate Rule;

“CER” or “Canada Energy Regulator”, the independent regulator of EBPC.

“COMFIT” means the Nova Scotia Community Feed in Tariff program which is offered by the Province of Nova Scotia and enables community organizations to be involved in renewable electricity generation;

“Company” means Emera;

Consolidated Balance Sheets” means the consolidated balance sheets contained within the Audited Financial Statements;

“Directors” mean the directors of Emera and “Director” means any one of them;

“Dividend Reinvestment Plan” or “DRIP” means the Company’s Common Shareholders’ Dividend Reinvestment and Share Purchase Plan;

“DR” means a depositary receipt representing common shares of Emera;

“EBPC” or “Emera Brunswick Pipeline Company means Emera Brunswick Pipeline Company Ltd., a company incorporated under the federal laws of Canada and a wholly-owned, indirect subsidiary of Emera;

ECI means Emera (Caribbean) Incorporated, a company incorporated under the laws of Barbados and an indirect subsidiary of Emera and the parent company of BLPC and GBPC;

“ECRC” means the environmental cost recovery clause;

 

 

Emera Incorporated – 2023 Annual Information Form    42


“Electricity Act” means the Electricity Act, 2004, c. 25, s. 1. (Nova Scotia);

“Emera” means Emera Incorporated, a public company incorporated under the laws of the Province of Nova Scotia and traded on the TSX under the symbol “EMA”;

Emera Energy means the businesses of Emera Energy Services, Brooklyn Energy and Bear Swamp;

Emera Energy LP” means a wholly-owned subsidiary of Emera formed under the laws of the Province of Nova Scotia;

“Emera Energy Services” or “EES” means Emera Energy LP and Emera Energy Services, Inc., a natural gas and electricity marketing and trading company and a wholly-owned, indirect subsidiary of Emera incorporated under the laws of the State of Delaware, which together form a natural gas and electricity marketing and trading business;

“ENL” or “Emera Newfoundland and Labrador” means Emera Newfoundland and Labrador Holdings Incorporated, a company incorporated under the laws of the Province of Newfoundland and Labrador and a wholly-owned, direct subsidiary of Emera, and the parent company of NSP Maritime Link Inc. and ENL Island Link Inc.;

“ENL Island Link Inc.” means ENL Island Link Incorporated, a company incorporated under the laws of the Province of Newfoundland and Labrador and a wholly-owned, direct subsidiary of ENL;

EPA” means the U.S. Environmental Protection Agency;

“Fair Trading Commission, Barbados” or “FTC” means the regulator of BLPC;

“FAM” means the fuel adjustment mechanism established by the UARB;

“FCM” means forward capacity market;

“FERC” means the United States Federal Energy Regulatory Commission;

“Fitch” means the credit rating agency Fitch Ratings Inc;

First Preferred Shares” means each series of Emera’s authorized first preferred shares, namely its Series 2016-A Conversion, First Preferred Shares, Series A First Preferred Shares, Series B First Preferred Shares, Series C First Preferred Shares, Series D First Preferred Shares, Series E First Preferred Shares, Series F First Preferred Shares, Series G First Preferred Shares Series H First Preferred Shares, Series I First Preferred Shares

Series J First Preferred Shares and Series L First Preferred Shares;

“FPSC” means the Florida Public Service Commission, the regulator of Tampa Electric and PGS;

“GBPA” means The Grand Bahama Port Authority, the regulator of GBPC;

“GBPC” or “Grand Bahama Power Company” means Grand Bahama Power Company Limited, a vertically integrated electric utility company incorporated under the laws of the Commonwealth of The Bahamas and an indirect subsidiary of ECI;

“Government of Canada Bond Yield” on any date means the yield to maturity on such date (assuming semi-annual compounding) of a Canadian dollar denominated non-callable Government of Canada bond with a term to maturity of five years as quoted as of 10:00 a.m. (Toronto time) on such date and which appears on the Bloomberg Screen GCAN5YR Page on such date; provided that, if such rate does not appear on the Bloomberg Screen GCAN5YR Page on such date, the Government of Canada Bond Yield will mean the average of the yields determined by two registered Canadian investment dealers selected by the Company as being the yield to maturity on such date (assuming semi-annual compounding) which a Canadian dollar denominated non-callable Government of Canada bond would carry if issued in Canadian dollars at 100 per cent of its principal amount on such date with a term to maturity of five years;

“Government of Canada T-Bill Rate” means, for any quarterly floating rate period, the average yield expressed as a percentage per annum on three month Government of Canada treasury bills, as reported by the Bank of Canada, for the most recent treasury bills auction preceding the applicable floating rate calculation date;

“GWh” means the amount of electricity measured in gigawatt hours;

“Hybrid Notes” means the $1.2 billion USD unsecured, fixed-to-floating subordinated notes of Emera due 2076;

“IFRS” means International Financial Reporting Standards;

IMP” means integrity management programs;

“IPPs” means independent power producers;

“km” means kilometre(s);

“Labrador-Island Transmission Link Project” or “LIL” means an electricity transmission project in Newfoundland and Labrador being developed by Nalcor, which will enable the transmission of the

 

 

Emera Incorporated – 2023 Annual Information Form    43


Muskrat Falls energy between Labrador and the island of Newfoundland;

“LNG” means liquefied natural gas;

“Lucelec” means St. Lucia Electricity Services Limited, a company incorporated under the laws of St. Lucia in which Emera holds an indirect 19.5 per cent interest through ECI;

“M&NP” means the Maritimes & Northeast Pipeline, a pipeline that transports natural gas between the Maritime Provinces and New England, in which Emera holds an indirect 12.9 per cent interest;

“Maritime Link” means the transmission project which includes two 170-km sub-sea cables between the island of Newfoundland and the Province of Nova Scotia, developed by NSP Maritime Link Inc.;

“Maritime Provinces” means the region of Canada consisting of the Provinces of Nova Scotia, New Brunswick and Prince Edward Island;

MD&A means Emera’s Management’s Discussion and Analysis for the fiscal year ended December 31, 2023, a copy of which is available electronically under Emera’s profile on SEDAR+ at www.sedarplus.ca;

Moodys” means the credit rating agency Moody’s Investor Services, Inc. a subsidiary of Moody’s Corporation;

“MW” means the amount of power measured in megawatts;

“Nalcor” means Nalcor Energy, a company that is incorporated under a special act of the Legislature of the Province of Newfoundland and Labrador as a Crown corporation;

“NB Power” means New Brunswick Power Corporation, a provincial Crown corporation formed under the laws of the Province of New Brunswick, responsible for the generation, transmission and distribution of electricity in the Province of New Brunswick;

“NERC” means North American Electric Reliability Corporation;

“New England” means the region of the United States consisting of the States of Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island and Vermont;

“NMGC” means New Mexico Gas Company, Inc., a regulated gas distribution utility incorporated under the laws of Delaware and serving customers across New Mexico;

“NMPRC” means the New Mexico Public Regulation Commission, the regulator of NMGC;

“NPCC” means Northeast Power Coordinating Council, Inc.;

“Northeastern United States” means the region of the United States consisting of New England and the States of New Jersey, New York and Pennsylvania;

“NS Block” means the electricity transmitted through the Maritime Link from the Muskrat Falls hydroelectric project

“NSP Maritime Link Inc.” or “NSPML” means NSP Maritime Link Incorporated, a wholly-owned direct subsidiary of ENL, incorporated under the laws of the Province of Newfoundland and Labrador, that developed the Maritime Link;

“NSPI” or “Nova Scotia Power” means Nova Scotia Power Incorporated, a vertically integrated electric utility incorporated under the laws of the Province of Nova Scotia and a wholly-owned direct and indirect subsidiary of Emera;

“Officers” mean the executive officers of Emera and “Officer” means any one of them;

“OM&G” means operating, maintenance and general;

OBPS” means output-based pricing system;

“Order” means a cease trade order, an order similar to a cease trade order or an order that denies a company access to any exemption under securities legislation that is in effect for a period of more than 30 consecutive days;

“PGAC” means purchased gas adjustment clause;

PGS” or “Peoples Gas System” means Peoples Gas System, Inc., formerly the Peoples Gas System Division of TEC, operating as a regulated gas distribution utility serving customers across Florida , and a wholly-owned direct subsidiary of TECO Gas Operations, Inc. existing under the laws of the State of Florida;

PP&E” means property, plant and equipment;

Privatization Act” means the Nova Scotia Power Privatization Act, S.N.S., 1992, c.8 - and all amendments thereto;

Province” means the Province of Nova Scotia, Canada and includes, when the context requires, the provincial government of Nova Scotia, and “provincial” refers to Nova Scotia;

“Public Utilities Act” means the Public Utilities Act (Nova Scotia);

 

 

Emera Incorporated – 2023 Annual Information Form    44


“Rating Agencies” means collectively Fitch, Moody’s and S&P, and “Rating Agency” means any one of the Rating Agencies;

“RENAC” means Repsol Energy North America Canada Partnership;

Reorganization Act” means the Nova Scotia Power Reorganization (1998) Act, S.N.S., 1998, c.19 - and all amendments thereto;

“Repsol” means Repsol S.A, the parent company of RENAC;

“RER” means the Nova Scotia Renewable Electricity Regulations;

“ROE” means return on equity;

“S&P” means the credit rating agency S&P Global Ratings, a division of S&P Global Inc.;

SeaCoast” means SeaCoast Gas Transmission, LLC, a company incorporated under the laws of the State of Delaware and a wholly-owned subsidiary of TECO Energy;

“Securities Act” means the United States Securities Act of 1933, as amended;

“SEDAR+” means the secure web-based system used by all market participants to file, disclose and search for information in Canada’s capital markets, which can be found at www.sedarplus.ca, and replaces SEDAR, the System for Electronic Documents Analysis and Retrieval;

Series 2016-A Conversion, First Preferred Shares means the cumulative preferential first preferred shares, Series 2016-A of Emera;

“Series A First Preferred Shares” means the cumulative 5-year rate reset first preferred shares, Series A of Emera;

“Series B First Preferred Shares” means the cumulative floating rate first preferred shares, Series B of Emera;

“Series C First Preferred Shares” means the cumulative rate reset first preferred shares, Series C of Emera;

“Series D First Preferred Shares” means the cumulative floating rate first preferred shares, Series D of Emera;

“Series E First Preferred Shares” means the cumulative redeemable first preferred shares, Series E of Emera;

“Series F First Preferred Shares” means the cumulative rate reset first preferred shares, Series F of Emera;

“Series G First Preferred Shares” means the cumulative floating rate first preferred shares, Series G of Emera;

“Series H First Preferred Shares” means the cumulative minimum rate reset first preferred shares, Series H of Emera;

Series I First Preferred Shares means the cumulative floating rate first preferred shares, Series I of Emera;

“Series J First Preferred Shares” means the cumulative minimum rate reset first preferred shares, Series J of Emera;

“Series K First Preferred Shares” means the cumulative floating rate first preferred shares, Series K of Emera;

“Series L First Preferred Shares” means the cumulative redeemable first preferred shares, Series L of Emera;

SO2” means sulphur dioxide;

“SoBRA” means solar base rate adjustment;

TEC means Tampa Electric Company, an integrated regulated electric utility, serving customers in West Central Florida, a wholly-owned subsidiary of TECO Energy, incorporated under the laws of the State of Florida ;

“TECO Energy” means TECO Energy, Inc., an energy-related holding company incorporated under the laws of the State of Florida with regulated electric and gas utilities in Florida and a regulated gas utility in New Mexico;

“TECO Gas Operations, Inc.” means the wholly-owned subsidiary of TECO Energy, incorporated under the laws of the State of Florida, and the parent company of PGSI, which as of January 1, 2023, currently owns the regulated gas utility known as PGS, formerly a division of TEC;

“TSX” means The Toronto Stock Exchange;

“UARB” means the Nova Scotia Utility and Review Board, the independent regulator of NSPI;

“USD” means U.S. dollars; and

“USGAAP” means the accounting principles which are recognized as being generally accepted and which are in effect from time to time in the U.S. as codified by the Financial Accounting Standards Board, or any successor institute.

 

 

Emera Incorporated – 2023 Annual Information Form    45


APPENDIX “B” – Summary of Terms and Conditions of Authorized Series of First Preferred Shares

As of December 31, 2023, the following series of First Preferred Shares have been authorized:

Series A, B, C, D, E, F, G, H, I, J, K and L First Preferred Shares

Holders of the First Preferred Shares are not entitled to attend any meetings of the shareholders of Emera or to vote at any such meeting, except: (i) where entitled by law; (ii) for meetings of the holders of first preferred shares as a class and holders of First Preferred Shares as a series; and (iii) in situations when Emera fails to pay, in the aggregate, eight quarterly dividends on the First Preferred Shares.

In any instance where the holders of First Preferred Shares are entitled to vote, each holder shall have one vote for each Preferred Share, subject to the restrictions described under “Share Ownership Restrictions” below.

Holders of Series A, C, F, H and J First Preferred Shares are entitled to receive fixed cumulative preferential cash dividends, as and when declared by the Board, to be reset periodically on established dates to an annualized rate equal to the sum of the then five-year Government of Canada Bond Yield, calculated at the start of the applicable five-year period, and a spread as set forth in the table below (subject, (i) in the case of the Series H preferred shares, to a fixed minimum reset of 4.90 per cent and (ii) in the case of the Series J preferred shares, to a fixed minimum reset of 4.25 per cent). Holders of the Series A, C, F, H and J First Preferred Shares have the right to convert their shares into an equal number of Series B, D, G, I and K First Preferred Shares, respectively, subject to certain conditions, on such conversion dates as set forth in the table below.

Holders of Series B, D, G, I and K First Preferred Shares will be entitled to receive floating rate cumulative preferential cash dividends, as and when declared by the Board. The dividends are payable quarterly, in the amount per share determined by multiplying the applicable quarterly floating dividend rate, which is the sum of the three-month Government of Canada T-Bill Rate , recalculated quarterly, on the applicable reset date plus a spread as set forth in the table below.

The Series A, C, F, H and J First Preferred Shares are redeemable by Emera, in whole or in part under certain circumstances by the payment of cash on the dates set forth in the table below at a price of $25.00 per share plus any accrued and unpaid dividends.

The Series B, D, G, I and K First Preferred Shares are redeemable by Emera, in whole or in part under certain circumstances after their respective initial redemption dates by payment in cash as set forth in the table below at a price equal to (i) $25.00 per share together with all accrued and unpaid dividends up to but excluding the date fixed for redemption in the case of redemptions as set out in the table below or (ii) $25.50 per share together with all accrued and unpaid dividends up to but excluding the date fixed for redemption in the case of redemptions on any other date.

Subject to certain conditions including the right of Emera to redeem, holders of the Series A, C, F, H and J First Preferred Shares, have the right to convert any or all of their Series A, C, F, H and J First Preferred Shares into an equal number of Series B, D, G, I and K First Preferred Shares, respectively. In addition, the Series A, C, F, H and J First Preferred Shares may be automatically converted by Emera into Series B, D, G, I and K First Preferred Shares, respectively if Emera determines that, following conversion by the holders, there would be less than 1,000,000 Series A, C, F, H and J First Preferred Shares outstanding, respectively.

Subject to automatic conversion conditions including the right of Emera to redeem the Series B, D, G, I and K First Preferred Shares, the holders of Series B, D, G, I and K First Preferred Shares have the right to convert any or all of their Series B, D, G, I and K First Preferred Shares into an equal number of Series A, C, F, H and J First Preferred Shares respectively. In addition, Series B, D, G, I and K First Preferred Shares may be automatically converted by Emera into Series A, C, F, H and J First Preferred Shares, respectively

 

Emera Incorporated – 2023 Annual Information Form    46


if Emera determines that, following conversion by the holders, there would be less than 1,000,000 Series B, D, G, I and K First Preferred Shares outstanding.

Holders of Series E First Preferred Shares will be entitled to receive fixed cumulative preferential cash dividends as and when declared by the Board in the amount of $1.125 per share per annum in perpetuity, subject to certain redemption rights. The Series E First Preferred Shares were not redeemable by the Company prior to August 18, 2018. The Series E First Preferred Shares are redeemable on or after August 18, 2018 by Emera in whole or in part, at the Company’s option without the consent of the holder, by the payment of: $26.00 per share if redeemed before August 15, 2019; $25.75 per share if redeemed on or after August 15, 2019 but before August 15, 2020; $25.50 per share if redeemed on or after August 15, 2020 but before August 15, 2021; $25.25 per share if redeemed on or after August 15, 2021 but before August 15, 2022; and $25.00 per share if redeemed on or after August 15, 2022; together, in each case, with all accrued and unpaid dividends up to but excluding the date fixed for redemption.

Holders of Series L First Preferred Shares will be entitled to receive fixed cumulative preferential cash dividends as and when declared by the Board in the amount of $1.150 per share per annum in perpetuity, subject to certain redemption rights. The Series L First Preferred Shares were not redeemable by the Company prior to November 15, 2026. The Series L First Preferred Shares are redeemable on or after November 15, 2026 by Emera in whole or in part, at the Company’s option without the consent of the holder, by the payment of: $26.00 per share if redeemed before November 15, 2027; $25.75 per share if redeemed on or after November 15, 2027 but before November 15, 2028; $25.50 per share if redeemed on or after November 15, 2028 but before November 15, 2029; $25.25 per share if redeemed on or after November 15, 2029 but before November 15, 2030; and $25.00 per share if redeemed on or after November 15, 2030; together, in each case, with all accrued and unpaid dividends up to but excluding the date fixed for redemption.

Applicable redemption, conversion, interest and reset dates and spreads are listed in the following table:

 

       

Series of First

Preferred Shares

   Initial Redemption /
Interest Reset Date
  

Subsequent Redemption / Conversion /

Interest Reset Dates

    Spreads 
       

Series A

   August 15, 2015    August 15, 2020 and every fifth year thereafter    1.84%
       

Series B

   August 15, 2020    August 15, 2025 and every fifth year thereafter    1.84%
       

Series C

   August 15, 2018    August 15, 2023 and every fifth year thereafter    2.65%
       

Series D

      August 15, 2023 and every fifth year thereafter    2.65%
       

Series E

   August 15, 2018      
       

Series F

   February 15, 2020    February 15, 2025 and every fifth year thereafter    2.63%
       

Series G

      February 15, 2025 and every fifth year thereafter    2.63%
       

Series H

   August 15, 2023    August 15, 2028 and every fifth year thereafter    2.54%
       

Series I

      August 15, 2028 and every fifth year thereafter    2.54%
       

Series J

   May 15, 2026    May 15, 2031 and every fifth year thereafter    3.28%
       

Series K

      May 15, 2031 and every fifth year thereafter    3.28%
       

Series L

   November 15, 2026       — 

Series 2016-A Conversion, First Preferred Shares

The Series 2016-A Conversion, First Preferred Shares were authorized pursuant to the Hybrid Notes offering in June 2016. As at December 31, 2023, there were no Series 2016-A Conversion, First Preferred Shares issued and outstanding.

Holders of Series 2016-A Conversion, First Preferred Shares are not entitled to attend any meetings of the shareholders of Emera or to vote at any such meeting, except: (i) where entitled by law; (ii) for meetings of

 

Emera Incorporated – 2023 Annual Information Form    47


the holders of first preferred shares as a class and holders of Series 2016-A Conversion, First Preferred Shares as a series; and (iii) in situations when Emera fails to pay, in the aggregate, eight quarterly dividends on the Series 2016-A Conversion, First Preferred Shares.

In any instance where the holders of Series 2016-A Conversion, First Preferred Shares are entitled to vote, each holder shall have one vote for each Series 2016-A Conversion, First Preferred Share, subject to the restrictions described under “Share Ownership Restrictions” below.

Holders of each series of Series 2016-A Conversion, First Preferred Shares will be entitled to receive cumulative preferential cash dividends, if, as and when declared by the Board, at the same rate as would have accrued on the related series of Hybrid Notes (had such Hybrid Notes remained outstanding). The Series 2016-A Conversion, First Preferred Shares do not have a fixed maturity date.

The Series 2016-A Conversion, First Preferred Shares are redeemable by Emera on June 15, 2026. After that date, Emera may redeem at any time all, or from time to time any part, of the outstanding Series 2016-A Conversion, First Preferred Shares, without the consent of the holders, by the payment of an amount in cash for each such share so redeemed of USD$1,000 per share together with an amount equal to all accrued and unpaid dividends thereon.

 

Emera Incorporated – 2023 Annual Information Form    48


APPENDIX “C” - MONTHLY TRADING VOLUME AND HIGH AND LOW PRICE FOR EMERA’S SECURITIES IN 2023

 

      Common  
Shares  
 

Depositary Receipts

 

 

 

Series of First Preferred Shares

 

 

 Barbados 
 BBD (1)

 

 

 

Bahamas 

 BSD (2)

 

     A         B         C         E         F         H         J         L   

December

High ($)

Low ($)

Volume

  50.55

47.33

19,145,916

  18.83

17.40

0

  9.42

8.70

0

  14.00

13.20

81,163

  15.70

14.76

24,431

  20.45

19.32

228,024

  16.94

16.11

57,698

  17.47

16.62

214,705

  21.90

19.75

215,190

  18.25

17.50

244,386

  17.05

16.30

267,602

November

High ($)

Low ($)

Volume

  49.21

45.45

28,093,789

  23.00

16.21

82

  8.97

8.19

0

  13.91

12.72

148,350

  15.95

15.06

10,561

  20.60

18.14

178,388

  17.10

15.20

37,638

  17.50

15.60

381,774

  21.80

18.98

188,378

  18.49

16.19

218,322

  17.41

15.23

305,514

October

High ($)

Low ($)

Volume

  48.84

43.67

36,544,687

  23.00

15.94

76

  8.94

7.97

0

  13.75

12.75

101,371

  16.39

15.21

30,259

  19.32

17.94

125,041

  16.28

14.99

70,245

  17.17

15.57

41,159

  19.93

18.30

144,040

  17.63

16.00

195,141

  16.40

15.10

147,818

September

High ($)

Low ($)

Volume

  52.31

47.32

18,371,308

  23.00

17.43

192

  9.69

8.75

0

  13.12

13.01

11,087

  15.75

15.02

11,445

  19.70

19.00

151,253

  16.69

15.94

62,159

  16.83

16.25

51,754

  20.34

19.51

113,419

  18.50

17.01

101,830

  16.78

16.06

129,228

August

High ($)

Low ($)

Volume

  53.53

50.04

22,784,822

  25.00

18.35

35

  10.10

10.10

1,000

  13.60

13.03

37,109

  17.00

15.50

13,238

  20.74

19.01

280,632

  16.95

16.39

34,752

  17.55

16.47

78,393

  21.49

19.41

219,728

  20.89

18.04

135,859

  17.00

16.01

80,944

July

High ($)

Low ($)

Volume

  55.74

52.41

20,071,924

  25.00

19.54

201

  10.54

9.88

0

  13.62

13.18

113,886

  17.96

15.97

52,124

  20.95

20.10

165,331

  17.15

16.80

60,766

  17.64

17.02

81,152

  22.90

20.48

132,309

  21.73

20.58

138,081

  17.35

16.85

108,285

June

High ($)

Low ($)

Volume

  56.75

52.96

15,758,704

  25.00

19.97

30

  10.56

9.99

0

  13.30

12.49

91,735

  15.97

14.21

17,410

  20.74

18.90

208,315

  17.65

16.75

29,981

  17.84

17.10

40,398

  21.65

20.24

127,602

  22.08

20.89

58,313

  18.15

16.91

30,399

May

High ($)

Low ($)

Volume

  59.52

55.57

27,608,566

  25.00

20.30

509

  11.03

10.21

0

  13.42

12.54

121,371

  15.35

14.50

38,700

  19.42

18.40

79,745

  18.25

17.27

31,981

  18.30

16.99

222,314

  21.02

20.19

77,556

  22.76

21.04

57,454

  18.49

17.57

67,226

April

High ($)

Low ($)

Volume

  59.16

54.67

27,990,485

  21.73

20.34

0

  10.86

10.17

0

  13.60

13.21

39,553

  16.05

15.25

25,220

  19.60

18.67

79,168

  18.50

17.74

33,017

  17.84

17.45

431,011

  20.86

20.00

90,965

  23.10

22.10

55,156

  19.03

18.00

100,356

March

High ($)

Low ($)

Volume

  56.59

51.94

23,800,570

  20.91

19.07

0

  10.45

9.54

0

  14.20

13.03

136,683

  16.43

15.56

19,660

  20.26

18.66

158,448

  19.08

17.82

58,620

  18.31

16.82

64,854

  21.87

20.04

96,223

  23.25

21.33

109,043

  18.85

18.05

78,142

February

High ($)

Low ($)

Volume

  55.50

52.36

30,781,125

  20.48

19.65

0

  9.60

9.60

210

  14.17

13.76

36,325

  16.50

16.00

16,498

  20.05

19.51

134,376

  19.07

18.06

62,935

  18.55

17.96

68,619

  23.45

21.25

78,081

  24.53

22.85

63,862

  19.27

18.40

70,049

January

High ($)

Low ($)

Volume

  55.31

51.00

28,195,557

  20.58

18.80

0

  10.29

9.40

0

  14.24

13.49

88,141

  16.50

15.05

20,360

  20.45

18.60

92,940

  19.10

16.97

46,564

  18.81

17.47

43,481

  22.80

20.95

83,125

  23.86

21.82

69,677

  19.28

17.20

108,678

 

(1)

The Barbados DRs trade on the BSE. During those months in 2023 when the Volume Traded was zero (0), the table above indicates the high and low trading prices of the Barbados DRs relative to those of Emera’s common shares on the TSX.

 

(2)

The Bahamas DRs trade on the BISX. During those months in 2023 when the Volume Traded was zero (0), the table above indicates the high and low trading prices of the Bahamas DRs relative to those of Emera’s common shares on the TSX.

 

Emera Incorporated – 2023 Annual Information Form    49


February 2023    LOGO

APPENDIX “D” - EMERA INCORPORATED AUDIT COMMITTEE CHARTER

 

 

 

PART I

MANDATE AND RESPONSIBILITIES

Committee Purpose

There shall be a committee of the Board of Directors (the “Board”) of Emera Inc. (“Emera”) which shall be known as the Audit Committee (the “Committee”). The Committee shall assist the Board in discharging its oversight responsibilities concerning:

 

-

the quality and integrity of Emera’s financial statements;

 

-

the effectiveness of Emera’s internal control systems over financial reporting;

 

-

the internal audit and assurance process;

 

-

the qualifications, independence and performance of the external auditors;

 

-

major financial risk exposures;

 

-

Emera’s compliance with legal requirements and securities regulations in respect of financial statements and financial reporting; and

 

-

any other duties set out in this Charter or delegated to the Committee by the Board.

 

1.

Financial Reporting

 

  (a)

The Committee shall be responsible for reviewing, assessing the completeness and clarity of the disclosures in, and recommending to the Board for approval:

 

  (i)

the audited annual financial statements of Emera, all related Management’s Discussion and Analysis, and earnings press releases;

 

  (ii)

any documents containing Emera’s audited financial statements; and,

 

  (iii)

the quarterly financial statements, all related Management’s Discussion and Analysis, and earnings press releases.

 

  (b)

The Board may delegate the approval of the quarterly financial statements, all related Management’s Discussion and Analysis, and earnings press releases to the Committee.

 

  (c)

The Committee shall oversee and assess that adequate procedures are in place for the review of public disclosure of financial information.

 

2.

External Auditors

 

  (a)

The Committee shall evaluate and recommend to the Board the external auditor to be nominated for the purpose of preparing or issuing the auditor’s report or performing other audit, review, or attest services for Emera, and the compensation of such external auditors.

 

  (b)

Once appointed, the external auditor shall report directly to the Committee, and the Committee shall oversee the work of the external auditor concerning the preparation or

 

Emera Incorporated – 2023 Annual Information Form    50


  issuance of the auditor’s report or the performance of other audit, review or attest services for Emera.

 

  (c)

The Committee shall be responsible for resolving disagreements between management and the external auditor concerning financial reporting.

 

  (d)

At least annually, the Committee shall obtain and review a report by the external auditors describing: (i) the firm’s internal quality control procedures; (ii) any material issues raised by the most recent internal quality control review, or peer review, of the firm, or by any inquiry or investigation by governmental or professional authorities, within the preceding five years, with respect to one or more external audits carried out by the firm, and any steps taken to deal with any such issues; and (iii) all relationships between the external auditors and Emera (to assess the auditors’ independence).

 

  (e)

The Committee shall annually evaluate the auditors’, including the lead audit partner’s, qualifications, performance, professional skepticism and independence.

 

  (f)

The Committee shall determine that the external audit firm has a process in place to address the rotation of the lead audit partner and other audit partners serving the account as required under prescribed independence rules.

 

  (g)

Every five (5) years, the Committee shall perform a comprehensive review of the performance of the external auditors over multiple years to provide further insight on the audit firm, its independence and application of professional standards.

 

  (h)

The Committee will review differences that were noted or proposed by the external auditors, but that were considered immaterial or insignificant; and any “management” or “internal control” letter issued, or proposed to be issued.

 

3.

Non-Audit Services

 

  (a)

The Committee shall be responsible for reviewing and pre-approving all non-audit services to be provided to Emera, or any of its subsidiaries, by the external auditor.

 

  (b)

The Committee may establish specific policies and procedures concerning the performance of non-audit services by the external auditor so long as the requirements of applicable legislation and regulation are satisfied.

 

  (c)

In accordance with policies and procedures established by the Committee, and applicable legislation and regulation, the Committee may delegate the pre-approval of non-audit services to a member of the Committee or a sub-committee thereof.

 

4.

Oversight and Monitoring of Audits

 

  (a)

The Committee shall meet with the external auditor prior to the audit to discuss the planning and staffing of the audit, including the general approach, scope, areas subject to significant risk of material misstatement, estimated fees and other terms of engagement.

 

Emera Incorporated – 2023 Annual Information Form    51


  (b)

The Committee shall discuss with the external auditor any issues that arise with Management or the internal auditors during the course of the audit and the adequacy of Management’s responses in addressing audit-related deficiencies.

 

  (c)

The Committee shall regularly review with the external auditors any audit problems or difficulties encountered during the course of the audit work, including any restrictions on the scope of the external auditors’ activities or access to requested information, and Management’s response.

 

  (d)

The Committee shall review with Management the results of internal and external audits.

 

  (e)

The Committee shall take such other reasonable steps as it may deem necessary to oversee that the audit was conducted in a manner consistent with applicable legal requirements and auditing standards of applicable professional or regulatory bodies.

 

5.

Oversight and Review of Accounting Principles and Practices

The Committee shall oversee, review and discuss with Management, the external auditor and the internal auditors:

 

  (a)

the quality, appropriateness and acceptability of Emera’s accounting principles and practices used in its financial reporting, changes in Emera’s accounting principles or practices and the application of particular accounting principles and disclosure practices by Management to new transactions or events;

 

  (b)

all significant financial reporting issues and judgments made in connection with the preparation of the financial statements, including the effects of alternative methods within generally accepted accounting principles on the financial statements and any “other opinions” sought by Management from an independent auditor, other than the Company’s external auditors, with respect to the accounting treatment of a particular item, and other material written communications between the external auditors and management;

 

  (c)

disagreements between Management and the external auditor or the internal auditors regarding the application of any accounting principles or practices;

 

  (d)

any material change to Emera’s auditing and accounting principles and practices as recommended by Management, the external auditor or the internal auditors or which may result from proposed changes to applicable generally accepted accounting principles;

 

  (e)

the effect of regulatory and accounting initiatives on Emera’s financial statements and other financial disclosures;

 

  (f)

any reserves, accruals, provisions, estimates or Management programs and policies, including factors that affect asset and liability carrying values and the timing of revenue and expense recognition, that may have a material effect upon the financial statements of Emera;

 

  (g)

the use of special purpose entities and the business purpose and economic effect of off-balance sheet transactions, arrangements, obligations, guarantees and other relationships of Emera and their impact on the reported financial results of Emera;

 

Emera Incorporated – 2023 Annual Information Form    52


  (h)

any legal matter, claim or contingency that could have a significant impact on the financial statements, Emera’s compliance policies and any material reports, inquiries or other correspondence received from regulators or governmental agencies and the manner in which any such legal matter, claim or contingency has been disclosed in Emera’s financial statements;

 

  (i)

the treatment for financial reporting purposes of any significant transactions which are not a normal part of Emera’s operations.

 

6.

Hiring Policies

The Committee shall review and approve Emera’s hiring policy concerning partners or employees, as well as former partners and employees, of the present or former external auditors of Emera.

 

7.

Pension Plans

The Committee shall exercise oversight of the pension plans in accordance with the Pension Oversight Framework adopted by Emera.

 

8.

Oversight of Finance Matters

 

  (a)

The Committee shall review the appointments of key financial executives involved in the financial reporting process of Emera, including the Chief Financial Officer.

 

  (b)

The Committee may request for review, and shall receive when requested, material tax policies and tax planning initiatives, tax payments and reporting and any pending tax audits or assessments. The Committee shall review Emera’s compliance with tax and financial reporting laws and regulations.

 

  (c)

The Committee shall meet at least annually with Management to review and discuss Emera’s major financial risk exposures and the policy steps Management has taken to monitor and control such exposures, including the use of financial derivatives, hedging activities, and credit and trading risks.

 

  (d)

The Committee may review any investments or transactions that the Committee wishes to review, or which the internal or external auditor, or any officer of Emera, may bring to the attention of the Committee within the context of this charter.

 

  (e)

The Committee shall review financial information of material subsidiaries of Emera and any auditor recommendations concerning such subsidiaries.

 

  (f)

The Committee may request for review, and shall receive when requested, all related party transactions required to be disclosed pursuant to generally accepted accounting principles, and discuss with Management the business rationale for the transactions and whether appropriate disclosures have been made.

 

Emera Incorporated – 2023 Annual Information Form    53


9.

Internal Controls

The Committee shall oversee:

 

  (a)

the adequacy and effectiveness of the Company’s internal accounting and financial controls and the recommendations of Management, the external auditor and the internal auditors for the improvement of accounting practices and internal controls; and

 

  (b)

management’s compliance with the Company’s processes, procedures and internal controls.

In exercising such oversight, the Committee shall review and discuss each of the foregoing with Management, the external auditor and the internal auditor.

The Committee will carry out the following specific duties:

 

  (c)

Review and discuss with the Chief Executive Officer and the Chief Financial Officer the procedures undertaken in connection with the Chief Executive Officer and Chief Financial Officer certifications for the annual and interim filings with applicable securities regulatory authorities.

 

  (d)

Review disclosures made by Emera’s Chief Executive Officer and Chief Financial Officer during their certification process for the annual and interim filing with applicable securities regulatory authorities about any significant deficiencies in the design or operation of internal controls which could adversely affect Emera’s ability to record, process, summarize and report financial data or any material weaknesses in the internal controls, and any fraud involving management or other employees who have a significant role in the Emera’s internal controls.

 

  (e)

Discuss with Emera’s Chief Legal Officer at least annually any legal matters that may have a material impact on the financial statements, operations, assets or compliance policies and any material reports or inquiries received by Emera or any of its subsidiaries from regulators or governmental agencies.

 

10.

Internal Auditor

 

  (a)

The lead internal auditor shall report directly to the Committee. The Committee shall approve the appointment, removal and replacement of the lead internal auditor. The Committee shall approve the remuneration of the lead internal auditor on appointment.

 

  (b)

The Committee shall review and approve the internal audit plan, including activities, organizational structure, staffing, qualifications and budget, and shall review all major changes to the plan. The Committee shall review and discuss with the internal auditor the scope, progress, and results of executing the internal audit plan. The Committee shall receive reports on the status of significant findings, recommendations, and management’s responses.

 

  (c)

The Committee shall meet periodically with the internal auditor to discuss the progress of their activities, any significant findings stemming from internal audits, any issues that arise with Management, and the adequacy of Management’s responses in addressing audit-related deficiencies.

 

Emera Incorporated – 2023 Annual Information Form    54


  (d)

The Committee shall obtain from the internal auditor and review summaries of the significant reports to Management prepared by the internal auditor, and the actual reports if requested by the Committee, and Management’s responses to such reports.

 

  (e)

The Committee shall annually receive and review a report on the Chief Executive Officers’ expense accounts.

 

  (f)

The Committee may communicate with the internal auditor with respect to their reports and recommendations, the extent to which prior recommendations have been implemented and any other matters that the internal auditor brings to the attention of the Committee.

 

  (g)

The Committee shall, at least biennially or more frequently as it deems necessary, approve the internal audit charter. The internal auditor shall confirm to the Committee annually that the function adheres to applicable professional standards. The Committee may provide feedback on the performance of the lead internal auditor as deemed necessary.

 

  (h)

The Committee shall, biennially or more frequently as it deems necessary, review the independence of the internal audit function and shall make recommendations to the Board on appropriate actions to be taken which the Committee deems necessary to protect and enhance the independence of the internal audit function.

 

  (i)

The Committee shall review the results of an external assessment, performed every five years by a qualified independent assessor or assessment team, of the internal audit function in conformance with International Standards for the Professional Practice of Internal Auditing (IPPF Standards).

 

11.

Complaints

The Committee shall oversee procedures relating to the receipt, retention, and treatment of complaints received concerning accounting, internal accounting controls, or auditing matters. The Committee shall also review procedures concerning the confidential, anonymous submission of concerns by Emera’s employees relating to questionable accounting or auditing matters. Without limiting the foregoing, the Committee shall receive periodic ethics updates under Emera’s Code of Conduct which relate to matters within the scope of responsibility of the Committee as defined in this Charter, and the Committee shall review the related activities within that scope under Emera’s Ethics Program, such as financial reporting, accounting and auditing, business integrity, and corporate assets and infrastructure.

 

12.

Other Responsibilities

The Committee shall:

 

  (a)

Periodically review Management’s process for identifying non-compliance with legal and regulatory requirements;

 

  (b)

Annually receive and review a report on executive officers’ compliance with the Company’s Code of Conduct;

 

  (c)

Annually provide feedback on the performance of the Chief Financial Officer;

 

Emera Incorporated – 2023 Annual Information Form    55


  (d)

Review actions taken by the Company to identify and manage risks related to the Audit Committee mandate, including Primary Enterprise Risks, which may have the potential to adversely impact the Company’s operations, strategy or reputation; and

 

  (e)

Perform such other duties and exercise such powers as may be directed or delegated to the Committee by the Board.

 

13.

Limitation on Authority

Nothing articulated herein is intended to assign to the Committee the Board’s responsibility to oversee Emera’s compliance with applicable laws or regulations or to expand applicable standards of liability under statutory or regulatory requirements for the Directors or the members of the Committee.

PART II

COMPOSITION

 

14.

Composition

 

  (a)

Emera’s Articles of Association require that the Committee shall be comprised of no less than three directors none of whom may be officers or employees of Emera nor may they be an officer or employee of any affiliate of Emera. In addition, all members of the Committee shall be independent as required by applicable legislation.

 

  (b)

The Board shall appoint members to the Committee who are financially literate, as required by applicable legislation, which at a minimum requires that Committee members have the ability to read and understand a set of financial statements that present a breadth and level of complexity of accounting issues that are generally comparable to the breadth and complexity of issues that can reasonably be expected to be raised by Emera’s financial statements.

 

  (c)

Committee members shall be appointed at the Board meeting following the election of Directors at Emera’s annual shareholders’ meeting and membership may be based upon the recommendation of the Nominating and Corporate Governance Committee.

 

  (d)

Pursuant to Emera’s Articles of Association, the Board may appoint, remove, or replace any member of the Committee at any time, and a member of the Committee shall cease to be a member of the Committee upon ceasing to be a Director. Subject to the foregoing, each member of the Committee shall hold office as such until the next annual meeting of shareholders after the member’s appointment to the Committee.

 

  (e)

The Secretary of the Committee shall advise Emera’s internal and external auditors of the names of the members of the Committee promptly following their election.

 

Emera Incorporated – 2023 Annual Information Form    56


PART III

COMMITTEE PROCEDURE

 

15.

Meetings

 

  (a)

Meetings of the Committee may be called by the Chair or at the request of any member. The Committee shall meet at least quarterly.

 

  (b)

The timing and location of meetings of the Committee, and the calling of and procedure at any such meeting, shall be determined from time to time by the Committee.

 

  (c)

Emera’s internal and external auditors shall be notified of all meetings of the Committee and shall have the right to appear before and be heard by the Committee.

 

  (d)

Emera’s internal or external auditors may request the Chair of the Committee to consider any matters which the internal or external auditors believe should be brought to the attention of the Committee or the Board.

 

16.

Separate Sessions

 

  (a)

The Committee Chair shall meet periodically with the Chief Financial Officer, the lead internal auditor and the external auditor in separate executive sessions to discuss any matters that the Committee or each of these groups believes should be discussed privately.

 

  (b)

The Chief Financial Officer, the lead internal auditor and the external auditor shall have access to the Committee to bring forward matters requiring its attention.

 

  (c)

The Committee shall meet periodically without Management present.

 

17.

Quorum

A majority of the members of the Committee present in person, by teleconferencing, or by videoconferencing, or by a combination thereof, will constitute a quorum.

 

18.

Chair

Pursuant to Emera’s Articles of Association, the Committee shall choose one of its members to act as Chair of the Committee, which person shall not be the Chair of Nova Scotia Power Inc.’s Audit Committee. In selecting a Committee Chair, the Committee may consider any recommendation made by the Nominating and Corporate Governance Committee.

 

19.

Secretary and Minutes

Pursuant to Emera’s Articles of Association, the Corporate Secretary of Emera shall act as the Secretary of the Committee. Emera’s Articles of Association require that the Minutes of the Committee be in writing and duly entered into Emera’s records, and the Minutes shall be circulated to all members of the Committee. The Secretary shall maintain all Committee records.

 

Emera Incorporated – 2023 Annual Information Form    57


20.

Board Relationships and Reporting

The Committee shall:

 

  (a)

Review annually the Committee’s Charter;

 

  (b)

Oversee the appropriate disclosure of the Committee’s Charter as well as other information concerning the Committee which is required to be disclosed by applicable legislation in Emera’s Annual Information Form and any other applicable disclosure documents;

 

  (c)

Report to the Board at the next following board meeting on any meeting held by the Committee, and as required, regularly report to the Board on Committee activities, issues, and related recommendations; and

 

  (d)

Maintain free and open communication between the Committee, the external auditors, internal auditors, and Management, and determine that all parties are aware of their responsibilities.

 

21.

Powers

The Committee shall:

 

  (a)

examine and consider such other matters, and meet with such persons, in connection with the internal or external audit of Emera’s accounts, which the Committee in its discretion determines to be advisable;

 

  (b)

have the authority to communicate directly with the internal and external auditors; and

 

  (c)

have the right to inspect all records of Emera or its affiliates and may elect to discuss such records, or any matters relating to the financial affairs of Emera with the officers or auditors of Emera and its affiliates.

 

22.

Experts and Advisors

The Committee may, in consultation with the Chairman of the Board, engage and compensate any outside adviser that it determines necessary in order to carry out its duties.

 

Emera Incorporated – 2023 Annual Information Form    58
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
exhibit992p1i0
Exhibit 99.2
1
Management’s Discussion & Analysis
As at February 26, 2024
Management’s Discussion & Analysis (“MD&A”) provides a review of the results of operations of Emera
Incorporated and its consolidated subsidiaries and investments (collectively referred to as “Emera” or the
“Company”) during the fourth quarter of, and for the full year of, 2023 relative to the same periods in 2022
and selected financial information for 2021; and its financial position as at December 31, 2023 relative to
December 31, 2022. The Company’s activities are carried out through five reportable segments: Florida
Electric Utility, Canadian Electric Utilities, Gas Utilities and Infrastructure, Other Electric Utilities, and
Other.
 
This MD&A should be read in conjunction with the Emera annual audited consolidated financial
statements and supporting notes as at and for the year ended December 31, 2023.
 
Emera follows United
States Generally Accepted Accounting Principles (“USGAAP” or “GAAP”). Additional information related
to Emera, including the Company’s Annual Information Form can be found on Sedar+ at
www.sedarplus.ca.
The accounting policies used by Emera’s rate-regulated entities may differ from those used by Emera’s
non-rate-regulated businesses with respect to the timing of recognition of certain assets, liabilities,
revenues and expenses. At December 31, 2023, Emera’s rate-regulated subsidiaries and investments
include:
 
Emera Rate-Regulated Subsidiary or Equity
Investment
Accounting Policies Approved/Examined By
Subsidiary
Tampa Electric Company (“TEC”)
(1)
Florida Public Service Commission (“FPSC”) and the
Federal Energy Regulatory Commission (“FERC”)
Nova Scotia Power Inc. ("NSPI")
Nova Scotia Utility and Review Board (“UARB”)
 
Peoples Gas System, Inc. (“PGS”)
(1)
FPSC
New Mexico Gas Company, Inc. (“NMGC”)
New Mexico Public Regulation Commission (“NMPRC”)
SeaCoast Gas Transmission, LLC ("SeaCoast")
FPSC
Emera Brunswick Pipeline Company Limited (“Brunswick
Pipeline”)
 
Canadian Energy Regulator ("CER")
Barbados Light & Power Company Limited (“BLPC”)
 
Fair Trading Commission, Barbados ("FTC")
Grand Bahama Power Company Limited (“GBPC”)
 
The Grand Bahama Port Authority (“GBPA”)
Equity Investments
NSP Maritime Link Inc. (“NSPML”)
UARB
Labrador Island Link Limited Partnership (“LIL”)
Newfoundland and Labrador Board of Commissioners of
Public Utilities
Maritimes & Northeast Pipeline Limited Partnership and
Maritimes & Northeast Pipeline, LLC (“M&NP”)
CER and FERC
St. Lucia Electricity Services Limited (“Lucelec”)
National Utility Regulatory Commission
(1) Effective January 1, 2023, Peoples Gas System ceased to be a division of TEC and the gas utility was
 
reorganized, resulting in a
separate legal entity called Peoples Gas System, Inc., a wholly owned direct subsidiary of TECO Gas Operations, Inc.
All amounts are in Canadian dollars (“CAD”), except for the Florida Electric Utility, Gas Utilities and
Infrastructure, and Other Electric Utilities sections of the MD&A, which are reported in United States
dollars (“USD”) unless otherwise stated.
Exhibit 99.2
2
TABLE
 
OF CONTENTS
Forward-looking Information……………………......
2
Introduction and Strategic Overview………….……
3
Non-GAAP Financial Measures and Ratios….…...
5
Consolidated Financial Review……….………….…
7
 
Significant Items Affecting Earnings………........
7
 
Consolidated Financial Highlights………………
 
7
 
Consolidated Income Statement Highlights……
9
Business Overview and Outlook…………….……..
11
 
Florida Electric Utility ………………...............…
12
 
Canadian Electric Utilities …..………….……….
13
 
Gas Utilities and Infrastructure..…….…….…….
17
 
Other Electric Utilities ……………………………
18
 
Other……………………………………………….
19
Consolidated Balance Sheet Highlights…………..
20
Other Developments…………………………………
21
Financial Highlights……………………………..…..
21
 
Florida Electric Utility …………..........................
21
 
Canadian Electric Utilities ……..…………..……
22
 
Gas Utilities and Infrastructure……………...…..
25
 
Other Electric Utilities …………………………....
27
 
Other…………………………………………….….
28
Liquidity and Capital Resources………..…………..
31
 
Consolidated Cash Flow Highlights…..…………
32
 
Working Capital……………………………………
33
 
Contractual Obligations…………………………..
33
 
Forecasted Consolidated Capital Investments…
34
 
Debt Management………………………………..
34
 
Credit Ratings……………………………………..
36
 
Guaranteed Debt………………………………….
37
 
Outstanding Stock Data………………………….
38
Pension Funding……………………………………..
38
Off-Balance Sheet Arrangements………………….
39
Dividend Payout Ratio……………………………….
40
Transactions with Related Parties….……………...
40
Enterprise Risk and Risk Management……………
41
Risk Management including Financial
 
Instruments…………………………………………
54
Disclosure and Internal Controls……….…………..
55
Critical Accounting Estimates….……………………
56
Changes in Accounting Policies and Practices…...
61
 
Future Accounting Pronouncements……………
61
Summary of Quarterly Results……........................
62
FORWARD
 
-LOOKING INFORMATION
This MD&A contains “forward-looking information” (“FLI”) and statements which reflect the current view
with respect to the Company’s expectations regarding future growth, results of operations, performance,
carbon dioxide emissions reduction goals, business prospects and opportunities,
 
and may not be
appropriate for other purposes within the meaning of applicable Canadian securities laws. All such
information and statements are made pursuant to safe harbour provisions contained in applicable
securities legislation. The words “anticipates”, “believes”, “budget”, “could”, “estimates”, “expects”,
“forecast”, “intends”, “may”, “might”, “plans”, “projects”, “schedule”, “should”, “targets”, “will”, “would” and
similar expressions are often intended to identify FLI, although not all FLI contains these identifying
words. The FLI reflects management’s current beliefs and is based on information currently available to
Emera’s management and should not be read as guarantees of future events, performance or results,
and will not necessarily be accurate indications of whether, or the time at which, such events,
performance or results will be achieved.
 
 
Exhibit 99.2
3
The FLI is based on reasonable assumptions and is subject to risks, uncertainties and other factors that
could cause actual results to differ materially from historical results or results anticipated by the FLI.
Factors that could cause results or events to differ from current expectations include, without limitation:
regulatory and political risk; operating and maintenance risks; changes in economic conditions;
commodity price and availability risk; liquidity and capital market risk; changes in credit ratings; future
dividend growth; timing and costs associated with certain capital investments; expected impacts on
Emera of challenges in the global economy; estimated energy consumption rates; maintenance of
adequate insurance coverage; changes in customer energy usage patterns; developments in technology
that could reduce demand for electricity; global climate change; weather risk, including higher frequency
and severity of weather events; risk of wildfires; unanticipated maintenance and other expenditures;
system operating and maintenance risk; derivative financial instruments and hedging; interest rate risk;
inflation risk; counterparty risk; disruption of fuel supply; country risks; supply chain risk; environmental
risks; foreign exchange (“FX”); regulatory and government decisions, including changes to environmental
legislation, financial reporting and tax legislation; risks associated with pension plan performance and
funding requirements; loss of service area; risk of failure of information technology (“IT”) infrastructure and
cybersecurity risks; uncertainties associated with infectious diseases, pandemics and similar public health
threats; market energy sales prices; labour relations; and availability of labour and management
resources.
 
Readers are cautioned not to place undue reliance on FLI, as actual results could differ materially from
the plans, expectations, estimates or intentions and statements expressed in the FLI. All FLI in this MD&A
is qualified in its entirety by the above cautionary statements and, except as required by law, Emera
undertakes no obligation to revise or update any FLI as a result of new information, future events or
otherwise.
INTRODUCTION AND STRATEGIC
 
OVERVIEW
Based in Halifax, Nova Scotia, Emera owns and operates cost-of-service rate-regulated electric and gas
utilities in Canada, the United States (“US”) and the Caribbean. Cost-of-service utilities provide essential
electric and gas services in designated territories under franchises and are overseen by regulatory
authorities. Emera’s strategic focus continues to be safely delivering cleaner, affordable and reliable
energy to its customers.
The majority of Emera’s investments in rate-regulated businesses are located in Florida with other
investments in Nova Scotia, New Mexico and the Caribbean.
 
Emera’s portfolio of regulated utilities
provides reliable earnings, cash flow and dividends. Earnings opportunities in regulated utilities are
generally driven by the magnitude of net investment in the utility (known as “rate base”), and the amount
of equity in the capital structure and the return on that equity (“ROE”) as approved through regulation.
Earnings are also affected by sales volumes and operating expenses.
Emera’s capital investment plan is approximately $9 billion over the 2024 through 2026 period with
approximately $2 billion of additional potential capital investments over the same period. The capital
investment plan and additional potential capital result in an anticipated compound annual rate base
growth in the range of approximately 7 per cent to 8 per cent through 2026. The capital investment plan
includes significant investments across the portfolio in renewable and cleaner generation, reliability and
system integrity investments, infrastructure modernization,
 
infrastructure expansion to meet the needs of
new and existing customers, and technologies to better support the business and customer experiences.
It is anticipated that approximately 75 per cent of Emera’s $9 billion capital investment plan over the 2024
through 2026 period will be made in Florida.
 
Emera’s capital investment plan is being funded primarily through internally generated cash flows, debt
raised at the operating company level consistent with regulated capital structures, equity, and select asset
sales. Generally, equity requirements in support of the Company’s capital investment plan are expected
to be funded through the issuance of preferred equity and the issuance of common equity through
Emera’s dividend reinvestment plan (“DRIP”) and at-the-market program (“ATM program”). Maintaining
investment-grade credit ratings is a priority of the Company.
Exhibit 99.2
4
Emera has provided annual dividend growth guidance of four to five per cent through 2026. The
Company targets a long-term dividend payout ratio of adjusted net income of 70 to 75 per cent and, while
the payout ratio is likely to exceed that target through and beyond the forecast period, it is expected to
return to that range over time. For further information on the non-GAAP measure “Dividend Payout Ratio
of Adjusted Net Income”, refer to the “Non-GAAP Financial Measures and Ratios”
 
section.
Seasonal patterns and other weather events affect demand and operating costs. Similarly, mark-to-
market (“MTM”) adjustments and foreign currency exchange can have a material impact on financial
results for a specific period. Emera’s consolidated net income and cash flows are impacted by
movements in the USD relative to the CAD. Emera may hedge both transactional and translational
exposure. These impacts, as well as the timing of capital investments and other factors, mean results in
any one quarter are not necessarily indicative of results in any other quarter, or for the year as a whole.
Energy markets worldwide are experiencing significant change and Emera is well-positioned to continue
to respond to shifting customer demands and meet the challenges of digitization, decarbonization and
decentralized generation, within complex regulatory environments.
Customers depend on energy and are looking for more choice, better control, and greater reliability. The
costs of decentralized generation and storage have become more competitive and advancing
technologies are transforming how utilities operate and interact with customers. Concurrently, climate
change and the increased frequency of extreme weather events are shaping government energy policy.
This is also creating a need to replace aging infrastructure and make investments to protect and harden
energy systems to deliver energy reliability and system resiliency. These factors combined with inflation,
higher interest rates and higher cost of capital place increased pressure on energy costs, and thus
customer rates, at a time when affordability is a challenge.
Emera’s strategy is centered on delivering value for customers, and in doing so creating value for
shareholders. This includes:
 
investing in cleaner and renewable sources of energy, in the related transmission assets, and in
energy storage needed to support intermittent renewables;
 
supporting increasing demand from customers and the ongoing electrification of other sectors;
 
improving system reliability and resiliency, including replacing aging infrastructure and expanding
systems to service new customers; and
 
investing in new internal and customer-facing technologies for improved cost efficiency and better
customer experiences.
 
Building on its decarbonization progress, Emera is continuing its efforts by establishing clear carbon
reduction goals and a vision to achieve net-zero carbon dioxide emissions by 2050.
This vision is inspired by Emera’s strong track record, the Company’s experienced team, and a visible
path to Emera’s interim carbon goals. With existing technologies and resources,
 
and subject to supportive
government and regulatory decisions, Emera is working to achieve the following goals compared to
corresponding 2005 levels:
 
 
A 55 per cent reduction in carbon dioxide emissions by 2025.
 
The retirement of Emera’s last existing coal unit no later than 2040.
 
An 80 per cent reduction in carbon dioxide emissions by 2040.
 
Achieving the above climate goals on these timelines is subject to the Company's regulatory obligations
and other external factors beyond Emera's control.
Emera seeks to deliver on its Climate Commitment while maintaining its focus on investing in reliability
and staying focused on the cost impacts for customers. Emera is also committed to identifying emerging
technologies and continuing to work constructively with policymakers, regulators, partners, investors and
customers to achieve these goals and realize its net-zero vision.
Emera is committed to world-class safety, operational excellence, good governance, excellent customer
service, reliability, being an employer of choice, and building constructive relationships.
Exhibit 99.2
5
NON-GAAP FINANCIAL MEASURES AND RATIOS
Emera uses financial measures and ratios that do not have standardized meaning under USGAAP and
may not be comparable to similar measures presented by other entities. The non-GAAP measures and
ratios are calculated by adjusting certain GAAP measures for specific items. Management believes
excluding these items better distinguishes ongoing operations of the business and allows investors to
better understand and evaluate the business. These measures and ratios are discussed and reconciled
below.
Adjusted Net Income Attributable to Common Shareholders, Adjusted Earnings (Loss) Per
Common Share (“EPS”) – Basic and Dividend Payout Ratio of Adjusted Net Income
Emera calculates an adjusted net income attributable to common shareholders (“adjusted net income”)
measure by excluding the effect of MTM adjustments, the GBPC impairment charge in 2022, and the
impact of the 2022 NSPML unrecoverable costs.
Management believes excluding from net income the effect of MTM valuations and changes thereto, until
settlement, better aligns the intent and financial effect of these contracts with the underlying cash flows,
and therefore excludes MTM adjustments for evaluation of performance and incentive compensation. The
MTM adjustments are related to the following:
 
held-for-trading (“HFT”) commodity derivative instruments, including adjustments related to the
price differential between the point where natural gas is sourced and where it is delivered, and
the related amortization of transportation capacity recognized as a result of certain Emera Energy
marketing and trading transactions;
 
the business activities of Bear Swamp Power Company LLC (“Bear Swamp”) included in Emera’s
equity income;
 
equity securities held in BLPC and Emera Energy; and
 
FX hedges entered into to hedge USD denominated operating unit earnings exposure.
For further detail on these MTM adjustments, refer to the “Consolidated Financial Review”, “Financial
Highlights – Other Electric Utilities”, and “Financial Highlights – Other” sections.
In Q4 2022, the Company recognized a $73 million non-cash goodwill impairment charge related to
GBPC due to a decline in the fair value (“FV”) of the reporting unit driven by the effects of macro-
economic factors on the discount rate calculation. Management believes excluding from net income the
effect of this charge better distinguishes ongoing operations of the business and allows investors to better
understand and evaluate the Company. For further details on the GBPC impairment charge, refer to
“Significant Items Impacting Earnings”, and “Financial Highlights – Other Electric Utilities” sections.
In February 2022, the UARB issued a decision to disallow recovery of $9 million in costs ($7 million after-
tax) included in NSPML’s final capital cost application. The after-tax unrecoverable costs were recognized
in “Income from equity investments” in Emera’s Consolidated Statements of Income. Management
believes excluding these unrecoverable costs from the calculation of adjusted net income better reflects
the underlying operations in the period. For further details on the 2022 NSPML unrecoverable costs, refer
to the “Financial Highlights – Canadian Electric Utilities” section.
Adjusted EPS – basic and dividend payout ratio of adjusted net income are non-GAAP ratios which are
calculated using adjusted net income, as described above. For further details on dividend payout ratio of
adjusted net income, see the “Dividend Payout Ratio” section.
Emera calculates adjusted net income for the Canadian Electric Utilities, Other Electric Utilities, and Other
segments. Reconciliation to the nearest GAAP measure is included in each segment. Refer to “Financial
Highlights – Canadian Electric Utilities”, “Financial Highlights – Other Electric Utilities” and “Financial
Highlights – Other” sections.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Exhibit 99.2
6
The following reconciles net income attributable to common shareholders to adjusted net income:
Three months ended
Year ended
For the
December 31
December 31
millions of dollars (except per share amounts)
2023
2022
2023
2022
2021
Net income attributable to common shareholders
$
 
289
$
 
483
$
 
978
$
 
945
$
 
510
MTM gain (loss), after-tax
(1)
 
114
 
307
 
169
 
175
 
(213)
GBPC impairment charge
 
 
-
 
 
(73)
 
-
 
 
(73)
 
-
 
NSPML unrecoverable costs
(2)
 
-
 
 
-
 
 
-
 
 
(7)
 
-
 
Adjusted net income
$
 
175
$
 
249
$
 
809
$
 
850
$
 
723
EPS – basic
$
 
1.04
$
 
1.80
$
 
3.57
$
 
3.56
$
 
1.98
Adjusted EPS – basic
$
 
0.63
$
 
0.93
$
 
2.96
$
 
3.20
$
 
2.81
(1) Net of income tax expense of $44 million for the three months ended December 31, 2023 (2022 – $124 million expense)
 
and $68
million expense for the year ended December 31, 2023 (2022 – $73 million expense) (2021 – $86 million recovery).
(2) Emera accounts for NSPML as an equity investment and therefore the after-tax unrecoverable costs were recorded
 
in “Income
from equity investments” on Emera’s Consolidated Statements of Income.
EBITDA and Adjusted EBITDA
Earnings before interest, income taxes, depreciation and amortization (“EBITDA”) and adjusted EBITDA
are non-GAAP financial measures used by Emera. These financial measures are used by numerous
investors and lenders to better understand cash flows and credit quality. EBITDA is useful to assess
Emera’s operating performance and indicates the Company’s ability to service or incur debt, invest in
capital, and finance working capital requirements.
Similar to adjusted net income calculations described above, adjusted EBITDA represents EBITDA
absent the income effect of MTM adjustments, the 2022 GBPC impairment charge and the 2022 NSPML
unrecoverable costs.
The following is a reconciliation of net income to EBITDA and Adjusted EBITDA:
Three months ended
Year ended
For the
December 31
December 31
millions of dollars
2023
2022
2023
2022
2021
Net income
(1)
$
 
307
$
 
499
$
 
1,045
$
 
1,009
$
 
561
Interest expense, net
 
241
 
206
 
925
 
709
 
611
Income tax expense (recovery)
 
51
 
154
 
128
 
185
 
(6)
Depreciation and amortization
 
264
 
254
 
1,049
 
952
 
902
EBITDA
$
 
863
$
 
1,113
$
 
3,147
$
 
2,855
$
 
2,068
MTM gain (loss), before-tax
 
158
 
431
 
237
 
248
 
(299)
GBPC impairment charge
 
-
 
 
(73)
 
-
 
 
(73)
 
-
 
NSPML unrecoverable costs
(2)
 
-
 
 
-
 
 
-
 
 
(7)
 
-
 
Adjusted EBITDA
$
 
705
$
 
755
$
 
2,910
$
 
2,687
$
 
2,367
(1) Net income is before Non-controlling interest in subsidiaries and Preferred stock dividends.
(2) Emera accounts for NSPML as an equity investment and therefore the after-tax unrecoverable costs were recorded
 
in “Income
from equity investments” on Emera’s Consolidated Statements of Income.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Exhibit 99.2
7
CONSOLIDATED
 
FINANCIAL REVIEW
Significant Items Affecting Earnings
2023
Earnings Impact of MTM Gain, After-Tax
MTM gain, after-tax decreased $193 million to $114 million in Q4 2023, compared to $307 million in Q4
2022 primarily due to unfavourable changes in existing positions, partially offset by higher amortization of
gas transportation assets in 2022 at Emera Energy Services (“EES”). For the year ended December 31,
2023, MTM gain, after-tax decreased $6 million to $169 million compared to $175 million for the same
period in 2022 primarily due to higher amortization of gas transportation assets at EES, partially offset by
favourable changes in existing positions at EES and gains on Corporate FX hedges.
 
2022
GBPC Impairment Charge
In Q4 2022, Emera recognized a goodwill impairment charge of $73 million ($0.27 per common share) for
GBPC due to a decline in the FV of the reporting unit driven by the effects of macro-economic factors on
discount rate calculations. This non-cash charge was recorded in “GBPC Impairment charge” on the
Consolidated Statements of Income and reduced the GBPC goodwill balance to nil. For further details,
refer to note 22 in the consolidated financial statements.
TECO Guatemala Holdings (“TGH”) International Arbitration and Award
In Q4 2022, a payment of $63 million ($45 million after tax and legal costs, or $0.17 per common share),
was made by the Republic of Guatemala to TECO Energy in satisfaction of the second and final award
issued by the International Centre of the Settlement of Investment Disputes tribunal regarding a dispute
over an investment of TGH, a wholly owned subsidiary of TECO Energy. The payment was recognized in
‘Other income, net” on the Consolidated Statements of Income. For further details, refer to note 8 in the
consolidated financial statements.
Consolidated Financial Highlights
For the
Three months ended
Year ended
millions of dollars
 
December 31
December 31
Adjusted net income
2023
2022
2023
2022
2021
Florida Electric Utility
$
 
115
$
 
124
$
 
627
$
 
596
$
 
462
Canadian Electric Utilities
 
68
 
46
 
247
 
222
 
241
Gas Utilities and Infrastructure
 
59
 
72
 
214
 
221
 
198
Other Electric Utilities
 
4
 
8
 
35
 
29
 
20
Other
 
(71)
 
(1)
 
(314)
 
(218)
 
(198)
Adjusted net income
$
 
175
$
 
249
$
 
809
$
 
850
$
 
723
MTM gain (loss), after-tax
 
114
 
307
 
169
 
175
 
(213)
GBPC impairment charge
 
-
 
 
(73)
 
-
 
 
(73)
 
-
 
NSPML unrecoverable costs
 
-
 
 
-
 
 
-
 
 
(7)
 
-
 
Net income attributable to common shareholders
$
 
289
$
 
483
$
 
978
$
 
945
$
 
510
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Exhibit 99.2
8
The following table highlights the significant changes in adjusted net income from 2022 to 2023:
For the
Three months ended
Year ended
millions of dollars
December 31
December 31
Adjusted net income – 2022
$
 
249
$
 
850
Operating Unit Performance
Increased earnings at NSPI due to new base rates and increased sales
volumes, partially offset by higher operating, maintenance and general
expenses ("OM&G"), interest expense and depreciation
 
17
 
10
Increased income from equity investments at NSPML quarter-over-
quarter primarily due to the Maritime Link holdback (the "holdback")
recognized in Q4 2022. Year-over-year also due to the partial reversal in
Q3 2023 of the holdback recognized in 2022
 
4
 
10
Decreased earnings quarter-over-quarter at TEC due to increased
interest expense, depreciation, state and municipal taxes, unfavourable
weather, and higher OM&G, partially offset by new base rates and
customer growth driving higher sales volumes. Increased earnings year-
over-year due to new base rates, the impact of a weaker CAD and
customer growth, partially offset by higher interest expense,
depreciation, state and municipal taxes, and OM&G, and unfavourable
weather
 
(9)
 
31
Decreased earnings quarter-over-quarter at NMGC primarily due to
lower asset optimization revenues and higher OM&G, partially offset by
new base rates. Increased earnings year-over-year due to new base
rates, partially offset by higher OM&G and interest expense
 
(11)
 
12
Decreased earnings at EES due to more favourable market conditions in
2022
 
(21)
 
(22)
Corporate
Decreased OM&G, pre-tax, due to timing of long-term compensation
and related hedges
 
13
 
10
Increased interest expense, pre-tax, due to higher interest rates and
higher debt levels
 
(9)
 
(51)
Decreased income tax recovery quarter-over-quarter primarily due to the
impact of effective state tax rates
 
(10)
 
2
TGH award, after tax and legal costs, in Q4 2022. Refer to the
"Significant Items Affecting Earnings" section
 
(45)
 
(45)
Other Variances
 
(3)
 
2
Adjusted net income – 2023
$
 
175
$
 
809
For further details of reportable segments contributions, refer to the "Financial Highlights" section.
For the
Year ended December 31
millions of dollars
2023
2022
2021
Operating cash flow before changes in working capital
$
 
2,336
$
 
1,147
$
 
1,337
Change in working capital
 
(95)
 
(234)
 
(152)
Operating cash flow
$
 
2,241
$
 
913
$
 
1,185
Investing cash flow
$
 
(2,917)
$
 
(2,569)
$
 
(2,332)
Financing cash flow
$
 
939
$
 
1,555
$
 
1,311
For further discussion of cash flow, refer to the "Consolidated Cash Flow Highlights" section.
As at
 
December 31
millions of dollars
2023
2022
2021
Total assets
$
 
39,480
$
 
39,742
$
 
34,244
Total long-term
 
debt (including current portion)
$
 
18,365
$
 
16,318
$
 
14,658
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Exhibit 99.2
9
Consolidated Income Statement Highlights
For the
 
Three months ended
Year ended
Year ended
millions of dollars
December 31
December 31
December 31
(except per share amounts)
2023
2022
Variance
2023
2022
Variance
2021
Operating revenues
$
 
1,972
$
 
2,358
$
 
(386)
$
 
7,563
$
 
7,588
$
 
(25)
$
 
5,765
Operating expenses
 
1,467
 
1,638
 
171
 
5,769
 
5,959
 
190
 
4,835
Income from operations
$
 
505
$
 
720
$
 
(215)
$
 
1,794
$
 
1,629
$
 
165
$
 
930
Other income, net
$
 
51
$
 
102
$
 
(51)
$
 
158
$
 
145
$
 
13
$
 
93
Interest expense, net
$
 
241
$
 
206
$
 
(35)
$
 
925
$
 
709
$
 
(216)
$
 
611
Net income attributable to
common shareholders
$
 
289
$
 
483
$
 
(194)
$
 
978
$
 
945
$
 
33
$
 
510
Adjusted net income
$
 
175
$
 
249
$
 
(74)
$
 
809
$
 
850
$
 
(41)
$
 
723
Weighted average shares of
common stock outstanding
 
(in millions)
(1)
 
277.7
 
269.0
 
8.7
 
273.6
 
265.5
 
8.1
 
257.2
EPS – basic
$
 
1.04
$
 
1.80
$
(0.76)
$
 
3.57
$
 
3.56
$
0.01
$
 
1.98
EPS – diluted
$
 
1.04
$
 
1.80
$
(0.76)
$
 
3.57
$
 
3.55
$
0.02
$
 
1.98
Adjusted EPS – basic
$
 
0.63
$
 
0.93
$
(0.30)
$
 
2.96
$
 
3.20
$
(0.24)
$
 
2.81
Adjusted EBITDA
$
 
705
$
 
755
$
 
(50)
$
 
2,910
$
 
2,687
$
 
223
$
 
2,367
Dividends per common share
declared
$
 
0.7175
$
 
0.6900
$
 
0.0275
$
 
2.7875
$
 
2.6775
$
 
0.1100
$
 
2.5750
Dividends per first preferred shares declared:
 
Series A
$
 
0.5456
$
 
0.5456
$
 
-
 
$
 
0.5456
 
Series B
$
 
1.5583
$
 
0.6869
$
 
0.8714
$
 
0.4873
 
Series C
$
 
1.2873
$
 
1.1802
$
 
0.1071
$
 
1.1802
 
Series E
$
 
1.1250
$
 
1.1250
$
 
-
 
$
 
1.1250
 
Series F
$
 
1.0505
$
 
1.0505
$
-
$
 
1.0505
 
Series H
$
 
1.3140
$
 
1.2250
$
 
0.0890
$
 
1.2250
 
Series J
$
 
1.0625
$
 
1.0625
$
 
-
 
$
 
0.6470
 
Series L
$
 
1.1500
$
 
1.1500
$
 
-
 
$
 
0.1638
(1) Effective February 10, 2022, deferred share units are no longer able to be settled in shares and are
 
therefore excluded from
weighted average shares of common stock outstanding.
Operating Revenues
For Q4 2023, operating revenues decreased $386 million compared to Q4 2022 and, excluding
decreased MTM gains of $286 million, decreased $100 million. The decrease was due to lower fuel
revenues at NMGC, TEC, and NSPI; decreased marketing and trading margin at EES; lower asset
optimization revenue at NMGC; and unfavourable weather at TEC. These decreases were partially offset
by new base rates at TEC, NSPI and NMGC; storm cost recovery surcharge revenue at TEC; customer
growth at TEC and NSPI; and favourable weather at NSPI.
For the year ended December 31, 2023, operating revenues decreased $25 million compared to 2022
and, excluding decreased MTM gains of $62 million, increased $37 million. The increase was due to new
base rates at TEC, NSPI and NMGC; the impact of a weaker CAD; storm cost recovery surcharge
revenue at TEC; and customer growth at TEC and NSPI. These increases were partially offset by lower
fuel revenues at NMGC, TEC, NSPI, PGS and BLPC; lower off-system sales at PGS; a change in fuel
cost recovery methodology for an industrial customer at NSPI; and decreased marketing and trading
margin at EES.
Exhibit 99.2
10
Operating Expenses
For Q4 2023, operating expenses decreased $171 million compared to Q4 2022 and excluding the 2022
GBPC impairment charge of $73 million, decreased $98 million. For the year ended December 31, 2023,
operating expenses decreased $190 million compared to 2022 and excluding the 2022 GBPC impairment
charge of $73 million, decreased $117 million. The decreases in both periods were due to lower fuel
expenses at TEC, NMGC, and PGS; partially offset by higher OM&G at TEC due to storm restoration
costs recognized related to the storm cost recovery surcharge revenue, and at NSPI due to higher power
generation and transmission and distribution field services cost. Year-over-year the decrease was also
due to a change in fuel cost recovery for an industrial customer at NSPI, partially offset by the impact of a
weaker CAD and the recognition of the Nova Scotia Renewable Electricity Regulations (“RER”) penalty at
NSPI.
 
Other Income, net
For Q4 2023, other income, net decreased $51 million compared to Q4 2022, primarily due to the TGH
award in Q4 2022. For the year ended December 31, 2023, other income, net increased $13 million
compared to 2022, primarily due to increased FX gains in 2023; higher interest income primarily at TEC;
and higher pension non-current service cost recovery, partially offset by the TGH award in 2022.
Interest Expense, net
Interest expense, net for Q4 2023 increased $35 million, and for the year ended December 31, 2023
increased $216 million compared to the same periods in 2022. The increases in both periods were due to
higher interest rates; higher borrowings to support capital investments and ongoing operations; and the
impact of a weaker CAD.
Net Income and Adjusted Net Income
Net income attributable to common shareholders for Q4 2023, compared to Q4 2022, was unfavourably
impacted by the $193 million decrease in MTM gains, after-tax, and favourably impacted by the $73
million GBPC impairment charge from 2022. Excluding these changes, adjusted net income decreased
$74 million. This was primarily due to the TGH award in Q4 2022; decreased earnings at EES, NMGC
and TEC; lower Corporate income tax recovery; and increased Corporate interest expense. These were
partially offset by increased earnings at NSPI and NSPML; and decreased Corporate OM&G due to the
timing of long-term compensation and related hedges.
Net income attributable to common shareholders for the year ended 2023, as compared to the same
period in 2022, was unfavourably impacted by the $6 million decrease in MTM gains, after-tax, and
favourably impacted by the $73 million GBPC impairment charge and the $7 million in NSPML
unrecoverable costs from 2022. Excluding these changes, adjusted net income decreased $41 million.
The decrease was primarily due to increased Corporate interest expense due to higher interest rates and
increased total debt; the TGH award in Q4 2022; and decreased earnings at EES. These were partially
offset by increased earnings at TEC, NMGC, NSPI and NSPML.
EPS and Adjusted EPS – Basic
EPS and Adjusted EPS – basic were lower for Q4
2023 due to the increase in weighted average shares
of common stock outstanding and decreased earnings as discussed above.
EPS – basic was higher for the year ended December 31, 2023, due to the impact of higher earnings as
discussed above. Adjusted EPS – basic was lower for the year ended December 31, 2023 due to the
increase in weighted average shares of common stock outstanding and decreased adjusted earnings, as
discussed above.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Exhibit 99.2
11
Effect of Foreign Currency Translation
Emera operates in Canada, the United States and various Caribbean countries and, as such, generates
revenues and incurs expenses denominated in local currencies which are translated into CAD for
financial reporting. Changes in translation rates, particularly in the value of the USD against the CAD, can
positively or adversely affect results.
Results of foreign operations are translated at the weighted average rate of exchange, and assets and
liabilities of foreign operations are translated at period end rates.
The relevant CAD/USD exchange rates
for 2023 and 2022 are as follows:
Three months ended
 
Year ended
December 31
December 31
2023
2022
2023
2022
Weighted average CAD/USD
 
$
1.36
$
1.37
$
1.35
$
1.34
Period end CAD/USD exchange rate
$
1.32
$
1.35
$
1.32
$
1.35
The table below includes Emera’s significant segments whose contributions to adjusted net income are
recorded in USD currency:
Three months ended
Year ended
For the
 
December 31
December 31
millions of USD
2023
2022
2023
2022
Florida Electric Utility
$
85
$
91
$
466
$
458
Gas Utilities and Infrastructure
 
(1)
41
45
142
143
Other Electric Utilities
3
7
26
23
Other segment
(2)
(18)
30
(95)
(50)
Total
(3)
$
111
$
173
$
539
$
574
(1) Includes USD net income from PGS, NMGC, SeaCoast and M&NP.
(2) Includes Emera Energy's USD adjusted net income from EES, Bear Swamp and interest expense on Emera Inc.'s USD
denominated debt.
(3) Excludes $73 million USD in MTM gain, after-tax, for the three months ended December 31, 2023 (2022 – $222 million USD
MTM gain, after-tax) and MTM gain, after-tax of $116
 
million USD for the year ended December 31, 2023 (2022 – $130 million USD
MTM gain, after-tax) and the GBPC impairment charge of nil for the three months and year ended December 31, 2023
 
(2022 – $54
million USD).
The translation impact of the change in FX rates on foreign denominated earnings increased net income
by $13 million in Q4 2023 and $46 million for the year ended December 31, 2023, compared to the same
periods in 2022. The translation impact of the change in FX rates on foreign denominated earnings
decreased adjusted net income by $3 million in Q4 2023 and increased adjusted net income by $20
million for the year ended December 31, 2023 compared to the same periods in 2022. Impacts of the
changes in the translation of the CAD include the impacts of Corporate FX hedges used to mitigate
translation risk of USD earnings in the Other segment.
BUSINESS OVERVIEW AND OUTLOOK
Emera’s 2023 results were impacted by macroeconomic conditions, specifically higher interest rates as
well as other impacts of inflation. These macroeconomic conditions are likely to continue for the near
term. For information on general economic risk, including interest rate and inflation risk, refer to the
“Enterprise Risk and Risk Management – General Economic Risk” section.
 
 
 
 
 
 
 
Exhibit 99.2
12
Florida Electric Utility
Florida Electric Utility consists of TEC, a vertically integrated regulated electric utility engaged in the
generation, transmission and distribution of electricity, serving customers in West Central Florida. TEC
has $12 billion USD of assets and approximately 840,000 customers at December 31, 2023. TEC owns
6,433 megawatts (“MW”) of generating capacity, of which 74 per cent is natural gas fired, 19 per cent is
solar and 7 per cent is coal. TEC owns 2,192 kilometres of transmission facilities and 20,299 kilometres of
distribution facilities. TEC meets the planning criteria for reserve capacity established by the FPSC, which
is a 20 per cent reserve margin over firm peak demand.
TEC’s approved regulated ROE range is 9.25 per cent to 11.25 per cent, based on an allowed equity
capital structure of 54 per cent. An ROE of 10.20 per cent is used for the calculation of the return on
investments for clauses.
TEC anticipates earning towards the lower end of the ROE range in 2024 but expects earnings to be
higher than 2023. Normalizing 2023 for weather, TEC sales volumes in 2024 are projected to be higher
than 2023 due to customer growth. TEC expects customer growth rates in 2024 to be comparable to
2023, reflective of the expected economic growth in Florida.
 
On February 1, 2024, TEC notified the FPSC of its intent to seek a base rate increase effective January
2025, reflecting a revenue requirement increase of approximately $290 to $320 million USD and
additional adjustments of approximately $100 million USD and $70 million USD for 2026 and 2027,
respectively. TEC’s proposed rates include recovery of solar generation projects, energy storage
capacity, a more resilient and modernized energy control center, and numerous other resiliency and
reliability projects. The filing range amounts are estimates until TEC files its detailed case in April 2024.
The FPSC is scheduled to hear the case in Q3 2024 with a decision expected by the end of 2024.
On August 16, 2023, TEC filed a petition to implement the 2024 Generation Base Rate Adjustment
provisions pursuant to the 2021 rate case settlement agreement. Inclusive of TEC’s ROE adjustment, the
increase of $22 million USD was approved by the FPSC on November 17, 2023.
On January 23, 2023, TEC petitioned the FPSC for recovery of the storm reserve regulatory asset and
the replenishment of the balance in the storm reserve to the approved storm reserve level of $56 million
USD, for a total of $131 million USD.
The storm cost recovery surcharge was approved by the FPSC on
March 7, 2023, and TEC began applying the surcharge in April 2023. Subsequently, on November 9,
2023, the FPSC approved TEC’s petition, filed on August 16, 2023, to update the total storm cost
collection to $134 million USD. It also changed the collection of the expected remaining balance of $29
million USD as of December 31, 2023, from over the first three months of 2024 to over the 12 months of
2024. The storm recovery is subject to review of the underlying costs for prudency and accuracy by the
FPSC and issuance of an order by the FPSC is expected by Q3 2024.
In Q3 2023, TEC was impacted by Hurricane Idalia. The related storm restoration costs were
approximately $35 million USD, which were charged to the storm reserve regulatory asset, resulting in
minimal impact to earnings. TEC will determine the timing of the request for recovery of Hurricane Idalia
costs at a future time.
On January 23, 2023, TEC requested an adjustment to its fuel charges to recover the 2022 fuel under-
recovery of $518 million USD over a period of 21 months. The request also included an adjustment to
2023 projected fuel costs to reflect the reduction in natural gas prices since September 2022 for a
projected reduction of $170 million USD for the balance of 2023. The changes were approved by the
FPSC on March 7, 2023, and were effective beginning on April 1, 2023.
 
In 2024, capital investment in the Florida Electric Utility segment is expected to be $1.3 billion USD (2023
– $1.3 billion USD), including allowance for funds used during construction (“AFUDC”). Capital projects
include solar investments,
 
grid modernization, storm hardening investments and building resilience.
 
Exhibit 99.2
13
Canadian Electric Utilities
Canadian Electric Utilities includes NSPI and ENL. NSPI is a vertically integrated regulated electric utility
engaged in the generation, transmission and distribution of electricity and the primary electricity supplier
to customers in Nova Scotia. ENL is a holding company with equity investments in NSPML and LIL: two
transmission investments related to the development of an 824 MW hydroelectric generating facility at
Muskrat Falls on the Lower Churchill River in Labrador.
 
NSPI
With $7.2 billion of assets and approximately 549,000 customers, NSPI owns 2,422 MW of generating
capacity, of which 44 per cent is coal and/or oil-fired; 28 per cent is natural gas and/or oil; 19 per cent is
hydro, wind, or solar; 7 per cent is petroleum coke (“petcoke”) and 2 per cent is biomass-fueled
generation. In addition, NSPI has contracts to purchase renewable energy from independent power
producers (“IPPs”) and community feed-in tariff (“COMFIT") participants, which own 532 MW of capacity.
NSPI also has rights to 153 MW of Maritime Link capacity, representing Nalcor Energy’s (“Nalcor”) Nova
Scotia Block (“NS Block”) delivery obligations,
 
as discussed below. NSPI owns approximately 5,000
kilometres of transmission facilities and 28,000 kilometres of distribution facilities.
Nalcor is obligated to provide NSPI with approximately 900 Gigawatt hours (“GWh”) of energy annually
over 35 years. In addition, for the first five years of the NS Block, Nalcor is obligated to provide
approximately 240 GWh of additional energy from the Supplemental Energy Block transmitted through
the Maritime Link. NSPI has the option of purchasing additional market-priced energy from Nalcor through
the Energy Access Agreement. The Energy Access Agreement enables NSPI to access a market-priced
bid from Nalcor for up to 1.8 Terawatt hours (“TWh”) of energy in any given year and, on average, 1.2
TWh of energy per year through August 31, 2041.
 
NSPI’s approved regulated ROE range is 8.75 per cent to 9.25 per cent, based on an actual five-quarter
average regulated common equity component of up to 40 per cent of approved rate base.
 
NSPI expects earnings and sales volumes to be higher in 2024 than 2023 but anticipates earning below
its allowed ROE range in 2024.
 
On January 29, 2024, NSPI applied to the UARB for approval of a structure that would begin to recover
the outstanding Fuel Adjustment Mechanism (“FAM”) balance. As part of the application, NSPI requested
approval for the sale of $117 million of the FAM
 
regulatory asset to Invest Nova Scotia, a provincial
Crown corporation, with the proceeds paid to NSPI upon approval. NSPI has requested approval to
collect from customers the amortization and financing costs of $117 million on behalf of Invest Nova
Scotia over a 10-year period, and remit those amounts to Invest Nova Scotia as collected, reducing short-
term customer rate increases relative to the currently established FAM process. If approved, this portion
of the FAM regulatory asset would be removed from the Consolidated Balance Sheets and NSPI would
collect the balance on behalf of Invest Nova Scotia in NSPI rates beginning in 2024. A decision is
expected in the first half of 2024. It is anticipated that NSPI will apply to the UARB later in 2024 to collect
additional under-recovered fuel amounts in 2025 or future periods, subject to the approval of the UARB.
On October 31, 2023, NSPI submitted an application to the UARB to defer $24 million in incremental
operating costs incurred during Hurricane Fiona storm restoration efforts in September 2022. NSPI is
seeking amortization of the costs over a period to be approved by the UARB during a future rate setting
process. At December 31, 2023, the $24 million is deferred to “Other long-term assets”, pending UARB
approval. A decision is expected from the UARB in 2024.
Exhibit 99.2
14
On September 16, 2023, Nova Scotia was struck by post-tropical storm Lee and as a result,
approximately 280,000 customers lost power. The total cost of storm restoration was $19 million, with $9
million charged to “OM&G”, $5 million capitalized to property, plant and equipment (“PP&E) and $5 million
deferred to the UARB approved storm rider. The storm rider, for each of 2023, 2024, and 2025, allows
NSPI to apply to the UARB for deferral and recovery of expenses if major storm restoration expenses
exceed approximately $10 million in any given year. The application for deferral of the storm rider is made
in the year following the year of the incurred costs, with recovery beginning in the year after the
application.
 
On February 2, 2023, the UARB approved the General Rate Application settlement agreement between
NSPI, key customer representatives and participating interest groups. This resulted in average customer
rate increases of 6.9 per cent effective on February 2, 2023, and a further average increase of 6.5 per
cent on January 1, 2024, with any under or over-recovery of fuel costs addressed through the UARB’s
established FAM process. It also established a storm rider, described above, and a demand-side
management rider. On March 27, 2023, the UARB issued a final order approving the electricity rates
effective on February 2, 2023.
In 2024, capital investment, including AFUDC, is expected to be $435 million (2023 – $451 million). NSPI
is primarily investing in capital projects required to support power system reliability and reliable service for
customers.
 
Environmental Legislation and Regulations
NSPI is subject to environmental laws and regulations set by both the Government of Canada and the
Province of Nova Scotia (the “Province”). NSPI continues to work with both levels of government to
comply with these laws and regulations to maximize efficiency of emission control measures and
minimize customer cost. NSPI anticipates that costs prudently incurred to achieve legislated compliance
will be recoverable under NSPI’s regulatory framework. NSPI faces risks associated with achieving
climate-related and environmental legislative requirements, including the risk of non-compliance, which
could adversely affect NSPI’s operations and financial performance. For further discussion on these risks
and environmental legislation and regulations, refer to the “Enterprise Risk and Risk Management”
section. Recent developments related to provincial and federal environmental laws and regulations are
outlined below.
Clean Electricity Solutions Task Force:
The Clean Electricity Solutions Task Force (the “Task
 
Force”) was created by the Province in April 2023
to advise the provincial government on Nova Scotia’s transition away from coal to more renewable
sources of energy. On February 23, 2024, the Task
 
Force released its report and recommendations,
based on engagement with stakeholders, including NSPI. The Task Force report focuses on findings
related to system operations, regulatory oversight, reliability, transmission and affordability.
 
The Task
Force announced a number of recommendations, including a strengthening of the authority and
independence of the regulator and the establishment of an independent system operator, in order to
support the continuing transition to clean energy and the achievement of federal and provincial clean
energy goals and legislation. The Province announced they intend to accept these recommendations and
will table enabling legislation in its upcoming session which starts February 27, 2024.
RER:
On April 6, 2023, the Province levied a $10 million penalty on NSPI for non-compliance with the RER
compliance period ending in 2022. The penalty was recorded in “OM&G” on the Consolidated Statements
of Income. On May 26, 2023, NSPI initiated an appeal of the penalty through a proceeding with the
UARB, as permitted under the RER. On October 12, 2023, the UARB decided that it will hear the appeal
by giving due deference to the Province’s decision but permitting the filing of new evidence to support the
parties’ positions. The hearing for the matter is scheduled for June 2024 and a decision is expected
before the end of 2024.
Exhibit 99.2
15
Carbon Pricing Regulations:
In November 2022, the Province enacted amendments to the Environment Act which provided the
framework for Nova Scotia to implement an output-based pricing system (“OBPS”) to comply with the
Government of Canada’s 2023 through 2030 carbon pollution pricing regulations effective January 1,
2023. The Government of Canada approved the Province’s proposed system, however the OBPS will be
subject to an interim review by the Government of Canada of the standards effective for 2026. The final
Output-Based Pricing System Reporting and Compliance Regulations were prescribed by Order in
Council dated January 30, 2024. The OBPS implements greenhouse gas (“GHG”) emissions
performance standards for large industrial GHG emitters that vary by fuel type. GHG emissions in excess
of the prescribed intensity standards will be subject to a carbon price that starts at $65 per tonne in 2023
and will increase by $15 per tonne annually, reaching $170 per tonne by 2030. NSPI’s regulatory
framework provides for the recovery of costs prudently incurred to comply with carbon pricing programs
pursuant to NSPI’s FAM.
Nova Scotia Cap-and-Trade Program Regulations:
NSPI was a participant in the Nova Scotia Cap-and-Trade Program and was subject to the 2019 through
2022 compliance period. On March 16, 2023, the Province provided NSPI with emissions allowances
sufficient to achieve compliance for the 2019 through 2022 compliance period. As such, compliance costs
accrued of $166 million were reversed in Q1 2023. The credits NSPI purchased from provincial auctions
in the amount of $6 million were not refunded and no further costs were incurred to achieve compliance
with the Nova Scotia Cap-and-Trade Program.
Other Legislation
Electricity Act Amendment:
On November 9, 2023, the Province enacted amendments in the Electricity Act which permit the
Governor in Council to approve energy storage projects proposed by a public utility and owned wholly or
in majority by the public utility if the project is in the best interest of ratepayers. Further, the amendments
to the Electricity Act expand the ability of the Province to require NSPI to enter into power purchase
agreements with renewable generation facilities by further empowering the Province to require NSPI to
enter into an agreement for the sale of the electricity to specified customers. This allows specified
customers to buy renewable electricity from specified producers, with NSPI managing the transmission
and sale of the energy. On December 21, 2023, the Governor in Council enacted regulations which
directed NSPI to install three 50 MW four-hour duration grid-scale batteries as part of the regulated
assets of NSPI.
Performance Standards Penalty Amendment:
On April 12, 2023, the Province enacted amendments to the Public Utilities Act which increased the
cumulative total of administrative penalties that could be levied by the UARB against NSPI for non-
compliance with current and future performance standards in a calendar year from $1 million to $25
million. Any administrative penalties levied against NSPI must be credited to customers and NSPI cannot
recover administrative penalties imposed through rates.
 
Exhibit 99.2
16
ENL
Total
 
equity earnings from NSPML and LIL are expected to be higher in 2024, compared to 2023 resulting
from an increased investment in LIL planned for 2024. Both the NSPML and LIL investments are
recorded as “Investments subject to significant influence” on Emera’s Consolidated Balance Sheets.
NSPML
Equity earnings from the Maritime Link are dependent on the approved ROE and operational
performance of NSPML. NSPML’s approved regulated ROE range is 8.75 per cent to 9.25 per cent,
based on an actual five-quarter average regulated common equity component of up to 30 per cent.
 
The Maritime Link assets entered service on January 15, 2018, enabling the transmission of energy
between Newfoundland and Nova Scotia, improved reliability and ancillary benefits, supporting the
efficiency and reliability of energy in both provinces. Nalcor’s NS Block delivery obligations commenced
on August 15, 2021, and the NS Block will be delivered over the next 35 years pursuant to the project
agreements.
 
On December 21, 2023, NSPML received approval to collect up to $164 million from NSPI for the
recovery of costs associated with the Maritime Link in 2024; subject to a holdback of $4 million per month,
as discussed below.
 
On October 4, 2023 and January 31, 2024, the UARB issued decisions providing clarification on
remaining aspects of the Maritime Link holdback mechanism primarily relating to release of past and
future holdback amounts and requirements to end the holdback mechanism. In these decisions, the
UARB agreed with the Company’s submission that $12 million ($8 million related to 2022 and $4 million
relating to 2023) of the previously recorded holdback remain credited to NSPI’s FAM, with the remainder
released to NSPML and recorded in Emera’s “Income from equity investments. NSPML did not record
any additional holdback in Q4 2023. The UARB also confirmed that the holdback mechanism will cease
once 90 per cent of NS Block deliveries are achieved for 12 consecutive months (subject to potential
relief for planned outages or exceptional circumstances) and the net outstanding balance of previously
underdelivered NS Block energy is less than 10 per cent of the contracted annual amount. In addition, the
UARB increased the monthly holdback amount from $2 million to $4 million beginning December 1, 2023.
NSPML expects to file an application to terminate the holdback mechanism in 2024.
 
NSPML does not anticipate any significant capital investment in 2024.
LIL
ENL is a limited partner with Nalcor in LIL. Construction of the LIL is complete and the Newfoundland
Electrical System Operator confirmed the asset to be operating suitably to support reliable system
operation and full functionality at 700MW, which was validated by the Government of Canada’s
Independent Engineer issuing its Commissioning Certificate on April 13, 2023.
Upon issuance of the Commissioning Certificate, AFUDC equity earnings ceased and cash equity
earnings and return of equity to Emera commenced. The first distribution was received from the LIL
partnership in Q4 2023.
Equity earnings from the LIL investment are based upon the book value of the equity investment and the
approved ROE. Emera’s current equity investment is $747 million, comprised of $410 million in equity
contribution and $337 million of accumulated equity earnings. Emera’s total equity contribution in the LIL,
excluding accumulated equity earnings, is estimated to be approximately $650 million once the final
costing has been confirmed by Nalcor to determine the amount of the remaining investment.
Exhibit 99.2
17
Gas Utilities and Infrastructure
Gas Utilities and Infrastructure includes PGS, NMGC, SeaCoast, Brunswick Pipeline and Emera’s equity
investment in M&NP.
 
PGS is a regulated gas distribution utility engaged in the purchase, distribution and
sale of natural gas serving customers in Florida. NMGC is an intrastate regulated gas distribution utility
engaged in the purchase, transmission, distribution and sale of natural gas serving customers in New
Mexico. SeaCoast is a regulated intrastate natural gas transmission company offering services in Florida.
Brunswick Pipeline is a regulated 145-kilometre pipeline delivering re-gasified liquefied natural gas from
Saint John, New Brunswick, to markets in the northeastern United States.
Peoples Gas System
With $2.8 billion USD of assets and approximately 490,000 customers, the PGS system includes 24,300
kilometres of natural gas mains and 13,500 kilometres of service lines. Natural gas throughput (the
amount of gas delivered to its customers, including transportation-only service) was 2 billion therms in
2023.
 
Beginning in 2024, the approved ROE range for PGS is 9.15 per cent to 11.15 per cent (2023 – 8.9 per
cent to 11.0 per cent), based on an allowed equity capital structure of 54.7 per cent (2023 – 54.7 per
cent). An ROE of 10.15 per cent (2023 – 9.9 per cent) is used for the calculation of return on investments
for clauses.
New Mexico Gas Company, Inc.
With $1.8 billion USD of assets and approximately 540,000 customers, NMGC’s system includes
approximately 2,408 kilometres of transmission pipelines and 17,657 kilometres of distribution pipelines.
Annual natural gas throughput was approximately 1 billion therms in 2023.
The approved ROE for NMGC is 9.375 per cent, on an allowed equity capital structure of 52 per cent.
 
Gas Utilities and Infrastructure Outlook
Gas Utilities and Infrastructure USD earnings are anticipated to be higher in 2024 than 2023, primarily
due to a base rate increase effective January 2024 at PGS and an expected base rate increase effective
Q4 2024 at NMGC, partially offset by lower asset optimization revenues expected at NMGC.
 
PGS expects rate base to be higher than in 2023 and anticipates earning within its allowed ROE range in
2024. USD earnings for 2024 are expected to be to be significantly higher than in 2023 primarily due to
higher revenue from new base rates in support of significant ongoing system investment and continued
customer growth in 2024, which is expected to be consistent with Florida’s population growth rates.
On April 4, 2023, PGS filed a rate case with the FPSC and a hearing for the matter was held in
September 2023. On November 9, 2023, the FPSC approved a $118 million USD increase to base
revenues which includes $11 million USD transferred from the cast iron and bare steel replacement rider,
for a net incremental increase to base revenues of $107 million USD. This reflects a 10.15 per cent
midpoint ROE with an allowed equity capital structure of 54.7 per cent. A final order was issued on
December 27, 2023, with the new rates effective January 2024.
 
The 2020 PGS rate case settlement provided the ability to reverse a total of $34 million USD of
accumulated depreciation through 2023. PGS reversed $20 million USD of accumulated depreciation in
2023 and $14 million USD in 2022.
Exhibit 99.2
18
NMGC expects 2024 rate base growth to be consistent with 2023, with slightly lower USD earnings as a
result of lower asset optimization revenues, partially offset by higher revenue from expected new base
rates, effective Q4 2024. NMGC anticipates earning near its authorized ROE in 2024. Customer growth
rates are expected to be consistent with historical trends.
 
On September 14, 2023, NMGC filed a rate case with the NMPRC for new base rates to become effective
Q4 2024. NMGC requested a $49 million USD increase in annual base revenues primarily as a result of
increased operating costs and capital investments in pipeline projects and related infrastructure. The rate
case includes a requested ROE of 10.5 per cent.
 
A final order from the NMPRC is expected in Q3 2024.
In 2024, capital investment in the Gas Utilities and Infrastructure segment is expected to be
approximately $465 million USD (2023 – $495 million USD), including AFUDC. PGS and NMGC will make
investments to maintain the reliability of their systems and support customer growth.
 
Other Electric Utilities
Other Electric Utilities includes Emera (Caribbean) Incorporated (“ECI”), a holding company with
regulated electric utilities. ECI’s regulated utilities include vertically integrated regulated electric utilities of
BLPC on the island of Barbados, GBPC on Grand Bahama Island, and an equity investment in Lucelec
on the island of St. Lucia.
BLPC
With $517 million USD of assets and approximately 134,000 customers, BLPC owns 243 MW of
generating capacity, of which 96 per cent is oil-fired and four per cent is solar.
 
BLPC owns approximately
188 kilometres of transmission facilities and 3,839 kilometres of distribution facilities. BLPC’s approved
regulated return on rate base for 2023 was 10 per cent.
GBPC
With $334 million USD of assets and approximately 19,000 customers, GBPC owns 98 MW of oil-fired
generation, approximately 90 kilometres of transmission facilities and 994 kilometres of distribution
facilities. GBPC’s approved regulatory return on rate base for 2024 is 8.52 per cent (2023 – 8.32 per
cent).
 
Other Electric Utilities Outlook
Other Electric Utilities’ USD earnings in 2024 are expected to increase over the prior year.
BLPC currently operates pursuant to a single integrated license to generate, transmit and distribute
electricity on the island of Barbados until 2028. In 2019, the Government of Barbados passed legislation
requiring multiple licenses for the supply of electricity. In 2021, BLPC reached commercial agreement with
the Government of Barbados for each of the license types, subject to the passage of implementing
legislation. The timing of the final enactment is unknown at this time, but BLPC will work towards the
implementation of the licenses once enacted.
Exhibit 99.2
19
In 2021, BLPC submitted a general rate review application to the FTC. In September 2022, the FTC
granted BLPC interim rate relief, allowing an increase in base rates of approximately $1 million USD per
month. On February 15, 2023, the FTC issued a decision on the application which included the following
significant items: an allowed regulatory ROE of 11.75 per cent, an equity capital structure of 55 per cent,
a directive to update the major components of rate base to September 16, 2022, and a directive to
establish regulatory liabilities related to the self-insurance fund of $50 million USD, prior year benefits
recognized on remeasurement of deferred income taxes of $5 million USD, and accumulated depreciation
of $16 million USD. On March 7, 2023, BLPC filed a Motion for Review and Variation (the “Motion”) and
applied for a stay of the FTC’s decision, which was subsequently granted. On November 20, 2023, the
FTC issued their decision dismissing the Motion. Interim rates continue to be in effect through to a date to
be determined in a final decision and order.
On December 1, 2023, BLPC appealed certain aspects of the FTC’s February 15 and November 20,
2023, decisions to the Supreme Court of Barbados in the High Court of Justice (the “Court”) and
requested that they be stayed. On December 11, 2023, the Court granted the stay.
 
BLPC’s position is
that the FTC made errors of law and jurisdiction in their decisions and believes the success of the appeal
is probable, and as a result, the adjustments to BLPC’s final rates and rate base, including any
adjustments to regulatory assets and liabilities, have not been recorded at this time. Management does
not expect the final decision and order to have a material impact on adjusted net income.
In 2024, capital investment in the Other Electric Utilities segment is expected to be approximately $80
million USD (2023 – $47 million USD), primarily in more efficient and cleaner sources of generation,
including renewables and battery storage.
 
Other
The Other segment includes those business operations that in a normal year are below the required
threshold for reporting as separate segments; and corporate expense and revenue items that are not
directly allocated to the operations of Emera’s subsidiaries and investments.
Business operations in the Other segment include Emera Energy and Block Energy LLC (“Block Energy”).
Emera Energy consists of EES, a wholly owned physical energy marketing and trading business and an
equity investment in a 50 per cent joint venture ownership of Bear Swamp, a 660 MW pumped storage
hydroelectric facility in northwestern Massachusetts. Block Energy is a wholly owned technology company
focused on finding ways to deliver renewable and resilient energy to customers.
Corporate items included in the Other segment are certain corporate-wide functions including executive
management, strategic planning, treasury services, legal, financial reporting, tax planning, corporate
business development, corporate governance, investor relations, risk management, insurance, acquisition
and disposition related costs, gains or losses on select assets sales, and corporate human resource
activities. It includes interest revenue on intercompany financings and interest expense on corporate debt
in both Canada and the United States. It also includes costs associated with corporate activities that are
not directly allocated to the operations of Emera’s subsidiaries and investments.
Earnings from EES are generally dependent on market conditions. In particular, volatility in natural gas
and electricity markets, which can be influenced by weather, local supply constraints and other supply
and demand factors, can provide higher levels of margin opportunity. The business is seasonal, with Q1
and Q4 usually providing the greatest opportunity for earnings. EES is generally expected to deliver
annual adjusted net income within its guidance range of $15 to $30 million USD.
The adjusted net loss from the Other segment is expected to be higher in 2024 due to increased interest
expense and lower contribution to net income from Emera Energy primarily as a result of one-time
investment tax credits at Bear Swamp in 2023.
 
The Other segment does not anticipate any significant capital investment in 2024.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Exhibit 99.2
20
CONSOLIDATED
 
BALANCE SHEET HIGHLIGHTS
Significant changes in the Consolidated Balance Sheets between December 31, 2022 and December 31,
2023 include:
millions of dollars
Increase
(Decrease)
Explanation
 
Assets
Cash and cash equivalents
$
 
257
Increased due to cash from operations, proceeds from long-term
debt issuances at PGS and NSPI, and issuance of Emera
common stock. These were partially offset by investment in PP&E
at the regulated utilities, net repayments of debt at TEC, and
dividends paid on Emera common stock
Derivative instruments (current and
long-term)
 
(156)
Decreased due to settlements of derivative instruments and
decreased pricing on power derivative instruments at NSPI,
partially offset by reversal of 2022 contracts at EES
Regulatory assets (current and long-
term)
 
(515)
Decreased due to higher fuel clause and storm cost recoveries at
TEC, and reversal of accrued Cap-and-Trade emission
compliance charges at NSPI. These were partially offset by
increased FAM deferrals at NSPI due to an under-recovery of fuel
costs and a change in fuel cost recovery methodology for an
industrial customer, and increased deferred income tax regulatory
assets at NSPI
Receivables and other assets
(current and long-term)
 
(1,079)
Decreased due to lower gas transportation assets, decreased
cash collateral and lower trade receivables as a result of lower
commodity prices at EES, and settlement of the gas hedge
receivable at NMGC
PP&E, net of accumulated
depreciation and amortization
 
1,380
Increased due to capital additions in excess of depreciation and
amortization, partially offset by the effect of FX translation of
Emera's non-Canadian affiliates
Goodwill
 
(141)
Decreased due to the effect of the FX translation of non-Canadian
affiliates
Liabilities and Equity
Short-term debt and long-term debt
(including current portion)
$
 
754
Issuance of long-term debt at PGS and NSPI and proceeds from
committed credit facilities at Emera, partially offset by net
repayments under committed credit facilities at NSPI and TEC,
repayment of debt at NMGC, and the effect of the FX translation
of non-Canadian affiliates
Accounts payable
 
(571)
Decreased due to lower commodity prices at EES, NMGC and
TEC, decreased cash collateral position on derivative instruments
and lower fuel related payables at NSPI
Deferred income tax liabilities, net of
deferred income tax assets
 
 
185
Increased due to tax deductions in excess of accounting
depreciation related to PP&E, partially offset by changes in
derivative instruments and increased tax credits related to solar
projects at TEC and Bear Swamp facility upgrades
Derivative instruments (current and
long-term)
 
(574)
Decreased due to changes in existing positions and reversal of
2022 contracts, partially offset by new contracts in 2023 at EES
Regulatory liabilities (current and
long-term)
 
(501)
Decreased due to lower deferrals related to derivative instruments
at NSPI and settlement of NMGC gas hedges
Other liabilities (current and long-
term)
 
(157)
Decreased due to reversal of accrued Cap-and-Trade emissions
compliance charges at NSPI
Common stock
 
700
Increased due to shares issued
Accumulated other comprehensive
income
 
(273)
Decreased due to the effect of the FX translation of non-Canadian
affiliates
Retained earnings
 
219
Increased due to net income in excess of dividends paid
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Exhibit 99.2
21
OTHER DEVELOPMENTS
Increase in Common Dividend
On September 20, 2023, the Emera Board of Directors (the “Board”) approved an increase in the annual
common share dividend rate to $2.87 from $2.76 per common share. The first payment was effective
November 15, 2023. Emera also extended its dividend growth rate target of four to five per cent through
2026.
FINANCIAL HIGHLIGHTS
Florida Electric Utility
Three months ended
Year ended
For the
December 31
December 31
millions of USD (except as indicated)
2023
2022
2023
2022
Operating revenues – regulated electric
$
 
613
$
 
597
$
 
2,637
$
 
2,523
Regulated fuel for generation and purchased power
$
 
162
$
 
201
$
 
682
$
 
832
Contribution to consolidated net income
 
$
 
85
$
 
91
$
 
466
$
 
458
Contribution to consolidated net income – CAD
$
 
115
$
 
124
$
 
627
$
 
596
Average fuel costs in dollars per MWh
$
 
34
$
 
41
$
 
31
$
 
39
The impact of the change in the FX rate increased CAD earnings for the three months and year ended
December 31, 2023, by $1 million and $22 million, respectively.
Net Income
Highlights of the net income changes are summarized in the following table:
For the
Three months ended
Year ended
millions of USD
December 31
December 31
Contribution to consolidated net income – 2022
$
91
$
 
458
Increased operating revenues due to storm cost recovery surcharge
revenue (offset in OM&G), new base rates and customer growth driving
higher sales volumes, partially offset by changes in fuel recovery
clause revenue and unfavourable weather
 
16
 
114
Decreased fuel for generation and purchased power due to lower
natural gas prices
 
39
 
150
Increased OM&G primarily due to storm cost recovery recognition
related to the storm surcharge (offset in revenue) and timing of
deferred clause recoveries
 
(25)
 
(136)
Increased depreciation and amortization due to additions to facilities
and generation projects placed in service
 
(8)
 
(33)
Increased interest expense due to higher interest rates and higher
borrowings to support capital investments and ongoing operations
 
(7)
 
(59)
Increased state, and municipal taxes due to higher retail sales and
higher taxable property placed in service
 
(8)
 
(33)
(Increased) decreased income tax expense primarily due to production
tax credits related to solar facilities
 
(6)
 
7
Other
 
(7)
 
(2)
Contribution to consolidated net income – 2023
$
 
85
$
 
466
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Exhibit 99.2
22
Operating Revenues – Regulated Electric
Annual electric revenues and sales volumes are summarized in the following table by customer class:
Electric Revenues
Electric Sales Volumes
 
(millions of USD)
(Gigawatt hours ("GWh"))
 
2023
2022
2023
2022
Residential
$
 
1,711
$
 
1,381
 
10,307
 
10,109
Commercial
 
803
 
666
 
6,462
 
6,300
Industrial
 
203
 
176
 
2,082
 
2,111
Other
(1)
 
(80)
 
300
 
2,194
 
2,352
Total
$
 
2,637
$
 
2,523
 
21,045
 
20,872
(1) Other includes regulatory deferrals related to clauses, sales to public authorities, off-system sales to
 
other utilities.
Regulated Fuel for Generation and Purchased Power
Annual production volumes are summarized in the following table:
Production Volumes (GWh)
2023
2022
Natural gas
 
 
17,843
 
17,083
Solar
 
1,748
 
1,492
Purchased power
 
 
1,443
 
1,685
Coal
 
 
744
 
1,325
Total
 
 
21,778
 
21,585
TEC’s fuel costs are affected by commodity prices and generation mix that is largely dependent on
economic dispatch of the generating fleet, bringing the lowest cost options on first (renewable energy
from solar or battery storage), such that the incremental
 
cost of production increases as sales volumes
increase. Generation mix may also be affected by plant outages, plant performance, availability of lower
priced short-term purchased power, availability of renewable solar generation, and compliance with
environmental standards and regulations.
Regulatory Environment
TEC is regulated by the FPSC and is also subject to regulation by the FERC. The FPSC sets rates at a
level that allows utilities such as TEC to collect total revenues or revenue requirements equal to their cost
of providing service, plus an appropriate return on invested capital. Base rates are determined in FPSC
rate setting hearings which can occur at the initiative of TEC, the FPSC or other interested parties. For
further details on TEC’s regulatory environment, base rates and recovery mechanisms, refer to note 6 in
the consolidated financial statements.
Canadian Electric Utilities
Three months ended
Year ended
For the
December 31
December 31
millions of dollars (except as indicated)
2023
2022
2023
2022
Operating revenues – regulated electric
$
 
439
$
 
421
$
 
1,671
$
 
1,675
Regulated fuel for generation and purchased power
(1)
$
 
234
$
 
173
$
 
777
$
 
950
Contribution to consolidated adjusted net income
$
 
68
$
 
46
$
 
247
$
 
222
NSPML unrecoverable costs
$
 
-
 
$
 
-
 
$
 
-
 
$
 
(7)
Contribution to consolidated net income
$
 
68
$
 
46
$
 
247
$
 
215
Average fuel costs in dollars per MWh
(2)
$
 
81
$
 
61
$
 
70
$
 
85
(1) Regulated fuel for generation and purchased power includes NSPI's FAM
 
deferral on the Consolidated Statements of Income,
however, it is excluded in the segment overview.
 
(2) Average fuel costs for the year ended December 31, 2023 include reversal of the $166 million
 
of the Nova Scotia Cap-and-Trade
Program provision (2022 – $134 million expense).
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Exhibit 99.2
23
Canadian Electric Utilities' contribution to consolidated adjusted net income is summarized in the following
table:
Three months ended
 
Year ended
For the
December 31
December 31
millions of dollars
2023
2022
2023
2022
NSPI
$
 
40
$
 
23
$
 
141
$
 
131
Equity investment in LIL
 
16
 
15
 
60
 
55
Equity investment in NSPML
(1)
 
12
 
8
 
46
 
36
Contribution to consolidated adjusted net income
 
$
 
68
$
 
46
$
 
247
$
 
222
(1) Excludes $7 million in NSPML unrecoverable costs, after-tax, for the year ended December 31, 2022.
Net Income
Highlights of the net income changes are summarized in the following table:
For the
Three months ended
Year ended
millions of dollars
December 31
December 31
Contribution to consolidated net income – 2022
$
 
46
$
 
215
Increased operating revenues quarter-over-quarter due to new rates,
increased residential, commercial and other class sales volumes, and
favourable weather, partially offset by decreased industrial sales
volume. Year-over-year decrease primarily due to changes in fuel cost
recovery methodology for an industrial customer
(1)
, partially offset by
quarter-over-quarter impacts noted above
 
18
 
(4)
Increased fuel for generation and purchased power quarter-over-quarter
due to increased commodity prices and partial reversal of Nova Scotia
Cap-and-Trade Program costs accrued in 2022, partially offset by a
change in generation mix. Year-over-year decreased due to reversal of
the Nova Scotia Cap-and-Trade Program provision in 2023, compared
to an expense in 2022, partially offset by increased commodity prices
and the Nova Scotia OBPS carbon tax accrual
 
(61)
 
173
Increased FAM deferral quarter-over-quarter due to under-recovery of
fuel costs. Year-over-year decreased due to reversal of the Nova Scotia
Cap-and-Trade provision in 2023, partially offset by increased under-
recovery of fuel costs and changes in the fuel recovery methodology for
an industrial customer
(1)
 
74
 
(69)
Increased OM&G due to higher costs for power generation and
transmission and distribution field services. Year-over-year also
increased due to the recognition of the RER penalty and higher
vegetation management costs
 
(8)
 
(46)
Increased depreciation and amortization due to increased PP&E in
service
 
(3)
 
(17)
Increased interest expense due to increased interest rates and higher
debt levels
 
(5)
 
(34)
Increased income from equity investments at NSPML quarter-over-
quarter primarily due to the holdback recognized in Q4 2022. Year-over-
year also increased due to partial reversal in Q3 2023 of the holdback
recognized in 2022, and higher equity earnings from LIL
 
5
 
15
NSPML unrecoverable costs in 2022
 
-
 
 
7
Other
 
2
 
7
Contribution to consolidated net income – 2023
$
 
68
$
 
247
(1) For more information on the changes in fuel cost recovery methodology for an industrial customer,
 
refer to note 6 in the 2023
consolidated financial statements
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Exhibit 99.2
24
NSPI
Operating Revenues – Regulated Electric
Annual electric revenues and sales volumes are summarized in the following tables by customer class:
Electric Revenues
Electric Sales Volumes
(millions of dollars)
(GWh)
 
2023
2022
2023
2022
Residential
$
 
910
$
 
834
 
4,986
 
4,822
Commercial
 
463
 
427
 
3,053
 
3,006
Industrial
 
219
 
353
 
2,164
 
2,480
Other
 
41
 
28
 
239
 
148
Total
$
 
1,633
$
 
1,642
 
10,442
 
10,456
Regulated Fuel for Generation and Purchased Power
Annual production volumes are summarized in the following table:
Production Volumes (GWh)
 
2023
2022
Coal
 
 
3,086
 
3,771
Natural gas
 
1,946
 
1,650
Purchased power
 
881
 
910
Petcoke
 
553
 
897
Oil
 
145
 
251
Total non-renewables
 
6,611
 
7,479
Purchased power - IPP,
 
COMFIT and imports
 
3,251
 
2,423
Wind, hydro and solar
 
1,149
 
1,105
Biomass
 
 
128
 
127
Total renewables
 
4,528
 
3,655
Total production volumes
 
11,139
 
11,134
NSPI’s fuel costs are affected by commodity prices and generation mix, which is largely dependent on
economic dispatch of the generating fleet. NSPI brings the lowest cost options on stream first after
renewable energy from IPPs including COMFIT participants, for which NSPI has power purchase
agreements in place, and the NS Block of energy, including the Supplemental Energy Block, which
carries no additional fuel cost outside of the UARB approved annual assessments paid to NSPML for the
use of the Maritime Link.
 
Generation mix may also be affected by plant outages, carbon pricing programs, including the Nova
Scotia OBPS, availability of renewable generation, availability of energy from the NS Block, plant
performance, and compliance with environmental regulations.
 
The Nova Scotia Cap-and-Trade Program provision related to the accrued cost of acquiring emissions
credits for the 2019 through 2022 compliance period. As of December 31, 2022, NSPI had recognized a
cumulative $166 million accrual in fuel costs related to anticipated purchase of emissions credits and $6
million related to credits purchased from provincial auction. Accrued compliance costs of $166 million
were reversed in Q1 2023 and NSPI does not anticipate further costs related to the Nova Scotia Cap-and-
Trade Program. For further information on the reversal of this non-cash accrual and the FAM regulatory
balance, refer to the “Business Overview and Outlook – Canadian Electric Utilities – NSPI” section and
note 6 in the consolidated financial statements.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Exhibit 99.2
25
Regulatory Environment - NSPI
NSPI is a public utility as defined in the Public Utilities Act and is subject to regulation under the Public
Utilities Act by the UARB. The Public Utilities Act gives the UARB supervisory powers over NSPI’s
operations and expenditures. Electricity rates for NSPI’s customers are subject to UARB approval. NSPI
is not subject to a general annual rate review process, but rather participates in hearings held from time to
time at NSPI’s or the UARB’s request. For further details on NSPI’s regulatory environment and recovery
mechanisms, refer to note 6 in the consolidated financial statements.
Gas Utilities and Infrastructure
Three months ended
Year ended
For the
December 31
December 31
millions of USD (except as indicated)
2023
2022
2023
2022
Operating revenues – regulated gas
(1)
$
 
290
$
 
372
$
 
1,114
$
 
1,296
Operating revenues – non-regulated
 
3
 
2
 
15
 
12
Total operating revenue
$
 
293
$
 
374
$
 
1,129
$
 
1,308
Regulated cost of natural gas
$
 
99
$
 
181
$
 
391
$
 
614
Contribution to consolidated net income
 
$
 
43
$
 
53
$
 
158
$
 
170
Contribution to consolidated net income – CAD
$
 
59
$
 
72
$
 
214
$
 
221
 
(1) Operating revenues – regulated gas includes $11
 
million of finance income from Brunswick Pipeline (2022 – $13 million) for the
three months ended December 31, 2023 and $46 million (2022 – $47 million) for the year ended December 31 2023;
 
however, it is
excluded from the gas revenues and cost of natural gas analysis below.
Gas Utilities and Infrastructure's contribution to consolidated net income is summarized in the following
table:
Three months ended
 
Year ended
For the
December 31
December 31
millions of USD
2023
2022
2023
2022
PGS
$
 
21
$
 
17
$
 
79
$
 
82
NMGC
 
14
 
22
 
43
 
35
Other
 
8
 
14
 
36
 
53
Contribution to consolidated net income
 
$
 
43
$
 
53
$
 
158
$
 
170
Impact of the change in the FX rate on CAD earnings was minimal for the three months ended and
increased CAD earnings for the year ended December 31, 2023, by $8 million.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Exhibit 99.2
26
Net Income
Highlights of the net income changes are summarized in the following table:
For the
Three months ended
Year ended
millions of USD
December 31
December 31
Contribution to consolidated net income – 2022
$
 
53
$
 
170
Decreased operating revenues due to lower fuel revenues at PGS and
NMGC, and lower off-system sales at PGS, partially offset by new base
rates at NMGC and customer growth at PGS
 
(71)
 
(181)
Decreased asset optimization revenue quarter-over-quarter at NMGC
 
(10)
 
2
Decreased cost of natural gas sold due to lower natural gas prices at
PGS and NMGC
 
82
 
223
Increased OM&G primarily due to higher labour and benefit costs
 
(10)
 
(20)
Decreased depreciation and amortization expense quarter-over-quarter
due to a higher reversal of accumulated depreciation in 2023 as a
result of the 2021 rate case settlement at PGS. Year-over-year
increase due to asset growth at PGS and NMGC, partially offset by a
higher reversal of accumulated depreciation in 2023 at PGS
 
6
 
(3)
Increased interest expense due to higher interest rates and increased
borrowings to support ongoing operations and capital investments
 
(10)
 
(33)
Other
 
3
 
-
 
Contribution to consolidated net income – 2023
$
 
43
$
 
158
Operating Revenues – Regulated Gas
Annual gas revenues and sales volumes are summarized in the following tables by customer class:
 
Gas Revenues
Gas Volumes
(millions of USD)
(Therms)
 
2023
2022
2023
2022
Residential
$
 
537
$
 
614
 
414
 
421
Commercial
 
315
 
354
 
839
 
836
Industrial
(1)
 
69
 
64
 
1,615
 
1,429
Other
(2)
 
147
 
217
 
266
 
227
Total
(3)
$
 
1,068
$
 
1,249
 
3,134
 
2,913
(1) Industrial gas revenue includes sales to power generation customers.
(2) Other gas revenue includes off-system sales to other utilities and various other items.
(3) Total gas revenue
 
excludes $46 million of finance income from Brunswick Pipeline (2022 – $47 million).
Regulated Cost of Natural Gas
PGS and NMGC purchase gas from various suppliers depending on the needs of their customers. In
Florida, gas is delivered to the PGS distribution system through interstate pipelines on which PGS has
firm transportation capacity for delivery by PGS to its customers. NMGC’s natural gas is transported on
major interstate pipelines and NMGC’s intrastate transmission and distribution system for delivery to
customers.
 
In Florida, natural gas service is unbundled for non-residential customers and residential customers who
use more than 1,999 therms annually and elect the option. In New Mexico, NMGC is required, if
requested, to provide transportation-only services for all customer classes. The commodity portion of
bundled sales is included in operating revenues, at the cost of the gas on a pass-through basis, therefore
no net earnings effect when a customer shifts to transportation-only sales.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Exhibit 99.2
27
Annual gas sales by type are summarized in the following table:
Gas Volumes by Type
 
(millions of Therms)
2023
2022
Transportation
 
2,461
 
2,206
System supply
 
673
 
707
Total
 
3,134
 
2,913
Regulatory Environments
PGS is regulated by the FPSC. The FPSC sets rates at a level that allows utilities such as PGS to collect
total revenues or revenue requirements equal to their cost of providing service, plus an appropriate return
on invested capital.
NMGC is subject to regulation by the NMPRC. The NMPRC sets rates at a level that allows NMGC to
collect total revenues equal to its cost of providing service, plus an appropriate return on invested capital.
 
For further information on PGS and NMGC’s regulatory environment and recovery mechanisms, refer to
note 6 in the consolidated financial statements.
Other Electric Utilities
.
Three months ended
Year ended
For the
December 31
December 31
millions of USD (except as indicated)
2023
2022
2023
2022
Operating revenues – regulated electric
$
 
104
$
 
98
$
 
390
$
 
398
Regulated fuel for generation and purchased power
$
 
57
$
 
54
$
 
204
$
 
223
Contribution to consolidated adjusted net income
$
 
3
$
 
7
$
 
26
$
 
23
Contribution to consolidated adjusted net income – CAD
$
 
4
$
 
8
$
 
35
$
 
29
GBPC Impairment charge
$
 
-
 
$
 
54
$
 
-
 
$
 
54
Equity securities MTM gain (loss)
$
 
2
$
 
1
$
 
2
$
 
(4)
Contribution to consolidated net income (loss)
$
 
5
$
 
(46)
$
 
28
$
 
(35)
Contribution to consolidated net income (loss) – CAD
$
 
6
$
 
(62)
$
 
37
$
 
(48)
Electric sales volumes (GWh)
 
323
 
301
 
1,260
 
1,239
Electric production volumes (GWh)
 
345
 
325
 
1,362
 
1,340
Average fuel cost in dollars per MWh
$
 
165
$
 
161
$
 
150
$
 
166
On March 31, 2022, Emera completed the sale of its 51.9 per cent interest in Dominica Electricity
Services Ltd. (“Domlec”) for proceeds which approximated carrying value. The sale did not have a
material impact on earnings.
The impact of the change in the FX rate on CAD earnings for the three months and year ended
December 31, 2023 was minimal.
Other Electric Utilities' contribution to consolidated adjusted net income is summarized in the following
table:
Three months ended
 
Year ended
For the
December 31
December 31
millions of USD
2023
2022
2023
2022
BLPC
$
 
4
$
 
5
$
 
18
$
 
11
GBPC
 
-
 
 
1
 
11
 
10
Other
 
(1)
 
1
 
(3)
 
2
Contribution to consolidated adjusted net income
 
$
 
3
$
 
7
$
 
26
$
 
23
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Exhibit 99.2
28
Net Income
Highlights of the net income changes are summarized in the following table:
For the
Three months ended
Year ended
millions of USD
December 31
December 31
Contribution to consolidated net income – 2022
$
 
(46)
$
 
(35)
Increased operating revenues quarter-over-quarter due to higher fuel
revenue at BLPC and GBPC as a result of higher fuel prices and higher
sales volumes at BLPC. Year-over-year decreased due to lower fuel
revenue at BLPC reflecting lower fuel prices, and the sale of Domlec in
Q1 2022, partially offset by interim rates at BLPC and increased sales
volumes at BLPC and GBPC
 
6
 
(8)
Increased fuel for generation and purchased power quarter-over-
quarter due to higher fuel costs at BLPC and GBPC. Decreased year-
over-year due to lower fuel prices and change in generation mix at
BLPC
 
(3)
 
19
GBPC impairment charge in 2022
 
54
 
54
Other
 
(6)
 
(2)
Contribution to consolidated net income – 2023
$
 
5
$
 
28
Regulatory Environments
BLPC is regulated by the FTC. Rates are set to recover prudently incurred costs of providing electricity
service to customers plus an appropriate return on capital invested.
 
GBPC is regulated by the GBPA. Rates are set to recover prudently incurred costs of providing electricity
service to customers plus an appropriate return on rate base.
 
For further details on BLPC and GBPC’s regulatory environments and recovery mechanisms, refer to note
6 in the consolidated financial statements.
Other
Three months ended
Year ended
For the
December 31
December 31
millions of dollars
2023
2022
2023
2022
Marketing and trading margin
(1) (2)
$
 
35
$
 
72
$
 
96
$
 
143
Other non-regulated operating revenue
 
5
 
3
 
27
 
16
Total operating revenues – non-regulated
$
 
40
$
 
75
$
 
123
$
 
159
Contribution to consolidated adjusted net income (loss)
$
 
(71)
$
 
(1)
$
 
(314)
$
 
(218)
MTM gain, after-tax
(3)
 
112
 
304
 
167
 
179
Contribution to consolidated net income (loss)
$
 
41
$
 
303
$
 
(147)
$
 
(39)
(1) Marketing and trading margin represents EES's purchases and sales of natural gas and electricity,
 
pipeline and storage capacity
costs and energy asset management services’ revenues.
(2) Marketing and trading margin excludes a MTM gain, pre-tax of $131 million in Q4 2023 (2022 – $430 million gain) and a gain
 
of
$216 million for the year ended December 31, 2023 (2022 – $281 million gain).
 
(3) Net of income tax expense of $44 million for the three months ended December 31, 2023 (2022 – $124 million expense)
 
and $68
million expense for the year ended December 31, 2023 (2022 – $73 million expense).
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Exhibit 99.2
29
Other's contribution to consolidated adjusted net income is summarized in the following table:
Three months ended
 
Year ended
For the
December 31
December 31
millions of dollars
2023
2022
2023
2022
Emera Energy:
 
EES
$
 
19
$
 
40
$
 
46
$
 
68
 
Other
 
6
 
1
 
18
 
2
Corporate – see breakdown of adjusted contribution below
 
(91)
 
(37)
 
(356)
 
(267)
Block Energy LLC
(1)
 
(4)
 
(5)
 
(18)
 
(18)
Other
 
(1)
 
-
 
 
(4)
 
(3)
Contribution to consolidated adjusted net income (loss)
$
 
(71)
$
 
(1)
$
 
(314)
$
 
(218)
(1) Previously Emera Technologies
 
LLC
Net Income
Highlights of the net income changes are summarized in the following table:
For the
Three months ended
 
Year ended
millions of dollars
December 31
December 31
Contribution to consolidated net income (loss) – 2022
$
 
303
$
 
(39)
Decreased marketing and trading margin quarter-over-quarter primarily
due to weather driven market conditions in Q4 2022 that increased
pricing and volatility. Year
 
-over-year decrease reflects less favourable
market conditions, specifically lower natural gas prices and volatility
and higher cost commitments for gas transportation in 2023 compared
to 2022
 
(37)
 
(47)
Decreased OM&G, pre-tax, primarily due to the timing of long-term
compensation and related hedges
 
12
 
10
Increased interest expense, pre-tax, due to increased interest rates
and increased total debt
 
(8)
 
(51)
Increased income tax recovery primarily due to increased losses before
provision for income taxes and the recognition of investment tax credits
related to Bear Swamp facility upgrades, partially offset by the impact
of effective state tax rates
 
7
 
26
TGH award in 2022, after tax and legal costs
 
(45)
 
(45)
Decreased MTM gain, after-tax, quarter-over-quarter due to
unfavourable changes in existing positions, partially offset by higher
amortization of gas transportation assets in 2022 at EES. Decreased
MTM gain after-tax, year-over-year primarily due to higher amortization
of gas transportation assets partially offset by favourable changes in
existing positions at EES and gains on Corporate FX hedges
 
(194)
 
(12)
Other
 
 
3
 
11
Contribution to consolidated net income (loss) – 2023
$
 
41
$
 
(147)
Exhibit 99.2
30
Emera Energy
 
EES derives revenue and earnings from wholesale marketing and trading of natural gas and electricity
within the Company’s risk tolerances, including those related to value-at-risk (“VaR”) and credit exposure.
EES purchases and sells physical natural gas and electricity, the related transportation and transmission
capacity rights, and provides energy asset management services. The primary market area for the natural
gas and power marketing and trading business is northeastern North America, including the Marcellus
and Utica shale supply areas. EES also participates in the Florida, United States Gulf Coast and
Midwest/Central Canadian natural gas markets. Its counterparties include electric and gas utilities, natural
gas producers, electricity generators and other marketing and trading entities. EES operates in a
competitive environment, and the business relies on knowledge of the region’s energy markets,
understanding of pipeline and transmission infrastructure, a network of counterparty relationships and a
focus on customer service. EES manages its commodity risk by limiting open positions, utilizing financial
products to hedge purchases and sales, and investing in transportation capacity rights to enable
movement across its portfolio.
EES’ contribution to consolidated adjusted net income was $19 million in Q4 2023, compared to $40
million in Q4 2022; and $46 million ($33 million USD) for the year ended December 31, 2023, compared
to $68 million ($50 million USD) for the same period in 2022. The 2023 and 2022 EES contribution to
consolidated adjusted net income was above the expected EES annual adjusted net income guidance
range of $15 to $30 million USD. Market conditions in 2022 were very favourable, due to high natural gas
pricing and volatility, which reflected weather patterns and geopolitical conditions.
MTM Adjustments
Emera Energy’s “Marketing and trading margin”, “Non-regulated fuel for generation and purchased
power”, “Income from equity investments” and “Income tax expense (recovery)” are affected by MTM
adjustments. Management believes excluding the effect of MTM valuations, and changes thereto, from
income until settlement better matches the financial effect of these contracts with the underlying cash
flows. Variance explanations of the MTM changes for this quarter and for the year are explained in the
table below.
 
Emera Energy has a number of asset management agreements (“AMA”) with counterparties, including
local gas distribution utilities, power utilities and natural gas producers in North America. The AMAs
involve Emera Energy buying or selling gas for a specific term, and the corresponding release of the
counterparties’ gas transportation/storage capacity to Emera Energy. MTM adjustments on these AMAs
arise on the price differential between the point where gas is sourced and where it is delivered. At
inception, the MTM adjustment is offset fully by the value of the corresponding gas transportation asset,
which is amortized over the term of the AMA contract.
 
Subsequent changes in gas price differentials, to the extent they are not offset by the accounting
amortization of the gas transportation asset, will result in MTM gains or losses recorded in income. MTM
adjustments may be substantial during the term of the contract, especially in the winter months of a
contract when delivered volumes and market pricing are usually at peak levels. As a contract is realized,
and volumes reduce, MTM volatility is expected to decrease. Ultimately, the gas transportation asset and
the MTM adjustment reduce to zero at the end of the contract term. As the business grows, and AMA
volumes increase, MTM volatility resulting in gains and losses may also increase.
Emera Corporate has FX forwards to manage the cash flow risk of forecasted USD cash inflows.
Fluctuations in the FX rate result in MTM gains or losses are recorded in “Other income, net” on the
Consolidated Statements of Income.
 
 
 
 
 
 
 
 
 
 
 
 
Exhibit 99.2
31
Corporate
Corporate's adjusted loss is summarized in the following table:
 
Three months ended
 
Year ended
For the
December 31
December 31
millions of dollars
2023
2022
2023
2022
Operating expenses
 
(1)
 
$
 
7
$
 
20
$
 
73
$
 
83
Interest expense
 
88
 
79
 
329
 
278
Income tax recovery
 
 
(25)
 
(35)
 
(111)
 
(109)
Preferred dividends
 
18
 
16
 
66
 
63
TGH award, after tax and legal costs
 
-
 
 
(45)
 
-
 
 
(45)
Other
 
(2)(3)
 
3
 
2
 
(1)
 
(3)
Corporate adjusted net loss
 
(4)
$
 
(91)
$
 
(37)
$
 
(356)
$
 
(267)
(1) Operating expenses include OM&G and depreciation.
 
(2) Other includes realized FX gains and losses on FX hedges entered into to hedge USD denominated operating unit earnings
exposure.
 
(3) Includes a realized net loss, pre-tax of $4 million ($3 million after-tax) for the three months ended December 31, 2023
 
(2022 – $5
million net loss, pre-tax and $4 million loss, after-tax) and a $11
 
million net loss, pre-tax ($8 million after-tax) for the year ended
December 31, 2023 (2022 – $6 million net loss, pre-tax and $5 million loss after-tax) on FX hedges, as discussed
 
above.
(4) Excludes a MTM gain, after-tax of $15 million for the three months ended December 31, 2023 (2022 – $9 million gain, after-tax)
and a MTM gain, after-tax of $20 million for the year ended December 31, 2023 (2022 – $12 million loss, after-tax).
LIQUIDITY AND CAPITAL
 
RESOURCES
The Company generates internally sourced cash from its various regulated and non-regulated energy
investments. Utility customer bases are diversified by both sales volumes and revenues among customer
classes. Emera’s non-regulated businesses provide diverse revenue streams and counterparties to the
business. Circumstances that could affect the Company’s ability to generate cash include changes to
global macro-economic conditions, downturns in markets served by Emera, impact of fuel commodity
price changes on collateral requirements and timely recoveries of fuel costs from customers, the loss of
one or more large customers, regulatory decisions affecting customer rates and the recovery of regulatory
assets, and changes in environmental legislation. Emera’s subsidiaries are generally in a financial
position to contribute cash dividends to Emera provided they do not breach their debt covenants, where
applicable, after giving effect to the dividend payment, and maintain their credit metrics.
Emera’s future liquidity and capital needs will be predominately for working capital requirements, ongoing
rate base investment, business acquisitions, greenfield development, dividends and debt servicing.
Emera has an approximate $9 billion capital investment plan over the 2024 through 2026 period with
approximately $2 billion of additional potential capital investments over the same period. Capital
investments at Emera’s regulated utilities are subject to regulatory approval.
Emera plans to use cash from operations, debt raised at the utilities, equity, and select asset sales to
support normal operations, repayment of existing debt, and capital requirements. Debt raised at certain of
the Company’s utilities is subject to applicable regulatory approvals. Generally, equity requirements in
support of the Company’s capital investment plan are expected to be funded through issuance of
preferred equity and issuance of common equity through Emera’s DRIP and ATM programs.
 
Emera has credit facilities with varying maturities that cumulatively provide $5.3 billion of credit, with
approximately $2.3 billion undrawn and available at December 31, 2023. The Company was holding a
cash balance of $588 million at December 31, 2023. For further discussion, refer to the “Debt
Management” section below. For additional information regarding the credit facilities, refer to notes 23
and 25 in the consolidated financial statements.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Exhibit 99.2
32
Consolidated Cash Flow Highlights
Significant changes in the Consolidated Statements of Cash Flows between the years ended December
31, 2023 and 2022 include:
millions of dollars
2023
2022
$ Change
Cash, cash equivalents and restricted cash, beginning of period
$
 
332
$
 
417
$
 
(85)
Provided by (used in):
 
Operating cash flow before changes in working capital
 
2,336
 
1,147
 
1,189
 
Change in working capital
 
(95)
 
(234)
 
139
Operating activities
$
 
2,241
$
 
913
$
 
1,328
Investing activities
 
(2,917)
 
(2,569)
 
(348)
Financing activities
 
939
 
1,555
 
(616)
Effect of exchange rate changes on cash, cash equivalents and restricted cash
 
(7)
 
16
 
(23)
Cash, cash equivalents, and restricted cash, end of period
$
 
588
$
 
332
$
 
256
Cash Flow from Operating Activities
Net cash provided by operating activities increased
$1,328 million to $2,241 million for the year ended
December 31, 2023, compared to $913 million in 2022.
Cash from operations before changes in working capital increased
$1,189 million for the year ended
December 31, 2023. This increase was due to higher fuel clause recoveries and favourable changes in
the storm reserve balance at TEC, decreased fuel for generation and purchased power expense at NSPI
driven by the decreased Nova Scotia Cap-and-Trade Program provision and a distribution received from
the LIL partnership. This was partially offset by a decrease in regulatory liabilities due to 2022 gas hedge
settlements at NMGC, and receipt of the TGH award in 2022.
Changes in working capital increased operating cash flows by $139 million for the year ended December
31, 2023. This increase was due to favourable changes in accounts receivable at NMGC due to receipt of
its 2022 gas hedge settlement, favourable changes in cash collateral positions at Emera Energy,
favourable changes in natural gas inventory at EES in 2023, and the required prepayment of income
taxes and related interest in 2022 at NSPI. These increases were offset by the timing of accounts payable
payments at NSPI, TEC and NMGC, unfavourable changes in cash collateral positions at NSPI, and
decreased accrual for the Nova Scotia Cap-and-Trade emissions compliance charges at NSPI.
Cash Flow used in Investing Activities
Net cash used in investing activities increased $348 million to $2,917 million for the year ended
December 31, 2023, compared to $2,569 million in 2022. The increase was due to higher capital
investment in 2023.
Capital expenditures for the year ended December 31, 2023, including AFUDC, were $2,976 million
compared to $2,646 million in 2022. Details of 2023 capital spending by segment are shown below:
 
 
$1,771 million – Florida Electric Utility (2022 – $1,481 million);
 
$461 million – Canadian Electric Utilities (2022 – $518 million);
 
$673 million – Gas Utilities and Infrastructure (2022 – $578 million);
 
 
$63 million – Other Electric Utilities (2022 – $63 million); and
 
$8 million – Other (2022 – $6 million).
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Exhibit 99.2
33
Cash Flow from Financing Activities
Net cash provided by financing activities decreased $616 million to $939 million for the year ended
December 31, 2023, compared to $1,555 million in 2022. This decrease was due to lower proceeds from
long-term debt at TEC, higher repayment of short-term debt at TEC, lower proceeds from short-term debt
at TECO Finance and Emera, and higher repayments of committed credit facilities at NSPI. This was
partially offset by proceeds from long-term debt at PGS and NSPI, retirement of long-term debt at TEC in
2022, and higher issuance of common stock.
Working Capital
As at December 31, 2023, Emera’s cash and cash equivalents were $567 million (2022 – $310 million)
and Emera’s investment in non-cash working capital was $831 million (2022 – $1,173 million). Of the
cash and cash equivalents held at December 31, 2023, $482 million was held by Emera’s foreign
subsidiaries (2022 – $250 million). A portion of these funds are invested in countries that have certain
exchange controls, approvals, and processes for repatriation. Such funds are available to fund local
operating and capital requirements unless repatriated.
 
Contractual Obligations
As at December 31, 2023, contractual commitments for each of the next five years and in aggregate
thereafter consisted of the following:
millions of dollars
2024
2025
2026
2027
2028
Thereafter
Total
Long-term debt principal
$
 
1,670
$
 
264
$
 
3,047
$
 
666
$
 
525
$
 
12,318
$
 
18,490
Interest payment obligations
(1)
 
836
 
807
 
719
 
626
 
587
 
7,438
 
11,013
Transportation
(2)
 
696
 
495
 
405
 
388
 
338
 
2,597
 
4,919
Purchased power
(3)
 
274
 
249
 
263
 
312
 
312
 
3,435
 
4,845
Fuel, gas supply and storage
 
556
 
215
 
62
 
-
 
 
5
 
-
 
 
838
Capital projects
 
778
 
111
 
70
 
1
 
-
 
 
-
 
 
960
Asset retirement obligations
 
10
 
2
 
1
 
1
 
2
 
407
 
423
Pension and post-retirement
obligations
(4)
 
28
 
29
 
38
 
47
 
32
 
155
 
329
Equity investment commitments
(5)
 
240
 
-
 
 
-
 
 
-
 
 
-
 
 
-
 
 
240
Other
 
154
 
147
 
56
 
46
 
35
 
221
 
659
$
 
5,242
$
 
2,319
$
 
4,661
$
 
2,087
$
 
1,836
$
 
26,571
$
 
42,716
(1) Future interest payments are calculated based on the assumption that all debt is outstanding until maturity.
 
For debt instruments
with variable rates, interest is calculated for all future periods using the rates in effect at December 31,
 
2023, including any expected
required payment under associated swap agreements.
(2) Purchasing commitments for transportation of fuel and transportation capacity on various pipelines.
 
Includes a commitment of
$134 million related to a gas transportation contract between PGS and SeaCoast through 2040.
(3) Annual requirement to purchase electricity production from IPPs or other utilities over varying contract lengths.
(4) The estimated contractual obligation is calculated as the current legislatively required contributions to the registered
 
funded
pension plans (excluding the possibility of wind-up), plus the estimated costs of further benefit accruals contracted under
 
NSPI's
Collective Bargaining Agreement and estimated benefit payments related to other unfunded benefit plans.
(5) Emera has a commitment to make equity contributions to the LIL related to an investment true up in 2024 and sustaining
 
capital
contributions over the life of the partnership.
 
The commercial agreements between Emera and Nalcor require true ups to finalize the
respective investment obligations of the parties in relation the Maritime Link and LIL which is expected to be approximately
 
$240
million in 2024. In addition, Emera has future commitments to provide sustaining capital to the LIL for routine capital and major
maintenance.
NSPI has a contractual obligation to pay NSPML for use of the Maritime Link over approximately 38 years
from its January 15, 2018 in-service date. In February 2022, the UARB issued its decision and Board
Order approving NSPML’s requested rate base of approximately $1.8 billion. In December 2023, the
UARB approved collection of up to $164 million from NSPI for recovery of Maritime Link costs in 2024.
The timing and amounts payable to NSPML for the remainder of the 38-year commitment period are
subject to UARB approval.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Exhibit 99.2
34
Construction of the LIL is complete and the Newfoundland Electrical System Operator confirmed the
asset to be operating suitably to support reliable system operation and full functionality at 700MW, which
was validated by the Government of Canada’s Independent Engineer issuing its Commissioning
Certificate on April 13, 2023.
Emera has committed to obtain certain transmission rights for Nalcor, if requested, to enable it to transmit
energy which is not otherwise used in Newfoundland and Labrador or Nova Scotia. Nalcor has the right to
transmit this energy from Nova Scotia to New England energy markets effective August 15, 2021 and
continuing for 50 years. As transmission rights are contracted, the obligations are included within “Other”
in the above table.
Forecasted Consolidated Capital Investments
The 2024 forecasted consolidated capital investments are as follows:
millions of dollars
Florida
Electric
Utility
Canadian
Electric
Utilities
Gas Utilities
and
Infrastructure
Other
Electric
Utilities
Other
Total
Generation
$
 
266
$
 
143
$
 
-
 
$
 
30
$
 
-
 
$
 
439
New renewable generation
 
280
 
-
 
 
-
 
 
-
 
 
-
 
 
280
Electric transmission
 
119
 
88
 
-
 
 
-
 
 
-
 
 
207
Electric distribution
 
496
 
142
 
-
 
 
58
 
-
 
 
696
Gas transmission and distribution
 
-
 
 
-
 
 
566
 
-
 
 
-
 
 
566
Facilities, equipment, vehicles, and other
 
567
 
63
 
51
 
17
 
4
 
702
$
 
1,728
$
 
436
$
 
617
$
 
105
$
 
4
$
 
2,890
Debt Management
In addition to funds generated from operations, Emera and its subsidiaries have, in aggregate, access to
committed syndicated revolving and non-revolving bank lines of credit in either CAD or USD per the table
below.
 
Undrawn
Credit
and
millions of Canadian dollars (unless otherwise indicated)
Maturity
Facilities
Utilized
Available
Emera – Unsecured committed revolving credit facility
June 2027
$
 
900
$
 
265
$
 
635
TEC (in USD) – Unsecured committed revolving credit facility
December 2026
 
800
 
707
 
93
NSPI – Unsecured committed revolving credit facility
December 2027
 
800
 
332
 
468
Emera – Unsecured non-revolving facility
 
December 2024
 
400
 
400
 
-
 
Emera – Unsecured non-revolving facility
 
February 2024
 
400
 
200
 
200
Emera – Unsecured non-revolving facility
August 2024
 
400
 
400
 
-
 
TECO Finance (in USD) – Unsecured committed revolving credit
facility
December 2026
 
400
 
185
 
215
NSPI – Unsecured non-revolving facility
July 2024
 
400
 
400
 
-
 
PGS (in USD) – Unsecured revolving facility
December 2028
 
250
 
55
 
195
TEC (in USD) - Unsecured revolving facility
February 2024
 
200
 
-
 
 
200
TEC (in USD) - Unsecured revolving facility
April 2024
 
200
 
-
 
 
200
NMGC (in USD) – Unsecured revolving credit facility
December 2026
 
125
 
21
 
104
NMGC (in USD) – Unsecured non-revolving facility
March 2024
 
23
 
23
 
-
 
Other (in USD) – Unsecured committed revolving credit facilities
Various
 
21
 
6
 
15
 
 
 
 
 
 
 
Exhibit 99.2
35
Emera and its subsidiaries have certain financial and other covenants associated with their debt and
credit facilities. Covenants are tested regularly, and the Company is in compliance with covenant
requirements as at December 31, 2023.
 
Emera’s significant covenant is listed below:
As at
Financial Covenant
Requirement
December 31, 2023
Emera
Syndicated credit facilities
Debt to capital ratio
Less than or equal to 0.70 to 1
0.57 : 1
Recent significant financing activity for Emera and its subsidiaries are discussed below by segment:
Florida Electric Utilities
On January 30, 2024, TEC issued $500 million USD of senior unsecured bonds that bear interest at 4.90
per cent with a maturity date of March 1, 2029. Proceeds from the issuance were primarily used for the
repayment of short-term borrowings outstanding under the 5-year credit facility. Therefore, $497 million
USD of short-term borrowings that was repaid was classified as long-term debt at December 31, 2023.
On November 24, 2023, TEC repaid its $400 million USD unsecured non-revolving facility, which expired
on December 13, 2023.
On April 3, 2023, TEC entered into a 364-day, $200 million USD senior unsecured revolving credit facility
which matures on April 1, 2024. The credit agreement contains customary representations and
warranties, events of default and financial and other covenants, and bears interest at a variable interest
rate, based on either the term secured overnight financing rate (“SOFR”), Wells Fargo’s prime rate, the
federal funds rate or the one-month SOFR, plus a margin. Proceeds from this facility will be used for
general corporate purposes.
On March 1, 2023, TEC entered into a 364-day, $200 million USD senior unsecured revolving credit
facility which matures on February 28, 2024. The credit facility contains customary representations and
warranties, events of default and financial and other covenants, and bears interest at a variable interest
rate, based on either the term SOFR, the Bank of Nova Scotia’s prime rate, the federal funds rate or the
one-month SOFR, plus a margin. Proceeds from this facility will be used for general corporate purposes.
 
Canadian Electric Utilities
On March 24, 2023, NSPI issued $500 million in unsecured notes. The issuance included $300 million
unsecured notes that bear interest at 4.95 per cent with a maturity date of November 15, 2032, and $200
million unsecured notes that bear interest at 5.36 per cent with a maturity date of March 24, 2053.
Proceeds from these issuances were added to the general funds of the Company and applied primarily to
refinance existing indebtedness, to finance capital investment and for general corporate purposes.
 
Gas Utilities and Infrastructure
On December 19, 2023, PGS completed an issuance of $925 million USD in senior notes. The issuance
included $350 million USD senior notes that bear interest at 5.42 per cent with a maturity date of
December 19, 2028, $350 million USD senior notes that bear interest at 5.63 per cent with a maturity date
of December 19, 2033 and $225 million USD senior notes that bear interest at 5.94 per cent with a
maturity date of December 19, 2053. Proceeds from these issuances were used to settle intercompany
loan agreements with TEC for the assets and liabilities transferred to PGS as part of the reorganization of
the gas division of Tampa Electric, effective
 
on January 1, 2023.
 
 
 
 
 
 
 
 
 
 
 
 
Exhibit 99.2
36
On December 1, 2023, PGS entered into a $250 million USD senior unsecured revolving credit facility
with a group of banks, maturing on December 1, 2028. PGS has the ability to request the lenders to
increase their commitments under the credit facility by up to $100 million USD in the aggregate subject to
agreement from participating lenders. The credit agreement contains customary representations and
warranties, events of default and financial and other covenants, and bears interest at Bankers’
Acceptances or prime rate advances, plus a margin. Proceeds from these facilities will be used for
general corporate purposes.
On October 19, 2023, NMGC issued $100 million USD in senior unsecured notes that bear interest at
6.36 per cent with a maturity date of October 19, 2033. Proceeds from the issuance were used to repay
short-term borrowings.
Other Electric Utilities
 
On May 24, 2023, GBPC issued a $28 million USD non-revolving term loan that bears interest at 4.00 per
cent with a maturity date of May 24, 2028. Proceeds from this issuance were used to repay GBPC’s $28
million USD bond, which matured in May 2023.
Other
 
On December 16, 2023, Emera amended its $400 million unsecured non-revolving facility to extend the
maturity date from December 16, 2023 to December 16, 2024. There were no other changes in
commercial terms from the prior agreement.
On August 18, 2023, Emera entered into a $400 million non-revolving term facility which matures on
February 19, 2024. The credit agreement contains customary representations and warranties, events of
default and financial and other covenants, and bears interest at Bankers’ Acceptances or prime rate
advances, plus a margin. Proceeds from this facility will be used for general corporate purposes. On
February 16, 2024, Emera extended the term of this agreement to a maturity date of February 19, 2025.
On June 30, 2023, Emera amended its $400 million unsecured non-revolving facility to extend the
maturity date from August 2, 2023 to August 2, 2024. There were no other changes in commercial terms
from the prior agreement.
 
On May 2, 2023, Emera issued $500 million in senior unsecured notes that bear interest at 4.84 per cent
with a maturity date of May 2, 2030. The proceeds were used to repay Emera’s $500 million unsecured
fixed rate notes, which matured in June 2023.
 
Credit Ratings
Emera and its subsidiaries have been assigned the following senior unsecured debt ratings:
Fitch
S&P
Moody's
DBRS
Emera Inc.
BBB (Negative)
BBB- (Negative)
Baa3 (Negative)
N/A
TEC
A (Negative)
BBB+ (Negative)
A3 (Negative)
N/A
PGS (1)
A (Negative)
N/A
N/A
N/A
NMGC
BBB+ (Negative)
N/A
N/A
N/A
NSPI
N/A
BBB- (Negative)
N/A
BBB (high)(stable)
(1) On November 10, 2023 Fitch Ratings ("Fitch") assigned first-time long-term issuer default rating of 'A-' to
 
PGS and an instrument
rating of 'A' for its private placements of senior unsecured bonds.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Exhibit 99.2
37
Guaranteed Debt
As of December 31, 2023, the Company had $2.75 billion USD (2022 – $2.75 billion USD) senior
unsecured notes ("US Notes”) outstanding.
 
The US Notes are fully and unconditionally guaranteed, on a joint and several basis, by Emera and
Emera US Holdings Inc. (in such capacity, the “Guarantor Subsidiaries”). Emera owns, directly or
indirectly, all of the limited and general partnership interests in Emera US Finance LP.
 
Other subsidiaries
of the Company do not guarantee the US Notes (such subsidiaries are referred to as the "Non-Guarantor
Subsidiaries"); however, Emera has unrestricted access to the assets of consolidated entities.
 
In compliance with Rule 13-01 of Regulation S-X, the Company is including summarized financial
information for Emera, Emera US Holdings Inc., and Emera US Finance LP (together, the "Obligor
Group"), on a combined basis after transactions and balances between the combined entities have been
eliminated. Investments in and equity earnings of the Non-Guarantor Subsidiaries have been excluded
from the summarized financial information.
 
The Obligor Group was not determined using geographic, service line or other similar criteria and, as a
result, the summarized financial information includes portions of Emera’s domestic and international
operations. Accordingly, this basis of presentation is not intended to present Emera’s financial condition
or results of operations for any purpose other than to comply with the specific requirements for guarantor
reporting.
Summarized Statement of Income (Loss)
 
The Company recognized income related to guaranteed debt under the following categories:
For the
Year ended December 31
millions of dollars
2023
2022
Loss from operations
$
 
(62)
$
 
(73)
Net gains (losses)
(1)
$
 
349
$
 
(131)
(1) Includes $750 million (2022 – $262 million) in interest and dividend income, net, from non-guarantor subsidiaries.
Summarized Balance Sheet
The Company has the following categories on the balance sheet related to guaranteed debt:
As at
December 31
millions of dollars
2023
2022
Current assets
 
(1)
$
 
223
$
 
172
Goodwill
 
5,871
 
6,012
Other assets
(2)
 
6,243
 
6,402
Total assets
 
(3)
$
 
12,337
$
 
12,586
Current liabilities
(4)
$
 
1,451
$
 
1,903
Long-term liabilities
(5)
 
6,815
 
6,431
Total liabilities
$
 
8,266
$
 
8,334
(1) Includes $179 million (2022 – $144 million) in amounts due from non-guarantor subsidiaries.
(2) Includes $5,941 million (2022 – $6,058 million) in amounts due from non-guarantor subsidiaries.
(3) Excludes investments in non-guarantor subsidiaries. Consolidated Emera total assets are $39,480 million
 
(2022 – $39,742 million).
(4) Includes $411 million (2022 – $392 million) due to non-guarantor
 
subsidiaries.
(5) Includes $619 million (2022 – $769 million) due to non-guarantor subsidiaries.
 
 
 
 
 
 
 
 
 
Exhibit 99.2
38
Outstanding Stock Data
Common Stock
millions of
millions of
Issued and outstanding:
shares
dollars
Balance, December 31, 2022
269.95
$
7,762
Issuance of common stock under ATM program
(1)
8.29
397
Issued under the DRIP,
 
net of discounts
5.26
272
Senior management stock options exercised and Employee Share Purchase Plan
0.62
31
Balance, December 31, 2023
284.12
$
8,462
(1) For the year ended December 31,2023, 8,287,037 common shares were issued under Emera's ATM
 
program at an average
price of $48.27 per share for gross proceeds of $400 million ($397 million net of after-tax issuance costs). As at December
31,2023, an aggregate gross sales limit of $200 million remained available for issuance under the ATM
 
program.
As at February 20, 2024, the amount of issued and outstanding common shares was 285.8 million.
If all outstanding stock options were converted as at February 20, 2024, an additional 3.1 million common
shares would be issued and outstanding.
ATM Equity Program
On October 3, 2023, Emera filed a short form base shelf prospectus, primarily in support of the renewal of
its ATM Program in Q4 2023 that will allow the Company to issue up to $600 million of common shares
from treasury to the public from time to time, at the Company’s discretion, at the prevailing market price.
This ATM Program is expected to remain in effect until November 4, 2025.
Preferred Stock
 
As at February 20, 2024, Emera had the following preferred shares issued and outstanding: Series A –
4.9 million; Series B – 1.1 million; Series C – 10.0 million; Series E – 5.0 million; Series F – 8.0 million;
Series H – 12.0 million; Series J – 8.0 million, and Series L – 9.0 million. Emera’s preferred shares do not
have voting rights unless the Company fails to pay, in aggregate, eight quarterly dividends.
On July 6, 2023, Emera announced it would not redeem the 10 million outstanding Cumulative Rate
Reset Preferred Shares, Series C (“Series C Shares”) or the 12 million outstanding Cumulative Minimum
Rate Reset First Preferred Shares, Series H (“Series H Shares”) on August 15, 2023.
 
On August 4, 2023, Emera announced after having taken into account all conversion notices received
from holders, no Series C Shares were converted into Cumulative Floating Rate First Preferred Shares,
Series D Shares and no Series H shares were converted into Cumulative Floating Rate First Preferred
Shares, Series I shares. The holders of the Series C Shares are entitled to receive a dividend of 6.434
per cent per annum on the Series C Shares during the five-year period commencing on August 15, 2023,
and ending on (and inclusive of) August 14, 2028 ($0.40213 per Series C Share per quarter). The holders
of the Series H Shares are entitled to receive a dividend of 6.324 per cent per annum on the Series H
Shares during the five-year period commencing on August 15, 2023, and ending on (and inclusive of)
August 14, 2028 ($0.39525 per Series H Share per quarter).
PENSION FUNDING
For funding purposes, Emera determines required contributions to its largest defined benefit (“DB”)
pension plans based on smoothed asset values. This reduces volatility in the cash funding requirement
as the impact of investment gains and losses are recognized over a three-year period. Expected cash
flow for DB pension plans is $34 million in 2024 (2023 – $42 million). All pension plan contributions are
tax deductible and will be funded with cash from operations.
 
 
 
 
 
 
 
 
Exhibit 99.2
39
Emera’s DB pension plans employ a long-term strategic approach with respect to asset allocation, real
return and risk. The underlying objective is to earn an appropriate return, given the Company’s goal of
preserving capital with an acceptable level of risk for the pension fund investments.
 
To
 
achieve the overall long-term asset allocation, pension assets are managed by external investment
managers per each pension plan’s investment policy and governance framework. The asset allocation
includes investments in the assets of domestic and global equities, domestic and global bonds and short-
term investments. The Company reviews investment manager performance on a regular basis and
adjusts the plans’ asset mixes as needed in accordance with the pension plans’ investment policy.
Emera’s projected contributions to defined contribution pension plans are $46 million for 2024 (2023 –
$45 million).
 
Defined Benefit Pension Plan Summary
in millions of dollars
Plans by region
TECO Energy
NSPI
Caribbean
 
Total
Assets as at December 31, 2023
$
 
907
$
 
1,381
$
 
10
$
 
2,298
Accounting obligation at December 31, 2023
$
 
896
$
 
1,361
$
 
16
$
 
2,273
Accounting expense (income) during fiscal 2023
$
 
4
$
 
(16)
$
 
1
$
 
(11)
Off-Balance Sheet Arrangements
Defeasance
Upon privatization in 1992, NSPI became responsible for managing a portfolio of defeasance securities
that provide principal and interest streams to match the related defeased debt, which at December 31,
2023 totalled $200 million (2022 – $200 million). The securities are held in trust for an affiliate of the
Province of Nova Scotia. Approximately 66 per cent of the defeasance portfolio consists of investments in
the related debt, eliminating all risk associated with this portion of the portfolio.
Guarantees and Letters of Credit
Emera has guarantees and letters of credit on behalf of third parties outstanding. The following significant
guarantees and letters of credit are not included within the Consolidated Balance Sheets as at December
31, 2023:
TECO Energy has issued a guarantee in connection with SeaCoast’s performance of obligations under a
gas transportation precedent agreement. The guarantee is for a maximum potential amount of $45 million
USD if SeaCoast fails to pay or perform under the contract. The guarantee expires five years after the
gas transportation precedent agreement termination date, which was terminated on January 1, 2022. In
the event TECO Energy’s and Emera’s long-term senior unsecured credit ratings are downgraded below
investment grade by Moody’s or S&P,
 
TECO Energy would be required to provide its counterparty a letter
of credit or cash deposit of $27 million USD.
TECO Energy issued a guarantee in connection with SeaCoast’s performance obligations under a firm
service agreement, which expires December 31, 2055, subject to two extension terms at the option of the
counterparty with a final expiration date of December 31, 2071. The guarantee is for a maximum potential
amount of $13 million USD if SeaCoast fails to pay or perform under the firm service agreement. In the
event that TECO Energy’s long-term senior unsecured credit ratings are downgraded below investment
grade by Moody’s or S&P,
 
TECO Energy would need to provide either a substitute guarantee from an
affiliate with an investment grade credit rating or a letter of credit or cash deposit of $13 million USD.
Emera Inc. has issued a guarantee of $66 million USD relating to outstanding notes of ECI. This
guarantee will automatically terminate on the date upon which the obligations have been repaid in full.
Exhibit 99.2
40
NSPI has issued guarantees on behalf of its subsidiary, NS Power Energy Marketing Incorporated, in the
amount of $104 million USD (2022 – $119 million USD) with terms of varying lengths.
The Company has standby letters of credit and surety bonds in the amount of $103 million USD
(December 31, 2022 – $145 million USD) to third parties that have extended credit to Emera and its
subsidiaries. These letters of credit and surety bonds typically have a one-year term and are renewed
annually as required.
Emera Inc., on behalf of NSPI, has a standby letter of credit to secure obligations under a supplementary
retirement plan. The expiry date of this letter of credit was extended to June 2024. The amount committed
as at December 31, 2023 was $56 million (December 31, 2022 – $63 million).
DIVIDEND PAYOUT
 
RATIO
Emera has provided annual dividend growth guidance of four to five per cent through 2026. The
Company targets a long-term dividend payout ratio of adjusted net income of 70 to 75 per cent and, while
the payout ratio is likely to exceed that target through and beyond the forecast period, it is expected to
return to that range over time. Emera’s common share dividends paid in 2023 were $2.7875 ($0.6900 in
Q1, Q2, and Q3 and $0.7175 in Q4) per common share and $2.6775 ($0.6625 in Q1, Q2, and Q3 and
$0.6900 in Q4) per common share for 2022, representing a dividend payout ratio of 78 per cent in 2023
(2022 – 75 per cent) and a dividend payout ratio of adjusted net income of 94 per cent in 2023 (2022 – 83
per cent).
 
On September 20, 2023, the Board approved an increase in the annual common share dividend rate to
$2.87 from $2.76 per common share. The first quarterly dividend payment at the increased rate was paid
on November 15, 2023.
TRANSACTIONS WITH RELATED
 
PARTIES
In the ordinary course of business, Emera provides energy and other services and enters into
transactions with its subsidiaries, associates and other related companies on terms similar to those
offered to non-related parties. Intercompany balances and intercompany transactions have been
eliminated on consolidation, except for the net profit on certain transactions between non-regulated and
regulated entities in accordance with accounting standards for rate-regulated entities. All material
amounts are under normal interest and credit terms.
 
Significant transactions between Emera and its associated companies are as follows:
 
Transactions between NSPI and NSPML related to the Maritime Link assessment are reported in the
Consolidated Statements of Income. NSPI’s expense is reported in Regulated fuel for generation and
purchased power, totalling $163 million for the year ended December 31, 2023 (2022 – $157 million).
NSPML is accounted for as an equity investment, and therefore corresponding earnings related to
this revenue are reflected in Income from equity investments. For further details, refer to the
“Business Overview and Outlook - Canadian Electric Utilities – ENL” and “Contractual Obligations”
sections.
Natural gas transportation capacity purchases from M&NP are reported in the Consolidated
Statements of Income. Purchases from M&NP reported net in Operating revenues, Non-regulated,
totalled $14 million for the year ended December 31, 2023 (2022
– $9 million).
There were no significant receivables or payables between Emera and its associated companies reported
on Emera’s Consolidated Balance Sheets as at December 31, 2023 and at December 31, 2022.
Exhibit 99.2
41
ENTERPRISE RISK AND RISK MANAGEMENT
Emera has an enterprise-wide risk management process, overseen by its Enterprise Risk Management
Committee (“ERMC”) and monitored by the Board, to ensure an effective, consistent and coherent
approach to risk management. Certain risk management activities for Emera are overseen by the ERMC
to ensure such risks are appropriately identified, assessed, monitored and subject to appropriate controls.
 
The Board has a Risk and Sustainability Committee (“RSC”) with a mandate to assist the Board in
carrying out its risk and sustainability oversight responsibilities. The RSC’s mandate includes oversight of
the Company’s Enterprise Risk Management framework, including the identification, assessment,
monitoring and management of enterprise risks. It also includes oversight of the Company’s approach to
sustainability and its performance relative to its sustainability objectives.
The Company’s financial risk management activities are focused on those areas that most significantly
impact profitability, quality and consistency of income, and cash flow. Emera’s
 
risk management focus
extends to key operational risks including safety and environment, which represent core values of Emera.
In this section, Emera describes the principal risks that management believes could materially affect its
business, revenues, operating income, net income, net assets, liquidity or capital resources. The nature
of risk is such that no list is comprehensive, and other risks may arise or risks not currently considered
material may become material in the future.
Regulatory and Political Risk
The Company’s rate-regulated subsidiaries and certain investments subject to significant influence are
subject to risk of the recovery of costs and investments. Regulatory and political risk can include changes
in regulatory frameworks, shifts in government policy, legislative changes, and regulatory decisions.
As cost-of-service utilities with an obligation to serve customers, Emera’s utilities operate under formal
regulatory frameworks, and must obtain regulatory approval to change or add rates and/or riders. Emera
also holds investments in entities in which it has significant influence, and which are subject to regulatory
and political risk including NSPML, LIL, and M&NP.
 
As a regulated Group II pipeline, the tolls of
Brunswick Pipeline are regulated by the CER on a complaint basis, as opposed to the regulatory approval
process described above. In the absence of a complaint, the CER does not normally undertake a detailed
examination of Brunswick Pipeline’s tolls, which are subject to a firm service agreement, expiring in 2034,
with Repsol Energy North America Canada Partnership.
 
Regulators administer the regulatory frameworks covering material aspects of the utilities’ businesses,
including applying market-based tests to determine the appropriate customer rates and/or riders, the
underlying allowed ROEs, deemed capital structures, capital investment, the terms and conditions for the
provision of service, performance standards, and affiliate transactions. Regulators also review the
prudency of costs and other decisions that impact customer rates and reliability of service and work to
ensure the financial health of the utility for the benefit of customers. Costs and investments can be
recovered upon approval by the respective regulator as an adjustment to rates and/or riders, which
normally require a public hearing process or may be mandated by other governmental bodies.
 
During
public hearing processes, consultants and customer representatives scrutinize the costs, actions and
plans of these rate-regulated companies, and their respective regulators determine whether to allow
recovery and to adjust rates based upon the evidence and any contrary evidence from other parties. In
some circumstances, other government bodies may influence the setting of rates. Regulatory decisions,
legislative changes, and prolonged delays in the recovery of costs or regulatory assets could result in
decreased rate affordability for customers and could materially affect Emera and its utilities.
 
Exhibit 99.2
42
Emera’s utilities generally manage this risk through transparent regulatory disclosure, ongoing
stakeholder and government consultation, and multi-party engagement on aspects such as utility
operations, regulatory audits, rate filings and capital plans. The subsidiaries work to establish
collaborative relationships with regulatory stakeholders, including customer representatives, both through
its approach to filings and additional efforts with technical conferences and, where appropriate, negotiated
settlements.
 
Changes in government and shifts in government policy and legislation can impact the commercial and
regulatory frameworks under which Emera and its subsidiaries operate. This includes initiatives regarding
deregulation or restructuring of the energy industry. Deregulation or restructuring of the energy industry
may result in increased competition and unrecovered costs that could adversely affect the Company’s
operations, net income and cash flows. State and local policies in some United States jurisdictions have
sought to prevent or limit the ability of utilities to provide customers the choice to use natural gas while in
other jurisdictions policies have been adopted to prevent limitations on the use of natural gas. Changes in
applicable state or local laws and regulations, including electrification legislation, could adversely impact
PGS and NMGC.
Emera cannot predict future legislative, policy, or regulatory changes, whether caused by economic,
political or other factors, or its ability to respond in an effective and timely manner or the resulting
compliance costs. Government interference in the regulatory process can undermine regulatory stability,
predictability, and independence, and could have a material adverse effect on the Company.
Global Climate Change Risk
The Company is subject to risks that may arise from the impacts of climate change. There is increasing
public concern about climate change and growing support for reducing carbon dioxide emissions.
Municipal, state, provincial and federal governments have been setting policies and enacting laws and
regulations to deal with climate change impacts in a variety of ways, including decarbonization initiatives
and promotion of cleaner energy and renewable energy generation of electricity. Refer to “Changes in
Environmental Legislation” risk below. Insurance companies have begun to limit their exposure to coal-
fired electricity generation and are evaluating the medium and long-term impacts of climate change which
may result in fewer insurers, more restrictive coverage and increased premiums. Refer to the “Insurance”
section below and “Uninsured Risk”.
Climate change may lead to increased frequency and intensity of events and related impacts such as
hurricanes, ice and other storms, heavy rainfall, cyclones, extreme winds, wildfires, flooding and
droughts. The potential impacts of climate change, such as rising sea levels and larger storm surges from
more intense hurricanes, can combine to produce even greater damage to coastal generation and other
facilities. Climate change is also characterized by rising global temperatures. Increased air temperatures
may bring increased frequency and severity of wildfires within the Company’s service territories. Refer to
“Weather Risk” and “System Operating and Maintenance Risks”.
The Company’s long-term capital investment plan includes significant investment across the portfolio in
renewable and cleaner generation, infrastructure modernization, storm hardening, energy storage and
customer-focused technologies. All these initiatives contribute toward mitigating the potential impacts of
climate change. The Company continues to engage with government, regulators, industry partners and
stakeholders to share information and participate in the development of climate change related policies
and initiatives.
 
Exhibit 99.2
43
Physical Impacts:
The Company is subject to physical risks that arise, or may arise, from global climate change, including
damage to operating assets from more frequent and intense weather events and from wildfires due to
warming air temperatures and increasing drought conditions. Substantially all of the Company’s fossil
fueled generation assets are located at or near coastal sites and, as such, are exposed to the separate
and combined effects of rising sea levels and increasing storm intensity, including storm surges and
flooding. Refer to “Weather Risk” for further information.
These risks are mitigated to an extent through features such as flood walls at certain plants and through
the location of plants on higher ground. Planned investments in under-grounding parts of the electricity
infrastructure contribute to risk mitigation, as does insurance coverage (for assets other than electricity
transmission and distribution assets). In addition, implementation of regulatory mechanisms for recovery
of costs, such as storm reserves and regulatory deferral accounts, help smooth out the recovery of storm
restoration costs over time.
 
Reputation:
Failure to address issues related to climate change could affect Emera’s reputation with stakeholders, its
ability to operate and grow, and the Company’s access to, and cost of, capital. Refer to “Liquidity and
Capital Market Risk”. The Company seeks to mitigate this in part by moving away from higher-carbon
generation in favour of lower-carbon generation and non-emitting renewable generation.
Supply Chain:
Changing carbon-related costs, policy and regulatory changes and shifts in supply and demand factors
could lead to more expensive or more scarce products and services that are required by the Company in
its operations. This could lead to supply shortages, delivery delays and the need to source alternate
products and services. The Company seeks to mitigate these risks through close monitoring of such
developments and adaptive changes to supply chain procurement strategies. Refer to “Supply Chain
Risk” and “Uninsured Risk”.
Insurance:
Given concerns regarding carbon-emitting generation, assets and businesses may, over time, become
difficult (or uneconomic) to insure in commercial insurance markets. In the short term, this may be
mitigated through increased investment in engineered protection or alternative risk financing (such as
funded self-insurance or regulatory structures, including storm reserves). Longer-term mitigation may be
achieved through infrastructure siting decisions and further engineered protections. This risk may also be
mitigated through the continued transition away from high-carbon generation sources to sources with low
or zero carbon dioxide emissions.
Policy:
Government and regulatory initiatives, including greenhouse gas emissions standards, air emissions
standards and generation mix standards, are being proposed and adopted in many jurisdictions in
response to concerns regarding the effects of climate change. In some jurisdictions, government policy
has included timelines for mandated shutdowns of coal generating facilities, percentage of electricity
generation from renewables, carbon pricing, emissions limits and cap and trade mechanisms. Over the
medium and longer terms, this could potentially lead to a significant portion of hydrocarbon infrastructure
assets being subject to additional regulation and limitations in respect of GHG emissions and operations.
 
The Company is subject to climate-related and environmental legislative and regulatory requirements.
Such legislative and regulatory initiatives could adversely affect Emera’s operations and financial
performance. Refer to “Regulatory and Political Risk” and “Changes in Environmental Legislation” risk.
The Company seeks to mitigate these risks through active engagement with governments and regulators
to pursue transition strategies that meet the needs of customers, stakeholders and the Company. This
has included NSPI’s participation in negotiated equivalency agreements in Nova Scotia to provide for an
affordable transition to lower-carbon generation. Equivalency agreements allow NSPI to achieve
compliance with federal GHG emissions regulations by meeting provincial legislative and regulatory
requirements as they are deemed to be equivalent. There is no guarantee that such equivalency
agreements will be renewed or remain in force in the future.
Exhibit 99.2
44
Regulatory:
Depending on the regulatory response to government legislation and regulations, the Company may be
exposed to the risk of reduced recovery through rates in respect of the affected assets. Valuation
impairments could result from such regulatory outcomes. Mitigation efforts in respect of these risks
include active engagement with policy makers and regulators to find mechanisms to avoid such impacts
while being responsive to customers’ and stakeholders’ objectives.
Legal:
The Company could face litigation or regulatory action related to environmental harms from carbon
dioxide emissions or climate change public disclosure issues. The Company addresses these risks
through compliance with all relevant laws, emissions reduction strategies, and public disclosure of climate
change risks.
Water Resources:
For thermal plants requiring cooling water, reduced availability of water resulting from climate change
could adversely impact operations or the costs of operations. The Company seeks ways to reduce and
recycle water as it does in its Polk power plant in Florida, where recovered and treated wastewater is
used in operations to reduce reliance on fresh water supplies in an area where water is not as abundant
as in other markets.
 
The Company operates hydroelectric generation in certain of its markets. Such generation depends on
availability of water and the hydrological profile of water sources. Changes in precipitation patterns, water
temperatures and air temperatures could adversely affect the availability of water and consequently the
amount of electricity that may be produced from such facilities. The Company is reinvesting in the
efficiency of certain hydroelectric generation facilities to increase generation capacity and continues to
monitor changing hydrology patterns. Such issues may also affect the availability of purchased power
from third-party owned hydroelectricity sources.
Weather Risk
The Company is subject to risks that arise or may arise from weather including seasonal variations
impacting energy sales, more frequent and intense weather events, changing air temperatures, wildfires
and extreme weather conditions associated with climate change. Refer to “Global Climate Change Risk”.
Fluctuations in the amount of electricity or natural gas used by customers can vary significantly in
response to seasonal changes in weather and could impact the operations, results of operations, financial
condition, and cash flows of the Company’s utilities. For example, TEC could see lower demand in
summer months if temperatures are cooler than expected. Further, extreme weather conditions such as
hurricanes and other severe weather conditions which may be associated with climate change could
cause these seasonal fluctuations to be more pronounced. In the absence of a regulatory recovery
mechanism for unanticipated costs, such events could influence the Company’s results of operations,
financial conditions or cash flows.
Extreme weather events create a risk of physical damage to the Company’s assets. High winds can
impact structures and cause widespread damage to transmission and distribution infrastructure, solar
generation, and wind powered generation. Higher frequency and severity of weather events increase the
likelihood of longer power outages and more fuel supply disruptions. Increased frequency and intensity of
flooding and storm surge could adversely affect the operations of utilities and in particular generation
assets. The impact of extreme weather events would be amplified if the same events affect multiple
utilities.
Exhibit 99.2
45
Each of Emera’s regulated electric utilities have programs for storm hardening of transmission and
distribution facilities to minimize damage, but there can be no assurance that these measures will fully
mitigate the risk. This risk to transmission and distribution facilities is typically not insured, and as such
the restoration cost is generally recovered through regulatory processes, either in advance through
reserves or designated self-insurance funds, or after the fact through the establishment of regulatory
assets. Recovery is not assured and is subject to prudency review. The risk to generation assets is, in
part, mitigated through the design, siting, construction and maintenance of such facilities, regular risk
assessments, engineered mitigation, emergency storm response plans, and insurance.
 
High winds and lack of precipitation increase the risk of wildfires resulting from the Company’s
infrastructure or for which the Company may otherwise have responsibility. The risk of wildfires is
addressed primarily through asset management programs for natural gas transmission and distribution
operations, and asset management, storm hardening, and vegetation management programs for electric
utilities, but there can be no assurance that these measures will fully mitigate the risk. If it is found to be
responsible for such a fire, the Company could suffer material costs, losses and damages, all or some of
which may not be recoverable through insurance, legal, regulatory cost recovery or other processes. If
not recovered through these means, they could materially affect Emera’s business, access to capital,
financial condition and results of operations including its reputation with customers, regulators,
governments and financial markets. Resulting costs could include fire suppression costs, regeneration,
timber value, increased insurance costs and costs arising from damages and losses incurred by third
parties.
 
Changes in Environmental Legislation
 
Emera is subject to regulation by federal, provincial, state, regional and local authorities regarding
environmental matters, primarily related to its utility operations. This includes laws setting GHG emissions
standards and air emissions standards. Emera is also subject to laws regarding waste management,
wastewater discharges and aquatic and terrestrial habitats.
Changes to GHG emissions standards and air emissions standards could adversely affect Emera’s
operations and financial performance.
 
Both the Government of Nova Scotia and the Government of Canada have enacted or introduced
legislation that includes goals of net-zero GHG emissions by 2050. The Province of Nova Scotia has
established targets with respect to the percentage of renewable energy in NSPI’s generation mix,
reductions in GHG emissions, as well as the goal to phase out coal-fired electricity generation by 2030.
Failure to meet such goals by 2030 could result in material fines, penalties, other sanctions and adverse
reputational impacts. NSPI continues to work with both the provincial and federal governments on
measures to seek to address their carbon reduction goals. Within Emera’s natural gas utilities, there are
ongoing efforts to reduce methane and carbon dioxide emissions through replacement of aging
infrastructure, more efficient operations, operational and supply chain optimization, renewable natural gas
projects, and support of public policy initiatives that address the effects of climate change.
In 2023, the United States Environmental Protection Agency proposed new carbon emission standards
for fossil fuel-fired power plants and the Government of Canada released draft Clean Electricity
Regulations which propose limitations on the use of natural gas generation. Until final rules are issued, it
is not certain what the impact will be on the Company and its operations.
 
These and other legislative or regulatory changes could influence decisions regarding capital investment,
early retirement of generation facilities and may result in stranded costs if the Company is not able to fully
recover the costs and investment in the affected generation assets. Recovery is not assured and is
subject to prudency review. Legislative or regulatory changes may curtail sales of natural gas to new
customers, which could reduce future customer growth in Emera’s natural gas businesses. Stricter
environmental laws and enforcement of such laws in the future could increase Emera’s exposure to
additional liabilities and costs. These changes could also affect earnings and strategy by changing the
nature and timing of capital investments.
Exhibit 99.2
46
Per- and polyfluoroalkyl substances (“PFAS”) are man-made chemicals that are widely used in consumer
products and can persist and bio-accumulate in the environment. The Company does not manufacture
PFAS but because these emerging contaminants of concern are so ubiquitous in products and the
environment, it may impact Emera’s operations. Changes in environmental laws and regulations related
to PFAS could result in new costs or obligations for investigation and cleanup and change the Company’s
strategy for land acquisition for projects such as solar generation.
In addition to imposing continuing compliance obligations, there are permit requirements, laws and
regulations authorizing the imposition of penalties for non-compliance, including fines, injunctive relief,
and other sanctions. The cost of complying with current and future environmental requirements is, and
may be, material to Emera. Failure to comply with environmental requirements or to recover
environmental costs in a timely manner through rates, could have a material adverse effect on Emera. In
addition, Emera’s business could be materially affected by changes in government policy, utility
regulation, and environmental and other legislation that could occur in response to environmental and
climate change concerns.
 
Emera manages its environmental risk by operating in a manner that is respectful and protective of the
environment and in compliance with applicable legal requirements and Company policy. Emera has
implemented this policy through the development and application of environmental management systems
in its operating subsidiaries. Comprehensive audit programs are in place to regularly assess compliance.
 
Cybersecurity Risk
Emera is exposed to potential risks related to cyberattacks and unauthorized access. The Company relies
on IT systems, cloud infrastructure, third-party service providers and the diligence of its team members to
effectively manage and safely operate its assets. This includes controls for interconnected systems of
generation, distribution and transmission as well as financial, billing and other enterprise systems. As the
Company operates critical assets, it may be at greater risk of cyberattacks, which could include those
from nation-state cyber threat actors. Major emerging and ongoing global conflicts may also elevate this
risk.
 
Cyberattacks can reach the Company’s assets and information via their interfaces with third parties or the
public internet and gain access to critical infrastructures. Cyberattacks can also occur via personnel with
access to critical assets or trusted networks. Methods used to attack critical assets could include generic
or energy-sector-specific malware delivered via network transfer, removable media, attachments, or links
in e-mails. The methods used by attackers are continuously evolving and can be difficult to predict and
detect.
Despite security measures in place, that are described below, the Company’s systems, assets and
information could experience security breaches that could cause system failures, disrupt operations, or
adversely affect safety. Such breaches could compromise customer, employee-related or other
information systems and could result in loss of service to customers, unavailability of critical assets, safety
issues, or the release, destruction, or misuse of critical, sensitive or confidential information. These
breaches could also delay delivery or result in contamination or degradation of hydrocarbon products the
Company transports, stores or distributes.
 
Cyberattacks or unauthorized accesses may cause lost revenues, costs, losses and damages all, or
some of which, may not be recoverable (through insurance, legal, regulatory cost recovery or other
processes). This could materially adversely affect Emera’s business and financial results including its
reputation with customers, regulators, governments and financial markets. Resulting costs could include,
amongst others, response, recovery and remediation costs, increased protection or insurance costs and
costs arising from damages and losses incurred by third parties. If any such security breaches occur,
there is no assurance they can be adequately addressed in a timely manner.
Exhibit 99.2
47
The Company seeks to manage these risks by aligning to a common set of cybersecurity standards and
policies derived, in part, on the National Institute of Standards and Technology’s Cyber Security
Framework, periodic security testing, program maturity objectives, cybersecurity incident readiness
program, and employee communication and training. With respect to certain of its assets, the Company is
required to comply with rules and standards relating to cybersecurity and IT including, but not limited to,
those mandated by bodies such as the North American Electric Reliability Corporation,
 
Northeast Power
Coordinating Council, and the United States Department of Homeland Security. The status of key
elements of the Company’s cybersecurity program is reported to the RSC. The Board oversees risk and
mitigation plans in relation to cybersecurity risks and receives a quarterly update in a risk dashboard at
each regularly scheduled Board meeting.
 
Public Health Risk
An outbreak of infectious disease, a pandemic or a similar public health threat, or a fear of any of the
foregoing, could adversely impact the Company, including causing operating, supply chain and project
development delays and disruptions, labour shortages and shutdowns (including as a result of
government regulation and prevention measures), which could have a negative impact on the Company’s
operations.
Any adverse changes in general economic and market conditions arising as a result of a public health
threat could negatively impact demand for electricity and natural gas, revenue, operating costs, timing
and extent of capital expenditures, results of financing efforts, or credit risk and counterparty risk; which
could result in a material adverse effect on the Company’s business. The Company maintains pandemic
and business contingency plans in each of its operations to manage and help mitigate the impact of any
such public health threat.
 
Energy Consumption Risk
Emera’s rate-regulated utilities are affected by demand for energy based on changing customer patterns
due to fluctuations in a number of factors including general economic conditions, weather events,
customers’ focus on energy efficiency, changes in rates, and advancements in new technologies such as
rooftop solar, electric vehicles and battery storage. Government policies promoting distributed generation,
and new technology developments that enable those policies, have the potential to impact how electricity
enters the system and how it is bought and sold. In addition, increases in distributed generation may
impact demand resulting in lower load and revenues. These changes could negatively impact Emera’s
operations, rate base, net earnings, and cash flows. The Company’s rate-regulated utilities are focused
on understanding customer demand, energy efficiency, and government policy to ensure that the impact
of these activities benefit customers, that they do not negatively impact the reliability of the energy service
and that they are addressed through regulations.
Foreign Exchange Risk
 
The Company is exposed to foreign currency exchange rate changes. Emera operates internationally,
with an increasing amount of the Company’s net income earned outside of Canada. As such, Emera is
exposed to movements in exchange rates between the CAD and, particularly, the USD, which could
positively or adversely affect results.
Consistent with the Company’s risk management policies, Emera manages currency risks through
matching United States denominated debt to finance its United States operations and may use foreign
currency derivative instruments to hedge specific transactions and earnings exposure. The Company may
enter FX forward and swap contracts to limit exposure on certain foreign currency transactions such as
fuel purchases, revenue streams and capital expenditures, and on net income earned outside of Canada.
The regulatory framework for the Company’s rate-regulated subsidiaries permits the recovery of prudently
incurred costs, including FX.
Exhibit 99.2
48
The Company does not utilize derivative financial instruments for foreign currency trading or speculative
purposes or to hedge the value of its investments in foreign subsidiaries. Exchange gains and losses on
net investments in foreign subsidiaries do not impact net income as they are reported in Accumulated
Other Comprehensive Income (Loss) ("AOCI”) (“AOCL”).
Liquidity and Capital Market Risk
Liquidity risk relates to Emera’s ability to ensure sufficient funds are available to meet its financial
obligations. Emera manages this risk by forecasting cash requirements on a continuous basis to
determine whether sufficient funds are available. Liquidity and capital needs could be financed through
internally generated cash flows, asset sales, short-term credit facilities, and ongoing access to capital
markets. The Company reasonably expects liquidity sources to meet capital needs.
Emera’s access to capital and cost of borrowing is subject to several risk factors, including financial
market conditions, market disruptions and ratings assigned by various market analysts, including credit
rating agencies. Disruptions in capital markets could prevent Emera from issuing new securities or cause
the Company to issue securities with less than preferred terms and conditions. Emera’s growth plan
requires significant capital investments in PP&E and the risk associated with changes in interest rates
could have an adverse effect on the cost of financing. The Company’s future access to capital and cost of
borrowing may be impacted by various market disruptions. The inability to access cost-effective capital
could have a material impact on Emera’s ability to fund its growth plan.
 
Emera is subject to financial risk associated with changes in its credit ratings. There are a number of
factors that rating agencies evaluate to determine credit ratings, including the Company’s business, its
regulatory framework and legislative environment, political interference in the regulatory process, the
ability to recover costs and earn returns, diversification, leverage, liquidity and increased exposure to
climate change-related impacts, including increased frequency and severity of hurricanes and other
severe weather events. A decrease in a credit rating could result in higher interest rates in future
financings, increased borrowing costs under certain existing credit facilities, limit access to the
commercial paper market, or limit the availability of adequate credit support for subsidiary operations. For
more information on interest rate risk, refer to “General Economic Risk – Interest Rate Risk”. For certain
derivative instruments, if the credit ratings of the Company were reduced below investment grade, the full
value of the net liability of these positions could be required to be posted as collateral. Emera manages
these risks by actively monitoring and managing key financial metrics with the objective of sustaining
investment grade credit ratings.
The Company has exposure to its own common share price through the issuance of various forms of
stock-based compensation, which affect earnings through revaluation of the outstanding units every
period. The Company uses equity derivatives to reduce the earnings volatility derived from stock-based
compensation.
General Economic Risk
The Company has exposure to the macro-economic conditions in North America and in other geographic
regions in which Emera operates. Like most utilities, economic factors such as consumer income,
employment and housing affect demand for electricity and natural gas and, in turn, the Company’s
financial results. Adverse changes in general economic conditions and inflation may impact the ability of
customers to afford rate increases arising from increases to fuel, operating, capital, environmental
compliance, and other costs, and therefore could materially affect Emera and its utilities. This may also
result in higher credit and counterparty risk, adverse shifts in government policy and legislation, and/or
increased risk to full and timely recovery of costs and regulatory assets.
Exhibit 99.2
49
Interest Rate Risk:
Emera utilizes a combination of fixed and floating rate debt financing for operations and capital
expenditures, resulting in an exposure to interest rate risk. Emera seeks to manage interest rate risk
through a portfolio approach that includes the use of fixed and floating rate debt with staggered
maturities. The Company will, from time to time, issue long-term debt or enter interest rate hedging
contracts to limit its exposure to fluctuations in floating interest rate debt.
 
For Emera’s regulated subsidiaries, the cost of debt is a component of rates and prudently incurred debt
costs are recovered from customers. Regulatory ROE will generally follow the direction of interest rates,
such that regulatory ROEs are likely to fall in times of reducing interest rates and rise in times of
increasing interest rates, albeit not directly and generally with a lag period reflecting the regulatory
process. Rising interest rates may also negatively affect the economic viability of project development
and acquisition initiatives.
Interest rates could also be impacted by changes in credit ratings. For more information, refer to “Liquidity
and Capital Market Risk”.
 
As with most other utilities and other similar yield-returning investments, Emera’s share price may be
affected by changes in interest rates and could underperform the market in an environment of rising
interest rates.
Inflation Risk:
The Company may be exposed to changes in inflation that may result in increased operating and
maintenance costs, capital investment, and fuel costs compared to the revenues provided by customer
rates. Emera’s utilities have budgeting and forecasting processes to identify inflationary risk factors and
measure operating performance, as well as collective bargaining agreements that mitigate the short-term
impact of inflation on labour costs of unionized employees.
Project Development and Land Use Rights Risk
The Company’s capital plan includes significant investment in generation, infrastructure modernization,
and customer-focused technologies. Any projects planned or currently in construction, particularly
significant capital projects, may be subject to risks including, but not limited to, impact on costs from
schedule delays, increased demand for renewable energy inputs, risk of cost overruns, ensuring
compliance with operating and environmental requirements and other events within or beyond the
Company’s control. The Company’s projects may also require approvals and permits at the federal,
provincial, state, regional and local levels. There is no assurance that Emera will be able to obtain the
necessary project approvals or applicable permits or receive regulatory approval to recover the costs in
rates.
Some of the Company’s assets are located on land owned by third parties, including Indigenous Peoples,
and may be subject to land claims. Present or future assets may be located on lands that have been used
for traditional purposes and therefore subject to specific consultations, consents, or conditions for
development or operation. If the Company’s rights to locate and operate its assets on any such lands are
subject to expiry or become invalid, it may incur material costs to renew rights or obtain such rights. If
reasonable terms for land-use rights cannot be negotiated, the Company may incur significant costs to
remove and relocate its assets and restore the land. Additional costs incurred could cause projects to be
uneconomical to proceed with.
Emera manages these project development and land use rights risks by deploying robust project and risk
management approaches, led by teams with extensive experience in large projects. The Company
consults with Indigenous Peoples in obtaining approvals, constructing, maintaining and operating such
facilities, consistent with laws and public policy frameworks. Emera maintains relationships through on-
going communications with stakeholders, including Indigenous Peoples, landowners and governments.
Exhibit 99.2
50
Counterparty Risk
Emera is exposed to risk related to its reliance on certain key partners, suppliers, and customers, any of
which may endure financial challenges resulting from commodity price and market volatility, economic
instability or adversity, adverse political or regulatory changes and other causes which may cause or
contribute to such parties’ insolvency, bankruptcy,
 
restructuring or default on their contractual obligations
to Emera.
 
Emera is also exposed to potential losses related to amounts receivable from customers,
energy marketing collateral deposits and derivative assets due to a counterparty’s non-performance
under an agreement.
Emera manages this counterparty risk through due diligence and third-party risk assessment processes
prior to signing contracts, contractual rights and remedies, regulatory frameworks, and by monitoring
significant developments with its customers, partners and suppliers. The Company also manages credit
risk with policies and procedures for counterparty analysis, exposure measurement, and exposure
monitoring and mitigation. Credit assessments may be conducted on new customers and counterparties,
and deposits or collateral may be requested on certain accounts. There is no assurance that
management strategies will be effective,
 
and significant counterparty defaults could have a material effect
on the Company.
Country Risk
The majority of Emera’s earnings are from outside of Canada, mostly concentrated in the United States.
Emera’s investments are currently in regions where political and economic risks are considered by the
Company to be acceptable. For more information, refer to the “Regulatory and Political Risk” and
“General Economic Risk” sections above. Emera’s operations in some countries may be subject to
changes in economic growth, restrictions on the repatriation of income or capital exchange controls,
inflation, the effect of global health, safety and environmental matters, including climate change, or
economic conditions and market conditions, and change in financial policy and availability of credit. The
Company mitigates this risk through a rigorous approval process for investment, and by forecasting cash
requirements on a continuous basis to determine whether sufficient funds are available in all affiliates.
 
Supply Chain Risk
Emera’s ability to meet customer energy requirements, respond to storm-related disruptions and execute
on our capital program in a cost-effective and timely manner are dependent on maintaining an efficient
supply chain. Domestic and global supply chain issues may delay the delivery or result in shortages of
certain materials, equipment and other resources that are critical to the Company’s operations. These
disruptions may be further exacerbated by inflationary pressures, labour shortages, government
incentives increasing demand for clean energy projects, and the impact of international conflicts, tariffs, or
other trade restrictions. Failure to eliminate or manage supply chain constraints may impact the
availability and cost of items and labour that are necessary to support operations and capital investment.
Emera continues to monitor the situation and seeks to mitigate the impacts of supply chain risk by
securing alternative suppliers, third party risk management, modifying design standards, and adjusting
the timing of work.
Commodity Price Risk
The Company’s utility fuel supply and purchase of other commodities is subject to commodity price risk.
In addition, Emera Energy is subject to commodity price risk through its portfolio of commodity contracts
and arrangements.
Exhibit 99.2
51
The Company manages this risk through established processes and practices to identify, monitor, report
and mitigate these risks. These include the Company’s commercial arrangements, such as the
combination of supply and purchase agreements, asset management agreements, pipeline transportation
agreements, and financial hedging instruments. In addition, its credit policies, counterparty credit
assessments, market and credit position reporting, and other risk management and reporting practices,
are also used to manage and mitigate this risk.
Regulated Utilities:
The Company’s utility fuel supply is exposed to broader global conditions, which may include impacts on
delivery reliability and price, despite contracted terms. Supply and demand dynamics in fuel markets can
be affected by a wide range of factors which are difficult to predict and may change rapidly, including but
not limited to, currency fluctuations, changes in global economic conditions, natural disasters,
transportation or production disruptions, and geo-political risks, such as political instability, conflicts,
changes to international trade agreements, trade sanctions or embargos. The Company seeks to manage
this risk using financial hedging instruments and physical contracts and through contractual protection
with counterparties, where applicable.
 
The majority of Emera’s regulated electric and gas utilities have adopted and implemented fuel
adjustment mechanisms and purchased gas adjustment mechanisms respectively, which further helps
manage commodity price risk, as the regulatory framework for the Company’s rate-regulated subsidiaries
permits the recovery of prudently incurred fuel and gas costs. There is no assurance that such
mechanisms and regulatory frameworks will continue to exist in the future. Prolonged and substantial
increases in fuel prices could result in decreased rate affordability, increased risk of recovery of costs or
regulatory assets, and/or negative impacts on customer consumption patterns and sales.
Emera Energy Marketing and Trading:
Emera Energy has employed further measures to manage commodity risk. The majority of Emera
Energy’s portfolio of electricity and gas marketing and trading contracts and, in particular, its natural gas
asset management arrangements, are contracted on a back-to-back basis, avoiding any material long or
short commodity positions. However, the portfolio is subject to commodity price risk, particularly with
respect to basis point differentials between relevant markets in the event of an operational issue or
counterparty default. Changes in commodity prices can also result in increased collateral requirements
associated with physical contracts and financial hedges, resulting in higher liquidity requirements and
increased costs to the business.
To
 
measure commodity price risk exposure, Emera Energy employs a number of controls and processes,
including an estimated VaR analysis of its exposures. The VaR
 
amount represents an estimate of the
potential change in FV that could occur from changes in Emera Energy’s portfolio or changes in market
factors within a given confidence level, if an instrument or portfolio is held for a specified time period. The
VaR calculation is used to quantify exposure to market risk associated with physical commodities,
primarily natural gas and power positions.
Future Employee Benefit Plan Performance and Funding Risk
Emera subsidiaries have both defined benefit and defined contribution employee pension plans that cover
their employees and retirees. All defined benefit plans are closed to new entrants, except for the TECO
Energy Group Retirement Plan and the Grand Bahama Power Company Limited Union Employees’
Pension Plan. The cost of providing these benefit plans varies depending on plan provisions, interest
rates, inflation, investment performance and actuarial assumptions concerning the future. Actuarial
assumptions include earnings on plan assets, discount rates (interest rates used to determine funding
levels, contributions to the plans and the pension and post-retirement liabilities) and expectations around
future salary growth, inflation and mortality. Three of the largest drivers of cost are investment
performance, interest rates and inflation, which are affected by global financial and capital markets.
Depending on future interest rates and future inflation and actual versus expected investment
performance, Emera could be required to make larger contributions in the future to fund these plans,
which could adversely affect Emera’s cash flows, financial condition and operations.
Exhibit 99.2
52
Each of Emera’s employee defined benefit pension plans are managed according to an approved
investment policy and governance framework. Emera employs a long-term approach with respect to asset
allocation and each investment policy outlines the level of risk which the Company is prepared to accept
with respect to the investment of the pension funds in achieving both the Company’s fiduciary and
financial objectives. Studies are routinely undertaken approximately every five years with the objective
that the plans’ asset allocations are appropriate for meeting Emera’s long-term pension objectives.
Labour Risk
Emera’s ability to deliver service to its customers and to execute its growth plan depends on attracting,
developing and retaining a skilled workforce. Utilities are faced with demographic challenges related to
trades, technical staff and engineers with an increasing number of employees expected to retire over the
next several years. Failure to attract, develop and retain an appropriately qualified workforce could
adversely affect the Company’s operations and financial results. Emera seeks to manage this risk through
maintaining competitive compensation programs, a dedicated talent acquisition team, human resources
programs and practices, including ethics and diversity training, employee engagement surveys,
succession planning for key positions and apprenticeship programs.
Approximately 30 per cent of Emera’s labour force is represented by unions and subject to collective
labour agreements. The inability to maintain or negotiate future agreements on acceptable terms could
result in higher labour costs and work disruptions, which could adversely affect service to customers and
have an adverse effect on the Company’s earnings, cash flow and financial position. Emera seeks to
manage this risk through ongoing discussions and working to maintain positive relationships with local
unions. The Company maintains contingency plans in each of its operations to manage and reduce the
effect of any potential labour disruption.
IT Risk
Emera relies on various IT systems to manage operations. This subjects Emera to inherent costs and
risks associated with maintaining, upgrading, replacing and changing these systems. This includes
impairment of its IT, potential disruption of internal control systems, substantial capital expenditures,
demands on management time and other risks of delays, difficulties in upgrading existing systems,
transitioning to new systems or integrating new systems into its current systems. Emera’s digital
transformation strategy, including investment in infrastructure modernization and customer focused
technologies, is driving increased investment in IT solutions, resulting in increased project risks
associated with the implementation of these solutions.
 
Emera manages these risks through IT asset lifecycle planning and management, governance, internal
auditing and testing of systems, and executive oversight. Employees with extensive subject matter
expertise assist in risk identification and mitigation, project management, implementation, change
management and training. System resiliency, formal disaster recovery and backup processes, combined
with critical incident response practices, table-top exercises, and simulations, help mitigate operational
disruptions.
 
Income Tax Risk
The computation of the Company’s provision for income taxes is impacted by changes in tax legislation in
Canada, the United States and the Caribbean. Any such changes could affect the Company’s future
earnings, cash flows, and financial position. The value of Emera’s existing deferred income tax assets
and liabilities are determined by existing tax laws and could be negatively impacted by changes in laws.
Emera monitors the status of existing tax laws to ensure that changes impacting the Company are
appropriately reflected in the Company’s tax compliance filings and financial results.
Exhibit 99.2
53
System Operating and Maintenance Risks
The safe and reliable operation of electric generation and electric and natural gas transmission and
distribution systems is critical to Emera’s operations. There are a variety of hazards and operational risks
inherent in operating electric utilities and natural gas transmission and distribution pipelines. Electric
generation, transmission and distribution operations can be impacted by risks such as mechanical
failures, supply chain issues impacting timely access to critical equipment, activities of third parties,
terrorism, cyberattacks, damage to facilities, solar panels and infrastructure caused by hurricanes,
storms, falling trees, lightning strikes, floods, fires and other natural disasters. Natural gas pipeline
operations can also be impacted by risks such as leaks, explosions, mechanical failures, activities of third
parties, terrorism, cyberattacks, and damage to the pipeline facilities and equipment caused by
hurricanes, storms, floods, fires and other natural disasters. Refer to “Global Climate Change Risk” and
“Weather Risk”. Electric utility and natural gas transmission and distribution pipeline operation interruption
could negatively affect revenue, earnings, and cash flows as well as customer and public confidence, and
public safety.
Emera manages these risks by investing in a highly skilled workforce, operating prudently, preventative
maintenance, safety and operations management systems, third-party risk program, and making effective
capital investments. Insurance, warranties, or recovery through regulatory mechanisms may not cover
any or all these losses, which could adversely affect the Company’s results of operations and cash flows.
 
Fuel Supply Disruptions:
Emera’s electric and natural gas utilities are also exposed to the risk of fuel supply chain disruptions, both
within and outside their service territories, which may be caused by severe weather or natural disasters.
This may also be caused by damage to, operational issues with, terrorist or cyberattacks on, third party
fuel production, storage, pipeline, and distribution facilities. The risk of fuel supply disruptions is managed
through contractual protections, maintaining a diversity of fuel suppliers and transportation contracts, and
contracting for access to third-party storage facilities. Significant unanticipated fuel supply disruptions
could result in increased exposure to commodity price risk for Emera’s regulated electric and gas utilities
and Emera Energy, and these could have adverse effects on service to utility customers and on the
Company’s reputation, earnings, cash flow and financial position.
 
Uninsured Risk
Emera and its subsidiaries maintain insurance to cover accidental loss suffered to its facilities and to
provide indemnity in the event of liability to third parties. This is consistent with Emera’s risk management
policies. Certain facilities, in particular coal and other thermal generation, may, over time, become more
difficult (or uneconomic) to insure as a result of the impact of global climate change. Refer to “Global
Climate Change Risk – Markets”. There are certain elements of Emera’s operations which are not
insured. These include a significant portion of its electric utilities’ transmission and distribution assets and
its gas utilities’ distribution assets, as is customary in the industry. The cost of this coverage is not
economically viable. In addition, Emera accepts deductibles and self-insured retentions under its various
insurance policies. Insurance is subject to coverage limits as well as time sensitive claims discovery and
reporting provisions and there can be no assurance that the types of liabilities or losses that may be
incurred by the Company and its subsidiaries will be covered by insurance.
The occurrence of significant uninsured claims, claims in excess of the insurance coverage limits
maintained by Emera and its subsidiaries, or claims that fall within a significant self-insured retention
could have a material adverse effect on Emera’s results of operations, cash flows and financial position, if
regulatory recovery is not available.
The Company manages its insured risk by aligning insurance limits with risk exposures, and for uninsured
assets and operations, that appropriate risk assessments and mitigation measures are in place. The
regulatory framework for the Company’s rate-regulated subsidiaries permits the recovery of prudently
incurred costs, including uninsured losses.
 
Exhibit 99.2
54
RISK MANAGEMENT INCLUDING FINANCIAL
INSTRUMENTS
 
Emera’s risk management policies and procedures provide a framework through which management
monitors various risk exposures. Risk management policies and practices are overseen by the Board.
The Company has established a number of processes and practices to identify, monitor, report on and
mitigate material risks to the Company. This includes establishment of the ERMC, whose responsibilities
include preparing an updated risk dashboard and heat map presented at regular meetings of the Board’s
Risk and Sustainability Committee. Furthermore, a corporate team independent from operations is
responsible for tracking and reporting on market and credit risks.
The Company manages exposure to normal operating and market risks relating to commodity prices, FX,
interest rates and share prices through contractual protections with counterparties where practicable, and
by using financial instruments consisting mainly of FX forwards and swaps, interest rate options and
swaps, equity derivatives, and coal, oil and gas futures, options, forwards and swaps. In addition, the
Company has contracts for the physical purchase and sale of natural gas. These physical and financial
contracts are classified as HFT. Collectively,
 
these contracts and financial instruments are considered
derivatives.
The Company recognizes the FV of all its derivatives on its balance sheet, except for non-financial
derivatives that meet the normal purchases and normal sales (“NPNS”) exception. Physical contracts that
meet the NPNS exception are not recognized on the balance sheet; these contracts are recognized in
income when they settle. A physical contract generally qualifies for the NPNS exception if the transaction
is reasonable in relation to the Company’s business needs, the counterparty owns or controls resources
within the proximity to allow for physical delivery, the Company intends to receive physical delivery of the
commodity, and the Company deems the counterparty creditworthy.
 
The Company continually assesses
contracts designated under the NPNS exception and will discontinue the treatment of these contracts
under this exemption if the criteria are no longer met.
 
Derivatives qualify for hedge accounting if they meet stringent documentation requirements and can be
proven to effectively hedge identified risk both at the inception and over the term of the instrument.
Specifically, for cash flow hedges, change in the FV of derivatives is deferred to AOCI and recognized in
income in the same period the related hedged item is realized. Where documentation or effectiveness
requirements are not met, the derivatives are recognized at FV with any changes in FV value recognized
in net income in the reporting period, unless deferred as a result of regulatory accounting.
Derivatives entered into by NSPI, NMGC and GBPC that are documented as economic hedges or for
which the NPNS exception has not been taken, are subject to regulatory accounting treatment. The
change in FV of the derivatives is deferred to a regulatory asset or liability. The gain or loss is recognized
in the hedged item when the hedged item is settled. Management believes any gains or losses resulting
from settlement of these derivatives related to fuel for generation and purchased power will be refunded
to or collected from customers in future rates. TEC has no derivatives related to hedging as a result of a
FPSC approved five-year moratorium on hedging of natural gas purchases that ended on December 31,
2022 and was extended through December 31, 2024 as a result of TEC’s 2021 rate case settlement
agreement.
Derivatives that do not meet any of the above criteria are designated as HFT, with changes in FV
normally recorded in net income of the period. The Company has not elected to designate any derivatives
to be included in the HFT category where another accounting treatment would apply.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Exhibit 99.2
55
Derivative Assets and Liabilities Recognized on the Balance Sheet
As at
December 31
December 31
millions of dollars
2023
2022
Regulatory Deferral:
Derivative instrument assets
(1)
$
 
16
$
 
238
Derivative instrument liabilities
(2)
 
(76)
 
(25)
Regulatory assets
(1)
 
88
 
30
Regulatory liabilities
 
(2)
 
(17)
 
(230)
Net asset
$
 
11
$
 
13
HFT Derivatives:
 
Derivative instrument assets
 
(1)
$
 
202
$
 
153
Derivatives instruments liabilities
(2)
 
(421)
 
(1,025)
Net liability
$
 
(219)
$
 
(872)
Other Derivatives:
Derivative instrument assets
(1)
$
 
22
$
 
5
Derivatives instruments liabilities
 
(2)
 
(7)
 
(28)
Net asset (liability)
$
 
15
$
 
(23)
(1) Current and other assets.
(2) Current and long-term liabilities.
 
Realized and Unrealized Gains (Losses) Recognized in Net Income
For the
Year ended December 31
millions of dollars
2023
2022
Regulatory Deferral:
Regulated fuel for generation and purchased power
(1)
$
 
62
$
 
210
HFT Derivatives:
Non-regulated operating revenues
$
 
1,037
$
 
64
Other Derivatives:
OM&G
$
 
(9)
$
 
(22)
Other income, net
 
17
 
(24)
Net gains (losses)
$
 
8
$
 
(46)
Total net gains
$
 
1,107
$
 
228
(1)
 
Realized gains (losses) on derivative instruments settled and consumed in the period, hedging relationships
 
that have been
terminated or the hedged transaction is no longer probable. Realized gains (losses) recorded in inventory will be recognized
 
in
“Regulated fuel for generation and purchased power” when the hedged item is consumed.
For the year ended December 31, 2023, unrealized gains of $2 million (2022 – $2 million), have been
reclassified out of AOCI into interest expense.
 
As at
December 31, 2023
December 31, 2022
Interest rate
Interest rate
millions of dollars
hedge
hedge
Total unrealized gain in AOCI – net of tax
$
14
$
 
16
DISCLOSURE AND INTERNAL CONTROLS
Management is responsible for establishing and maintaining adequate disclosure controls and
procedures (“DC&P”) and internal control over financial reporting (“ICFR”), as defined in National
Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings (“NI 52-109”). The
Company’s internal control framework is based on criteria published in the Internal Control Integrated
Framework (2013), a report issued by the Committee of Sponsoring Organizations (“COSO”) of the
Treadway Commission. Management, including the Chief Executive Officer and Chief Financial Officer,
evaluated the design and effectiveness of the Company’s DC&P and ICFR as at December 31, 2023 to
provide reasonable assurance regarding the reliability of financial reporting in accordance with USGAAP.
Exhibit 99.2
56
Management recognizes the inherent limitations in internal control systems, no matter how well designed.
Control systems determined to be appropriately designed can only provide reasonable assurance with
respect to the reliability of financial reporting and may not prevent or detect all misstatements.
There were no changes in the Company’s ICFR, during the year ended December 31, 2023, that have
materially affected, or are reasonably likely to materially affect, the Company’s internal control over
financial reporting.
CRITICAL ACCOUNTING ESTIMATES
The preparation of consolidated financial statements in accordance with USGAAP requires management
to make estimates and assumptions. These may affect reported amounts of assets and liabilities at the
date of the financial statements and reported amounts of revenues and expenses during the reporting
periods. Significant areas requiring use of management estimates relate to rate-regulated assets and
liabilities, accumulated reserve for cost of removal, pension and post-retirement benefits, unbilled
revenue, useful lives for depreciable assets, goodwill and long-lived assets impairment assessments,
income taxes, asset retirement obligations (“ARO”), and valuation of financial instruments. Management
evaluates the Company’s estimates on an ongoing basis based upon historical experience, current and
expected conditions and assumptions believed to be reasonable at the time the assumption is made, with
any adjustments recognized in income in the year they arise.
Rate Regulation
The rate-regulated accounting policies of Emera’s rate-regulated subsidiaries and regulated equity
investments are subject to examination and approval by their respective regulators and may differ from
the accounting policies of non-rate-regulated companies. Differences occur when regulators render their
decisions on rate applications or other matters, and generally involve a difference in the timing of revenue
and expense recognition. The accounting for these items is based on expectations of the future actions of
the regulators. Assumptions and judgments used by regulatory authorities continue to have an impact on
recovery of costs, rates earned on invested capital, and the timing and amount of assets to be recovered.
Application of regulatory accounting guidance is a critical accounting policy as a change in these
assumptions may result in a material impact on reported assets, liabilities and the results of operations.
As at December 31, 2023, the Company had recorded $3,105 million (2022 – $3,620 million) of regulatory
assets and $1,772 million (2022 – $2,273 million) of regulatory liabilities.
Accumulated Reserve – Cost of Removal
TEC, PGS, NMGC and NSPI recognize non-ARO costs of removal (“COR”) as regulatory liabilities. The
non-ARO COR represent estimated funds received from customers through depreciation rates to cover
future COR of PP&E upon retirement that are not legally required. The companies accrue for COR over
the life of the related assets based on depreciation studies approved by their respective regulators. Costs
are estimated based on historical experience and future expectations, including expected timing and
estimated future cash outlays. As at December 31, 2023, the balance of the Accumulated reserve – COR
within regulatory liabilities was $849 million (2022 – $895 million).
Pension and Other Post-Retirement Employee Benefits
The Company provides post-retirement benefits to employees, including defined benefit pension plans.
The cost of providing these benefits is dependent upon many factors that result from actual plan
experience and assumptions of future expectations.
 
 
 
 
 
 
 
 
 
 
Exhibit 99.2
57
The accounting related to employee post-retirement benefits is a critical accounting estimate. Changes in
the estimated benefit obligation, affected by employee demographics - including age, compensation
levels, employment periods, contribution levels and earnings - could have a material impact on reported
assets, liabilities, accumulated other comprehensive income and results of operations. Changes in key
actuarial assumptions, including anticipated rates of return on plan assets and discount rates used in
determining the accrued benefit obligation and benefit costs, could change annual funding requirements.
This could have a significant impact on the Company’s annual earnings and cash requirements.
Pension plan assets are comprised primarily of equity and fixed income investments. Fluctuations in
actual equity market returns and changes in interest rates may result in changes to pension costs in
future periods.
The Company’s accounting policy is to amortize the net actuarial gain or loss that exceeds 10 per cent of
the greater of the projected benefit obligation / accumulated post-retirement benefit obligation (“PBO”)
and the market-related value of assets, over active plan members’ average remaining service period. For
the largest plans this is currently 8.0 years (8.4 years for 2023 benefit cost) for Canadian plans and a
weighted average of 11.5 years for United States plans. The Company’s use of smoothed asset values
reduces volatility related to amortization of actuarial investment experience. As a result, the main cause of
volatility in reported pension cost is the discount rate used to determine the PBO.
 
The discount rate used to determine benefit costs is based on the yield of high quality long-term corporate
bonds in each operating entity’s country and is determined with reference to bonds which have the same
duration as the PBO as at January 1 of the fiscal year. The following table shows the discount rate for
benefit cost purposes and the expected return on plan assets for each plan:
2023
2022
Discount rate for
benefit cost
purposes
Expected
return on
 
plan assets
Discount rate for
benefit cost
 
purposes
Expected
 
return on
 
plan assets
TECO Energy Group Retirement Plan
5.55%
7.05%
2.78%
6.50%
TECO Energy Group Supplemental
Executive Retirement Plan
(1)
5.45%/5.31%
N/A
2.35/5.33%
N/A
TECO Energy Group Benefit
Restoration Plan (1)
5.48/5.30/5.49%
N/A
2.27/4.19/5.48%
N/A
TECO Energy Post-retirement Health
and Welfare Plan
5.53%/6.14%
N/A
2.84%
N/A
New Mexico Gas Company Retiree
Medical Plan
5.55%
2.50%
2.85%
1.50%
NSPI
 
5.17%, 5.19%
6.25%
3.25%, 3.48%
5.75%
GBPC Salaried
5.75%
 
6.00%
5.75%
6.00%
GBPC Union
5.75%
 
5.35%
5.75%
5.35%
(1) The discount rate for benefit cost purposes is updated throughout the year as special events occur,
 
such as settlements and
curtailments
Based on management’s estimate, the reported benefit cost for defined benefit and defined contribution
plans was $43 million in 2023 (2022 – $64 million). The reported benefit cost is impacted by numerous
assumptions, including the discount rate and asset return assumptions. A 0.25 per cent change in the
discount rate and asset return assumptions would have had +/- impact on the 2023 benefit cost of $0.5
million and $2.5 million, respectively (2022 – $0.5 million and $1 million).
 
Exhibit 99.2
58
Unbilled Revenue
Electric and gas revenues are billed on a systematic basis over a one or two-month period for NSPI and a
one-month period for other Emera utilities. At the end of each month, the Company must make an
estimate of energy delivered to customers since the date their meter was last read and determine related
revenues earned but not yet billed. The unbilled revenue is estimated based on several factors, including
current month’s generation, estimated customer usage by class, weather, line losses, inter-period
changes to customer classes and applicable customer rates. Based on the extent of estimates included in
determination of unbilled revenue, actual results may differ from the estimate. At December 31, 2023,
unbilled revenues totalled $363 million (2022 – $424 million) on total regulated operating revenues of
$7,235 million (2022 – $7,154 million).
PP&E
PP&E represents 62 per cent of total assets on the Company’s balance sheet and includes generation,
transmission and distribution, and other assets of the Company.
Depreciation is determined by the straight-line method, based on the estimated remaining service lives of
depreciable assets in each category. The service lives of regulated PP&E are determined based on
depreciation studies and require appropriate regulatory approval. Due to the magnitude of the Company’s
PP&E, changes in estimated depreciation rates can have a material impact on depreciation expense and
accumulated depreciation.
Depreciation expense was $1,019 million for the year ended December 31, 2023 (2022 – $927 million).
Goodwill Impairment Assessments
Goodwill is calculated as the excess of the purchase price of an acquired entity over the estimated FV of
identifiable assets acquired, and liabilities assumed at the acquisition date.
 
Goodwill is subject to assessment for impairment at the reporting unit level annually, or if an event or
change in circumstances indicates that the FV of a reporting unit may be below its carrying value.
Application of the goodwill impairment test requires management judgment on significant assumptions
and estimates. When assessing goodwill for impairment, the Company has the option of first performing a
qualitative assessment to determine whether a quantitative assessment is necessary. In performing a
qualitative assessment, management considers, among other factors, macroeconomic conditions,
industry and market considerations and overall financial performance.
If the Company performs a qualitative assessment and determines it is more likely than not that its FV is
less than its carrying amount, or if the Company chooses to bypass the qualitative assessment, a
quantitative test is performed. The quantitative test compares the FV of the reporting unit to its carrying
amount, including goodwill. If the carrying amount of the reporting unit exceeds its FV, an impairment loss
is recorded. Significant assumptions used in estimating the FV of a reporting unit include discount and
growth rates, rate case assumptions including future cost of capital, valuation of the reporting units' net
operating loss (“NOL”), and projected operating and capital cash flows. Adverse changes in these
assumptions could result in a future material impairment of the goodwill assigned to Emera’s reporting
units.
Exhibit 99.2
59
As of December 31, 2023, $5,868 million (2022 – $6,009 million) of Emera’s goodwill represents the
excess of the acquisition purchase price for TECO Energy (TEC, PGS and NMGC reporting units) over
the FV assigned to identifiable assets acquired and liabilities assumed. In Q4 2023, qualitative
assessments were performed for NMGC and PGS, given the significant excess of FV over carrying
amounts calculated during the last quantitative tests in Q4 2022 and Q4 2019, respectively. Management
concluded it was more likely than not that the FV of these reporting units exceeded their respective
carrying amounts, including goodwill. As such, no quantitative testing was required. Given the length of
time passed since the last quantitative impairment test for the TEC reporting unit, Emera elected to
bypass a qualitative assessment and performed a quantitative impairment assessment in Q4 2023 using
a combination of the income and market approach. This assessment estimated that the FV of the TEC
reporting unit exceeded its carrying amount, including goodwill, and as a result no impairment charges
were recognized.
As of December 31, 2023, the Company had goodwill with a total carrying amount of $5,871 million
(December 31, 2022 – $6,012 million). The change in the carrying value of goodwill from 2022 to 2023
was a result of the effect of the FX translation of Emera’s foreign affiliates.
In Q4 2022, as a result of a quantitative assessment, the Company recorded a goodwill impairment
charge of $73 million, reducing the GBPC goodwill balance to nil as at December 31, 2022. For further
detail, refer to note 22 in the consolidated financial statements.
Long-Lived Assets Impairment Assessments
The Company assesses whether there has been an impairment of long-lived assets and intangibles when
a triggering event occurs, such as a significant market disruption or the sale of a business. The
assessment involves comparing undiscounted expected future cash flows, to the carrying value of the
asset. When the undiscounted cash flow analysis indicates a long-lived asset is not recoverable, the
amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-
lived asset over its estimated FV.
The Company believes accounting estimates related to asset impairments are critical estimates, as they
are highly susceptible to change and the impact of an impairment on reported assets and earnings could
be material. Management is required to make assumptions based on expectations regarding results of
operations for significant/indefinite future periods and current and expected market conditions in such
periods. Markets can experience significant uncertainties. Estimates based on the Company’s
assumptions relating to future results of operations or other recoverable amounts are based on a
combination of historical experience, fundamental economic analysis, observable market activity and
independent market studies. The Company’s expectations regarding uses and holding periods of assets
are based on internal long-term budgets and projections, which consider external factors and market
forces, as of the end of each reporting period. Assumptions made by management are consistent with
generally accepted industry approaches and assumptions used for valuation and pricing activities.
As at December 31, 2023, there were no indications of impairment of Emera’s long-lived assets. No
impairment charges were recognized in either 2023 or 2022.
Exhibit 99.2
60
Income Taxes
 
Income taxes are determined based on expected tax treatment of transactions recorded in the
consolidated financial statements. In determining income taxes, tax legislation is interpreted in a variety of
jurisdictions, the likelihood that deferred income tax assets will be recovered from future taxable income is
assessed, and assumptions are made about expected timing of reversal of deferred income tax assets
and liabilities. Uncertainty associated with application of tax statutes and regulations and outcomes of tax
audits and appeals, requires that judgments and estimates be made in the accrual process and in
calculation of effective tax rates. Only income tax benefits that meet the “more likely than not” threshold
may be recognized or continue to be recognized. Unrecognized tax benefits are evaluated quarterly and
changes are recorded based on new information, including issuance of relevant guidance by the courts or
tax authorities and developments occurring in examinations of the Company’s tax returns.
The Company believes accounting estimates related to income taxes are critical estimates. Realization of
deferred income tax assets depends on the generation of sufficient taxable income, both operating and
capital, in future periods. A change in estimated valuation allowance could have a material impact on
reported assets and results of operations. Administrative actions of tax authorities, changes in tax law or
regulation, and uncertainty associated with the application of tax statutes and regulations, could change
the Company’s estimate of income taxes, including the potential for elimination or reduction of the
Company’s ability to realize tax benefits and to utilize deferred income tax assets.
 
Asset Retirement Obligations
Measurement of the FV of AROs requires the Company to make reasonable estimates concerning the
method and timing of settlement associated with legally obligated costs. There are uncertainties in
estimating future asset-retirement costs due to potential events, such as changing legislation or
regulations, and advances in remediation technologies. Emera has AROs associated with remediation of
generation, transmission, distribution and pipeline assets.
 
An ARO represents the FV of estimated cash flows necessary to discharge the future obligation using the
Company’s credit-adjusted risk-free rate. The amounts are reduced by actual expenditures incurred.
Estimated future cash flows are based on completed depreciation studies, remediation reports, prior
experience, estimated useful lives, and governmental regulatory requirements. The present value of the
liability is recorded and the carrying amount of the related long-lived asset is correspondingly increased.
The amount capitalized at inception is depreciated in the same manner as the related long-lived asset.
Over time, the liability is accreted to its estimated future value. Accretion expense is included as part of
“Depreciation and amortization expense”. Any accretion expense not yet approved by the regulator is
recorded in “PP&E” and included in the next depreciation study. Accordingly,
 
changes to the ARO or cost
recognition attributable to changes in the factors discussed above, should not impact the results of
operations of the Company.
Some of the Company’s transmission and distribution assets may have conditional AROs that are not
recognized in the consolidated financial statements as the FV of these obligations could not be
reasonably estimated given insufficient information to do so. A conditional ARO refers to a legal obligation
to perform an asset retirement activity in which the timing and/or method of settlement are conditional on
a future event that may or may not be within the control of the entity. Management monitors these
obligations and a liability is recognized at FV when an amount can be determined.
As at December 31, 2023, AROs recorded on the balance sheet were $192 million (2022 – $174 million).
The Company estimates the undiscounted amount of cash flow required to settle the obligations is
approximately $426 million (2022 – $429 million), which will be incurred between 2023 and 2061. The
majority of these costs will be incurred between 2028 and 2050.
Exhibit 99.2
61
Financial Instruments
The Company is required to determine the FV of all derivatives except those that qualify for the normal
purchase, normal sale exception. FV is the price that would be received for the sale of an asset or paid to
transfer a liability in an orderly arms-length transaction between market participants at the measurement
date. FV measurements are required to reflect assumptions that market participants would use in pricing
an asset or liability based on the best available information, including the risks inherent in a particular
valuation technique, such as a pricing model, and the risks inherent in the inputs to the model.
Level Determinations and Classifications
The Company uses Level 1, 2, and 3 classifications in the FV hierarchy. The FV measurement of a
financial instrument is included in only one of the three levels and is based on the lowest level input
significant to the derivation of the FV. FV is determined, directly or indirectly,
 
using inputs that are
observable for the asset or liability. Only in limited circumstances does the Company enter into
commodity transactions involving non-standard features where market observable data is not available or
have contract terms that extend beyond five years.
CHANGES IN ACCOUNTING POLICIES AND
PRACTICES
Future Accounting Pronouncements
The Company considers the applicability and impact of all ASUs issued by the Financial Accounting
Standards Board (“FASB”). The following updates have been issued by the FASB, but as allowed, have
not yet been adopted by Emera. Any ASUs not included below were assessed and determined to be
either not applicable to the Company or to have an insignificant impact on the consolidated financial
statements.
Improvements to Income Tax Disclosures
In December 2023, the FASB issued ASU 2023-09, Income Taxes
 
(Topic
 
740): Improvements to Income
Tax
 
Disclosures. The standard enhances the transparency, decision usefulness and effectiveness of
income tax disclosures by requiring consistent categories and greater disaggregation of information in the
reconciliation of income taxes computed using the enacted statutory income tax rate to the actual income
tax provision and effective income tax rate, as well as the disaggregation of income taxes paid (refunded)
by jurisdiction. The standard also requires disclosure of income (loss) before provision for income taxes
and income tax expense (recovery) in accordance with U.S. Securities and Exchange Commission
Regulation S-X 210.4-08(h), Rules of General Application – General Notes to Financial Statements:
Income Tax
 
Expense, and the removal of disclosures no longer considered cost beneficial or relevant.
The guidance will be effective for annual reporting periods beginning after December 15, 2024, and
interim periods within annual reporting periods beginning after December 15, 2025. Early adoption is
permitted. The standard will be applied on a prospective basis, with retrospective application permitted.
The Company is currently evaluating the impact of adoption of the standard on its consolidated financial
statements.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Exhibit 99.2
62
Improvements to Reportable Segment Disclosures
In November 2023, the FASB issued ASU 2023-07, Segment Reporting (Topic
 
280), Improvements to
Reportable Segment Disclosures. The change in the standard improves reportable segment disclosure
requirements, primarily through enhanced disclosures about significant segment expenses. The changes
improve financial reporting by requiring disclosure of incremental segment information on an annual and
interim basis for all public entities to enable investors to develop more decision-useful financial analyses.
The guidance will be effective for annual reporting periods beginning after December 15, 2023, and for
interim periods beginning after December 15, 2024. Early adoption is permitted. The standard will be
applied retrospectively. The Company is currently evaluating the impact of adoption of the standard on its
consolidated financial statements.
 
SUMMARY OF QUARTERLY
 
RESULTS
For the quarter ended
millions of dollars
 
Q4
Q3
Q2
Q1
Q4
Q3
Q2
Q1
(except per share amounts)
2023
2023
2023
2023
2022
2022
2022
2022
Operating revenues
$
 
1,972
$
 
1,740
$
 
1,418
$
 
2,433
$
 
2,358
$
 
1,835
$
 
1,380
$
 
2,015
Net income (loss) attributable to
common shareholders
$
 
289
$
 
101
$
 
28
$
 
560
$
 
483
$
 
167
$
 
(67)
$
 
362
Adjusted net income
$
 
175
$
 
204
$
 
162
$
 
268
$
 
249
$
 
203
$
 
156
$
 
242
EPS – basic
$
1.04
$
 
0.37
$
 
0.10
$
 
2.07
$
 
1.80
$
 
0.63
$
 
(0.25)
$
 
1.38
EPS – diluted
$
1.04
$
 
0.37
$
 
0.10
$
 
2.07
$
 
1.80
$
 
0.63
$
 
(0.25)
$
 
1.38
Adjusted EPS – basic
$
0.63
$
 
0.75
$
 
0.60
$
 
0.99
$
 
0.93
$
 
0.76
$
 
0.59
$
 
0.92
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.
1.84 5 25.5 25 P3Y P3Y 25 - 50 - 6 7 P3Y P3Y 1 6 P5Y P3Y 25.5 273.8 August 15, 2025 August 15, 2028 February 15, 2025 August 15, 2025 August 15, 2028 five
Exhibit 99.3
1
EMERA INCORPORATED
Consolidated
Financial Statements
December 31, 2023 and 2022
Exhibit 99.3
2
MANAGEMENT REPORT
Management's Responsibility for Financial Reporting
The accompanying consolidated financial statements of Emera Incorporated and the information in this
annual report are the responsibility of management and have been approved by the Board of Directors
(“Board”).
The consolidated financial statements have been prepared by management in accordance with United
States Generally Accepted Accounting Principles. When alternative accounting methods exist,
management has chosen those it considers most appropriate in the circumstances. In preparation of
these consolidated financial statements, estimates are sometimes necessary when transactions affecting
the current accounting period cannot be finalized with certainty until future periods. Management
represents that such estimates, which have been properly reflected in the accompanying consolidated
financial statements, are based on careful judgments and are within reasonable limits of materiality.
Management has determined such amounts on a reasonable basis in order to ensure that the
consolidated financial statements are presented fairly in all material respects. Management has prepared
the financial information presented elsewhere in the annual report and has ensured that it is consistent
with that in the consolidated financial statements.
Emera Incorporated maintains effective systems of internal accounting and administrative controls,
consistent with reasonable cost. Such systems are designed to provide reasonable assurance that the
financial information is reliable and accurate, and that Emera Incorporated's assets are appropriately
accounted for and adequately safeguarded.
 
The Board is responsible for ensuring that management fulfils its responsibilities for financial reporting
and is ultimately responsible for reviewing and approving the consolidated financial statements. The
Board carries out this responsibility principally through its Audit Committee.
The Audit Committee is appointed by the Board, and its members are directors who are not officers or
employees of Emera Incorporated. The Audit Committee meets periodically with management, as well as
with the internal auditors and with the external auditors, to discuss internal controls over the financial
reporting process, auditing matters and financial reporting issues, to satisfy itself that each party is
properly discharging its responsibilities, and to review the annual report, the consolidated financial
statements and the external auditors' report. The Audit Committee reports its findings to the Board for
consideration when approving the consolidated financial statements for issuance to the shareholders.
 
The Audit Committee also considers, for review by the Board and approval by the shareholders, the
appointment of the external auditors.
 
The consolidated financial statements have been audited by Ernst & Young LLP,
 
the external auditors, in
accordance with Canadian Generally Accepted Auditing Standards and with the standards of the Public
Company Accounting Oversight Board. Ernst & Young LLP has full and free access to the Audit
Committee.
February 26, 2024
“Scott Balfour”
“Gregory Blunden”
President and Chief Executive Officer
 
President and Chief Executive Officer
 
Chief Financial Officer
 
Exhibit 99.3
3
Report of Independent Registered Public Accounting Firm
To
 
the Shareholders and the Board of Directors of Emera Incorporated
Opinion on the Consolidated Financial Statements
 
We have audited the accompanying Consolidated Balance Sheets of Emera Incorporated (the
“Company“) as of December 31, 2023 and 2022, the related Consolidated Statements of Income,
Consolidated Statements of Comprehensive Income, Consolidated Statements of Changes in Equity and
Consolidated Statements of Cash Flows for the years then ended, and the related notes (collectively
referred to as the “consolidated financial statements“). In our opinion, the consolidated financial
statements present fairly, in all material respects, the consolidated financial position of the Company as of
December 31, 2023 and 2022, and the consolidated results of its operations and its consolidated cash
flows for each of the two years in the period ended December 31, 2023, in conformity with United States
generally accepted accounting principles.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company‘s management. Our
responsibility is to express an opinion on the Company‘s consolidated financial statements based on our
audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board
(United States) (“PCAOB”) and are required to be independent with respect to the Company in
accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities
and Exchange Commission and the PCAOB.
 
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that
we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial
statements are free of material misstatement, whether due to error or fraud. The Company is not required
to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part
of our audits we are required to obtain an understanding of internal control over financial reporting but not
for the purpose of expressing an opinion on the effectiveness of the Company's internal control over
financial reporting. Accordingly, we express no such opinion.
 
Our audits included performing procedures to assess the risks of material misstatement of the
consolidated financial statements, whether due to error or fraud, and performing procedures that respond
to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and
disclosures in the consolidated financial statements. Our audits also included evaluating the accounting
principles used and significant estimates made by management, as well as evaluating the overall
presentation of the consolidated financial statements. We believe that our audits provide a reasonable
basis for our opinion.
 
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.
Exhibit 99.3
4
Accounting for the effects of rate regulation
Description of the
Matter
As disclosed in note 6 of the consolidated financial statements, the
Company has $3.1 billion in regulatory assets and $1.8 billion in regulatory
liabilities. The Company’s rate-regulated subsidiaries are subject to
regulation by various federal, state and provincial regulatory authorities in
the geographic regions in which they operate. The regulatory rates are
designed to recover the prudently incurred costs of providing the regulated
products or services and provide a reasonable return on the equity invested
or assets, as applicable. In addition to regulatory assets and liabilities, rate
regulation impacts multiple financial statement line items, including, but not
limited to, property, plant and equipment (“PP&E”), operating revenues and
expenses, income taxes, and depreciation expense.
Auditing the impact of rate regulation on the Company’s financial
statements is complex and highly judgmental due to the significant
judgments made by the Company to support its accounting and disclosure
for regulatory matters when final regulatory decisions or orders have not yet
been obtained or when regulatory formulas are complex. There is also
subjectivity involved in assessing the potential impact of future regulatory
decisions on the financial statements. Although the Company expects to
recover costs from customers through rates, there is a risk that the regulator
will not approve full recovery of the costs incurred. The Company’s
judgments include making an assessment of the probability of recovery of
and return on costs incurred, of the potential disallowance of part of the cost
incurred, or of the probable refund of gains or amounts previously collected
from customers through future rates.
How We Addressed
the Matter in Our
Audit
We performed audit procedures that included, amongst others, assessing
the Company’s evaluation of the probability of future recovery for regulatory
assets, PP&E, and refund of regulatory liabilities by obtaining and reviewing
relevant regulatory orders, filings, testimony, hearings and correspondence,
and other publicly available information. For regulatory matters for which
regulatory decisions or orders have not yet been obtained, we inspected the
rate-regulated subsidiaries’ filings for any evidence that might contradict the
Company’s assertions, and reviewed other regulatory orders, filings and
correspondence for other entities within the same or similar jurisdictions to
assess the likelihood of recovery or refund in future rates based on the
regulator’s treatment of similar costs under similar circumstances. We
obtained and evaluated an analysis from the Company and corroborated
that analysis with letters from legal counsel, when appropriate, regarding
cost recoveries, gains or amounts previously collected from customers or
future changes in rates. We also assessed the methodology, accuracy and
completeness of the Company’s calculations of regulatory asset and liability
balances based on provisions and formulas outlined in rate orders and
other correspondence with the regulators. We evaluated the Company's
disclosures related to the impacts of rate regulation.
Fair Value (“FV”) measurement of derivative financial
instruments
Description of the
Matter
Held-for-trading (“HFT”) derivative assets of $348 million and liabilities of
$567 million, disclosed in note 15 to the consolidated financial statements,
are measured at FV. The Company recognized $1,037 million in realized
and unrealized gains during the year with respect to HFT derivatives.
Exhibit 99.3
5
Auditing the Company’s valuation of HFT derivatives is complex and highly
judgmental due to the complexity of the contract terms and valuation
models, and the significant estimation required in determining the FV of the
contracts. In determining the FV of HFT derivatives, significant assumptions
about future economic and market assumptions with uncertain outcomes
are used, including third-party sourced forward commodity pricing curves
based on illiquid markets, internally developed correlation factors and basis
differentials. These assumptions have a significant impact on the FV of the
HFT derivatives.
 
How We Addressed
the Matter in Our
Audit
We performed audit procedures that included, amongst others, reviewing
executed contracts and agreements for the identification of inputs and
assumptions impacting the valuation of derivatives. With the support of our
valuation specialists, we assessed the methodology and mathematical
accuracy of the Company’s valuation models and compared the commodity
pricing curves used by the Company to current market and economic data.
For the forward commodity pricing curves, we compared the Company’s
pricing curves to independently sourced pricing curves. We also assessed
the methodology and mathematical accuracy of the Company’s calculations
to develop correlation factors and basis differentials. In addition, we
assessed whether the FV hierarchy disclosures in note 16 to the
consolidated financial statements were consistent with the source of the
significant inputs and assumptions used in determining the FV of
derivatives.
 
/s/
Ernst & Young LLP
Chartered Professional Accountants
We have served as the Company‘s auditor since 1998.
Halifax, Canada
February 26, 2024
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Exhibit 99.3
6
Emera Incorporated
Consolidated Statements of Income
 
For the
Year ended December 31
millions of dollars (except per share amounts)
2023
2022
Operating revenues
 
Regulated electric
$
 
5,746
$
 
5,473
 
Regulated gas
 
1,489
 
1,681
 
Non-regulated
 
328
 
434
 
Total operating revenues (note 5)
 
7,563
 
7,588
Operating expenses
 
Regulated fuel for generation and purchased power
 
1,881
 
2,171
 
Regulated cost of natural gas
 
527
 
800
 
Operating, maintenance and general expenses ("OM&G")
 
1,879
 
1,596
 
Provincial, state, and municipal taxes
 
 
433
 
367
 
Depreciation and amortization
 
1,049
 
952
 
GBPC Impairment charge (note 22)
-
 
 
73
 
Total operating expenses
 
5,769
 
5,959
Income from operations
 
1,794
 
1,629
Income from equity investments (note 7)
 
146
 
129
Other income, net (note 8)
 
158
 
145
Interest expense, net (note 9)
 
925
 
709
Income before provision for income taxes
 
1,173
 
1,194
Income tax expense (note 10)
 
128
 
185
Net income
 
 
1,045
 
1,009
Non-controlling interest in subsidiaries
 
1
 
1
Preferred stock dividends
 
66
 
63
Net income attributable to common shareholders
$
 
978
$
 
945
Weighted average shares of common stock outstanding (in millions) (note 12)
 
Basic
 
274
 
266
 
Diluted
 
274
 
266
Earnings per common share (note 12)
 
Basic
$
 
3.57
$
 
3.56
 
Diluted
$
 
3.57
$
 
3.55
Dividends per common share declared
$
 
2.7875
$
 
2.6775
The accompanying notes are an integral part of these consolidated financial statements.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Exhibit 99.3
7
Emera Incorporated
Consolidated Statements of Comprehensive Income
 
For the
Year ended December 31
millions of dollars
2023
2022
Net income
 
$
 
1,045
$
 
1,009
Other comprehensive (loss) income, net of tax
Foreign currency translation adjustment
(1)
(270)
 
629
Unrealized gains (losses) on net investment hedges
(2) (3)
 
38
(97)
Cash flow hedges – reclassification adjustment for gains included in income
(4)
(2)
(2)
Unrealized losses on available-for-sale investment
-
 
(1)
Net change in unrecognized pension and post-retirement benefit obligation
(5)
 
(39)
 
24
Other comprehensive (loss) income
(6)
 
(273)
 
553
Comprehensive income
 
772
 
1,562
Comprehensive income attributable to non-controlling interest
 
1
 
1
Comprehensive Income of Emera Incorporated
$
 
771
$
 
1,561
The accompanying notes are an integral part of these consolidated financial statements.
1) Net of tax recovery of $7 million for the year ended December 31, 2023 (2022 – $
7
 
million expense).
2) The Company has designated $
1.2
 
billion United States dollar (USD) denominated Hybrid Notes as a hedge of the foreign
currency exposure of its net investment in USD denominated operations.
 
3) Net of tax expense of nil for the year ended December 31, 2023 (2022 – $6 million recovery).
4) Net of tax expense of nil for the year ended December 31, 2023 (2022 – $1 million recovery).
5) Net of tax expense of $
1
 
million for the year ended December 31, 2023 (2022 – $
1
 
million expense).
6) Net of tax recovery of $6 million for the year ended December 31, 2023 (2022 – $
1
 
million expense).
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Exhibit 99.3
8
Emera Incorporated
Consolidated Balance Sheets
As at
December 31
December 31
millions of dollars
2023
2022
Assets
Current assets
 
Cash and cash equivalents
$
 
567
$
 
310
 
Restricted cash (note 32)
 
21
 
22
 
Inventory (note 14)
 
790
 
769
 
Derivative instruments (notes 15 and 16)
 
174
 
296
 
Regulatory assets (note 6)
 
339
 
602
 
Receivables and other current assets (note 18)
 
1,817
 
2,897
 
3,708
 
4,896
Property, plant and equipment ("PP&E"),
net of accumulated depreciation
and amortization of $
9,994
 
and $
9,574
, respectively (note 20)
 
24,376
 
22,996
Other assets
 
Deferred income taxes (note 10)
 
208
 
237
 
Derivative instruments (notes 15 and 16)
 
66
 
100
 
Regulatory assets (note 6)
 
2,766
 
3,018
 
Net investment in direct finance and sales type leases (note 19)
 
621
 
604
 
Investments subject to significant influence (note 7)
 
1,402
 
1,418
 
Goodwill (note 22)
 
5,871
 
6,012
 
Other long-term assets (note 32)
 
462
 
461
 
11,396
 
11,850
Total assets
$
 
39,480
$
 
39,742
Liabilities and Equity
Current liabilities
 
Short-term debt (note 23)
$
 
1,433
$
 
2,726
 
Current portion of long-term debt (note 25)
 
676
 
574
 
Accounts payable
 
 
1,454
 
2,025
 
Derivative instruments (notes 15 and 16)
 
386
 
888
 
Regulatory liabilities (note 6)
 
168
 
495
 
Other current liabilities (note 24)
 
427
 
579
 
4,544
 
7,287
Long-term liabilities
 
Long-term debt (note 25)
 
17,689
 
15,744
 
Deferred income taxes (note 10)
 
2,352
 
2,196
 
Derivative instruments (notes 15 and 16)
 
118
 
190
 
Regulatory liabilities (note 6)
 
1,604
 
1,778
 
Pension and post-retirement liabilities (note 21)
 
265
 
281
 
Other long-term liabilities (note 7 and 26)
 
820
 
825
 
22,848
 
21,014
Equity
 
Common stock (note 11)
 
8,462
 
7,762
 
Cumulative preferred stock (note 28)
 
1,422
 
1,422
 
Contributed surplus
 
82
 
81
 
Accumulated other comprehensive income ("AOCI') (note 13)
 
305
 
578
 
Retained earnings
 
 
1,803
 
1,584
 
Total Emera Incorporated equity
 
12,074
 
11,427
 
Non-controlling interest in subsidiaries (note 29)
 
14
 
14
 
Total equity
 
12,088
 
11,441
Total liabilities and equity
$
 
39,480
$
 
39,742
Commitments and contingencies (note 27)
Approved on behalf of the Board of Directors
The accompanying notes are an integral part of
 
 
“M. Jacqueline Sheppard”
 
 
“Scott Balfour”
these consolidated financial statements.
 
Chair of the Board
 
 
President and Chief Executive Officer
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Exhibit 99.3
9
Emera Incorporated
Consolidated Statements of Cash Flows
 
For the
Year ended December 31
millions of dollars
2023
2022
Operating activities
Net income
 
$
 
1,045
$
 
1,009
Adjustments to reconcile net income to net cash provided by operating activities:
 
Depreciation and amortization
 
1,060
 
959
 
Income from equity investments, net of dividends
(22)
(61)
 
Allowance for funds used during construction ("AFUDC") – equity
(38)
(52)
 
Deferred income taxes, net
 
97
 
152
 
Net change in pension and post-retirement liabilities
(68)
(48)
 
NSPI Fuel adjustment mechanism ("FAM")
(88)
(162)
 
Net change in Fair Value ("FV") of derivative instruments
(666)
 
206
 
Net change in regulatory assets and liabilities
 
 
554
(471)
 
Net change in capitalized transportation capacity
 
434
(445)
 
GBPC impairment charge
-
 
 
73
 
Other operating activities, net
 
28
(13)
Changes in non-cash working capital (note 30)
(95)
(234)
Net cash provided by operating activities
 
2,241
 
913
Investing activities
 
Additions to PP&E
(2,937)
(2,596)
 
Other investing activities
 
20
 
27
Net cash used in investing activities
(2,917)
(2,569)
Financing activities
 
Change in short-term debt, net
(66)
 
1,028
 
Proceeds from short-term debt with maturities greater than 90 days
 
548
 
544
 
Repayment of short-term debt with maturities greater than 90 days
(1,086)
(680)
 
Proceeds from long-term debt, net of issuance costs
 
1,932
 
784
 
Retirement of long-term debt
(151)
(367)
 
Net (repayments) proceeds under committed credit facilities
(96)
 
511
 
Issuance of common stock, net of issuance costs
 
424
 
277
 
Dividends on common stock
(488)
(472)
 
Dividends on preferred stock
(66)
(63)
 
Other financing activities
 
(12)
(7)
Net cash provided by financing activities
 
939
 
1,555
Effect of exchange rate changes on cash, cash equivalents, and restricted cash
(7)
 
16
Net increase (decrease) in cash, cash equivalents, and restricted cash
 
256
(85)
Cash, cash equivalents, and restricted cash, beginning of year
 
332
 
417
Cash, cash equivalents, and restricted cash, end of year
$
 
588
$
 
332
Cash, cash equivalents, and restricted cash consists of:
Cash
$
 
559
$
 
302
Short-term investments
 
8
 
8
Restricted cash
 
21
 
22
Cash, cash equivalents, and restricted cash
$
 
588
$
 
332
Supplementary Information to Consolidated Statements of Cash Flows (note 30)
The accompanying notes are an integral part of these consolidated financial statements.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Exhibit 99.3
10
Emera Incorporated
Consolidated Statements of Changes in Equity
Non-
Common
Preferred
Contributed
Retained
Controlling
Total
 
Stock
Stock
Surplus
AOCI
Earnings
Interest
Equity
millions of dollars
Balance, December 31, 2022
$
 
7,762
$
 
1,422
$
 
81
$
 
578
$
 
1,584
$
 
14
$
 
11,441
Net income of Emera Inc.
-
 
-
 
-
 
-
 
 
1,044
 
1
 
1,045
Other comprehensive loss, net of tax
recovery of $
6
 
million
-
 
-
 
-
 
(273)
-
 
-
 
(273)
Dividends declared on preferred stock
(note 28)
-
 
-
 
-
 
-
 
(66)
-
 
(66)
Dividends declared on common stock
($
2.7875
/share)
-
 
-
 
-
 
-
 
(759)
-
 
(759)
Issued under the at-the-market
program ("ATM"), net of after-tax
issuance costs
 
397
-
 
-
 
-
 
-
 
-
 
 
397
Issued under the Dividend
Reinvestment Program ("DRIP"), net of
discount
 
272
-
 
-
 
-
 
-
 
-
 
 
272
Senior management stock options
exercised and Employee Common
Share Purchase Plan ("ECSPP")
 
31
-
 
 
1
-
 
-
 
-
 
 
32
Other
-
 
-
 
-
 
-
 
-
 
(1)
(1)
Balance, December 31, 2023
$
 
8,462
$
 
1,422
$
 
82
$
 
305
$
 
1,803
$
 
14
$
 
12,088
Balance, December 31, 2021
$
 
7,242
$
 
1,422
$
 
79
$
 
25
$
 
1,348
$
 
34
$
 
10,150
Net income of Emera Inc.
-
 
-
 
-
 
-
 
 
1,008
 
1
 
1,009
Other comprehensive income, net of tax
expense of $
1
 
million
-
 
-
 
-
 
 
553
-
 
-
 
 
553
Dividends declared on preferred stock
(note 28)
-
 
-
 
-
 
-
 
(63)
-
 
(63)
Dividends declared on common stock
($
2.6775
/share)
-
 
-
 
-
 
-
 
(709)
-
 
(709)
Issued under the ATM, net of after-tax
issuance costs
 
248
-
 
-
 
-
 
-
 
-
 
 
248
Issued under the DRIP,
 
net of discount
 
238
-
 
-
 
-
 
-
 
-
 
 
238
Senior management stock options
exercised and ECSPP
 
34
-
 
 
2
-
 
-
 
-
 
 
36
Disposal of non-controlling interest of
Dominica Electricity Services Ltd
("Domlec")
-
 
-
 
-
 
-
 
-
 
(20)
(20)
Other
-
 
-
 
-
 
-
 
-
 
(1)
(1)
Balance, December 31, 2022
$
 
7,762
$
 
1,422
$
 
81
$
 
578
$
 
1,584
$
 
14
$
 
11,441
The accompanying notes are an integral part of these consolidated financial statements.
Exhibit 99.3
11
Emera Incorporated
Notes to the Consolidated Financial Statements
As at December 31, 2023 and 2022
1.
 
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Nature of Operations
Emera Incorporated (“Emera” or the “Company”) is an energy and services company which invests in
electricity generation, transmission and distribution, and gas transmission and distribution.
 
At December 31, 2023, Emera’s reportable segments include the following:
 
 
Florida Electric Utility, which consists of Tampa
 
Electric (“TEC”), a vertically integrated regulated
electric utility, serving approximately
840,000
 
customers in West Central Florida;
 
Canadian Electric Utilities, which includes:
 
Nova Scotia Power Inc. (“NSPI”), a vertically integrated regulated electric utility and the
primary electricity supplier in Nova Scotia, serving approximately
549,000
 
customers; and
 
Emera Newfoundland & Labrador Holdings Inc. (“ENL”), consisting of two transmission
investments related to an
824
 
megawatt (“MW”) hydroelectric generating facility at Muskrat
Falls on the Lower Churchill River in Labrador, developed by Nalcor Energy.
 
ENL’s two
investments are:
 
a
100
 
per cent equity interest in NSP Maritime Link Inc. (“NSPML”), which developed
the Maritime Link Project, a $
1.8
 
billion transmission project, including AFUDC; and
 
a
31
 
per cent equity interest in the partnership capital of Labrador-Island Link Limited
Partnership (“LIL”), a $
3.7
 
billion electricity transmission project in Newfoundland and
Labrador.
 
 
Gas Utilities and Infrastructure, which includes:
 
Peoples Gas System Inc. (“PGS”), a regulated gas distribution utility, serving approximately
490,000
 
customers across Florida. Effective January 1, 2023, Peoples Gas System ceased
to be a division of Tampa
 
Electric Company and the gas utility was reorganized, resulting in a
separate legal entity called Peoples Gas System Inc., a wholly owned direct subsidiary of
TECO Gas Operations, Inc.;
 
New Mexico Gas Company, Inc. (“NMGC”), a regulated gas distribution utility,
 
serving
approximately
540,000
 
customers in New Mexico;
 
 
Emera Brunswick Pipeline Company Limited (“Brunswick Pipeline”), a
145
-kilometre pipeline
delivering re-gasified liquefied natural gas from Saint John, New Brunswick to the United
States border under a
25
-year firm service agreement with Repsol Energy North America
Canada Partnership (“Repsol Energy”), which expires in 2034;
 
 
SeaCoast Gas Transmission, LLC (“SeaCoast”), a regulated intrastate natural gas
transmission company offering services in Florida; and
 
a
12.9
 
per cent equity interest in Maritimes & Northeast Pipeline (“M&NP”), a
1,400
-kilometre
pipeline that transports natural gas throughout markets in Atlantic Canada and the
northeastern United States.
 
 
Other Electric Utilities, which includes Emera (Caribbean) Incorporated (“ECI”), a holding company
with regulated electric utilities that include:
 
The Barbados Light & Power Company Limited (“BLPC”), a vertically integrated regulated
electric utility on the island of Barbados, serving approximately
134,000
 
customers;
 
 
Grand Bahama Power Company Limited (“GBPC”), a vertically integrated regulated electric
utility on Grand Bahama Island, serving approximately
19,000
 
customers; and
 
a
19.5
 
per cent equity interest in St. Lucia Electricity Services Limited (“Lucelec”), a vertically
integrated regulated electric utility on the island of St. Lucia.
Exhibit 99.3
12
 
Emera’s other reportable segment includes investments in energy-related non-regulated companies
which include:
 
Emera Energy, which consists of:
 
Emera Energy Services (“EES”), a physical energy business that purchases and sells
natural gas and electricity and provides related energy asset management services;
 
 
Brooklyn Power Corporation (“Brooklyn Energy”), a
30
 
MW biomass co-generation
electricity facility in Brooklyn, Nova Scotia; and
 
a
50.0
 
per cent joint venture interest in Bear Swamp Power Company LLC (“Bear
Swamp”), a
660
 
MW pumped storage hydroelectric facility in northwestern
Massachusetts.
 
 
Emera US Finance LP (“Emera Finance”) and TECO Finance, Inc. (“TECO Finance”),
financing subsidiaries of Emera;
 
Block Energy LLC (previously Emera Technologies LLC), a wholly owned technology
company focused on finding ways to deliver renewable and resilient energy to customers;
 
Emera US Holdings Inc., a wholly owned holding company for certain of Emera’s assets
located in the United States; and
 
Other investments.
Basis of Presentation
These consolidated financial statements are prepared and presented in accordance with United States
Generally Accepted Accounting Principles (“USGAAP”) and in the opinion of management, include all
adjustments that are of a recurring nature and necessary to fairly state the financial position of Emera.
 
 
All dollar amounts are presented in Canadian dollars (“CAD”), unless otherwise indicated.
Principles of Consolidation
These consolidated financial statements include the accounts of Emera Incorporated, its majority-owned
subsidiaries, and a variable interest entity (“VIE”) in which Emera is the primary beneficiary. Emera uses
the equity method of accounting to record investments in which the Company has the ability to exercise
significant influence, and for VIEs in which Emera is not the primary beneficiary.
The Company performs ongoing analysis to assess whether it holds any VIEs or whether any
reconsideration events have arisen with respect to existing VIEs. To identify potential VIEs, management
reviews contractual and ownership arrangements such as leases, long-term purchase power agreements,
tolling contracts, guarantees, jointly owned facilities and equity investments. VIEs of which the Company
is deemed the primary beneficiary must be consolidated. The primary beneficiary of a VIE has both the
power to direct the activities of the VIE that most significantly impacts its economic performance and the
obligation to absorb losses or the right to receive benefits of the VIE that could potentially be significant to
the VIE. In circumstances where Emera has an investment in a VIE but is not deemed the primary
beneficiary, the VIE is accounted for using the equity method. For further details on VIEs, refer to note 32.
Intercompany balances and transactions have been eliminated on consolidation, except for the net profit
on certain transactions between certain non-regulated and regulated entities in accordance with
accounting standards for rate-regulated entities. The net profit on these transactions, which would be
eliminated in the absence of the accounting standards for rate-regulated entities, is recorded in non-
regulated operating revenues. An offset is recorded to PP&E, regulatory assets, regulated fuel for
generation and purchased power, or OM&G, depending on the nature of the transaction.
 
Exhibit 99.3
13
Use of Management Estimates
 
The preparation of consolidated financial statements in accordance with USGAAP requires management
to make estimates and assumptions. These may affect reported amounts of assets and liabilities at the
date of the financial statements and reported amounts of revenues and expenses during the reporting
periods. Significant areas requiring use of management estimates relate to rate-regulated assets and
liabilities, accumulated reserve for cost of removal, pension and post-retirement benefits, unbilled
revenue, useful lives for depreciable assets, goodwill and long-lived assets impairment assessments,
income taxes, asset retirement obligations (“ARO”), and valuation of financial instruments. Management
evaluates the Company’s estimates on an ongoing basis based upon historical experience, current and
expected conditions and assumptions believed to be reasonable at the time the assumption is made, with
any adjustments recognized in income in the year they arise.
Regulatory Matters
Regulatory accounting applies where rates are established by, or subject to approval by, an
 
independent
third-party regulator. Rates are designed to recover prudently incurred costs of providing regulated
products or services and provide an opportunity for a reasonable rate of return on invested capital, as
applicable. For further detail, refer to note 6.
Foreign Currency Translation
 
Monetary assets and liabilities denominated in foreign currencies are converted to CAD at the rates of
exchange prevailing at the balance sheet date. The resulting differences between the translation at the
original transaction date and the balance sheet date are included in income.
Assets and liabilities of foreign operations whose functional currency is not the Canadian dollar are
translated using exchange rates in effect at the balance sheet date and the results of operations at the
average exchange rate in effect for the period. The resulting exchange gains and losses on the assets
and liabilities are deferred on the balance sheet in AOCI.
The Company designates certain USD denominated debt held in CAD functional currency companies as
hedges of net investments in USD denominated foreign operations. The change in the carrying amount of
these investments, measured at exchange rates in effect at the balance sheet date is recorded in Other
Comprehensive Income (“OCI”).
Revenue Recognition
Regulated Electric and Gas Revenue:
Electric and gas revenues, including energy charges, demand charges, basic facilities charges and
clauses and riders, are recognized when obligations under the terms of a contract are satisfied, which is
when electricity and gas are delivered to customers over time as the customer simultaneously receives
and consumes the benefits. Electric and gas revenues are recognized on an accrual basis and include
billed and unbilled revenues. Revenues related to the sale of electricity and gas are recognized at rates
approved by the respective regulators and recorded based on metered usage, which occurs on a
periodic, systematic basis, generally monthly or bi-monthly. At the end of each reporting period, electricity
and gas delivered to customers, but not billed, is estimated and corresponding unbilled revenue is
recognized. The Company’s estimate of unbilled revenue at the end of the reporting period is calculated
by estimating the megawatt hours (“MWh”) or therms delivered to customers at the established rates
expected to prevail in the upcoming billing cycle. This estimate includes assumptions as to the pattern of
energy demand, weather, line losses and inter-period changes to customer classes.
Exhibit 99.3
14
Non-regulated Revenue:
Marketing and trading margins are comprised of Emera Energy’s corresponding purchases and sales of
natural gas and electricity, pipeline capacity costs and energy asset management revenues. Revenues
are recorded when obligations under terms of the contract are satisfied and are presented on a net basis
reflecting the nature of contractual relationships with customers and suppliers.
Energy sales are recognized when obligations under the terms of the contracts are satisfied, which is
when electricity is delivered to customers over time.
 
Other non-regulated revenues are recorded when obligations under the terms of the contract are
satisfied.
Other:
Sales, value add, and other taxes, except for gross receipts taxes discussed below, collected by the
Company concurrent with revenue-producing activities are excluded from revenue.
Franchise Fees and Gross Receipts
TEC and PGS recover from customers certain costs incurred, on a dollar-for-dollar basis, through prices
approved by the Florida Public Service Commission (“FPSC”). The amounts included in customers’ bills
for franchise fees and gross receipt taxes are included as “Regulated electric” and “Regulated gas”
revenues in the Consolidated Statements of Income. Franchise fees and gross receipt taxes payable by
TEC and PGS are included as an expense on the Consolidated Statements of Income in “Provincial, state
and municipal taxes”.
NMGC is an agent in the collection and payment of franchise fees and gross receipt taxes and is not
required by a tariff to present the amounts on a gross basis. Therefore, NMGC’s franchise fees and gross
receipt taxes are presented net with no line item impact on the Consolidated Statements of Income.
PP&E
 
PP&E is recorded at original cost, including AFUDC or capitalized interest, net of contributions received in
aid of construction.
The cost of additions, including betterments and replacements of units, are included in “PP&E” on the
Consolidated Balance Sheets. When units of regulated PP&E are replaced, renewed or retired, their cost,
plus removal or disposal costs, less salvage proceeds, is charged to accumulated depreciation, with no
gain or loss reflected in income. Where a disposition of non-regulated PP&E occurs, gains and losses are
included in income as the dispositions occur.
The cost of PP&E represents the original cost of materials, contracted services, direct labour, AFUDC for
regulated property or interest for non-regulated property, ARO, and overhead attributable to the capital
project. Overhead includes corporate costs such as finance, information technology and labour costs,
along with other costs related to support functions, employee benefits, insurance, procurement, and fleet
operating and maintenance. Expenditures for project development are capitalized if they are expected to
have a future economic benefit.
Normal maintenance projects and major maintenance projects that do not increase overall life of the
related assets are expensed as incurred. When a major maintenance project increases the life or value of
the underlying asset, the cost is capitalized.
 
Depreciation is determined by the straight-line method, based on the estimated remaining service lives of
the depreciable assets in each functional class of depreciable property. For some of Emera’s rate-
regulated subsidiaries, depreciation is calculated using the group remaining life method, which is applied
to the average investment, adjusted for anticipated costs of removal less salvage, in functional classes of
depreciable property. The service lives of regulated assets require regulatory approval.
Exhibit 99.3
15
Intangible assets, which are included in “PP&E” on the Consolidated Balance Sheets, consist primarily of
computer software and land rights. Amortization is determined by the straight-line method, based on the
estimated remaining service lives of the asset in each category. For some of Emera’s rate-regulated
subsidiaries, amortization is calculated using the amortizable life method which is applied to the net book
value to date over the remaining life of those assets. The service lives of regulated intangible assets
require regulatory approval.
Goodwill
Goodwill is calculated as the excess of the purchase price of an acquired entity over the estimated FV of
identifiable assets acquired and liabilities assumed at the acquisition date. Goodwill is carried at initial
cost less any write-down for impairment and is adjusted for the impact of foreign exchange (“FX”).
Goodwill is subject to assessment for impairment at the reporting unit level annually, or if an event or
change in circumstances indicates that the FV of a reporting unit may be below its carrying value. When
assessing goodwill for impairment, the Company has the option of first performing a qualitative
assessment to determine whether a quantitative assessment is necessary. In performing a qualitative
assessment management considers, among other factors, macroeconomic conditions, industry and
market considerations and overall financial performance.
If the Company performs a qualitative assessment and determines it is more likely than not that its FV is
less than its carrying amount, or if the Company chooses to bypass the qualitative assessment, a
quantitative test is performed. The quantitative test compares the FV of the reporting unit to its carrying
amount, including goodwill. If the carrying amount of the reporting unit exceeds its FV, an impairment loss
is recorded. Management estimates the FV of the reporting unit by using the income approach, or a
combination of the income and market approach. The income approach uses a discounted cash flow
analysis which relies on management’s best estimate of the reporting unit’s projected cash flows. The
analysis includes an estimate of terminal values based on these expected cash flows using a
methodology which derives a valuation using an assumed perpetual annuity based on the reporting unit’s
residual cash flows. The discount rate used is a market participant rate based on a peer group of publicly
traded comparable companies and represents the weighted average cost of capital of comparable
companies. For the market approach, management estimates FV based on comparable companies and
transactions within the utility industry. Significant assumptions used in estimating the FV of a reporting
unit using an income approach include discount and growth rates, rate case assumptions including future
cost of capital, valuation of the reporting unit’s net operating loss (“NOL”) and projected operating and
capital cash flows. Adverse changes in these assumptions could result in a future material impairment of
the goodwill assigned to Emera’s reporting units.
 
As of December 31, 2023, $
5,868
 
million of Emera’s goodwill represents the excess of the acquisition
purchase price for TECO Energy (TEC, PGS and NMGC reporting units) over the FV assigned to
identifiable assets acquired and liabilities assumed. In Q4 2023, qualitative assessments were performed
for NMGC and PGS given the significant excess of FV over carrying amounts calculated during the last
quantitative tests in Q4 2022 and Q4 2019, respectively. Management concluded it was more likely than
not that the FV of these reporting units exceeded their respective carrying amounts, including goodwill. As
such, no quantitative testing was required. Given the length of time passed since the last quantitative
impairment test for the TEC reporting unit, Emera elected to bypass a qualitative assessment and
performed a quantitative impairment assessment in Q4 2023 using a combination of the income and
market approach. This assessment estimated that the FV of the TEC reporting unit exceeded its carrying
amount, including goodwill, and as a result, no impairment charges were recognized.
In Q4 2022, as a result of a quantitative assessment, the Company recorded a goodwill impairment
charge of $
73
 
million, reducing the GBPC goodwill balance to
nil
 
as at December 31, 2022. For further
details, refer to note 22.
Exhibit 99.3
16
Income Taxes and Investment Tax
 
Credits
Emera recognizes deferred income tax assets and liabilities for the future tax consequences of events
that have been included in financial statements or income tax returns. Deferred income tax assets and
liabilities are determined based on the difference between the carrying value of assets and liabilities on
the Consolidated Balance Sheets, and their respective tax bases using enacted tax rates in effect for the
year in which the differences are expected to reverse. The effect of a change in income tax rates on
deferred income tax assets and liabilities is recognized in earnings in the period when the change is
enacted, unless required to be offset to a regulatory asset or liability by law or by order of the regulator.
Emera recognizes the effect of income tax positions only when it is more likely than not that they will be
realized. Management reviews all readily available current and historical information, including forward-
looking information, and the likelihood that deferred income tax assets will be recovered from future
taxable income is assessed and assumptions are made about the expected timing of reversal of deferred
income tax assets and liabilities. If management subsequently determines it is likely that some or all of a
deferred income tax asset will not be realized, a valuation allowance is recorded to reflect the amount of
deferred income tax asset expected to be realized.
 
Generally, investment tax credits are recorded as a reduction to income tax expense in the current or
future periods to the extent that realization of such benefit is more likely than not. Investment tax credits
earned on regulated assets by TEC, PGS and NMGC are deferred and amortized as required by
regulatory practices.
TEC, PGS, NMGC and BLPC collect income taxes from customers based on current and deferred income
taxes. NSPI, ENL and Brunswick Pipeline collect income taxes from customers based on income tax that
is currently payable, except for the deferred income taxes on certain regulatory balances specifically
prescribed by regulators. For the balance of regulated deferred income taxes, NSPI, ENL and Brunswick
Pipeline recognize regulatory assets or liabilities where the deferred income taxes are expected to be
recovered from or returned to customers in future years. These regulated assets or liabilities are grossed
up using the respective income tax rate to reflect the income tax associated with future revenues that are
required to fund these deferred income tax liabilities, and the income tax benefits associated with reduced
revenues resulting from the realization of deferred income tax assets. GBPC is not subject to income
taxes.
Emera classifies interest and penalties associated with unrecognized tax benefits as interest and
operating expense, respectively. For further detail, refer to note 10.
Derivatives and Hedging Activities
The Company manages its exposure to normal operating and market risks relating to commodity prices,
FX, interest rates and share prices through contractual protections with counterparties where practicable,
and by using financial instruments consisting mainly of FX forwards and swaps, interest rate options and
swaps, equity derivatives, and coal, oil and gas futures, options, forwards and swaps. In addition, the
Company has contracts for the physical purchase and sale of natural gas. These physical and financial
contracts are classified as HFT. Collectively,
 
these contracts and financial instruments are considered
derivatives.
The Company recognizes the FV of all its derivatives on its balance sheet, except for non-financial
derivatives that meet the normal purchases and normal sales (“NPNS”) exception. Physical contracts that
meet the NPNS exception are not recognized on the balance sheet; these contracts are recognized in
income when they settle. A physical contract generally qualifies for the NPNS exception if the transaction
is reasonable in relation to the Company’s business needs, the counterparty owns or controls resources
within the proximity to allow for physical delivery, the Company intends to receive physical delivery of the
commodity, and the Company deems the counterparty creditworthy.
 
The Company continually assesses
contracts designated under the NPNS exception and will discontinue the treatment of these contracts
under this exemption if the criteria are no longer met.
 
Exhibit 99.3
17
Derivatives qualify for hedge accounting if they meet stringent documentation requirements and can be
proven to effectively hedge identified risk both at the inception and over the term of the instrument.
Specifically, for cash flow hedges, change in the FV of derivatives is deferred to AOCI and recognized in
income in the same period the related hedged item is realized. Where documentation or effectiveness
requirements are not met, the derivatives are recognized at FV with any changes in FV recognized in net
income in the reporting period, unless deferred as a result of regulatory accounting.
Derivatives entered into by NSPI, NMGC and GBPC that are documented as economic hedges or for
which the NPNS exception has not been taken, are subject to regulatory accounting treatment. The
change in FV of the derivatives is deferred to a regulatory asset or liability. The gain or loss is recognized
in the hedged item when the hedged item is settled. Management believes any gains or losses resulting
from settlement of these derivatives related to fuel for generation and purchased power will be refunded
to or collected from customers in future rates. TEC has no derivatives related to hedging as a result of a
FPSC approved five-year moratorium on hedging of natural gas purchases that ended on December 31,
2022 and was extended through December 31, 2024 as a result of TEC’s 2021 rate case settlement
agreement.
Derivatives that do not meet any of the above criteria are designated as HFT, with changes in FV
normally recorded in net income of the period. The Company has not elected to designate any derivatives
to be included in the HFT category where another accounting treatment would apply.
Emera classifies gains and losses on derivatives as a component of non-regulated operating revenues,
fuel for generation and purchased power, other expenses, inventory, and OM&G, depending on the
nature of the item being economically hedged. Transportation capacity arising as a result of marketing
and trading derivative transactions is recognized as an asset in “Receivables and other current assets”
and amortized over the period of the transportation contract term. Cash flows from derivative activities are
presented in the same category as the item being hedged within operating or investing activities on the
Consolidated Statements of Cash Flows. Non-hedged derivatives are included in operating cash flows on
the Consolidated Statements of Cash Flows.
Derivatives, as reflected on the Consolidated Balance Sheets, are not offset by the FV amounts of cash
collateral with the same counterparty. Rights to reclaim cash collateral are recognized in “Receivables
and other current assets” and obligations to return cash collateral are recognized in “Accounts payable”.
Leases
The Company determines whether a contract contains a lease at inception by evaluating whether the
contract conveys the right to control the use of an identified asset for a period of time in exchange for
consideration.
 
Emera has leases with independent power producers (“IPP”) and other utilities for annual requirements to
purchase wind and hydro energy over varying contract lengths which are classified as finance leases.
These finance leases are not recorded on the Company’s Consolidated Balance Sheets as payments
associated with the leases are variable in nature and there are no minimum fixed lease payments. Lease
expense associated with these leases is recorded as “Regulated fuel for generation and purchased
power” on the Consolidated Statements of Income.
Operating lease liabilities and right-of-use assets are recognized on the Consolidated Balance Sheets
based on the present value of the future minimum lease payments over the lease term at commencement
date. As most of Emera’s leases do not provide an implicit rate, the incremental borrowing rate at
commencement of the lease is used in determining the present value of future lease payments. Lease
expense is recognized on a straight-line basis over the lease term and is recorded as “Operating,
maintenance and general” on the Consolidated Statements of Income.
Exhibit 99.3
18
Where the Company is the lessor, a lease is a sales-type lease if certain criteria are met and the
arrangement transfers control of the underlying asset to the lessee. For arrangements where the criteria
are met due to the presence of a third-party residual value guarantee, the lease is a direct financing
lease.
 
For direct finance leases, a net investment in the lease is recorded that consists of the sum of the
minimum lease payments and residual value, net of estimated executory costs and unearned income.
The difference between the gross investment and the cost of the leased item is recorded as unearned
income at the inception of the lease. Unearned income is recognized in income over the life of the lease
using a constant rate of interest equal to the internal rate of return on the lease.
 
For sales-type leases, the accounting is similar to the accounting for direct finance leases however, the
difference between the FV and the carrying value of the leased item is recorded at lease commencement
rather than deferred over the term of the lease.
 
Emera has certain contractual agreements that include lease and non-lease components, which
management has elected to account for as a single lease component.
Cash, Cash Equivalents and Restricted Cash
Cash equivalents consist of highly liquid short-term investments with original maturities of three months or
less at acquisition.
Receivables and Allowance for Credit Losses
Utility customer receivables are recorded at the invoiced amount and do not bear interest. Standard
payment terms for electricity and gas sales are approximately 30 days. A late payment fee may be
assessed on account balances after the due date. The Company recognizes allowances for credit losses
to reduce accounts receivable for amounts expected to be uncollectable. Management estimates credit
losses related to accounts receivable by considering historical loss experience, customer deposits,
current events, the characteristics of existing accounts and reasonable and supportable forecasts that
affect the collectability of the reported amount. Provisions for credit losses on receivables are expensed
to maintain the allowance at a level considered adequate to cover expected losses. Receivables are
written off against the allowance when they are deemed uncollectible.
Inventory
Fuel and materials inventories are valued at the lower of weighted-average cost or net realizable value,
unless evidence indicates the weighted-average cost will be recovered in future customer rates.
 
Asset Impairment
Long-Lived Assets:
Emera assesses whether there has been an impairment of long-lived assets and intangibles when a
triggering event occurs, such as a significant market disruption or sale of a business.
 
The assessment involves comparing undiscounted expected future cash flows to the carrying value of the
asset. When the undiscounted cash flow analysis indicates a long-lived asset is not recoverable, the
amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-
lived asset over its estimated FV. The Company’s assumptions relating to future results of operations or
other recoverable amounts, are based on a combination of historical experience, fundamental economic
analysis, observable market activity and independent market studies. The Company’s expectations
regarding uses and holding periods of assets are based on internal long-term budgets and projections,
which consider external factors and market forces, as of the end of each reporting period. The
assumptions made are consistent with generally accepted industry approaches and assumptions used for
valuation and pricing activities.
Exhibit 99.3
19
As at December 31, 2023, there are no indications of impairment of Emera’s long-lived assets.
No
impairment charges related to long-lived assets were recognized in 2023 or 2022.
 
Equity Method Investments:
The carrying value of investments accounted for under the equity method are assessed for impairment by
comparing the FV of these investments to their carrying values, if a FV assessment was completed, or by
reviewing for the presence of impairment indicators. If an impairment exists, and it is determined to be
other-than-temporary, a charge is recognized in earnings equal to the amount the carrying value exceeds
the investment’s FV.
No
 
impairment of equity method investments was required in either 2023 or 2022.
Financial Assets:
Equity investments, other than those accounted for under the equity method, are measured at FV, with
changes in FV recognized in the Consolidated Statements of Income. Equity investments that do not
have readily determinable FV are recorded at cost minus impairment, if any, plus or minus changes
resulting from observable price changes in orderly transactions for the identical or similar investments.
No
impairment of financial assets was required in either 2023 or 2022.
 
Asset Retirement Obligations
An ARO is recognized if a legal obligation exists in connection with the future disposal or removal costs
resulting from the permanent retirement, abandonment or sale of a long-lived asset. A legal obligation
may exist under an existing or enacted law or statute, written or oral contract, or by legal construction
under the doctrine of promissory estoppel.
An ARO represents the FV of estimated cash flows necessary to discharge the future obligation, using
the Company’s credit adjusted risk-free rate. The amounts are reduced by actual expenditures incurred.
Estimated future cash flows are based on completed depreciation studies, remediation reports, prior
experience, estimated useful lives, and governmental regulatory requirements. The present value of the
liability is recorded and the carrying amount of the related long-lived asset is correspondingly increased.
The amount capitalized at inception is depreciated in the same manner as the related long-lived asset.
Over time, the liability is accreted to its estimated future value. AROs are included in “Other long-term
liabilities” and accretion expense is included as part of “Depreciation and amortization”. Any regulated
accretion expense not yet approved by the regulator is recorded in “Property, plant and equipment” and
included in the next depreciation study.
Some of the Company’s transmission and distribution assets may have conditional AROs that are not
recognized in the consolidated financial statements, as the FV of these obligations could not be
reasonably estimated, given insufficient information to do so. A conditional ARO refers to a legal
obligation to perform an asset retirement activity in which the timing and/or method of settlement are
conditional on a future event that may or may not be within the control of the entity. Management
monitors these obligations and a liability is recognized at FV in the period in which an amount can be
determined.
Cost of Removal (“COR”)
TEC, PGS, NMGC and NSPI recognize non-ARO COR as regulatory liabilities. The non-ARO COR
represent funds received from customers through depreciation rates to cover estimated future non-legally
required COR of PP&E upon retirement. The companies accrue for COR over the life of the related
assets based on depreciation studies approved by their respective regulators. The costs are estimated
based on historical experience and future expectations, including expected timing and estimated future
cash outlays.
Exhibit 99.3
20
Stock-Based Compensation
The Company has several stock-based compensation plans: a common share option plan for senior
management; an employee common share purchase plan; a deferred share unit (“DSU”) plan; a
performance share unit (“PSU”) plan; and a restricted share unit (“RSU”) plan. The Company accounts for
its plans in accordance with the FV-based method of accounting for stock-based compensation. Stock-
based compensation cost is measured at the grant date, based on the calculated FV of the award, and is
recognized as an expense over the employee’s or director’s requisite service period using the graded
vesting method. Stock-based compensation plans recognized as liabilities are initially measured at FV
and re-measured at FV at each reporting date, with the change in liability recognized in income.
Employee Benefits
The costs of the Company’s pension and other post-retirement benefit programs for employees are
expensed over the periods during which employees render service. The Company recognizes the funded
status of its defined-benefit and other post-retirement plans on the balance sheet and recognizes
changes in funded status in the year the change occurs. The Company recognizes unamortized gains
and losses and past service costs in “AOCI” or “Regulatory assets” on the Consolidated Balance Sheets.
The components of net periodic benefit cost other than the service cost component are included in “Other
income, net” on the Consolidated Statements of Income. For further detail, refer to note 21.
2.
 
FUTURE ACCOUNTING PRONOUNCEMENTS
The Company considers the applicability and impact of all ASUs issued by the Financial Accounting
Standards Board (“FASB”). The following updates have been issued by the FASB, but as allowed, have
not yet been adopted by Emera. Any ASUs not included below were assessed and determined to be
either not applicable to the Company or to have an insignificant impact on the consolidated financial
statements.
Improvements to Income Tax Disclosures
In December 2023, the FASB issued ASU 2023-09, Income Taxes
 
(Topic
 
740): Improvements to Income
Tax
 
Disclosures. The standard enhances the transparency, decision usefulness and effectiveness of
income tax disclosures by requiring consistent categories and greater disaggregation of information in the
reconciliation of income taxes computed using the enacted statutory income tax rate to the actual income
tax provision and effective income tax rate, as well as the disaggregation of income taxes paid (refunded)
by jurisdiction. The standard also requires disclosure of income (loss) before provision for income taxes
and income tax expense (recovery) in accordance with U.S. Securities and Exchange Commission
Regulation S-X 210.4-08(h), Rules of General Application – General Notes to Financial Statements:
Income Tax
 
Expense, and the removal of disclosures no longer considered cost beneficial or relevant.
The guidance will be effective for annual reporting periods beginning after December 15, 2024, and
interim periods within annual reporting periods beginning after December 15, 2025. Early adoption is
permitted. The standard will be applied on a prospective basis, with retrospective application permitted.
The Company is currently evaluating the impact of adoption of the standard on its consolidated financial
statements.
Exhibit 99.3
21
Improvements to Reportable Segment Disclosures
In November 2023, the FASB issued ASU 2023-07, Segment Reporting (Topic
 
280), Improvements to
Reportable Segment Disclosures. The change in the standard improves reportable segment disclosure
requirements, primarily through enhanced disclosures about significant segment expenses. The changes
improve financial reporting by requiring disclosure of incremental segment information on an annual and
interim basis for all public entities to enable investors to develop more decision-useful financial analyses.
The guidance will be effective for annual reporting periods beginning after December 15, 2023, and for
interim periods beginning after December 15, 2024. Early adoption is permitted. The standard will be
applied retrospectively. The Company is currently evaluating the impact of adoption of the standard on its
consolidated financial statements.
3.
 
DISPOSITIONS
On March 31, 2022, Emera completed the sale of its
51.9
 
per cent interest in Domlec for proceeds which
approximated its carrying value. Domlec was included in the Company’s Other Electric reportable
segment up to its date of sale. The sale did not have a material impact on earnings.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Exhibit 99.3
22
4.
 
SEGMENT INFORMATION
Emera manages its reportable segments separately due in part to their different operating, regulatory and
geographical environments. Segments are reported based on each subsidiary’s contribution of revenues,
net income attributable to common shareholders and total assets, as reported to the Company’s chief
operating decision maker.
Florida
 
Canadian
Gas Utilities
Other
Inter-
Electric
Electric
and
Electric
Segment
millions of dollars
Utility
Utilities
Infrastructure
Utilities
Other
Eliminations
Total
For the year ended December 31, 2023
 
Operating revenues from
external customers (1)
$
 
3,548
$
 
1,671
$
 
1,510
$
 
526
$
 
308
$
 
-
 
$
 
7,563
Inter-segment revenues
(1)
 
8
-
 
 
14
-
 
 
31
(53)
 
-
 
 
Total operating revenues
 
3,556
 
1,671
 
1,524
 
526
 
339
(53)
 
7,563
Regulated fuel for generation
and purchased power
 
920
 
699
-
 
 
275
-
 
(13)
 
1,881
Regulated cost of natural gas
-
 
-
 
 
527
-
 
-
 
-
 
 
527
OM&G
 
830
 
384
 
405
 
130
 
151
(21)
 
1,879
Provincial, state and municipal
taxes
 
289
 
45
 
91
 
3
 
5
-
 
 
433
Depreciation and amortization
 
571
 
276
 
126
 
68
 
8
-
 
 
1,049
Income from equity
investments
-
 
 
109
 
21
 
4
 
12
-
 
 
146
Other income, net
 
69
 
32
 
11
 
7
 
20
 
19
 
158
Interest expense, net
(2)
 
271
 
170
 
129
 
23
 
332
-
 
 
925
Income tax expense
(recovery)
 
117
(9)
 
64
-
 
(44)
-
 
 
128
Non-controlling interest in
subsidiaries
-
 
-
 
-
 
 
1
-
 
-
 
 
1
Preferred stock dividends
-
 
-
 
-
 
-
 
 
66
-
 
 
66
Net income (loss) attributable
to common shareholders
$
 
627
$
 
247
$
 
214
$
 
37
$
(147)
$
-
 
$
 
978
Capital expenditures
$
 
1,736
$
 
450
$
 
664
$
 
63
$
 
8
$
-
 
$
 
2,921
As at December 31, 2023
Total assets
$
 
21,119
$
 
8,634
$
 
7,735
$
 
1,311
$
 
1,938
$
(1,257)
$
 
39,480
Investments subject to
significant influence
$
-
 
$
 
1,236
$
 
118
$
 
48
$
-
 
$
-
 
$
 
1,402
Goodwill
$
 
4,628
$
-
 
$
 
1,240
$
-
 
$
 
3
$
-
 
$
 
5,871
(1) All significant inter-company balances and transactions have been eliminated on consolidation except for certain transactions
between non-regulated and regulated entities. Management believes elimination of these transactions would understate PP&E,
OM&G, or regulated fuel for generation and purchased power. Inter-company
 
transactions that have not been eliminated are
measured at the amount of consideration established and agreed to by the related parties. Eliminated transactions are
 
included in
determining reportable segments.
(2) Segment net income is reported on a basis that includes internally allocated financing costs of $
95
 
million for the year ended
December 31, 2023, between the Florida Electric Utility,
 
Gas Utilities and Infrastructure and Other segments.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Exhibit 99.3
23
Florida
 
Canadian
Gas Utilities
Other
Inter-
Electric
Electric
and
Electric
Segment
millions of dollars
Utility
Utilities
Infrastructure
Utilities
Other
Eliminations
Total
For the year ended December 31, 2022
 
Operating revenues from
external customers
(1)
$
 
3,280
$
 
1,675
$
 
1,697
$
 
518
$
 
418
$
 
-
 
$
 
7,588
Inter-segment revenues
(1)
 
7
-
 
 
7
-
 
 
22
(36)
 
-
 
 
Total operating revenues
 
3,287
 
1,675
 
1,704
 
518
 
440
(36)
 
7,588
Regulated fuel for generation
and purchased power
 
1,086
 
803
-
 
 
290
-
 
(8)
 
2,171
Regulated cost of natural gas
-
 
-
 
 
800
-
 
-
 
-
 
 
800
OM&G
 
625
 
338
 
365
 
123
 
156
(11)
 
1,596
Provincial, state and municipal
taxes
 
235
 
43
 
83
 
3
 
3
-
 
 
367
Depreciation and amortization
 
507
 
259
 
118
 
61
 
7
-
 
 
952
Income from equity
investments
-
 
 
87
 
21
 
4
 
17
-
 
 
129
Other income (expenses), net
 
68
 
24
 
13
-
 
 
23
 
17
 
145
Interest expense, net
(2)
 
185
 
136
 
81
 
19
 
288
-
 
 
709
GBPC impairment charge
-
 
-
 
-
 
 
73
-
 
-
 
 
73
Income tax expense (recovery)
 
121
(8)
 
70
-
 
 
2
-
 
 
185
Non-controlling interest in
subsidiaries
-
 
-
 
-
 
 
1
-
 
-
 
 
1
Preferred stock dividends
-
 
-
 
-
 
-
 
 
63
-
 
 
63
Net income (loss) attributable
to common shareholders
$
 
596
$
 
215
$
 
221
$
(48)
$
(39)
$
-
 
$
 
945
Capital expenditures
$
 
1,425
$
 
507
$
 
574
$
 
63
$
 
6
$
-
 
$
 
2,575
As at December 31, 2022
Total assets
$
 
21,053
$
 
8,223
$
 
7,737
$
 
1,337
$
 
2,835
$
(1,443)
$
 
39,742
Investments subject to
significant influence
$
-
 
$
 
1,241
$
 
128
$
 
49
$
-
 
$
-
 
$
 
1,418
Goodwill
$
 
4,739
$
-
 
$
 
1,270
$
-
 
$
 
3
$
-
 
$
 
6,012
(1) All significant inter-company balances and transactions have been eliminated on consolidation except for certain transactions
between non-regulated and regulated entities. Management believes elimination of these transactions would understate PP&E,
OM&G, or regulated fuel for generation and purchased power. Inter-company
 
transactions that have not been eliminated are
measured at the amount of consideration established and agreed to by the related parties. Eliminated transactions are
 
included in
determining reportable segments.
(2) Segment net income is reported on a basis that includes internally allocated financing costs of $
13
 
million for the year ended
December 31, 2022, between the Gas Utilities and Infrastructure and Other segments.
Geographical Information
Revenues (based on country of origin of the product or service sold)
For the
Year ended December 31
millions of dollars
2023
2022
United States
 
5,310
$
 
5,346
Canada
 
1,727
 
1,725
Barbados
 
389
 
384
The Bahamas
 
137
 
122
Dominica
-
 
 
11
$
 
7,563
$
 
7,588
Property Plant and Equipment:
As at
 
December 31
December 31
millions of dollars
2023
2022
United States
$
 
18,588
$
 
17,382
Canada
 
4,878
 
4,689
Barbados
 
576
 
583
The Bahamas
 
334
 
342
$
 
24,376
$
 
22,996
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Exhibit 99.3
24
5.
 
REVENUE
The following disaggregates the Company’s revenue by major source:
Electric
Gas
Other
Florida
Canadian
Other
 
Gas Utilities
Inter-
Electric
Electric
Electric
and
 
Segment
millions of dollars
Utility
Utilities
Utilities
Infrastructure
Other
Eliminations
Total
For the year ended December 31, 2023
 
Regulated Revenue
Residential
$
 
2,307
$
 
910
$
 
183
$
 
724
$
-
 
$
-
 
$
 
4,124
Commercial
 
1,083
 
463
 
285
 
425
-
 
-
 
 
2,256
Industrial
 
274
 
219
 
33
 
93
-
 
(13)
 
606
Other electric
 
395
 
41
 
7
-
 
-
 
-
 
 
443
Regulatory deferrals
(522)
-
 
 
12
-
 
-
 
-
 
(510)
Other (1)
 
 
19
 
38
 
6
 
199
-
 
(8)
 
254
Finance income (2)(3)
-
 
-
 
-
 
 
62
-
 
 
62
 
Regulated revenue
$
 
3,556
$
 
1,671
$
 
526
$
 
1,503
$
-
 
$
(21)
$
 
7,235
Non-Regulated Revenue
Marketing and trading margin (4)
-
 
-
 
-
 
-
 
 
96
-
 
 
96
Other non-regulated operating
revenue
-
 
-
 
-
 
 
21
 
27
(23)
 
25
Mark-to-market (3)
-
 
-
 
-
 
-
 
 
216
(9)
 
207
 
Non-regulated revenue
$
-
 
$
-
 
$
-
 
$
 
21
$
 
339
$
(32)
$
 
328
Total operating revenues
$
 
3,556
$
 
1,671
$
 
526
$
 
1,524
$
 
339
$
(53)
$
 
7,563
For the year ended December 31, 2022
 
Regulated Revenue
Residential
$
 
1,799
$
 
834
$
 
184
$
 
800
$
-
 
$
-
 
$
 
3,617
Commercial
 
869
 
427
 
282
 
461
-
 
-
 
 
2,039
Industrial
 
230
 
353
 
32
 
83
-
 
(7)
 
691
Other electric
 
398
 
28
 
6
-
 
-
 
-
 
 
432
Regulatory deferrals
(27)
-
 
 
6
-
 
-
 
-
 
(21)
Other (1)
 
 
18
 
33
 
8
 
283
-
 
(7)
 
335
Finance income (2)(3)
-
 
-
 
-
 
 
61
-
 
-
 
 
61
 
Regulated revenue
$
 
3,287
$
 
1,675
$
 
518
$
 
1,688
$
-
 
$
(14)
 
7,154
Non-Regulated
 
Marketing and trading margin (4)
-
 
-
 
-
 
-
 
 
143
-
 
 
143
Other non-regulated operating
revenue
-
 
-
 
-
 
 
16
 
16
(10)
 
22
Mark-to-market (3)
-
 
-
 
-
 
-
 
 
281
(12)
 
269
 
Non-regulated revenue
$
-
 
$
-
 
$
-
 
$
 
16
$
 
440
$
(22)
 
434
Total operating revenues
$
 
3,287
$
 
1,675
$
 
518
$
 
1,704
$
 
440
$
(36)
$
 
7,588
(1) Other includes rental revenues, which do not represent revenue from contracts with customers.
(2) Revenue related to Brunswick Pipeline's service agreement with Repsol Energy Canada.
(3) Revenue which does not represent revenues from contracts with customers.
(4) Includes gains (losses) on settlement of energy related derivatives, which do not represent revenue from contracts
 
with
customers.
Remaining Performance Obligations:
Remaining performance obligations primarily represent gas transportation contracts, lighting contracts,
and long-term steam supply arrangements with fixed contract terms. As of December 31, 2023, the
aggregate amount of the transaction price allocated to remaining performance obligations was $
488
million (2022 – $
450
 
million). This amount includes $
134
 
million of future performance obligations related
to a gas transportation contract between SeaCoast and PGS through
2040
. This amount excludes
contracts with an original expected length of one year or less and variable amounts for which Emera
recognizes revenue at the amount to which it has the right to invoice for services performed. Emera
expects to recognize revenue for the remaining performance obligations through
2043
.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Exhibit 99.3
25
6. REGULATORY
 
ASSETS AND LIABILITIES
 
Regulatory assets represent prudently incurred costs that have been deferred because it is probable they
will be recovered through future rates or tolls collected from customers. Management believes existing
regulatory assets are probable for recovery either because the Company received specific approval from
the applicable regulator, or due to regulatory precedent established for similar circumstances. If
management no longer considers it probable that an asset will be recovered, deferred costs are charged
to income.
 
Regulatory liabilities represent obligations to make refunds to customers or to reduce future revenues for
previous collections. If management no longer considers it probable that a liability will be settled, the
related amount is recognized in income.
For regulatory assets and liabilities that are amortized, the amortization is as approved by the respective
regulator.
As at
December 31
December 31
millions of dollars
 
2023
2022
Regulatory assets
Deferred income tax regulatory assets
$
 
1,233
$
 
1,166
TEC capital cost recovery for early retired assets
 
 
671
 
674
NSPI FAM
 
395
 
307
Pension and post-retirement medical plan
 
364
 
369
Cost recovery clauses
 
151
 
707
Deferrals related to derivative instruments
 
88
 
30
Storm cost recovery clauses
 
 
52
 
138
Environmental remediations
 
26
 
27
Stranded cost recovery
 
25
 
27
NMGC winter event gas cost recovery
-
 
 
69
Other
 
100
 
106
$
 
3,105
$
 
3,620
Current
$
 
339
$
 
602
Long-term
 
2,766
 
3,018
Total regulatory assets
 
$
 
3,105
$
 
3,620
Regulatory liabilities
Accumulated reserve – COR
 
849
 
895
Deferred income tax regulatory liabilities
 
830
 
877
Cost recovery clauses
 
 
32
 
70
BLPC Self-insurance fund ("SIF") (note 32)
 
29
 
30
Deferrals related to derivative instruments
 
17
 
230
NMGC gas hedge settlements (note 18)
-
 
 
162
Other
 
15
 
9
$
 
1,772
$
 
2,273
Current
$
 
168
$
 
495
Long-term
 
1,604
 
1,778
Total regulatory liabilities
$
 
1,772
$
 
2,273
Deferred Income Tax Regulatory Assets and Liabilities
To
 
the extent deferred income taxes are expected to be recovered from or returned to customers in future
years, a regulatory asset or liability is recognized as appropriate.
 
Exhibit 99.3
26
TEC Capital Cost Recovery for Early Retired Assets
This regulatory asset is related to the remaining net book value of Big Bend Power Station Units 1
through 3 and smart meter assets that were retired. The balance earns a rate of return as permitted by
the FPSC and is recovered as a separate line item on customer bills for a period of
15 years
. This
recovery mechanism is authorized by and survives the term of the settlement agreement approved by the
FPSC in 2021. For further information, refer to “Big Bend Modernization Project” in the TEC section
below.
NSPI FAM
NSPI has a FAM, approved by the UARB, allowing NSPI to recover fluctuating fuel and certain fuel-
related costs from customers through regularly scheduled fuel rate adjustments. Differences between
prudently incurred fuel costs and amounts recovered from customers through electricity rates in a year
are deferred to a FAM regulatory asset or liability and recovered from or returned to customers in
subsequent periods.
 
Pension and Post-Retirement Medical Plan
 
This asset is primarily related to the deferred costs of pension and post-retirement benefits at TEC, PGS
and NMGC. It is included in rate base and earns a rate of return as permitted by the FPSC and NMPRC,
as applicable. It is amortized over the remaining service life of plan participants.
Cost Recovery Clauses
 
These assets and liabilities are related to TEC, PGS and NMGC clauses and riders. They are recovered
or refunded through cost-recovery mechanisms approved by the FPSC or New Mexico Public Regulation
Commission (“NMPRC”), as applicable, on a dollar-for-dollar basis in a subsequent period.
Deferrals Related to Derivative Instruments
This asset is primarily related to NSPI deferring changes in FV of derivatives that are documented as
economic hedges or that do not qualify for NPNS exemption, as a regulatory asset or liability as approved
by the UARB. The realized gain or loss is recognized when the hedged item settles in regulated fuel for
generation and purchased power, other income, inventory,
 
or OM&G, depending on the nature of the item
being economically hedged.
Storm Cost Recovery Clauses
TEC and PGS Storm Reserve:
The storm reserve is for hurricanes and other named storms that cause significant damage to TEC and
PGS systems. As allowed by the FPSC, if charges to the storm reserve exceed the storm liability, the
excess is to be carried as a regulatory asset. TEC and PGS can petition the FPSC to seek recovery of
restoration costs over a 12-month period or longer, as determined by the FPSC, as well as replenish the
reserve. In 2022, TEC and PGS were impacted by Hurricane Ian. For further information, refer to “TEC
Storm Reserve” in the Florida Electric Utility section below.
NSPI Storm Rider:
NSPI has a UARB approved storm rider for each of 2023, 2024 and 2025, which gives NSPI the option to
apply to the UARB for recovery of costs if major storm restoration expenses exceed approximately $
10
million in a given year.
 
GBPC Storm Restoration:
This asset represents storm restoration costs incurred by GBPC. GBPC maintains insurance for its
generation facilities and, as with most utilities, its transmission and distribution networks are not covered
by commercial insurance.
 
Exhibit 99.3
27
In January 2020, the Grand Bahama Port Authority (“GBPA”) approved recovery of $
15
 
million USD of
2019 costs related to Hurricane Dorian, over a five-year period from 2021 through 2025.
Restoration costs associated with Hurricane Matthew in 2016 are being recovered through an approved
fuel charge. For further information, refer to “Storm Restoration Costs – Hurricane Matthew” in the GBPC
section below.
Environmental Remediations
This asset is primarily related to PGS costs associated with environmental remediation at Manufactured
Gas Plant sites. The balance is included in rate base, partially offsetting the related liability, and earns a
rate of return as permitted by the FPSC. The timing of recovery is based on a settlement agreement
approved by the FPSC.
Stranded Cost Recovery
Due to decommissioning of a GBPC steam turbine in 2012, the GBPA approved recovery of a $
21
 
million
USD stranded cost through electricity rates; it is included in rate base and expected to be included in
rates in future years.
 
NMGC Winter Event Gas Cost Recovery
In February 2021, the State of New Mexico experienced an extreme cold weather event that resulted in
an incremental $
108
 
million USD for gas costs above what it would normally have paid during this period.
NMGC normally recovers gas supply and related costs through a purchased gas adjustment clause
(“PGAC”). On June 15, 2021, the NMPRC approved recovery of $
108
 
million USD and related borrowing
costs in customer rates over a period of
30 months
 
from July 1, 2021, to December 31, 2023.
Accumulated Reserve – COR
This regulatory liability represents the non-ARO COR reserve in TEC, PGS, NMGC and NSPI. AROs
represent the FV of estimated cash flows associated with the Company’s legal obligation to retire its
PP&E. Non-ARO COR represent estimated funds received from customers through depreciation rates to
cover future COR of PP&E value upon retirement that are not legally required. This reduces rate base for
ratemaking purposes. This liability is reduced as COR are incurred and increased as depreciation is
recorded for existing assets and as new assets are put into service.
NMGC Gas Hedge Settlements
This regulatory liability represents regulatory deferral of gas options exercised above strike price but
settled subsequent to the period end. The value from cash settlement of these options flows to customers
via the PGAC.
Other Regulatory Assets and Liabilities
Comprised of regulatory assets and liabilities that are not individually significant.
Exhibit 99.3
28
Regulatory Environments and Updates
Florida Electric Utility
TEC is regulated by the FPSC and is also subject to regulation by the Federal Energy Regulatory
Commission. The FPSC sets rates at a level that allows utilities such as TEC to collect total revenues or
revenue requirements equal to their cost of providing service, plus an appropriate return on invested
capital. Base rates are determined in FPSC rate setting hearings which can occur at the initiative of TEC,
the FPSC or other interested parties.
TEC’s approved regulated return on equity (“ROE”) range for 2023 and 2022 was
9.25
 
per cent to
11.25
per cent based on an allowed equity capital structure of
54
 
per cent. An ROE of
10.20
 
per cent (2022 –
10.20
 
per cent) is used for the calculation of the return on investments for clauses.
Base Rates:
On February 1, 2024, TEC notified the FPSC of its intent to seek a base rate increase effective January
2025, reflecting a revenue requirement increase of approximately $
290
 
to $
320
 
million USD and
additional adjustments of approximately $
100
 
million USD and $
70
 
million USD for 2026 and 2027,
respectively. TEC’s proposed rates include recovery of solar generation projects, energy storage
capacity, a more resilient and modernized energy control center, and numerous other resiliency and
reliability projects. The filing range amounts are estimates until TEC files its detailed case in April 2024.
The FPSC is scheduled to hear the case in Q3 2024.
On August 16, 2023, TEC filed a petition to implement the 2024 Generation Base Rate Adjustment
provisions pursuant to the 2021 rate case settlement agreement. Inclusive of TEC’s ROE adjustment, the
increase of $
22
 
million USD was approved by the FPSC on November 17, 2023.
Fuel Recovery and Other Cost Recovery Clauses:
TEC has a fuel recovery clause approved by the FPSC, allowing the opportunity to recover fluctuating
fuel expenses from customers through annual fuel rate adjustments. The FPSC annually approves cost-
recovery rates for purchased power, capacity,
 
environmental and conservation costs, including a return
on capital invested. Differences between prudently incurred fuel costs and the cost-recovery rates and
amounts recovered from customers through electricity rates in a year are deferred to a regulatory asset or
liability and recovered from or returned to customers in subsequent periods.
 
On January 23, 2023, TEC requested an adjustment to its fuel charges to recover the 2022 fuel under-
recovery of $
518
 
million USD over a period of
21 months
. The request also included an adjustment to
2023 projected fuel costs to reflect the reduction in natural gas prices since September 2022 for a
projected reduction of $
170
 
million USD for the balance of 2023. The changes were approved by the
FPSC on March 7, 2023, and were effective beginning on April 1, 2023.
The mid-course fuel adjustment requested by TEC on January 19, 2022, was approved on March 1,
2022. The rate increase, effective with the first billing cycle in April 2022, covered higher fuel and capacity
costs of $
169
 
million USD, and was spread over customer bills from April 1, 2022 through December
2022.
Big Bend Modernization Project:
TEC invested $
876
 
million USD, including $
91
 
million USD of AFUDC, between 2018 and 2022 to
modernize the Big Bend Power Station. The modernization project repowered Big Bend Unit 1 with
natural gas combined-cycle technology and eliminated coal as this unit’s fuel. As part of the
modernization project, TEC in 2020 retired the Unit 1 components that would not be used in the
modernized plant and did the same for Big Bend Unit 2 in 2021. TEC retired Big Bend Unit 3 in 2023 as it
was in the best interests of the customers from an economic, environmental risk and operational
perspective. On December 31, 2021, the remaining costs of the retired Big Bend coal generation assets,
Units 1 through 3, of $
636
 
million USD and $
267
 
million USD in accumulated depreciation were
reclassified to a regulatory asset on the balance sheet.
Exhibit 99.3
29
TEC’s 2021 settlement agreement provides for cost recovery of the Big Bend Modernization project in two
phases. The first phase was a revenue increase to cover the costs of the assets in service during 2022,
among other items. The remainder of the project costs were recovered as part of the 2023 subsequent
year adjustment. The settlement agreement also includes a new charge to recover the remaining costs of
the retired Big Bend coal generation assets, Units 1 through 3, which are spread over
15 years
, effective
January 1, 2022. This recovery mechanism was authorized by and survives the term of the settlement
agreement approved by the FPSC in 2021.
Storm Reserve:
In September 2022, TEC was impacted by Hurricane Ian, with $
119
 
million USD of restoration costs
charged against TEC’s FPSC approved storm reserve. Total restoration costs charged to the storm
reserve exceeded the reserve balance and have been deferred as a regulatory asset for future recovery.
 
On January 23, 2023, TEC petitioned the FPSC for recovery of the storm reserve regulatory asset and
the replenishment of the balance in the storm reserve to the approved storm reserve level of $
56
 
million
USD, for a total of $
131
 
million USD. The storm cost recovery surcharge was approved by the FPSC on
March 7, 2023, and TEC began applying the surcharge in April 2023. Subsequently, on November 9,
2023, the FPSC approved TEC’s petition, filed on August 16, 2023, to update the total storm cost
collection to $
134
 
million USD. It also changed the collection of the expected remaining balance of $
29
million USD as of December 31, 2023, from over the first three months of 2024 to over the 12 months of
2024. The storm recovery is subject to review of the underlying costs for prudency and accuracy by the
FPSC.
In Q3 2023, TEC was impacted by Hurricane Idalia. The related storm restoration costs were
approximately $
35
 
million USD, which were charged to the storm reserve regulatory asset, resulting in
minimal impact to earnings.
Storm Protection Cost Recovery Clause and Settlement Agreement:
The Storm Protection Plan (“SPP”) Cost Recovery Clause provides a process for Florida investor-owned
utilities, including TEC, to recover transmission and distribution storm hardening costs for incremental
activities not already included in base rates. Differences between prudently incurred clause-recoverable
costs and amounts recovered from customers through electricity rates in a year are deferred and
recovered from or returned to customers in a subsequent year. A settlement agreement was approved on
August 10, 2020, and TEC’s cost recovery began in January 2021. The current approved plan addressed
the years 2023, 2024 and 2025 and was approved by the FPSC on October 4, 2022.
Canadian Electric Utilities
NSPI
NSPI is a public utility as defined in the Public Utilities Act of Nova Scotia (“Public Utilities Act”) and is
subject to regulation under the Public Utilities Act by the UARB. The Public Utilities Act gives the UARB
supervisory powers over NSPI’s operations and expenditures. Electricity rates for NSPI’s customers are
also subject to UARB approval. NSPI is not subject to a general annual rate review process, but rather
participates in hearings held from time to time at NSPI’s or the UARB’s request.
NSPI is regulated under a cost-of-service model, with rates set to recover prudently incurred costs of
providing electricity service to customers and provide a reasonable return to investors. NSPI’s approved
regulated ROE range for 2023 and 2022 was
8.75
 
per cent to
9.25
 
per cent based on an actual five
quarter average regulated common equity component of up to
40
 
per cent of approved rate base.
Exhibit 99.3
30
General Rate Application (“GRA”):
On February 2, 2023, the UARB approved the GRA settlement agreement between NSPI, key customer
representatives and participating interest groups. This resulted in average customer rate increases of
6.9
per cent effective on February 2, 2023, and further average increases of
6.5
 
per cent on January 1, 2024,
with any under or over-recovery of fuel costs addressed through the UARB’s established FAM process. It
also established a storm rider and a demand-side management rider. On March 27, 2023, the UARB
issued a final order approving the electricity rates effective on February 2, 2023.
Fuel Recovery:
For the period of 2020 through 2022, NSPI operated under a three-year fuel stability plan with no fuel rate
adjustments related to the under-recovery of fuel and fuel-related costs in the period.
 
On January 29, 2024, NSPI applied to the UARB for approval of a structure that would begin to recover
the outstanding FAM balance. As part of the application, NSPI requested approval for the sale of $
117
million of the FAM regulatory asset to Invest Nova Scotia, a provincial Crown corporation, with the
proceeds paid to NSPI upon approval. NSPI has requested approval to collect from customers the
amortization and financing costs of $
117
 
million on behalf of Invest Nova Scotia over a
10
-year period,
and remit those amounts to Invest Nova Scotia as collected, reducing short-term customer rate increases
relative to the currently established FAM process. If approved, this portion of the FAM regulatory asset
would be removed from the Consolidated Balance Sheets and NSPI would collect the balance on behalf
of Invest Nova Scotia in NSPI rates beginning in 2024.
 
Storm Rider:
The storm rider was effective as of the GRA decision date. The application for deferral and recovery of
the storm rider is made in the year following the year of the incurred cost, with recovery beginning in the
year after the application. Total major storm restoration expense for 2023 was $
31
 
million, of which $
21
million was deferred to the storm rider.
Hurricane Fiona:
On October 31, 2023, NSPI submitted an application to the UARB to defer $
24
 
million in incremental
operating costs incurred during Hurricane Fiona storm restoration efforts in September 2022. NSPI is
seeking amortization of the costs over a period to be approved by the UARB during a future rate setting
process. At December 31, 2023, the $
24
 
million is deferred to “Other long-term assets”, pending UARB
approval.
 
Maritime Link:
The Maritime Link is a $
1.8
 
billion (including AFUDC) transmission project including
two
170
-kilometre
sub-sea cables, connecting the island of Newfoundland and Nova Scotia. The Maritime Link entered
service on January 15, 2018 and NSPI started interim assessment payments to NSPML at that time.
 
Any difference between the amounts recovered from customers through rates and those approved by the
UARB through the NSPML interim assessment application will be addressed through the FAM.
 
Nova Scotia Cap-and-Trade (“Cap-and-Trade”)
 
Program:
As of December 31, 2022, the FAM included a cumulative $
166
 
million in fuel costs related to the accrued
purchase of emissions credits and $
6
 
million related to credits purchased from provincial auctions. On
March 16, 2023, the Province of Nova Scotia provided NSPI with emissions allowances sufficient to
achieve compliance for the 2019 through 2022 period. As such, compliance costs accrued of $
166
 
million
were reversed in Q1 2023. The credits NSPI purchased from provincial auctions in the amount of $
6
million were not refunded and no further costs were incurred to achieve compliance with the Cap-and-
Trade Program.
Exhibit 99.3
31
Extra Large Industrial Active Demand Tariff:
On July 5, 2023, NSPI received approval from the UARB to change the methodology in which fuel cost
recovery from an industrial customer is calculated. Due to significant volatility in commodity prices in
2022, the previous methodology did not result in a reasonable determination of the fuel cost to serve this
customer. The change in methodology,
 
effective January 1, 2022, results in a shifting of fuel costs from
this industrial customer to the FAM. This adjustment was recorded in Q2 2023 resulting in a $
51
 
million
increase to the FAM regulatory asset and an offsetting decrease to unbilled revenue within Receivables
and other current assets. This adjustment had minimal impact on earnings.
NSPML
Equity earnings from the Maritime Link are dependent on the approved ROE and operational
performance of NSPML. NSPML’s approved regulated ROE range is
8.75
 
per cent to
9.25
 
per cent,
based on an actual five-quarter average regulated common equity component of up to
30
 
per cent.
 
Nalcor’s Nova Scotia Block (“NS Block”) delivery obligations commenced on August 15, 2021 and
delivery will continue over the next
35 years
 
pursuant to the agreements.
 
In February 2022, the UARB issued its decision and Board Order approving NSPML’s requested rate
base of approximately $
1.8
 
billion less $
9
 
million of costs ($
7
 
million after-tax) that would not have
otherwise been recoverable if incurred by NSPI.
On October 4, 2023 and January 31, 2024, the UARB issued decisions providing clarification on
remaining aspects of the Maritime Link holdback mechanism primarily relating to release of past and
future holdback amounts and requirements to end the holdback mechanism. In these decisions, the
UARB agreed with the Company’s submission that $
12
 
million ($
8
 
million related to 2022 and $
4
 
million
relating to 2023) of the previously recorded holdback remain credited to NSPI’s FAM, with the remainder
released to NSPML and recorded in Emera’s “Income from equity investments. NSPML did not record
any additional holdback in Q4 2023. The UARB also confirmed that the holdback mechanism will cease
once
90
 
per cent of NS Block deliveries are achieved for 12 consecutive months (subject to potential
relief for planned outages or exceptional circumstances) and the net outstanding balance of previously
underdelivered NS Block energy is less than
10
 
per cent of the contracted annual amount. In addition, the
UARB increased the monthly holdback amount from $
2
 
million to $
4
 
million beginning December 1, 2023.
 
On December 21, 2023, NSPML received approval to collect up to $
164
 
million (2023 – $
164
 
million)
from NSPI for the recovery of costs associated with the Maritime Link in 2024; subject to a holdback of up
to $
4
 
million a month, as discussed above.
Gas Utilities and Infrastructure
PGS
PGS is regulated by the FPSC. The FPSC sets rates at a level that allows utilities such as PGS to collect
total revenues or revenue requirements equal to their cost of providing service, plus an appropriate return
on invested capital.
PGS’s approved ROE range for 2023 and 2022 was
8.9
 
per cent to
11.0
 
per cent with a
9.9
 
per cent
midpoint, based on an allowed equity capital structure of
54.7
 
per cent.
 
Base Rates:
On April 4, 2023, PGS filed a rate case with the FPSC and a hearing for the matter was held in
September 2023. On November 9, 2023, the FPSC approved a $
118
 
million USD increase to base
revenues which includes $
11
 
million USD transferred from the cast iron and bare steel replacement rider,
for a net incremental increase to base revenues of $
107
 
million USD. This reflects a
10.15
 
per cent
midpoint ROE with an allowed equity capital structure of
54.7
 
per cent.  A final order was issued on
December 27, 2023, with the new rates effective January 2024.
Exhibit 99.3
32
The 2020 PGS rate case settlement provided the ability to reverse a total of $
34
 
million USD of
accumulated depreciation through 2023. PGS reversed $
20
 
million USD of accumulated depreciation in
2023 and $
14
 
million USD in 2022.
Fuel Recovery:
PGS recovers the costs it pays for gas supply and interstate transportation for system supply through its
PGAC. This clause is designed to recover actual costs incurred by PGS for purchased gas, gas storage
services, interstate pipeline capacity, and other related items associated with the purchase, distribution,
and sale of natural gas to its customers. These charges may be adjusted monthly based on a cap
approved annually by the FPSC.
Recovery of Energy Conservation and Pipeline Replacement Programs:
The FPSC annually approves a conservation charge that is intended to permit PGS to recover prudently
incurred expenditures in developing and implementing cost effective energy conservation programs which
are required by Florida law and approved and monitored by the FPSC. PGS also has a Cast Iron/Bare
Steel Pipe Replacement clause to recover the cost of accelerating the replacement of cast iron and bare
steel distribution lines in the PGS system. In February 2017, the FPSC approved expansion of the Cast
Iron/Bare Steel clause to allow recovery of accelerated replacement of certain obsolete plastic pipe. The
majority of cast iron and bare steel pipe has been removed from its system, with replacement of obsolete
plastic pipe continuing until 2028 under the rider.
 
NMGC
NMGC is subject to regulation by the NMPRC. The NMPRC sets rates at a level that allows NMGC to
collect total revenues equal to its cost of providing service, plus an appropriate return on invested capital.
 
NMGC’s approved ROE for 2023 and 2022 was
9.375
 
per cent on an allowed equity capital structure of
52
 
per cent.
 
Base Rates:
On September 14, 2023, NMGC filed a rate case with the NMPRC for new base rates to become effective
Q4 2024. NMGC requested $
49
 
million USD in annual base revenues primarily as a result of increased
operating costs and capital investments in pipeline projects and related infrastructure. The rate case
includes a requested ROE of
10.5
 
per cent.
Fuel Recovery:
NMGC recovers gas supply costs through a PGAC. This clause recovers actual costs for purchased gas,
gas storage services, interstate pipeline capacity, and other related items associated with the purchase,
transmission, distribution, and sale of natural gas to its customers. On a monthly basis, NMGC can adjust
charges based on the next month’s expected cost of gas and any prior month under-recovery or over-
recovery. The NMPRC requires that NMGC annually file a reconciliation of the PGAC period costs and
recoveries. NMGC must file a PGAC Continuation Filing with the NMPRC every four years to establish
that the continued use of the PGAC is reasonable and necessary. NMGC received approval of its PGAC
Continuation in December 2020, for the four-year period ending December 2024.
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.
Exhibit 99.3
33
Brunswick Pipeline
 
Brunswick Pipeline is a
145
-kilometre pipeline delivering natural gas from the Saint John LNG import
terminal near Saint John, New Brunswick to markets in the northeastern United States. Brunswick
Pipeline entered into a
25
-year firm service agreement commencing in July 2009 with Repsol Energy
North America Canada Partnership. The agreement provides for a predetermined toll increase in the fifth
and fifteenth year of the contract. The pipeline is considered a Group II pipeline regulated by the Canada
Energy Regulator (“CER”). The CER Gas Transportation Tariff
 
is filed by Brunswick Pipeline in
compliance with the requirements of the CER Act and sets forth the terms and conditions of the
transportation rendered by Brunswick Pipeline.
Other Electric Utilities
BLPC
 
BLPC is regulated by the Fair Trading Commission (“FTC”), under the Utilities Regulation (Procedural)
Rules 2003. BLPC is regulated under a cost-of-service model, with rates set to recover prudently incurred
costs of providing electricity service to customers plus an appropriate return on capital invested. BLPC’s
approved regulated return on rate base was
10
 
per cent for 2023 and 2022.
Licenses:
BLPC currently operates pursuant to a single integrated license to generate, transmit and distribute
electricity on the island of Barbados until 2028. In 2019, the Government of Barbados passed legislation
requiring multiple licenses for the supply of electricity. In 2021, BLPC reached commercial agreement with
the Government of Barbados for each of the license types, subject to the passage of implementing
legislation. The timing of the final enactment is unknown at this time, but BLPC will work towards the
implementation of the licenses once enacted.
Base Rates:
In 2021, BLPC submitted a general rate review application to the FTC. In September 2022, the FTC
granted BLPC interim rate relief, allowing an increase in base rates of approximately $
1
 
million USD per
month. On February 15, 2023, the FTC issued a decision on the
 
application which included the following
significant items: an allowed regulatory ROE of
11.75
 
per cent, an equity capital structure of
55
 
per cent,
a directive to update the major components of rate base to September 16, 2022, and a directive to
establish regulatory liabilities related to the self-insurance fund of $
50
 
million USD, prior year benefits
recognized on remeasurement of deferred income taxes of $
5
 
million USD, and accumulated depreciation
of $
16
 
million USD. On March 7, 2023, BLPC filed a Motion for Review and Variation (the “Motion”) and
applied for a stay of the FTC’s decision, which was subsequently granted. On November 20, 2023, the
FTC issued their decision dismissing the Motion. Interim rates continue to be in effect through to a date to
be determined in a final decision and order.
 
On December 1, 2023, BLPC appealed certain aspects of the FTC’s February 15 and November 20,
2023, decisions to the Supreme Court of Barbados in the High Court of Justice (the “Court”) and
requested that they be stayed. On December 11, 2023, the Court granted the stay.
 
BLPC’s position is
that the FTC made errors of law and jurisdiction in their decisions and believes the success of the appeal
is probable, and as a result, the adjustments to BLPC’s final rates and rate base, including any
adjustments to regulatory assets and liabilities, have not been recorded at this time.
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.
Exhibit 99.3
34
Clean Energy Transition Program (“CETP”):
On May 31, 2023, the FTC approved BLPC’s application to establish an alternative cost recovery
mechanism to recover prudently incurred costs associated with its CETP (the “Decision”). The
mechanism is intended to facilitate the timely recovery between rate cases of costs associated with
approved renewable energy assets. BLPC will be required to submit an individual application for the
recovery of costs of each asset through the cost recovery mechanism, meeting the minimum criteria as
set out in the Decision. On October 5, 2023, BLPC applied to the FTC to recover the costs of a battery
storage system through the CETP.
Fuel Hedging:
On October 21, 2021, the FTC approved BLPC’s application to implement a fuel hedging program which
will be incorporated into the calculation of the fuel clause adjustment. On November 10, 2021, BLPC
requested the FTC review the required
50
/50 cost sharing arrangement between BLPC and customers in
relation to the hedging administrative costs, or any gains and losses associated with the hedging
program.
GBPC
GBPC is regulated by the GBPA. The GBPA
 
has granted GBPC a licensed, regulated and exclusive
franchise to produce, transmit and distribute electricity on the island until 2054. Rates are set to recover
prudently incurred costs of providing electricity service to customers plus an appropriate return on rate
base. GBPC’s approved regulated return on rate base was
8.32
 
per cent for 2023 (2022 –
8.23
 
per cent).
Base Rates:
There is a fuel pass-through mechanism and tariff review policy with new rates submitted every three
years. On January 14, 2022, the GBPA issued its decision on GBPC’s application for rate review that was
filed with the GBPA on September 23, 2021. The decision, which became effective April 1, 2022, allows
for an increase in revenues of $
3.5
 
million USD. The rates include a regulatory ROE of
12.84
 
per cent.
Fuel Recovery:
GBPC’s fuel costs flow through a fuel pass-through mechanism which provides the opportunity to recover
all prudently incurred fuel costs from customers in a timely manner.
Effective November 1, 2022, GBPC’s fuel pass through charge was increased due to an increase in
global oil prices impacting the unhedged fuel cost. In 2023, the fuel pass through charge was adjusted
monthly, in-line with actual fuel costs.
Storm Restoration Costs – Hurricane Matthew:
As part of the recovery of costs incurred as a result of Hurricane Matthew, in 2016, the GBPA approved a
fixed per kWh fuel charge and allowed the difference between this and the actual cost of fuel to be
applied to the Hurricane Matthew regulatory asset. As part of its decision on GBPC’s application for rate
review, issued January 14, 2022, and effective April 1, 2022, the GBPA
 
approved the continued
amortization of the remaining regulatory asset over the three year period ending December 31, 2024.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Exhibit 99.3
35
7.
 
INVESTMENTS SUBJECT TO SIGNIFICANT INFLUENCE AND EQUITY INCOME
Equity Income
Percentage
Carrying Value
For the year ended
of
As at December 31
December 31
Ownership
millions of dollars
2023
2022
2023
2022
2023
LIL
(1)
$
 
747
$
 
740
$
 
63
$
 
58
 
31.0
NSPML
 
489
 
501
 
46
 
29
 
100.0
M&NP
 
(2)
 
118
 
128
 
21
 
21
 
12.9
Lucelec
(2)
 
48
 
49
 
4
 
4
 
19.5
Bear Swamp
 
(3)
-
 
-
 
 
12
 
17
 
50.0
$
 
1,402
$
 
1,418
$
 
146
$
 
129
(1) Emera indirectly owns
100
 
per cent of the Class B units, which comprises
24.5
 
per cent of the total units issued. Percentage
ownership in LIL is subject to change, based on the balance of capital investments required from Emera and Nalcor Energy
 
to
complete construction of the LIL. Emera’s ultimate percentage investment in LIL will be determined upon
 
final costing of
 
all transmission projects related to the Muskrat Falls development, including the LIL, Labrador Transmission
 
Assets and Maritime
Link Projects, such that Emera’s total investment in the Maritime Link and LIL will equal
49
 
per cent of the cost of all of these
transmission developments.
(2) Emera has significant influence over the operating and financial decisions of these companies through Board representation
 
and
therefore, records its investment in these entities using the equity method.
 
(3) The investment balance in Bear Swamp is in a credit position primarily as a result of a $
179
 
million distribution received in 2015.
Bear Swamp's credit investment balance of $
81
 
million (2022 – $
95
 
million) is recorded in Other long-term liabilities on the
Consolidated Balance Sheets.
 
Equity investments include a $
10
 
million difference between the cost and the underlying FV of the
investees' assets as at the date of acquisition. The excess is attributable to goodwill.
Emera accounts for its variable interest investment in NSPML as an equity investment (note 32).
NSPML's consolidated summarized balance sheets are illustrated as follows:
As at
December 31
millions of dollars
2023
2022
Balance Sheets
Current assets
$
 
21
$
 
17
PP&E
 
1,473
 
1,517
Regulatory assets
 
272
 
265
Non-current assets
 
29
 
29
Total assets
$
 
1,795
$
 
1,828
Current liabilities
$
 
48
$
 
48
Long-term debt
(1)
 
1,109
 
1,149
Non-current liabilities
 
149
 
130
Equity
 
489
 
501
Total liabilities and equity
$
 
1,795
$
 
1,828
(1) The project debt has been guaranteed by the Government of Canada.
8.
 
OTHER INCOME, NET
For the
Year ended December 31
millions of dollars
2023
2022
Interest income
$
 
43
$
 
25
AFUDC
 
38
 
52
Pension non-current service cost recovery
 
35
 
24
FX gains (losses)
 
20
(26)
TECO Guatemala Holdings award
(1)
-
 
 
63
Other
 
 
22
 
7
$
 
158
$
 
145
(1) On December 15, 2022, a payment of $
63
 
million was made by the Republic of Guatemala to TECO Energy in satisfaction of the
second and final award issued by the International Centre of the Settlement of Investment Disputes tribunal regarding a dispute
 
over
an investment in TGH, a wholly-owned subsidiary of TECO Energy.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Exhibit 99.3
36
9.
 
INTEREST EXPENSE, NET
Interest expense, net consisted of the following:
For the
Year ended December 31
millions of Canadian dollars
2023
2022
Interest on debt
 
$
 
954
$
 
727
Allowance for borrowed funds used during construction
(16)
(21)
Other
(13)
 
3
$
 
925
$
 
709
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
2023
2022
Income before provision for income taxes
$
 
1,173
$
 
1,194
Statutory income tax rate
29.0%
29.0%
Income taxes, at statutory income tax rate
 
340
 
346
Deferred income taxes on regulated income recorded as regulatory assets and
regulatory liabilities
(72)
(70)
Tax credits
(53)
(18)
Foreign tax rate variance
(36)
(44)
Amortization of deferred income tax regulatory liabilities
(33)
(33)
Tax effect
 
of equity earnings
(15)
(10)
GBPC impairment charge
 
-
 
 
21
Other
(3)
(7)
Income tax expense
$
 
128
$
 
185
Effective income tax rate
11%
15%
On August 16, 2022, the United States Inflation Reduction Act (“IRA”) was signed into legislation. The
IRA includes numerous tax incentives for clean energy, such as the extension and modification of existing
investment and production tax credits for projects placed in service through 2024 and introduces new
technology-neutral clean energy related tax credits beginning in 2025. As of December 31, 2023, the
Company has recorded a $
30
 
million (2022 - $
9
 
million) regulatory liability on the Consolidated Balance
Sheets in recognition of its obligation to pass the incremental tax benefits realized to customers.
The following table reflects the composition of taxes on income from continuing operations presented in
the Consolidated Statements of Income for the years ended December 31:
millions of dollars
2023
2022
Current income taxes
 
Canada
$
 
26
$
 
25
 
United States
 
5
 
8
Deferred income taxes
 
Canada
 
93
 
122
 
United States
 
128
 
252
Investment tax credits
 
United States
(29)
(7)
Operating loss carryforwards
 
Canada
(93)
(94)
 
United States
(2)
(121)
Income tax expense
$
 
128
$
 
185
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Exhibit 99.3
37
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
2023
2022
Canada
$
 
171
$
 
173
United States
 
964
 
1,063
Other
 
38
(42)
Income before provision for income taxes
$
 
1,173
$
 
1,194
The deferred income tax assets and liabilities presented in the Consolidated Balance Sheets as at
December 31 consisted of the following:
millions of dollars
2023
2022
Deferred income tax assets:
Tax loss carryforwards
$
 
1,195
$
 
1,207
Tax credit carryforwards
 
454
 
415
Derivative instruments
 
205
 
45
Regulatory liabilities
 
 
175
 
264
Other
 
372
 
341
Total deferred income tax assets before valuation allowance
 
2,401
 
2,272
Valuation allowance
(363)
(312)
Total deferred income tax assets after valuation allowance
$
 
2,038
$
 
1,960
Deferred income tax (liabilities):
PP&E
$
(3,223)
$
(2,981)
Derivative instruments
(235)
(125)
Investments subject to significant influence
(216)
(181)
Regulatory assets
(196)
(310)
Other
(312)
(322)
Total deferred income tax liabilities
 
$
(4,182)
$
(3,919)
Consolidated Balance Sheets presentation:
Long-term deferred income tax assets
$
 
208
$
 
237
Long-term deferred income tax liabilities
(2,352)
(2,196)
Net deferred income tax liabilities
$
(2,144)
$
(1,959)
Considering all evidence regarding the utilization of the Company’s deferred income tax assets, it has
been determined that Emera is more likely than not to realize all recorded deferred income tax assets,
except for certain loss carryforwards and unrealized capital losses on long-term debt and investments. A
valuation allowance of $
363
 
million has been recorded as at December 31, 2023 (2022 – $
312
 
million)
related to the loss carryforwards, long-term debt and investments.
The Company intends to indefinitely reinvest earnings from certain foreign operations. Accordingly, as at
December 31, 2023, $
4.7
 
billion (2022 – $
3.8
 
billion) in cumulative temporary differences for which
deferred taxes might otherwise be required, have not been recognized. It is impractical to estimate the
amount of income and withholding tax that might be payable if a reversal of temporary differences
occurred.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Exhibit 99.3
38
Emera’s NOL, capital loss and tax credit carryforwards and their expiration periods as at December 31,
2023 consisted of the following:
Subject to
Tax
Valuation
Net Tax
Expiration
millions of dollars
Carryforwards
Allowance
Carryforwards
Period
Canada
 
NOL
$
 
2,914
$
(1,164)
$
 
1,750
2026 - 2043
 
Capital loss
 
73
(73)
-
 
Indefinite
United States
 
Federal NOL
$
 
1,360
$
(1)
$
 
1,359
2036 - Indefinite
 
State NOL
 
1,003
(1)
 
1,002
2026 - Indefinite
 
Tax credit
 
454
(3)
 
451
2025 - 2043
Other
 
NOL
$
 
81
$
(28)
$
 
53
2024 - 2030
The following table provides details of the change in unrecognized tax benefits for the years ended
December 31 as follows:
millions of dollars
2023
2022
Balance, January 1
$
 
33
$
 
28
Increases due to tax positions related to current year
 
5
 
5
Increases due to tax positions related to a prior year
 
1
 
2
Decreases due to tax positions related to a prior year
(2)
(2)
Balance, December 31
$
 
37
$
 
33
Unrecognized tax benefits relate to the timing of certain tax deductions at NSPI and research and
development tax credits primarily at TEC. The total amount of unrecognized tax benefits as at December
31, 2023 was $
37
 
million (2022 – $
33
 
million), which would affect the effective tax rate if recognized. The
total amount of accrued interest with respect to unrecognized tax benefits was $
9
 
million (2022 – $
7
million) with $
2
 
million interest expense recognized in the Consolidated Statements of Income (2022 – $
1
million).
No
 
penalties have been accrued. The balance of unrecognized tax benefits could change in the
next 12 months as a result of resolving Canada Revenue Agency (“CRA”) and Internal Revenue Service
audits. A reasonable estimate of any change cannot be made at this time.
During 2022, the CRA issued notices of reassessment to NSPI for the 2013 through 2016 taxation years.
NSPI and the CRA are currently in a dispute with respect to the timing of certain tax deductions for
its 2006 through 2010 and 2013 through 2016 taxation years. The ultimate permissibility of the tax
deductions is not in dispute; rather, it is the timing of those deductions. The cumulative net amount in
dispute to date is $
126
 
million (2022 – $
126
 
million), including interest. NSPI has prepaid $
55
 
million of
the amount in dispute, as required by CRA.
On November 29, 2019, NSPI filed a Notice of Appeal with the Tax Court of Canada with respect to its
dispute of the 2006 through 2010 taxation years. Should NSPI be successful in defending its position, all
payments including applicable interest will be refunded. If NSPI is unsuccessful in defending any portion
of its position, the resulting taxes and applicable interest will be deducted from amounts previously paid,
with the difference, if any, either owed to, or refunded from, the CRA. The related tax deductions will be
available in subsequent years.
Should NSPI be similarly reassessed by the CRA for years not currently in dispute, further payments will
be required; however, the ultimate permissibility of these deductions would be similarly not in dispute.
NSPI and its advisors believe that NSPI has reported its tax position appropriately. NSPI continues to
assess its options to resolving the dispute; however, the outcome of the Notice of Appeal process is not
determinable at this time.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Exhibit 99.3
39
Emera files a Canadian federal income tax return, which includes its Nova Scotia provincial income tax.
Emera’s subsidiaries file Canadian, US, Barbados, and St. Lucia income tax returns. As at December 31,
2023, the Company’s tax years still open to examination by taxing authorities include 2005 and
subsequent years.
 
11.
 
COMMON STOCK
Authorized
:
 
Unlimited number of non-par value common shares.
2023
2022
Issued and outstanding:
millions
of shares
 
millions of
dollars
millions of
shares
 
millions of
dollars
Balance, January 1
 
269.95
$
 
7,762
 
261.07
$
 
7,242
Issuance of common stock under ATM program
(1)(2)
 
8.29
 
397
 
4.07
 
248
Issued under the DRIP,
 
net of discounts
 
5.26
 
272
 
4.21
 
238
Senior management stock options exercised and Employee Share
Purchase Plan
 
0.62
 
31
 
0.60
 
34
Balance, December 31
 
284.12
$
 
8,462
 
269.95
$
 
7,762
(1) For the year ended December 31, 2022, a total of
4,072,469
 
common shares were issued under Emera's ATM program
 
at an
average price of $
61.31
 
per share for gross proceeds of $
250
 
million ($
248
 
million net of after-tax issuance costs).
(2) For the year ended December 31, 2023, a total of
8,287,037
 
common shares were issued under Emera's ATM program
 
at an
average price of $
48.27
 
per share for gross proceeds of $
400
 
million ($
397
 
million net of after-tax issuance costs).
As at December 31, 2023, the following common shares were reserved for issuance:
6
 
million (2022 –
6
million) under the senior management stock option plan,
2
 
million (2022 –
2.7
 
million) under the employee
common share purchase plan and
18
 
million (2022 –
10
 
million) under the DRIP.
 
The issuance of common shares under the common share compensation arrangements does not allow
the plans to exceed
10
 
per cent of Emera's outstanding common shares. As at December 31, 2023,
Emera was in compliance with this requirement.
 
ATM Equity Program
On October 3, 2023, Emera filed a short form base shelf prospectus, primarily in support of the renewal of
its ATM Program in Q4 2023 that will allow the Company to issue up to $
600
 
million of common shares
from treasury to the public from time to time, at the Company’s discretion, at the prevailing market price.
This ATM Program is expected to remain in effect until November 4, 2025.
12.
 
EARNINGS PER SHARE
Basic earnings per share is determined by dividing net income attributable to common shareholders by
the weighted average number of common shares outstanding during the period. Diluted EPS is computed
by dividing net income attributable to common shareholders by the weighted average number of common
shares outstanding during the period, adjusted for the exercise and/or conversion of all potentially dilutive
securities. Such dilutive items include Company contributions to the senior management stock option
plan, convertible debentures and shares issued under the DRIP.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Exhibit 99.3
40
The following table reconciles the computation of basic and diluted earnings per share:
For the
Year ended December 31
millions of dollars (except per share amounts)
2023
2022
Numerator
Net income attributable to common shareholders
$
 
977.7
$
 
945.1
Diluted numerator
 
977.7
 
945.1
Denominator
Weighted average shares of common stock outstanding – basic
 
273.6
 
265.5
Stock-based compensation
 
 
0.2
 
0.4
Weighted average shares of common stock outstanding – diluted
 
273.8
 
265.9
Earnings per common share
Basic
 
$
 
3.57
$
 
3.56
Diluted
$
 
3.57
$
 
3.55
13.
 
ACCUMULATED OTHER COMPREHENSIVE INCOME
The components of AOCI are as follows:
millions of dollars
Unrealized
(loss) gain on
translation of
self-sustaining
foreign
operations
Net change in
net investment
hedges
Losses on
derivatives
recognized
 
as cash flow
hedges
Net change
on available-
for-sale
investments
Net change in
unrecognized
pension and
post-retirement
benefit costs
Total
 
AOCI
For the year ended December 31, 2023
Balance, January 1, 2023
$
 
639
$
(62)
$
 
16
$
(2)
$
(13)
$
 
578
Other comprehensive (loss)
 
income before
 
reclassifications
(270)
 
38
 
-
 
-
 
-
 
(232)
Amounts reclassified from
 
AOCI
-
 
-
 
(2)
-
 
(39)
(41)
Net current period other
comprehensive (loss) income
(270)
 
38
(2)
-
 
(39)
(273)
Balance, December 31, 2023
$
 
369
$
(24)
$
 
14
$
(2)
$
(52)
$
 
305
For the year ended December 31, 2022
Balance, January 1, 2022
$
 
10
$
 
35
$
 
18
$
(1)
$
(37)
$
 
25
Other comprehensive
 
income (loss) before
 
reclassifications
 
629
(97)
-
 
(1)
-
 
 
531
Amounts reclassified from
 
AOCI
-
 
-
 
(2)
-
 
 
24
 
22
Net current period other
comprehensive income (loss)
 
629
(97)
(2)
(1)
 
24
 
553
Balance, December 31, 2022
$
 
639
$
(62)
$
 
16
$
(2)
$
(13)
$
 
578
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Exhibit 99.3
41
The reclassifications out of AOCI are as follows:
For the
Year ended December 31
millions of dollars
2023
2022
Affected line item in the Consolidated Financial Statements
Gains on derivatives recognized as cash flow hedges
 
Interest rate hedge
Interest expense, net
$
(2)
$
(2)
Net change in unrecognized pension and post-retirement benefit costs
 
Actuarial losses
Other income, net
$
-
 
$
 
10
 
Past service costs
Other income, net
 
2
-
 
 
Amounts reclassified into obligations
Pension and post-retirement benefits
(40)
 
15
Total before tax
(38)
 
25
Income tax expense
(1)
(1)
Total net of tax
$
(39)
$
 
24
Total reclassifications out of AOCI, net of tax, for the period
$
(41)
$
 
22
14.
 
INVENTORY
As at
December 31
December 31
millions of dollars
 
2023
2022
Fuel
 
$
 
382
$
 
404
Materials
 
 
408
 
365
Total
$
 
790
$
 
769
15.
 
DERIVATIVE
 
INSTRUMENTS
Derivative assets and liabilities relating to the foregoing categories consisted of the following:
Derivative Assets
Derivative Liabilities
As at
December 31
December 31
December 31
December 31
millions of dollars
2023
2022
2023
2022
Regulatory deferral:
 
Commodity swaps and forwards
$
 
16
$
 
186
$
 
76
$
 
42
 
FX forwards
 
3
 
18
 
3
 
1
 
Physical natural gas purchases and sales
-
 
 
52
-
 
-
 
 
19
 
256
 
79
 
43
HFT derivatives:
 
Power swaps and physical contracts
 
29
 
89
 
36
 
77
 
Natural gas swaps, futures, forwards, physical
 
 
contracts
 
319
 
340
 
531
 
1,224
 
348
 
429
 
567
 
1,301
Other derivatives:
 
Equity derivatives
 
 
4
-
 
-
 
 
5
 
FX forwards
 
18
 
5
 
7
 
23
 
22
 
5
 
7
 
28
Total gross current derivatives
 
389
 
690
 
653
 
1,372
Impact of master netting agreements:
 
Regulatory deferral
(3)
(18)
(3)
(18)
 
HFT derivatives
(146)
(276)
(146)
(276)
Total impact of master netting agreements
(149)
(294)
(149)
(294)
Total derivatives
$
 
240
$
 
396
$
 
504
$
 
1,078
Current
(1)
 
174
 
296
 
386
 
888
Long-term
(1)
 
66
 
100
 
118
 
190
Total derivatives
$
 
240
$
 
396
$
 
504
$
 
1,078
(1) Derivative assets and liabilities are classified as current or long-term based upon the maturities of the underlying
 
contracts.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Exhibit 99.3
42
Cash Flow Hedges
On May 26, 2021, a treasury lock was settled for a gain of $
19
 
million that is being amortized through
interest expense over
10 years
 
as the underlying hedged item settles.
The amounts related to cash flow hedges recorded in AOCI consisted of the following:
For the
Year ended December 31
millions of dollars
2023
2022
Interest
Interest
rate hedge
rate hedge
Realized gain in interest expense, net
$
 
2
$
 
2
Total gains in net income
$
 
2
$
 
2
As at
December 31
December 31
millions of dollars
2023
2022
Interest
Interest
rate hedge
rate hedge
Total unrealized gain in AOCI – effective portion, net of tax
$
 
14
$
 
16
The Company expects $
2
 
million of unrealized gains currently in AOCI to be reclassified into net income
within the next 12 months.
Regulatory Deferral
The Company has recorded the following changes with respect to derivatives receiving regulatory
deferral:
Physical
Commodity
Physical
Commodity
natural gas
swaps and
FX
natural gas
swaps and
FX
millions of dollars
purchases
forwards
forwards
purchases
forwards
forwards
For the year ended December 31
2023
2022
Unrealized gain (loss) in regulatory
assets
$
-
 
$
(109)
$
(3)
$
-
 
$
(69)
$
 
1
Unrealized gain (loss) in regulatory
liabilities
(3)
(73)
-
 
 
28
 
343
 
16
Realized (gain) loss in regulatory
assets
-
 
(5)
-
 
-
 
 
48
-
 
Realized (gain) loss in regulatory
liabilities
-
 
 
2
-
 
-
 
(41)
-
 
Realized (gain) loss in inventory
(1)
-
 
 
4
(10)
-
 
(121)
 
1
Realized (gain) in regulated fuel for
generation and purchased power
(2)
(49)
(9)
(4)
(64)
(146)
-
 
Other
-
 
(14)
-
 
-
 
-
 
-
 
Total change in derivative instruments
$
(52)
$
(204)
$
(17)
$
(36)
$
 
14
$
 
18
(1) Realized (gains) losses will be recognized in fuel for generation and purchased power when the hedged item is consumed.
(2) Realized (gains) losses on derivative instruments settled and consumed in the period and hedging relationships that have been
terminated or the hedged transaction is no longer probable.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Exhibit 99.3
43
As at December 31, 2023, the Company had the following notional volumes designated for regulatory
deferral that are expected to settle as outlined below:
millions
2024
2025-2026
Physical natural gas purchases:
Natural gas (MMBtu)
 
7
 
6
Commodity swaps and forwards purchases:
Natural gas (MMBtu)
 
16
 
10
Power (MWh)
 
1
 
1
Coal (metric tonnes)
 
1
-
 
FX swaps and forwards:
FX contracts (millions of USD)
$
 
241
$
 
70
Weighted average rate
 
1.3155
 
1.3197
% of USD requirements
63%
17%
HFT Derivatives
The Company has recognized the following realized and unrealized gains (losses) with respect to HFT
derivatives:
For the
 
Year ended December 31
millions of dollars
2023
2022
Power swaps and physical contracts in non-regulated operating revenues
$
(6)
$
 
17
Natural gas swaps, forwards, futures and physical contracts in non-regulated
operating revenues
 
1,043
 
47
Total gains in net income
$
 
1,037
$
 
64
As at December 31, 2023, the Company had the following notional volumes of outstanding HFT
derivatives that are expected to settle as outlined below:
2028 and
 
millions
 
2024
2025
2026
2027
thereafter
Natural gas purchases (Mmbtu)
 
296
 
80
 
50
 
38
 
30
Natural gas sales (Mmbtu)
 
338
 
86
 
16
 
6
 
4
Power purchases (MWh)
 
1
-
 
-
 
-
 
-
 
Power sales (MWh)
 
1
-
 
-
 
-
 
-
 
Other Derivatives
As at December 31, 2023, the Company had equity derivatives in place to manage the cash flow risk
associated with forecasted future cash settlements of deferred compensation obligations and FX forwards
in place to manage cash flow risk associated with forecasted USD cash inflows.
The equity derivatives
hedge the return on
2.9
 
million shares and extends until December 2024. The FX forwards have a
combined notional amount of $508 million USD and expire in 2023, 2024 and 2025.
For the
Year ended December 31
millions of dollars
2023
2022
FX
Equity
FX
Equity
Forwards
Derivatives
Forwards
Derivatives
Unrealized gain (loss) in OM&G
$
-
 
$
 
4
$
-
 
$
(5)
Unrealized gain (loss) in other income, net
 
28
-
 
(18)
-
 
Realized loss in OM&G
-
 
(13)
-
 
(17)
Realized loss in other income, net
(11)
-
 
(6)
-
 
Total gains (losses) in net income
$
 
17
$
(9)
$
(24)
$
(22)
Exhibit 99.3
44
Credit Risk
The Company is exposed to credit risk with respect to amounts receivable from customers, energy
marketing collateral deposits and derivative assets. Credit risk is the potential loss from a counterparty’s
non-performance under an agreement. The Company manages credit risk with policies and procedures
for counterparty analysis, exposure measurement, and exposure monitoring and mitigation. Credit
assessments are conducted on all new customers and counterparties, and deposits or collateral are
requested on any high-risk accounts.
 
The Company assesses the potential for credit losses on a regular basis and, where appropriate,
maintains provisions. With respect to counterparties, the Company has implemented procedures to
monitor the creditworthiness and credit exposure of counterparties and to consider default probability in
valuing the counterparty positions. The Company monitors counterparties’ credit standing, including those
that are experiencing financial problems, have significant swings in default probability rates, have credit
rating changes by external rating agencies, or have changes in ownership. Net liability positions are
adjusted based on the Company’s current default probability. Net asset positions are adjusted based on
the counterparty’s current default probability. The Company assesses credit risk internally for
counterparties that are not rated.
As at December 31, 2023, the maximum exposure the Company had to credit risk was $
1.2
 
billion (2022
– $
1.9
 
billion), which included accounts receivable net of collateral/deposits and assets related to
derivatives.
 
It is possible that volatility in commodity prices could cause the Company to have material credit risk
exposures with one or more counterparties. If such counterparties fail to perform their obligations under
one or more agreements, the Company could suffer a material financial loss. The Company transacts with
counterparties as part of its risk management strategy for managing commodity price, FX and interest
rate risk. Counterparties that exceed established credit limits can provide a cash deposit or letter of credit
to the Company for the value in excess of the credit limit where contractually required. The total cash
deposits/collateral on hand as at December 31, 2023 was $
310
 
million (2022 – $
386
 
million), which
mitigated the Company’s maximum credit risk exposure. The Company uses the cash as payment for the
amount receivable or returns the deposit/collateral to the customer/counterparty where it is no longer
required by the Company.
The Company enters into commodity master arrangements with its counterparties to manage certain
risks, including credit risk to these counterparties. The Company generally enters into International Swaps
and Derivatives Association agreements, North American Energy Standards Board agreements and, or
Edison Electric Institute agreements. The Company believes entering into such agreements offers
protection by creating contractual rights relating to creditworthiness, collateral, non-performance and
default.
As at December 31, 2023, the Company had $
142
 
million (2022 – $
131
 
million) in financial assets,
considered to be past due, which have been outstanding for an average
64
 
days. The FV of these
financial assets was $
127
 
million (2022 – $
114
 
million), the difference of which was included in the
allowance for credit losses. These assets primarily relate to accounts receivable from electric and gas
revenue.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Exhibit 99.3
45
Concentration Risk
The Company's concentrations of risk consisted of the following:
As at
December 31, 2023
December 31, 2022
millions of
dollars
% of total
exposure
millions of
dollars
% of total
exposure
Receivables, net
Regulated utilities:
Residential
$
 
476
31%
$
 
455
19%
Commercial
 
194
13%
 
192
8%
Industrial
 
84
5%
 
121
5%
Other
 
103
7%
 
122
5%
Cash collateral
 
94
6%
-
0%
 
951
62%
 
890
37%
Trading group:
Credit rating of A- or above
 
47
3%
 
125
5%
Credit rating of BBB- to BBB+
 
33
2%
 
75
3%
Not rated
 
108
7%
 
307
13%
 
188
12%
 
507
21%
Other accounts receivable
 
151
10%
 
585
25%
 
1,290
84%
 
1,982
83%
Derivative Instruments
(current and long-term)
Credit rating of A- or above
 
138
9%
 
202
9%
Credit rating of BBB- to BBB+
 
7
1%
 
8
0%
Not rated
 
95
6%
 
186
8%
 
240
16%
 
396
17%
$
 
1,530
100%
$
 
2,378
100%
Cash Collateral
The Company’s cash collateral positions consisted of the following:
As at
December 31
December 31
millions of dollars
2023
2022
Cash collateral provided to others
$
 
101
$
 
224
Cash collateral received from others
$
 
22
$
 
112
Collateral is posted in the normal course of business based on the Company’s creditworthiness, including
its senior unsecured credit rating as determined by certain major credit rating agencies. Certain
derivatives contain financial assurance provisions that require collateral to be posted if a material adverse
credit-related event occurs. If a material adverse event resulted in the senior unsecured debt falling below
investment grade, the counterparties to such derivatives could request ongoing full collateralization.
As at December 31, 2023, the total FV of derivatives in a liability position was $
504
 
million (December 31,
2022
 
$
1,078
 
million). If the credit ratings of the Company were reduced below investment grade, the full
value of the net liability position could be required to be posted as collateral for these derivatives.
Exhibit 99.3
46
16.
 
FV MEASUREMENTS
The Company is required to determine the FV of all derivatives except those which qualify for the NPNS
exemption (see note 1) and uses a market approach to do so. The three levels of the FV hierarchy are
defined as follows:
Level 1 - Where possible, the Company bases the fair valuation of its financial assets and liabilities on
quoted prices in active markets (“quoted prices”) for identical assets and liabilities.
Level 2 - Where quoted prices for identical assets and liabilities are not available, the valuation of certain
contracts must be based on quoted prices for similar assets and liabilities with an adjustment related to
location differences. Also, certain derivatives are valued using quotes from over-the-counter clearing
houses.
Level 3 - Where the information required for a Level 1 or Level 2 valuation is not available, derivatives
must be valued using unobservable or internally-developed inputs. The primary reasons for a Level 3
classification are as follows:
 
While valuations were based on quoted prices, significant assumptions were necessary to reflect
seasonal or monthly shaping and locational basis differentials.
 
The term of certain transactions extends beyond the period when quoted prices are available and,
accordingly, assumptions were made to extrapolate prices from the last quoted period through the
end of the transaction term.
 
The valuations of certain transactions were based on internal models, although quoted prices were
utilized in the valuations.
Derivative assets and liabilities are classified in their entirety based on the lowest level of input that is
significant to the FV measurement.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Exhibit 99.3
47
The following tables set out the classification of the methodology used by the Company to FV its
derivatives:
As at
December 31, 2023
millions of dollars
Level 1
Level 2
Level 3
Total
Assets
Regulatory deferral:
 
Commodity swaps and forwards
$
 
7
$
 
6
$
-
 
$
 
13
 
FX forwards
-
 
 
3
-
 
 
3
 
7
 
9
-
 
 
16
HFT derivatives:
 
Power swaps and physical contracts
(5)
 
23
-
 
 
18
 
Natural gas swaps, futures, forwards, physical
 
 
contracts and related transportation
 
42
 
108
 
34
 
184
 
37
 
131
 
34
 
202
Other derivatives:
 
FX forwards
-
 
 
18
-
 
 
18
 
Equity derivatives
 
 
4
-
 
-
 
 
4
 
4
 
18
-
 
 
22
Total assets
 
48
 
158
 
34
 
240
Liabilities
Regulatory deferral:
 
Commodity swaps and forwards
 
43
 
30
-
 
 
73
 
FX forwards
-
 
 
3
-
 
 
3
 
43
 
33
-
 
 
76
HFT derivatives:
 
Power swaps and physical contracts
-
 
 
24
-
 
 
24
 
Natural gas swaps, futures, forwards and physical
 
 
contracts
 
13
 
19
 
365
 
397
 
13
 
43
 
365
 
421
Other derivatives:
 
FX forwards
-
 
 
7
-
 
 
7
-
 
 
7
-
 
 
7
Total liabilities
 
56
 
83
 
365
 
504
Net assets (liabilities)
 
$
(8)
$
 
75
$
(331)
$
(264)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Exhibit 99.3
48
As at
December 31, 2022
millions of dollars
Level 1
Level 2
Level 3
Total
Assets
Regulatory deferral:
 
Commodity swaps and forwards
$
 
120
$
 
48
$
-
 
$
 
168
 
FX forwards
-
 
 
18
-
 
 
18
 
Physical natural gas purchases and sales
-
 
-
 
 
52
 
52
 
120
 
66
 
52
 
238
HFT derivatives:
 
Power swaps and physical contracts
 
9
 
31
 
4
 
44
 
Natural gas swaps, futures, forwards, physical
 
 
contracts and related transportation
 
3
 
72
 
34
 
109
 
12
 
103
 
38
 
153
Other derivatives:
 
FX forwards
-
 
 
5
-
 
 
5
Total assets
 
132
 
174
 
90
 
396
Liabilities
Regulatory deferral:
 
Commodity swaps and forwards
 
15
 
9
-
 
 
24
 
FX forwards
-
 
 
1
-
 
 
1
 
15
 
10
-
 
 
25
HFT derivatives:
 
Power swaps and physical contracts
 
2
 
28
 
1
 
31
 
Natural gas swaps, futures, forwards and physical
 
 
contracts
 
51
 
118
 
825
 
994
 
53
 
146
 
826
 
1,025
Other derivatives:
 
FX forwards
-
 
 
23
-
 
 
23
 
Equity derivatives
 
5
-
 
-
 
 
5
Total liabilities
 
73
 
179
 
826
 
1,078
Net assets (liabilities)
$
 
59
$
(5)
$
(736)
$
(682)
The change in the FV of the Level 3 financial assets for the year ended December 31, 2023 was as
follows:
Regulatory Deferral
HFT Derivatives
Physical natural
Natural
 
millions of dollars
gas purchases
Power
 
gas
Total
Balance, January 1, 2023
$
 
52
$
 
4
$
 
34
$
 
90
Realized gains (losses) included in fuel for generation
and purchased power
(49)
-
 
-
 
(49)
Unrealized gains (losses) included in regulatory
assets and liabilities
(3)
-
 
-
 
(3)
Total realized and unrealized gains (losses) included
in non-regulated operating revenues
-
 
(4)
-
 
(4)
Balance, December 31, 2023
$
-
 
$
-
 
$
 
34
$
 
34
The change in the FV of the Level 3 financial liabilities for the year ended December 31, 2023 was as
follows:
 
HFT Derivatives
Natural
millions of dollars
Power
 
gas
Total
Balance, January 1, 2023
$
 
1
$
 
825
$
 
826
Total realized and unrealized gains included in non-
regulated operating revenues
(1)
(460)
(461)
Balance, December 31, 2023
 
$
-
 
$
 
365
$
 
365
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Exhibit 99.3
49
Significant unobservable inputs used in the FV measurement of Emera’s natural gas and power
derivatives include third-party sourced pricing for instruments based on illiquid markets. Significant
increases (decreases) in any of these inputs in isolation would result in a significantly lower (higher) FV
measurement. Other unobservable inputs used include internally developed correlation factors and basis
differentials; own credit risk; and discount rates. Internally developed correlations and basis differentials
are reviewed on a quarterly basis based on statistical analysis of the spot markets in the various illiquid
term markets. Discount rates may include a risk premium for those long-term forward contracts with
illiquid future price points to incorporate the inherent uncertainty of these points. Any risk premiums for
long-term contracts are evaluated by observing similar industry practices and in discussion with industry
peers.
 
The Company uses a modelled pricing valuation technique for determining the FV of Level 3 derivative
instruments. The following table outlines quantitative information about the significant unobservable
inputs used in the FV measurements categorized within Level 3 of the FV hierarchy:
Significant
Weighted
 
millions of dollars
FV
Unobservable Input
Low
High
average
(1)
Assets
Liabilities
As at December 31, 2023
HFT derivatives – Natural
 
34
365
Third-party pricing
$1.27
$16.25
$4.85
gas swaps, futures, forwards
 
and physical contracts
 
Total
$
34
$
365
Net liability
$
331
As at December 31, 2022
Regulatory deferral –
Physical
$
52
$
-
Third-party pricing
$5.79
$31.85
$12.27
natural gas purchases
HFT derivatives – Power
 
4
1
Third-party pricing
$43.24
$269.10
$138.79
swaps and physical contracts
HFT derivatives – Natural
 
34
825
Third-party pricing
$2.45
$33.88
$12.01
gas swaps, futures, forwards
 
and physical contracts
 
Total
$
90
$
826
Net liability
$
736
(1) Unobservable inputs were weighted by the relative FV of the instruments.
Long-term debt is a financial liability not measured at FV on the Consolidated Balance Sheets. The
balance consisted of the following:
As at
Carrying
millions of dollars
Amount
FV
Level 1
Level 2
Level 3
Total
December 31, 2023
$
 
18,365
$
 
16,621
$
-
 
$
 
16,363
$
 
258
$
 
16,621
December 31, 2022
$
 
16,318
$
 
14,670
$
-
 
$
 
14,284
$
 
386
$
 
14,670
The Company has designated $
1.2
 
billion USD denominated Hybrid Notes as a hedge of the foreign
currency exposure of its ne
t investment
 
in USD denominated operations. The Company’s Hybrid Notes
are contingently convertible into preferred shares in the event of bankruptcy or other related events. A
redemption option on or after June 15, 2026 is available and at the control of the Company. The Hybrid
Notes are classified as Level 2 financial assets. As at December 31, 2023, the FV of the Hybrid Notes
was $
1.2
 
billion (2022 – $
1.1
 
billion). An after-tax foreign currency gain of $
38
 
million was recorded in
AOCI for the year ended December 31, 2023 (2022 – $
97
 
million after-tax loss).
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Exhibit 99.3
50
17.
 
RELATED PARTY
 
TRANSACTIONS
In the ordinary course of business, Emera provides energy and other services and enters into
transactions with its subsidiaries, associates and other related companies on terms similar to those
offered to non-related parties. Intercompany balances and intercompany transactions have been
eliminated on consolidation, except for the net profit on certain transactions between non-regulated and
regulated entities in accordance with accounting standards for rate-regulated entities. All material
amounts are under normal interest and credit terms.
 
Significant transactions between Emera and its associated companies are as follows:
 
Transactions between NSPI and NSPML related to the Maritime Link assessment are reported in the
Consolidated Statements of Income. NSPI’s expense is reported in Regulated fuel for generation and
purchased power, totalling $
163
 
million for the year ended December 31, 2023 (2022 – $
157
 
million).
NSPML is accounted for as an equity investment, and therefore corresponding earnings related to
this revenue are reflected in Income from equity investments.
Natural gas transportation capacity purchases from M&NP are reported in the Consolidated
Statements of Income. Purchases from M&NP reported net in Operating revenues, Non-regulated,
totalled $
14
 
million for the year ended December 31, 2023 (2022
– $
9
 
million).
There were no significant receivables or payables between Emera and its associated companies reported
on Emera’s Consolidated Balance Sheets as at December 31, 2023 and at December 31, 2022.
18.
 
RECEIVABLES AND OTHER CURRENT ASSETS
As at
December 31
December 31
millions of dollars
 
2023
2022
Customer accounts receivable – billed
$
 
805
$
 
1,096
Capitalized transportation capacity
(1)
 
358
 
781
Customer accounts receivable – unbilled
 
363
 
424
Prepaid expenses
 
105
 
82
Income tax receivable
 
10
 
9
Allowance for credit losses
(15)
(17)
NMGC gas hedge settlement receivable
 
(2)
 
-
 
 
162
Other
 
191
 
360
Total receivables and other current assets
$
 
1,817
$
 
2,897
(1) Capitalized transportation capacity represents the value of transportation/storage received by EES on asset management
agreements at the inception of the contracts. The asset is amortized over the term of each contract.
(2) Offsetting amount is included in regulatory liabilities for NMGC as gas hedges are part of the PGAC. For more information,
 
refer
to note 6.
19.
 
LEASES
Lessee
The Company has operating leases for buildings, land, telecommunication services, and rail cars.
Emera’s leases have remaining lease terms of 1 year to 62 years, some of which include options to
extend the leases for up to 65 years. These options are included as part of the lease term when it is
considered reasonably certain they will be exercised.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Exhibit 99.3
51
As at
December 31
December 31
millions of dollars
 
Classification
2023
2022
Right-of-use asset
Other long-term assets
$
54
$
 
58
Lease liabilities
 
Current
Other current liabilities
3
 
3
 
Long-term
Other long-term liabilities
55
 
59
Total lease liabilities
$
58
$
 
62
The Company recorded lease expense of $
127
 
million for the year ended December 31, 2023 (2022 –
$
138
 
million), of which $
119
 
million (2022 – $
131
 
million) related to variable costs for power generation
facility finance leases, recorded in “Regulated fuel for generation and purchased power” in the
Consolidated Statements of Income.
 
Future minimum lease payments under non-cancellable operating leases for each of the next five years
and in aggregate thereafter are as follows:
millions of dollars
2024
2025
2026
2027
2028
Thereafter
Total
Minimum lease payments
$
 
6
$
 
5
$
 
3
$
 
3
$
 
3
$
 
111
$
 
131
Less imputed interest
(73)
Total
$
 
58
Additional information related to Emera's leases is as follows:
Year ended December 31
For the
2023
2022
Cash paid for amounts included in the measurement of lease liabilities:
 
Operating cash flows for operating leases (millions of dollars)
$
 
8
$
 
8
Right-of-use assets obtained in exchange for lease obligations:
 
Operating leases (millions of dollars)
$
 
1
$
 
1
Weighted average remaining lease term (years)
 
44
 
44
Weighted average discount rate- operating leases
3.93%
3.98%
Lessor
The Company’s net investment in direct finance and sales-type leases primarily relates to Brunswick
Pipeline, Seacoast, compressed natural gas (“CNG”) stations, a renewable natural gas (“RNG”) facility
and heat pumps.
The Company manages its risk associated with the residual value of the Brunswick Pipeline lease
through proper routine maintenance of the asset.
Customers have the option to purchase CNG station assets by paying a make-whole payment at the date
of the purchase based on a targeted internal rate of return or may take possession of the CNG station
asset at the end of the lease term for no cost. Customers have the option to purchase heat pumps at the
end of the lease term for a nominal fee.
Commencing in October 2023, the Company leased a RNG facility to a biogas producer that is classified
as a sales-type lease. The term of the facility lease is
15 years
, with a nominal value purchase at the end
of the term and a net investment of approximately $
35
 
million USD.
 
Commencing in January 2022, the Company leased Seacoast pipeline, a 21-mile, 30-inch lateral that is
classified as a sales-type lease. The term of the pipeline lateral lease is
34
 
years with a net investment of
$
100
 
million USD. The lessee of the pipeline lateral has renewal options for an additional
16
 
years. These
renewal options have not been included as part of the pipeline lateral lease term as it is not reasonably
certain that they will be exercised.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Exhibit 99.3
52
Direct finance and sales-type lease unearned income is recognized in income over the life of the lease
using a constant rate of interest equal to the internal rate of return on the lease and is recorded as
“Operating revenues – regulated gas” and “Other income, net” on the Consolidated Statements of
Income.
The total net investment in direct finance and sales-type leases consist of the following:
 
As at
December 31
December 31
millions of dollars
 
2023
2022
Total minimum lease payment to be received
$
 
1,360
$
 
1,393
Less: amounts representing estimated executory costs
(190)
(205)
Minimum lease payments receivable
$
 
1,170
$
 
1,188
Estimated residual value of leased property (unguaranteed)
 
183
 
183
Less: Credit loss reserve
(2)
-
 
Less: unearned finance lease income
(693)
(733)
Net investment in direct finance and sales-type leases
$
 
658
$
638
Principal due within one year (included in "Receivables and other
current assets")
 
37
 
34
Net Investment in direct finance and sales type leases - long-term
$
621
$
604
As at December 31, 2023, future minimum lease payments to be received for each of the next five years
and in aggregate thereafter were as follows:
millions of dollars
2024
2025
2026
2027
2028
Thereafter
Total
Minimum lease payments to be
received
$
 
97
$
 
99
$
 
98
$
 
97
$
 
96
$
 
873
$
 
1,360
Less: executory costs
(190)
Total
$
 
1,170
20.
 
PROPERTY,
 
PLANT AND EQUIPMENT
PP&E consisted of the following regulated and non-regulated assets:
 
As at
December 31
December 31
millions of dollars
 
Estimated useful life
2023
2022
Generation
3
 
to
131
$
 
13,500
$
 
13,083
Transmission
10
 
to
80
 
2,835
 
2,731
Distribution
4
 
to
80
 
7,417
 
6,978
Gas transmission and distribution
6
 
to
92
 
5,536
 
5,061
General plant and other
 
(1)
2
 
to
71
 
2,985
 
2,723
Total cost
 
32,273
 
30,576
Less: Accumulated depreciation
(1)
(9,994)
(9,574)
 
22,279
 
21,002
Construction work in progress
(1)
 
2,097
 
1,994
Net book value
$
 
24,376
$
 
22,996
(1) SeaCoast owns a
50
% undivided ownership interest in a jointly owned
26
-mile pipeline lateral located in Florida, which went into
service in 2020. At December 31, 2023, SeaCoast’s share of plant in service was $
27
 
million USD (2022 – $
27
 
million USD), and
accumulated depreciation of $
2
 
million USD (2022 – $
1
 
million USD). SeaCoast’s undivided ownership interest is financed with its
funds and all operations are accounted for as if such participating interest were a wholly owned facility.
 
SeaCoast’s share of direct
expenses of the jointly owned pipeline is included in "OM&G" in the Consolidated Statements of Income.
21.
 
EMPLOYEE BENEFIT PLANS
Emera maintains a number of contributory defined-benefit (“DB”) and defined-contribution (“DC”) pension
plans, which cover substantially all of its employees. In addition, the Company provides non-pension
benefits for its retirees. These plans cover employees in Nova Scotia, New Brunswick, Newfoundland and
Labrador, Florida, New Mexico, Barbados, and Grand Bahama Island.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Exhibit 99.3
53
Emera’s net periodic benefit cost included the following:
Benefit Obligation and Plan Assets:
The changes in benefit obligation and plan assets, and the funded status for all plans were as follows:
For the
 
Year ended December 31
millions of dollars
2023
2022
Change in Projected Benefit Obligation
("PBO") and Accumulated Post-
retirement Benefit Obligation ("APBO")
Defined benefit
pension plans
Non-pension
benefit plans
Defined benefit
pension plans
Non-pension
benefit plans
Balance, January 1
$
 
2,158
$
 
243
$
 
2,624
$
 
318
Service cost
 
30
 
3
 
41
 
4
Plan participant contributions
 
6
 
6
 
6
 
6
Interest cost
 
111
 
13
 
80
 
9
Plan amendments
-
 
(14)
-
 
-
 
Benefits paid
 
(147)
(29)
(174)
(31)
Actuarial losses (gains)
 
146
 
10
(480)
(79)
Settlements and curtailments
(8)
-
 
(6)
-
 
FX translation adjustment
(23)
(5)
 
67
 
16
Balance, December 31
$
 
2,273
$
 
227
$
 
2,158
$
 
243
Change in plan assets
Balance, January 1
$
 
2,163
$
 
46
$
 
2,702
$
 
51
Employer contributions
 
42
 
23
 
45
 
24
Plan participant contributions
 
 
6
 
6
 
6
 
6
Benefits paid
(147)
(29)
(174)
(31)
Actual return on assets, net of expenses
 
262
 
3
(489)
(7)
Settlements and curtailments
(8)
-
 
(6)
-
 
FX translation adjustment
(20)
(1)
 
79
 
3
Balance, December 31
$
 
2,298
$
 
48
$
 
2,163
$
 
46
Funded status, end of year
 
$
 
25
$
(179)
$
 
5
$
(197)
The actuarial losses recognized in the period are primarily due to changes in the discount rate, higher
than expected indexation, and compensation-related assumption changes.
Plans with PBO/APBO
in Excess of Plan Assets:
The aggregate financial position for all pension plans where the PBO or APBO (for post-retirement benefit
plans) exceeded the plan assets for the years ended December 31 was as follows:
millions of dollars
2023
2022
Defined benefit
pension plans
Non-pension
benefit plans
Defined benefit
pension plans
Non-pension
benefit plans
PBO/APBO
$
 
120
$
 
205
$
 
1,006
$
 
221
FV of plan assets
 
37
-
 
 
914
-
 
Funded status
$
(83)
$
(205)
$
(92)
$
(221)
Plans with Accumulated Benefit Obligation (“ABO”)
in Excess of Plan Assets:
The ABO for the DB pension plans was $
2,172
 
million as at December 31, 2023 (2022 – $
2,080
 
million).
The aggregate financial position for those plans with an ABO in excess of the plan assets for the years
ended December 31 was as follows:
millions of dollars
2023
2022
Defined benefit
pension plans
Defined benefit
pension plans
ABO
$
 
114
$
 
111
FV of plan assets
 
37
 
33
Funded status
$
(77)
$
(78)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Exhibit 99.3
54
Balance Sheet:
The amounts recognized in the Consolidated Balance Sheets consisted of the following:
As at
December 31
December 31
millions of dollars
2023
2022
Defined benefit
pension plans
Non-pension
benefit plans
Defined benefit
pension plans
Non-pension
benefit plans
Other current liabilities
$
(5)
$
(18)
$
(13)
$
(20)
Long-term liabilities
(78)
(187)
(80)
(201)
Other long-term assets
 
108
 
26
 
98
 
24
AOCI, net of tax and regulatory assets
 
385
 
20
 
358
 
22
Less: Deferred income tax (expense)
recovery in AOCI
(8)
(1)
(7)
(1)
Net amount recognized
$
 
402
$
(160)
$
 
356
$
(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:
Regulatory assets
Actuarial
 
(gains) losses
Past service
(gains) costs
millions of dollars
Defined Benefit Pension Plans
Balance, January 1, 2023
$
 
336
$
 
15
$
-
 
Amortized in current period
(6)
(3)
-
 
Current year additions
 
1
 
41
-
 
Change in FX rate
(7)
-
 
-
 
Balance, December 31, 2023
$
 
324
$
 
53
$
-
 
Non-pension benefits plans
Balance, January 1, 2023
$
 
31
$
(10)
$
-
 
Amortized in current period
 
2
 
3
-
 
Current year reductions
(3)
(1)
(3)
Change in FX rate
(1)
-
 
 
1
Balance, December 31, 2023
$
 
29
$
(8)
$
(2)
As at
December
31
December
31
millions of dollars
2023
2022
Defined benefit
pension plans
Non-pension
benefit plans
Defined benefit
pension plans
Non-pension
benefit plans
Actuarial losses (gains)
$
 
53
(8)
$
 
15
$
(10)
Past service gains
-
 
(2)
-
 
-
 
Deferred income tax expense
 
8
 
1
 
7
 
1
AOCI, net of tax
 
61
(9)
 
22
(9)
Regulatory assets
 
324
 
29
 
336
 
31
AOCI, net of tax and regulatory assets
$
 
385
$
 
20
$
 
358
$
 
22
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Exhibit 99.3
55
Benefit Cost Components:
Emera's net periodic benefit cost included the following:
As at
Year ended December 31
millions of dollars
2023
2022
Defined benefit
pension plans
Non-pension
benefit plans
Defined benefit
pension plans
Non-pension
benefit plans
Service cost
$
 
30
$
 
3
$
 
41
$
 
4
Interest cost
 
111
 
13
 
80
 
9
Expected return on plan assets
(161)
(2)
(144)
-
 
Current year amortization of:
 
Actuarial losses (gains)
 
1
(3)
 
8
-
 
 
Regulatory assets (liability)
 
6
(2)
 
21
 
2
Settlement, curtailments
 
2
-
 
 
2
-
 
Total
$
(11)
$
 
9
$
 
8
$
 
15
The expected return on plan assets is determined based on the market-related value of plan assets of
$
2,577
 
million as at January 1, 2023 (2022 – $
2,482
 
million), adjusted for interest on certain cash flows
during the year.
The market-related value of assets is based on a five-year smoothed asset value. Any
investment gains (or losses) in excess of (or less than) the expected return on plan assets are recognized
on a straight-line basis into the market-related value of assets over a five-year period.
Pension Plan Asset Allocations:
Emera’s investment policy includes discussion regarding the investment philosophy, the level of risk
which the Company is prepared to accept with respect to the investment of the Pension Funds, and the
basis for measuring the performance of the assets. Central to the policy is the target asset allocation by
major asset categories. The objective of the target asset allocation is to diversify risk and to achieve asset
returns that meet or exceed the plan’s actuarial assumptions. The diversification of assets reduces the
inherent risk in financial markets by requiring that assets be spread out amongst various asset classes.
Within each asset class, a further diversification is undertaken through the investment in a broad range of
investment and non-investment grade securities. Emera’s target asset allocation is as follows:
Canadian Pension Plans
Asset Class
Target Range at Market
Short-term securities
0%
to
10%
Fixed income
34%
to
49%
Equities:
 
Canadian
7%
to
17%
 
Non-Canadian
35%
to
59%
Non-Canadian Pension Plans
Asset Class
Target Range at Market
Weighted average
Cash and cash equivalents
0%
to
10%
Fixed income
29%
to
49%
Equities
48%
to
68%
Pension Plan assets are overseen by the respective Management Pension Committees in the sponsoring
companies. All pension investments are in accordance with policies approved by the respective Board of
Directors of each sponsoring company.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Exhibit 99.3
56
The following tables set out the classification of the methodology used by the Company to FV its
investments:
millions of dollars
NAV
Level 1
Level 2
Total
Percentage
As at
December 31, 2023
Cash and cash equivalents
$
-
$
40
$
-
$
40
2
%
Net in-transits
-
(9)
-
(9)
-
%
Equity securities:
 
Canadian equity
-
96
-
96
4
%
 
United States equity
 
-
141
-
141
6
%
 
Other equity
-
112
-
112
5
%
Fixed income securities:
 
Government
-
-
172
172
8
%
 
Corporate
-
-
90
90
4
%
 
Other
-
4
5
9
-
%
Mutual funds
-
50
-
50
2
%
Other
-
6
(1)
5
-
%
Open-ended investments
measured at NAV
 
(1)
1,006
-
-
1,006
44
%
Common collective trusts
measured at NAV
(2)
586
-
-
586
25
%
Total
 
$
1,592
$
440
$
266
$
2,298
100
%
As at
December 31, 2022
Cash and cash equivalents
$
-
$
70
$
-
$
70
3
%
Net in-transits
-
(70)
-
(70)
(3)
%
Equity securities:
 
Canadian equity
-
87
-
87
4
%
 
United States equity
 
-
233
-
233
11
%
 
Other equity
-
186
-
186
8
%
Fixed income securities:
 
Government
-
-
104
104
5
%
 
Corporate
-
-
83
83
4
%
 
Other
-
3
11
14
1
%
Mutual funds
-
68
-
68
3
%
Other
-
-
(3)
(3)
-
%
Open-ended investments
measured at NAV
 
(1)
790
-
-
790
36
%
Common collective trusts
measured at NAV
(2)
601
-
-
601
28
%
Total
 
$
 
1,391
$
 
577
$
 
195
$
 
2,163
100
%
(1) Net asset value ("NAV") investments are open-ended
 
registered and non-registered mutual funds, collective investment trusts,
or pooled funds. NAV’s are calculated
 
at least monthly and the funds honour subscription and redemption activity regularly.
(2) The common collective trusts are private funds valued at NAV.
 
The NAVs are calculated based on bid prices
 
of the underlying
securities. Since the prices are not published to external sources, NAV
 
is used as a practical expedient. Certain funds invest
primarily in equity securities of domestic and foreign issuers while others invest in long duration U.S. investment grade fixed
income assets and seeks to increase return through active management of interest rate and credit risks. The funds honour
subscription and redemption activity regularly.
Refer to note 16 for more information on the FV hierarchy and inputs used to measure FV.
Post-Retirement Benefit Plans:
There are no assets set aside to pay for most of the Company’s post-retirement benefit plans. As is
common practice, post-retirement health benefits are paid from general accounts as required. The
primary exception to this is the NMGC Retiree Medical Plan, which is fully funded.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Exhibit 99.3
57
Investments in Emera:
As at December 31, 2023 and 2022, assets related to the pension funds and post-retirement benefit plans
did not hold any material investments in Emera or its subsidiaries securities. However, as a significant
portion of assets for the benefit plan are held in pooled assets, there may be indirect investments in these
securities.
Cash Flows:
The following table shows expected cash flows for DB pension and other post-retirement benefit plans:
millions of dollars
Defined benefit
pension plans
Non-pension
benefit plans
Expected employer contributions
2024
$
 
34
$
 
19
Expected benefit payments
2024
 
172
 
21
2025
 
163
 
21
2026
 
166
 
21
2027
 
171
 
21
2028
 
173
 
20
2029 – 2033
 
890
 
95
Assumptions:
The following table shows the assumptions that have been used in accounting for DB pension and other
post-retirement benefit plans:
2023
2022
(weighted average assumptions)
Defined benefit
pension plans
Non-pension
benefit plans
Defined benefit
pension plans
Non-pension
benefit plans
Benefit obligation – December 31:
Discount rate - past service
4.89
%
4.89
%
5.33
%
5.31
%
Discount rate - future service
4.88
%
4.89
%
5.34
%
5.32
%
Rate of compensation increase
3.87
%
3.85
%
3.62
%
3.61
%
Health care trend
 
- initial (next year)
-
6.04
%
-
5.40
%
 
- ultimate
 
-
3.76
%
-
3.77
%
 
- year ultimate reached
2043
2043
Benefit cost for year ended December 31:
Discount rate - past service
5.33
%
5.31
%
3.05
%
2.81
%
Discount rate - future service
5.34
%
5.32
%
3.18
%
2.92
%
Expected long-term return on plan assets
6.56
%
2.16
%
6.07
%
1.32
%
Rate of compensation increase
3.62
%
3.61
%
3.31
%
3.29
%
Health care trend
 
- initial (current year)
-
5.40
%
-
5.09
%
 
- ultimate
 
-
3.77
%
-
3.77
%
 
- year ultimate reached
2043
2042
Actual assumptions used differ by plan.
The expected long-term rate of return on plan assets is based on historical and projected real rates of
return for the plan’s current asset allocation, and assumed inflation. A real rate of return is determined for
each asset class. Based on the asset allocation, an overall expected real rate of return for all assets is
determined. The asset return assumption is equal to the overall real rate of return assumption added to
the inflation assumption, adjusted for assumed expenses to be paid from the plan.
The discount rate is based on high-quality long-term corporate bonds, with maturities matching the
estimated cash flows from the pension plan.
Defined Contribution Plan:
Emera also provides a DC pension plan for certain employees. The Company’s contribution for the year
ended December 31, 2023 was $
45
 
million (2022 – $
41
 
million).
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Exhibit 99.3
58
22.
 
GOODWILL
The change in goodwill for the year ended December 31 was due to the following:
millions of dollars
 
2023
2022
Balance, January 1
$
 
6,012
$
 
5,696
Change in FX rate
(141)
 
389
GBPC impairment charge
-
 
(73)
Balance, December 31
$
 
5,871
$
 
6,012
Goodwill is subject to an annual assessment for impairment at the reporting unit level. The goodwill on
Emera’s Consolidated Balance Sheets at December 31, 2023, primarily related to TECO Energy
(reporting units with goodwill are TEC, PGS, and NMGC).
 
In 2023, Emera performed qualitative impairment assessments for NMGC and PGS, concluding that the
FV of the reporting units exceeded their respective carrying amounts, and as such, no quantitative
assessments were performed and
no
 
impairment charges were recognized. Given the length of time
passed since the last quantitative impairment test for the TEC reporting unit, Emera elected to bypass a
qualitative assessment and performed a quantitative impairment assessment in Q4 2023 using a
combination of the income approach and market approach. This assessment estimated that the FV of the
TEC reporting unit exceeded its carrying amount, including goodwill, and as a result
no
 
impairment
charges were recognized.
In 2022, the Company elected to bypass a qualitative assessment and performed a quantitative
impairment assessment for GBPC, using the income approach. It was determined that the FV did not
exceed its carrying amount, including goodwill. As a result of this assessment, a goodwill impairment
charge of $
73
 
million was recorded in 2022, reducing the GBPC goodwill balance to nil as at December
31, 2022. This non-cash charge is included in “GBPC impairment charge” on the Consolidated
Statements of Income.
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
 
2023
Weighted
average
 
interest rate
2022
Weighted
average
 
interest rate
TEC
Advances on revolving credit facilities
$
 
277
5.68
%
$
 
1,380
5.00
%
Emera
Non-revolving term facilities
 
796
6.07
%
 
796
5.19
%
Bank indebtedness
 
 
9
-
%
-
 
-
%
TECO Finance
 
Advances on revolving credit and term facilities
 
245
6.54
%
 
481
5.47
%
PGS
Advances on revolving credit facilities
 
73
6.36
%
-
 
-
%
NMGC
Advances on revolving credit facilities
 
25
6.46
%
 
59
5.15
%
GBPC
Advances on revolving credit facilities
 
8
5.54
%
 
10
5.25
%
Short-term debt
$
 
1,433
$
 
2,726
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Exhibit 99.3
59
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
Maturity
2023
2022
TEC - Unsecured committed revolving credit facility
2026
$
 
401
$
 
1,084
TECO Energy/TECO Finance - revolving credit facility
2026
-
 
 
542
TECO Finance - Unsecured committed revolving credit facility
2026
 
529
-
 
Emera - Unsecured non-revolving term facility
2024
 
400
 
400
Emera - Unsecured non-revolving term facility
2024
 
400
 
400
PGS - Unsecured revolving credit facility
2028
 
331
-
 
TEC - Unsecured revolving facility
2024
 
265
 
542
TEC - Unsecured revolving facility
2024
 
265
-
 
NMGC - Unsecured revolving credit facility
2026
 
165
 
169
Other - Unsecured committed revolving credit facilities
Various
 
17
 
18
Total
$
 
2,773
$
 
3,155
Less:
Advances under revolving credit and term facilities
 
1,433
 
2,731
Letters of credit issued within the credit facilities
 
3
 
4
Total advances under available facilities
 
1,436
 
2,735
Available capacity under existing agreements
$
 
1,337
$
 
420
The weighted average interest rate on outstanding short-term debt at December 31, 2023 was
5.95
 
per
cent (2022 –
5.01
 
per cent).
Recent Significant Financing Activity by Segment
Florida Electric Utilities
 
On November 24, 2023, TEC repaid its $
400
 
million USD unsecured non-revolving facility, which expired
on
December 13, 2023
.
 
On April 3, 2023, TEC entered into a
364
-day, $
200
 
million USD senior unsecured revolving credit facility
which matures on
April 1, 2024
. The credit agreement contains customary representations and
warranties, events of default and financial and other covenants, and bears interest at a variable interest
rate, based on either the term secured overnight financing rate (“SOFR”), Wells Fargo’s prime rate, the
federal funds rate or the one-month SOFR, plus a margin.
On March 1, 2023, TEC entered into a
364
-day, $
200
 
million USD senior unsecured revolving credit
facility which matures on
February 28, 2024
. The credit facility contains customary representations and
warranties, events of default and financial and other covenants, and bears interest at a variable interest
rate, based on either the term SOFR, the Bank of Nova Scotia’s prime rate, the federal funds rate or the
one-month SOFR, plus a margin.
Gas Utilities and Infrastructure
On December 1, 2023, PGS entered into a $
250
 
million USD senior unsecured revolving credit facility
with a group of banks, maturing on
December 1, 2028
. PGS has the ability to request the lenders to
increase their commitments under the credit facility by up to $
100
 
million USD in the aggregate subject to
agreement from participating lenders. The credit agreement contains customary representations and
warranties, events of default and financial and other covenants, and bears interest at Bankers’
Acceptances or prime rate advances, plus a margin.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Exhibit 99.3
60
Other
On December 16, 2023, Emera amended its $
400
 
million unsecured non-revolving facility to extend the
maturity date from
December 16, 2023
 
to
December 16, 2024
. There were no other changes in
commercial terms from the prior agreement.
On June 30, 2023, Emera amended its $
400
 
million unsecured non-revolving facility to extend the
maturity date from
August 2, 2023
 
to
August 2, 2024
. There were no other changes in commercial terms
from the prior agreement.
24.
 
OTHER CURRENT LIABILITIES
As at
December 31
December 31
millions of dollars
 
2023
2022
Accrued charges
$
 
172
$
 
174
Nova Scotia Cap-and-Trade Program provision (note 6)
-
 
 
172
Accrued interest on long-term debt
 
107
 
97
Pension and post-retirement liabilities (note 21)
 
23
 
33
Sales and other taxes payable
 
11
 
14
Income tax payable
 
2
 
9
Other
 
112
 
80
$
 
427
$
 
579
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Exhibit 99.3
61
25.
 
LONG-TERM DEBT
Bonds, notes and debentures are at fixed interest rates and are unsecured unless noted below. Included
are certain bankers’ acceptances and commercial paper where the Company has the intention and the
unencumbered ability to refinance the obligations for a period greater than one year.
Long-term debt as at December 31 consisted of the following:
Weighted average interest
rate
(1)
millions of dollars
2023
2022
Maturity
2023
2022
Emera
 
Bankers acceptances, SOFR loans
 
Variable
Variable
2027
$
 
465
$
 
403
Unsecured fixed rate notes
4.84%
2.90%
2030
 
500
 
500
Fixed to floating subordinated notes
(2)
6.75%
6.75%
2076
 
1,587
 
1,625
$
 
2,552
$
 
2,528
Emera Finance
 
Unsecured senior notes
3.65%
3.65%
2024 - 2046
$
 
3,637
$
 
3,725
TEC
(3)
Fixed rate notes and bonds
4.61%
4.15%
2024 - 2051
$
 
5,654
$
 
4,341
PGS
Fixed rate notes and bonds
5.63%
3.78%
2028 - 2053
$
 
1,223
$
 
772
NMGC
Fixed rate notes and bonds
3.78%
3.11%
2026 - 2051
$
 
642
$
 
521
Non-revolving term facility, floating rate
Variable
Variable
2024
 
30
 
108
$
 
672
$
 
629
NMGI
Fixed rate notes and bonds
3.64%
3.64%
2024
$
 
198
$
 
203
NSPI
Discount Notes
(4)
Variable
Variable
2024 - 2027
$
 
721
$
 
881
Medium term fixed rate notes
5.13%
5.14%
2025 - 2097
 
3,165
 
2,665
$
 
3,886
$
 
3,546
EBP
Senior secured credit facility
Variable
Variable
2026
$
 
246
$
 
249
ECI
Secured senior notes
Variable
Variable
2027
$
 
75
$
 
86
Amortizing fixed rate notes
4.00%
3.97%
2026
 
79
 
100
Non-revolving term facility, floating rate
Variable
Variable
2025
 
29
 
30
Non-revolving term facility, fixed rate
2.15%
2.05%
2025 - 2027
 
155
 
91
Secured fixed rate senior notes
(5)
3.09%
3.06%
2024 - 2029
 
84
 
142
$
 
422
$
 
449
Adjustments
Fair market value adjustment - TECO Energy acquisition
$
-
 
$
 
2
Debt issuance costs
(125)
(126)
Amount due within one year
(676)
(574)
$
(801)
$
(698)
Long-Term Debt
$
 
17,689
$
 
15,744
(1) Weighted average interest rate of fixed rate long-term debt.
(2) In 2023, the Company recognized $
109
 
million in interest expense (2022 – $
110
 
million) related to its fixed to floating
subordinated notes.
(3) A substantial part of TEC’s tangible assets are pledged as collateral to secure its first mortgage bonds. There are currently
 
no
bonds outstanding under TEC’s first mortgage bond indenture.
(4) Discount notes are backed by a revolving credit facility which matures in 2027. Banker’s acceptances are issued under NSPI’s
non-revolving term facility which matures in 2024. NSPI has the intention and unencumbered ability to refinance bankers’
acceptances for a period of greater than one year.
(5) Notes are issued and payable in either USD or BBD.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Exhibit 99.3
62
The Company’s total long-term revolving credit facilities, outstanding borrowings and available capacity as
at December 31 were as follows:
millions of dollars
Maturity
2023
2022
Emera – revolving credit facility
(1)
June 2027
$
 
900
$
 
900
TEC - Unsecured committed revolving credit facility
December 2026
 
657
-
 
NSPI - revolving credit facility
(1)
December 2027
 
800
 
800
NSPI - non-revolving credit facility
July 2024
 
400
 
400
Emera - Unsecured non-revolving credit facility
February 2024
 
400
-
 
NMGC - Unsecured non-revolving credit facility
March 2024
 
30
 
108
ECI – revolving credit facilities
October 2024
 
10
 
11
Total
$
 
3,197
$
 
2,219
Less:
Borrowings under credit facilities
 
1,884
 
1,396
Letters of credit issued inside credit facilities
 
6
 
12
Use of available facilities
$
 
1,890
$
 
1,408
Available capacity under existing agreements
$
 
1,307
$
 
811
(1) Advances on the revolving credit facility can be made by way of overdraft on accounts up to $
50
 
million.
Debt Covenants
Emera and its subsidiaries have debt covenants associated with their credit facilities. Covenants are
tested regularly and the Company is in compliance with covenant requirements. Emera’s significant
covenants are listed below:
As at
Financial Covenant
Requirement
December 31, 2023
Emera
Syndicated credit facilities
Debt to capital ratio
Less than or equal to
0.70
 
to 1
0.57
 
: 1
Recent Significant Financing Activity by Segment
Florida Electric Utility
On January 30, 2024, TEC issued $
500
 
million USD of senior unsecured bonds that bear interest at
4.90
per cent with a maturity date of
March 1, 2029
. Proceeds from the issuance were primarily used for
repayment of short-term borrowings outstanding under the
5
-year credit facility. Therefore, $
497
 
million
USD of short-term borrowings that were repaid was classified as long-term debt at December 31, 2023.
Canadian Electric Utilities
On March 24, 2023, NSPI issued $
500
 
million in unsecured notes. The issuance included $
300
 
million
unsecured notes that bear interest at
4.95
 
per cent with a maturity date of
November 15, 2032
, and $
200
million unsecured notes that bear interest at
5.36
 
per cent with a maturity date of
March 24, 2053
.
 
Gas Utilities and Infrastructure
On December 19, 2023, PGS completed an issuance of $
925
 
million USD in senior notes. The issuance
included $
350
 
million USD senior notes that bear interest at
5.42
 
per cent with a maturity date of
December 19, 2028
, $
350
 
million USD senior notes that bear interest at
5.63
 
per cent with a maturity date
of
December 19, 2033
 
and $
225
 
million USD senior notes that bear interest at
5.94
 
per cent with a
maturity date of
December 19, 2053
.
On October 19, 2023, NMGC issued $
100
 
million USD in senior unsecured notes that bear interest at
6.36
 
per cent with a maturity date of
October 19, 2033
.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Exhibit 99.3
63
Other Electric Utilities
 
On May 24, 2023, GBPC issued a $
28
 
million USD non-revolving term loan that bears interest at
4.00
 
per
cent with a maturity date of
May 24, 2028
.
 
Other
 
On August 18, 2023, Emera entered into a $
400
 
million non-revolving term facility with a maturity date of
February 19, 2024
. The credit agreement contains customary representations and warranties, events of
default and financial and other covenants, and bears interest at Bankers’ Acceptances or prime rate
advances, plus a margin. On February 16, 2024, Emera extended the term of this agreement to a
maturity date of
February 19, 2025
.
On May 2, 2023, Emera issued $
500
 
million in senior unsecured notes that bear interest at
4.84
 
per cent
with a maturity date of
May 2, 2030
.
 
Long-Term Debt Maturities
As at December 31, long-term debt maturities, including capital lease obligations, for each of the next five
years and in aggregate thereafter are as follows:
millions of dollars
2024
2025
2026
2027
2028
Thereafter
Total
Emera
$
 
199
$
-
 
$
 
1,587
$
 
266
$
-
 
$
 
500
$
 
2,552
Emera US Finance LP
 
397
-
 
 
992
-
 
-
 
 
2,248
 
3,637
TEC
 
397
-
 
-
 
-
 
-
 
 
5,257
 
5,654
PGS
-
 
-
 
-
 
-
 
 
463
 
760
 
1,223
NMGC
 
30
-
 
 
93
-
 
-
 
 
549
 
672
NMGI
 
198
-
 
-
 
-
 
-
 
-
 
 
198
NSPI
 
398
 
125
 
40
 
323
-
 
 
3,000
 
3,886
EBP
-
 
-
 
 
246
-
 
-
 
-
 
 
246
ECI
 
51
 
139
 
89
 
77
 
62
 
4
 
422
Total
$
 
1,670
$
 
264
$
 
3,047
$
 
666
$
 
525
$
 
12,318
$
 
18,490
26.
 
ASSET RETIREMENT OBLIGATIONS
AROs mostly relate to reclamation of land at the thermal, hydro and combustion turbine sites; and the
disposal of polychlorinated biphenyls in transmission and distribution equipment and a pipeline site.
Certain hydro, transmission and distribution assets may have additional AROs that cannot be measured
as these assets are expected to be used for an indefinite period and, as a result, a reasonable estimate of
the FV of any related ARO cannot be made.
 
The change in ARO for the years ended December 31 is as follows:
millions of dollars
2023
2022
Balance, January 1
$
 
174
$
 
174
Accretion included in depreciation expense
 
9
 
9
Change in FX rate
(1)
 
3
Additions
-
 
 
1
Accretion deferred to regulatory asset (included in PP&E)
 
18
 
1
Liabilities settled
(8)
(1)
Revisions in estimated cash flows
-
 
(13)
Balance, December 31
$
 
192
$
 
174
 
 
 
 
 
 
 
 
 
 
 
 
Exhibit 99.3
64
27.
 
COMMITMENTS AND CONTINGENCIES
 
A.
Commitments
As at December 31, 2023, contractual commitments (excluding pensions and other post-retirement
obligations, long-term debt and asset retirement obligations) for each of the next five years and in
aggregate thereafter consisted of the following:
millions of dollars
2024
2025
2026
2027
2028
Thereafter
Total
Transportation
(1)
$
 
696
$
 
495
$
 
405
$
 
388
$
 
338
$
 
2,597
$
 
4,919
Purchased power
(2)
 
274
 
249
 
263
 
312
 
312
 
3,435
 
4,845
Fuel, gas supply and storage
 
556
 
215
 
62
-
 
 
5
-
 
 
838
Capital projects
 
778
 
111
 
70
 
1
-
 
-
 
 
960
Equity investment commitments
(3)
 
240
-
 
-
 
-
 
-
 
-
 
 
240
Other
 
154
 
147
 
56
 
46
 
35
 
221
 
659
$
 
2,698
$
 
1,217
$
 
856
$
 
747
$
 
690
$
 
6,253
$
 
12,461
(1) Purchasing commitments for transportation of fuel and transportation capacity on various pipelines.
 
Includes a commitment of
$
134
 
million related to a gas transportation contract between PGS and SeaCoast through 2040.
(2) Annual requirement to purchase electricity production from IPPs or other utilities over varying contract lengths.
(3) Emera has a commitment to make equity contributions to the LIL related to an investment true up in 2024 and sustaining
 
capital
contributions over the life of the partnership.
 
The commercial agreements between Emera and Nalcor require true ups to finalize the
respective investment obligations of the parties in relation the Maritime Link and LIL which is expected to be approximately
 
$
240
million in 2024. In addition, Emera has future commitments to provide sustaining capital to the LIL for routine capital and major
maintenance.
NSPI has a contractual obligation to pay NSPML for use of the Maritime Link over approximately
38 years
from its January 15, 2018 in-service date. In February 2022, the UARB issued its decision and Board
Order approving NSPML’s requested rate base of approximately $
1.8
 
billion. In December 2023, the
UARB approved the collection of up to $
164
 
million from NSPI for the recovery of Maritime Link costs in
2024. The timing and amounts payable to NSPML for the remainder of the
38
-year commitment period
are subject to UARB approval.
Construction of the LIL is complete, and the Newfoundland Electrical System Operator confirmed the
asset to be operating suitably to support reliable system operation and full functionality at
700
MW, which
was validated by the Government of Canada’s Independent Engineer issuing its Commissioning
Certificate on April 13, 2023.
Emera has committed to obtain certain transmission rights for Nalcor, if requested, to enable it to transmit
energy which is not otherwise used in Newfoundland and Labrador or Nova Scotia. Nalcor has the right to
transmit this energy from Nova Scotia to New England energy markets effective August 15, 2021 and
continuing for
50 years
. As transmission rights are contracted, the obligations are included within “Other”
in the above table.
B.
Legal Proceedings
Superfund and Former Manufactured Gas Plant Sites
Previously, TEC had been a potentially responsible party (“PRP”) for certain superfund sites through its
Tampa
 
Electric and former PGS divisions, as well as for certain former manufactured gas plant sites
through its PGS division. As a result of the separation of the PGS division into a separate legal entity,
Peoples Gas System, Inc. is also now a PRP for those sites (in addition to third party PRPs for certain
sites).
 
While the aggregate joint and several liability associated with these sites has not changed as a
result of the PGS legal separation, the sites continue to present the potential for significant response
costs. As at December 31, 2023, the aggregate financial liability of the Florida utilities is estimated to be
$
15
 
million ($
11
 
million USD), primarily at PGS. This estimate assumes that other involved PRPs are
credit-worthy entities. This amount has been accrued and is primarily reflected in the long-term liability
section under “Other long-term liabilities” on the Consolidated Balance Sheets. The environmental
remediation costs associated with these sites are expected to be paid over many years.
 
Exhibit 99.3
65
The estimated amounts represent only the portion of the cleanup costs attributable to the Florida utilities.
The estimates to perform the work are based on the Florida utilities’ experience with similar work,
adjusted for site-specific conditions and agreements with the respective governmental agencies. The
estimates are made in current dollars, are not discounted and do not assume any insurance recoveries.
In instances where other PRPs are involved, most of those PRPs are believed to be currently credit-
worthy and are likely to continue to be credit-worthy for the duration of the remediation work. However, in
those instances that they are not, the Florida utilities could be liable for more than their actual percentage
of the remediation costs. Other factors that could impact these estimates include additional testing and
investigation which could expand the scope of the cleanup activities, additional liability that might arise
from the cleanup activities themselves or changes in laws or regulations that could require additional
remediation. Under current regulations, these costs are recoverable through customer rates established
in base rate proceedings.
Other Legal Proceedings
Emera and its subsidiaries may, from time to time, be involved in other legal proceedings, claims and
litigation that arise in the ordinary course of business which the Company believes would not reasonably
be expected to have a material adverse effect on the financial condition of the Company.
C.
Principal Financial Risks and Uncertainties
Emera believes the following principal financial risks could materially affect the Company in the normal
course of business. Risks associated with derivative instruments and FV measurements are discussed in
note 15 and note 16.
 
Sound risk management is an essential discipline for running the business efficiently and pursuing the
Company’s strategy successfully. Emera has an enterprise-wide risk management process, overseen by
its Enterprise Risk Management Committee (“ERMC”) and monitored by the Board of Directors, to ensure
an effective, consistent and coherent approach to risk management. The Board of Directors has a Risk
and Sustainability Committee (‘RSC”) with a mandate that includes oversight of the Company’s Enterprise
Risk Management framework, including the identification, assessment, monitoring and management of
enterprise risks. It also includes oversight of the Company’s approach to sustainability and its
performance relative to its sustainability objectives.
Regulatory and Political Risk
The Company’s rate-regulated subsidiaries and certain investments subject to significant influence are
subject to risk of the recovery of costs and investments. Regulatory and political risk can include changes
in regulatory frameworks, shifts in government policy, legislative changes, and regulatory decisions.
As cost-of-service utilities with an obligation to serve customers, Emera’s utilities operate under formal
regulatory frameworks, and must obtain regulatory approval to change or add rates and/or riders. Emera
also holds investments in entities in which it has significant influence, and which are subject to regulatory
and political risk including NSPML, LIL, and M&NP.
 
As a regulated Group II pipeline, the tolls of
Brunswick Pipeline are regulated by the CER on a complaint basis, as opposed to the regulatory approval
process described above. In the absence of a complaint, the CER does not normally undertake a detailed
examination of Brunswick Pipeline’s tolls, which are subject to a firm service agreement, expiring in 2034,
with Repsol Energy North America Canada Partnership.
 
Exhibit 99.3
66
Regulators administer the regulatory frameworks covering material aspects of the utilities’ businesses,
including applying market-based tests to determine the appropriate customer rates and/or riders, the
underlying allowed ROEs, deemed capital structures, capital investment, the terms and conditions for the
provision of service, performance standards, and affiliate transactions. Regulators also review the
prudency of costs and other decisions that impact customer rates and reliability of service and work to
ensure the financial health of the utility for the benefit of customers. Costs and investments can be
recovered upon approval by the respective regulator as an adjustment to rates and/or riders, which
normally require a public hearing process or may be mandated by other governmental bodies.
 
During
public hearing processes, consultants and customer representatives scrutinize the costs, actions and
plans of these rate-regulated companies, and their respective regulators determine whether to allow
recovery and to adjust rates based upon the evidence and any contrary evidence from other parties. In
some circumstances, other government bodies may influence the setting of rates. Regulatory decisions,
legislative changes, and prolonged delays in the recovery of costs or regulatory assets could result in
decreased rate affordability for customers and could materially affect Emera and its utilities.
 
Emera’s utilities generally manage this risk through transparent regulatory disclosure, ongoing
stakeholder and government consultation and multi-party engagement on aspects such as utility
operations, regulatory audits, rate filings and capital plans. The subsidiaries work to establish
collaborative relationships with regulatory stakeholders, including customer representatives, both through
its approach to filings and additional efforts with technical conferences and, where appropriate, negotiated
settlements.
 
Changes in government and shifts in government policy and legislation can impact the commercial and
regulatory frameworks under which Emera and its subsidiaries operate. This includes initiatives regarding
deregulation or restructuring of the energy industry. Deregulation or restructuring of the energy industry
may result in increased competition and unrecovered costs that could adversely affect the Company’s
operations, net income and cash flows. State and local policies in some United States jurisdictions have
sought to prevent or limit the ability of utilities to provide customers the choice to use natural gas while in
other jurisdictions policies have been adopted to prevent limitations on the use of natural gas. Changes in
applicable state or local laws and regulations, including electrification legislation, could adversely impact
PGS and NMGC.
Emera cannot predict future legislative, policy, or regulatory changes, whether caused by economic,
political or other factors, or its ability to respond in an effective and timely manner or the resulting
compliance costs. Government interference in the regulatory process can undermine regulatory stability,
predictability, and independence, and could have a material adverse effect on the Company.
Foreign Exchange Risk
 
The Company is exposed to foreign currency exchange rate changes. Emera operates internationally,
with an increasing amount of the Company’s net income earned outside of Canada. As such, Emera is
exposed to movements in exchange rates between the CAD and, particularly, the USD, which could
positively or adversely affect results.
 
 
Consistent with the Company’s risk management policies, Emera manages currency risks through
matching United States denominated debt to finance its United States operations and may use foreign
currency derivative instruments to hedge specific transactions and earnings exposure. The Company may
enter FX forward and swap contracts to limit exposure on certain foreign currency transactions such as
fuel purchases, revenue streams and capital expenditures, and on net income earned outside of Canada.
The regulatory framework for the Company’s rate-regulated subsidiaries permits the recovery of prudently
incurred costs, including FX.
The Company does not utilize derivative financial instruments for foreign currency trading or speculative
purposes or to hedge the value of its investments in foreign subsidiaries. Exchange gains and losses on
net investments in foreign subsidiaries do not impact net income as they are reported in AOCI.
Exhibit 99.3
67
Liquidity and Capital Market Risk
Liquidity risk relates to Emera’s ability to ensure sufficient funds are available to meet its financial
obligations. Emera manages this risk by forecasting cash requirements on a continuous basis to
determine whether sufficient funds are available. Liquidity and capital needs could be financed through
internally generated cash flows, asset sales, short-term credit facilities, and ongoing access to capital
markets.
 
Emera’s access to capital and cost of borrowing is subject to several risk factors, including financial
market conditions, market disruptions and ratings assigned by various market analysts, including credit
rating agencies. Disruptions in capital markets could prevent Emera from issuing new securities or cause
the Company to issue securities with less than preferred terms and conditions. Emera’s growth plan
requires significant capital investments in PP&E and the risk associated with changes in interest rates
could have an adverse effect on the cost of financing. The Company’s future access to capital and cost of
borrowing may be impacted by various market disruptions. The inability to access cost-effective capital
could have a material impact on Emera’s ability to fund its growth plan.
 
 
Emera is subject to financial risk associated with changes in its credit ratings. There are a number of
factors that rating agencies evaluate to determine credit ratings, including the Company’s business, its
regulatory framework and legislative environment, political interference in the regulatory process, the
ability to recover costs and earn returns, diversification, leverage, liquidity and increased exposure to
climate change-related impacts, including increased frequency and severity of hurricanes and other
severe weather events. A decrease in a credit rating could result in higher interest rates in future
financings, increased borrowing costs under certain existing credit facilities, limit access to the
commercial paper market, or limit the availability of adequate credit support for subsidiary operations. For
more information on interest rate risk, refer to “General Economic Risk – Interest Rate Risk”. For certain
derivative instruments, if the credit ratings of the Company were reduced below investment grade, the full
value of the net liability of these positions could be required to be posted as collateral. Emera manages
these risks by actively monitoring and managing key financial metrics with the objective of sustaining
investment grade credit ratings.
The Company has exposure to its own common share price through the issuance of various forms of
stock-based compensation, which affect earnings through revaluation of the outstanding units every
period. The Company uses equity derivatives to reduce the earnings volatility derived from stock-based
compensation.
General Economic Risk
The Company has exposure to the macro-economic conditions in North America and in other geographic
regions in which Emera operates. Like most utilities, economic factors such as consumer income,
employment and housing affect demand for electricity and natural gas, and in turn the Company’s
financial results. Adverse changes in general economic conditions and inflation may impact the ability of
customers to afford rate increases arising from increases to fuel, operating, capital, environmental
compliance, and other costs, and therefore could materially affect Emera and its utilities. This may also
result in higher credit and counterparty risk, adverse shifts in government policy and legislation, and/or
increased risk to full and timely recovery of costs and regulatory assets.
Interest Rate Risk:
Emera utilizes a combination of fixed and floating rate debt financing for operations and capital
expenditures, resulting in an exposure to interest rate risk. Emera seeks to manage interest rate risk
through a portfolio approach that includes the use of fixed and floating rate debt with staggered
maturities. The Company will, from time to time, issue long-term debt or enter interest rate hedging
contracts to limit its exposure to fluctuations in floating interest rate debt.
 
Exhibit 99.3
68
For Emera’s regulated subsidiaries, the cost of debt is a component of rates and prudently incurred debt
costs are recovered from customers. Regulatory ROE will generally follow the direction of interest rates,
such that regulatory ROEs are likely to fall in times of reducing interest rates and rise in times of
increasing interest rates, albeit not directly and generally with a lag period reflecting the regulatory
process. Rising interest rates may also negatively affect the economic viability of project development
and acquisition initiatives.
Interest rates could also be impacted by changes in credit ratings. For more information, refer to “Liquidity
and Capital Market Risk”.
 
As with most other utilities and other similar yield-returning investments, Emera’s share price may be
affected by changes in interest rates and could underperform the market in an environment of rising
interest rates.
Inflation Risk:
 
The Company may be exposed to changes in inflation that may result in increased operating and
maintenance costs, capital investment, and fuel costs compared to the revenues provided by customer
rates. Emera’s utilities have budgeting and forecasting processes to identify inflationary risk factors and
measure operating performance, as well as collective bargaining agreements that mitigate the short-term
impact of inflation on labour costs of unionized employees.
Commodity Price Risk
The Company’s utility fuel supply and purchase of other commodities is subject to commodity price risk.
In addition, Emera Energy is subject to commodity price risk through its portfolio of commodity contracts
and arrangements.
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.
Exhibit 99.3
69
Emera Energy Marketing and Trading:
Emera Energy has employed further measures to manage commodity risk. The majority of Emera
Energy’s portfolio of electricity and gas marketing and trading contracts and, in particular, its natural gas
asset management arrangements, are contracted on a back-to-back basis, avoiding any material long or
short commodity positions. However, the portfolio is subject to commodity price risk, particularly with
respect to basis point differentials between relevant markets in the event of an operational issue or
counterparty default. Changes in commodity prices can also result in increased collateral requirements
associated with physical contracts and financial hedges, resulting in higher liquidity requirements and
increased costs to the business.
To
 
measure commodity price risk exposure, Emera Energy employs a number of controls and processes,
including an estimated VaR analysis of its exposures. The VaR
 
amount represents an estimate of the
potential change in FV that could occur from changes in Emera Energy’s portfolio or changes in market
factors within a given confidence level, if an instrument or portfolio is held for a specified time period. The
VaR calculation is used to quantify exposure to market risk associated with physical commodities,
primarily natural gas and power positions.
Income Tax Risk
The computation of the Company’s provision for income taxes is impacted by changes in tax legislation in
Canada, the United States and the Caribbean. Any such changes could affect the Company’s future
earnings, cash flows, and financial position. The value of Emera’s existing deferred income tax assets
and liabilities are determined by existing tax laws and could be negatively impacted by changes in laws.
Emera monitors the status of existing tax laws to ensure that changes impacting the Company are
appropriately reflected in the Company’s tax compliance filings and financial results.
 
D.
Guarantees and Letters of Credit
Emera has guarantees and letters of credit on behalf of third parties outstanding. The following significant
guarantees and letters of credit are not included within the Consolidated Balance Sheets as at December
31, 2023
:
TECO Energy has issued a guarantee in connection with SeaCoast’s performance of obligations under a
gas transportation precedent agreement. The guarantee is for a maximum potential amount of $
45
 
million
USD if SeaCoast fails to pay or perform under the contract. The guarantee expires five years after the
gas transportation precedent agreement termination date, which was terminated on January 1, 2022. In
the event that TECO Energy’s and Emera’s long-term senior unsecured credit ratings are downgraded
below investment grade by Moody’s Investor Services (“Moody’s”) or S&P Global Ratings (“S&P”). TECO
Energy would be required to provide its counterparty a letter of credit or cash deposit of $
27
 
million USD.
TECO Energy issued a guarantee in connection with SeaCoast’s performance obligations under a firm
service agreement, which expires on December 31, 2055, subject to two extension terms at the option of
the counterparty with a final expiration date of December 31, 2071. The guarantee is for a maximum
potential amount of $
13
 
million USD if SeaCoast fails to pay or perform under the firm service agreement.
In the event that TECO Energy’s long-term senior unsecured credit ratings are downgraded below
investment grade by Moody’s or S&P,
 
TECO Energy would need to provide either a substitute guarantee
from an affiliate with an investment grade credit rating or a letter of credit or cash deposit of $
13
 
million
USD.
Emera Inc. has issued a guarantee of $
66
 
million USD relating to outstanding notes of ECI. This
guarantee will automatically terminate on the date upon which the obligations have been repaid in full.
NSPI has issued guarantees on behalf of its subsidiary, NS Power Energy Marketing Incorporated, in the
amount of $
104
 
million USD (2022 – $
119
 
million USD) with terms of varying lengths.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Exhibit 99.3
70
The Company has standby letters of credit and surety bonds in the amount of $
103
 
million USD
(December 31, 2022 – $
145
 
million USD) to third parties that have extended credit to Emera and its
subsidiaries. These letters of credit and surety bonds typically have a one-year term and are renewed
annually as required.
Emera Inc., on behalf of NSPI, has a standby letter of credit to secure obligations under a supplementary
retirement plan. The expiry date of this letter of credit was extended to June 2024. The amount committed
as at December 31, 2023 was $
56
 
million (December 31, 2022 – $
63
 
million).
Collaborative Arrangements
For the years ended December 31, 2023 and 2022, the Company has identified the following material
collaborative arrangements:
Through NSPI, the Company is a participant in three wind energy projects in Nova Scotia. The
percentage ownership of the wind project assets is based on the relative value of each party’s project
assets by the total project assets. NSPI has power purchase arrangements to purchase the entire net
output of the projects and, therefore, NSPI’s portion of the revenues are recorded net within regulated fuel
for generation and purchased power. NSPI’s portion of operating expenses is recorded in “OM&G” on the
Consolidated Statements of Income. In 2023, NSPI recognized $
8
 
million net expense (2022 – $
12
million) in “Regulated fuel for generation and purchased power” and $
3
 
million (2022 – $
3
 
million) in
“OM&G” on the Consolidated Statements of Income.
28.
 
CUMULATIVE PREFERRED STOCK
Authorized:
Unlimited number of First Preferred shares, issuable in series.
Unlimited number of Second Preferred shares, issuable in series.
December 31, 2023
December 31, 2022
Annual Dividend
Redemption
Issued and
Net
Issued and
Net
 
Per Share
Price per share
Outstanding
Proceeds
Outstanding
Proceeds
Series A
$
0.5456
$
25.00
4,866,814
$
 
119
4,866,814
$
 
119
Series B
Floating
$
25.00
1,133,186
$
 
28
1,133,186
$
 
28
Series C
$
1.6085
$
25.00
10,000,000
$
 
245
10,000,000
$
 
245
Series E
$
1.1250
$
25.00
5,000,000
$
 
122
5,000,000
$
 
122
Series F
$
1.0505
$
25.00
8,000,000
$
 
195
8,000,000
$
 
195
Series H
$
1.5810
$
25.00
12,000,000
$
 
295
12,000,000
$
 
295
Series J
$
1.0625
$
25.00
8,000,000
$
 
196
8,000,000
$
 
196
Series L
$
1.1500
$
26.00
9,000,000
$
 
222
9,000,000
$
 
222
Total
58,000,000
$
 
1,422
58,000,000
$
 
1,422
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Exhibit 99.3
71
Characteristics of the First Preferred Shares:
First Preferred Shares
(1)(2)
Initial Yield
 
(%)
Current
Annual
Dividend
 
($)
Minimum
 
Reset
Dividend
Yield (%)
Earliest Redemption
and/or Conversion
Option Date
Redemption
Value
 
($)
Right to
Convert on
a one for
one basis
Fixed rate reset
(3)(4)
 
Series A
4.400
0.5456
1.84
August 15, 2025
25.00
 
Series B
 
Series C
 
(5)(6)
4.100
1.6085
2.65
August 15, 2028
25.00
 
Series D
 
Series F
4.202
1.0505
2.63
February 15, 2025
25.00
 
Series G
Minimum rate reset
(3)(4)
 
Series B
2.393
Floating
1.84
August 15, 2025
25.00
 
Series A
 
Series H
(5)(7)
4.900
1.5810
4.90
August 15, 2028
25.00
 
Series I
 
Series J
4.250
1.0625
4.25
May 15, 2026
25.00
 
Series K
Perpetual fixed rate
 
Series E
 
(8)
4.500
1.1250
25.00
 
 
Series L
(9)
4.600
1.1500
November 15, 2026
26.00
 
(1) Holders are entitled to receive fixed or floating cumulative cash dividends when declared by the Board of Directors of the
Corporation.
(2) On or after the specified redemption dates, the Corporation has the option to redeem for cash the outstanding First
 
Preferred
Shares, in whole or in part, at the specified per share redemption value plus all accrued and unpaid dividends up to but
 
excluding the
dates fixed for redemption.
(3) On the redemption and/or conversion option date the reset annual dividend per share will be determined by multiplying
 
$
25.00
 
per
share by the annual fixed or floating dividend rate, which for Series A, C, F and H is the sum of the five-year Government
 
of Canada
Bond Yield on the applicable reset date, plus the applicable reset dividend yield
 
(Series H annual reset rate must be a minimum of
4.90
 
per cent) and for Series B equals the Government of Treasury Bill Rate on the applicable
 
reset date, plus 1.84 per cent.
(4) On each conversion option date, the holders have the option, subject to certain conditions, to convert any or all of their
 
Shares
into an equal number of Cumulative Redeemable First Preferred Shares of a specified series. The Company has the right
 
to redeem
 
the outstanding Preferred Shares, Series D, Series G and Series I shares without the consent of the holder every five years
 
thereafter
for cash, in whole or in part at a price of $
25.00
 
per share plus all accrued and unpaid dividends up to but excluding the date fixed for
redemption and $
25.50
 
per share plus all accrued and unpaid dividends up to but excluding the date fixed for redemption in the case
of redemptions on any other date after August 15, 2028, February 15, 2025 and August 15, 2028, respectively.
 
The reset dividend
yield for Series I equals the Government of Treasury Bill Rate on the applicable reset date, plus
2.54
 
per cent.
(5) On July 6, 2023, Emera announced it would not redeem the outstanding Preferred Shares, Series C and Series
 
H on August 15,
2023. On August 4, 2023, Emera announced after having taken into account all conversion notices received from holders,
 
no Series
C Shares were converted into Series D Shares and no Series H Shares were converted into Series I shares.
 
(6) The annual fixed dividend per share for Series C Shares was reset from $
1.1802
 
to $
1.6085
 
for the five-year period from and
including August 15, 2028.
(7) The annual fixed dividend per share for Series H Shares was reset from $
1.2250
 
to $
1.5810
 
for the five-year period from and
including August 15, 2028.
(8) First Preferred Shares, Series E are redeemable at $25.00 per share.
(9) First Preferred Shares, Series L are redeemable at $
26.00
 
on or after November 15, 2026 to November 15, 2027, decreasing
$
0.25
 
each year until November 15, 2030 and $
25.00
 
per share thereafter.
First Preferred Shares are neither redeemable at the option of the shareholder nor have a mandatory
redemption date. They are classified as equity and the associated dividends are deducted on the
Consolidated Statements of Income before arriving at “Net income attributable to common shareholders”
and shown on the Consolidated Statement of Changes in Equity as a deduction from retained earnings.
The First Preferred Shares of each series rank on a parity with the First Preferred Shares of every other
series and are entitled to a preference over the Second Preferred Shares, the Common Shares, and any
other shares ranking junior to the First Preferred Shares with respect to the payment of dividends and the
distribution of the remaining property and assets or return of capital of the Company in the liquidation,
dissolution or wind-up, whether voluntary or involuntary.
In the event the Company fails to pay, in aggregate, eight quarterly dividends on any series of the First
Preferred Shares, the holders of the First Preferred Shares, for only so long as the dividends remain in
arrears, will be entitled to attend any meeting of shareholders of the Company at which directors are to be
elected and to vote for the election of two directors out of the total number of directors elected at any such
meeting.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Exhibit 99.3
72
29.
 
NON-CONTROLLING INTEREST IN SUBSIDIARIES
As at
December 31
December 31
millions of dollars
 
2023
2022
Preferred shares of GBPC
 
$
 
14
$
 
14
$
 
14
$
 
14
Preferred shares of GBPC:
Authorized:
10,000
 
non-voting cumulative redeemable variable perpetual preferred shares.
2023
2022
Issued and outstanding:
number of
shares
millions of
dollars
number of
shares
millions of
dollars
Outstanding as at December 31
10,000
$
 
14
10,000
$
 
14
GBPC Non–Voting Cumulative Variable Perpetual Preferred Stock:
The preferred shares are redeemable by GBPC after June 17, 2021
, at $
1,000
 
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
 
Year ended December 31
millions of dollars
2023
2022
Changes in non-cash working capital:
 
Inventory
$
(31)
$
(214)
 
Receivables and other current assets
(1)
 
653
(636)
 
Accounts payable
(538)
 
423
 
Other current liabilities
(2)
(179)
 
193
Total non-cash working capital
 
$
(95)
$
(234)
(1) Includes $
162
 
million related to the January 2023 settlement of NMGC gas hedges (2022 – ($
162
) million). Offsetting regulatory
liability is included in operating cash flow before working capital resulting in no impact to net cash provided by operating activities.
(2) Includes ($
166
) million related to the Nova Scotia Cap-and-Trade program (2022 – $
172
 
million). For further detail, refer to note
6. Offsetting regulatory asset (FAM) balance is
 
included in operating cash flow before working capital resulting in no impact to net
cash provided by operating activities.
For the
 
Year ended December 31
millions of dollars
2023
2022
Supplemental disclosure of cash paid:
Interest
$
 
930
$
 
699
Income taxes
$
 
43
$
 
67
Supplemental disclosure of non-cash activities:
Common share dividends reinvested
$
 
271
$
 
237
Decrease in accrued capital expenditures
$
(19)
$
(13)
Reclassification of short-term debt to long-term debt
$
 
657
$
-
 
Reclassification of long-term debt to short-term debt
$
-
 
$
 
500
Supplemental disclosure of operating activities:
Net change in short-term regulatory assets and liabilities
$
 
123
$
(157)
Exhibit 99.3
73
31.
 
STOCK-BASED COMPENSATION
Employee Common Share Purchase Plan and Common Shareholders Dividend
Reinvestment and Share Purchase Plan
Eligible employees may participate in the ECSPP. As of December 31, 2023, the plan allows employees
to make cash contributions of a minimum of $25 to a maximum of $20,000 CAD or $15,000 USD per year
for the purpose of purchasing common shares of Emera. The Company also contributes 20 per cent of
the employees’ contributions to the plan.
The plan allows reinvestment of dividends for all participants except where prohibited by law.
 
The
maximum aggregate number of Emera common shares reserved for issuance under this plan is
7
 
million
common shares. As at December 31, 2023, Emera was in compliance with this requirement.
Compensation cost for shares issued under the ECSPP for the year ended December 31, 2023 was $
3
million (2022 – $
3
 
million) and was included in “OM&G” on the Consolidated Statements of Income.
 
The Company also has a Common Shareholders DRIP, which provides an opportunity for shareholders
residing in Canada to reinvest dividends and purchase common shares. This plan provides for a discount
of up to 5 per cent from the average market price of Emera’s common shares for common shares
purchased in connection with the reinvestment of cash dividends. The discount was 2 per cent in 2023.
Stock-Based Compensation Plans
Stock Option Plan
The Company has a stock option plan that grants options to senior management of the Company for a
maximum term of 10 years. The option price of the stock options is the closing price of the Company’s
common shares on the Toronto Stock Exchange on the last business day on which such shares were
traded before the date on which the option is granted. The maximum aggregate number of shares
issuable under this plan is 14.7 million shares. As at December 31, 2023, Emera was in compliance with
this requirement.
Stock options granted in 2021 and prior vest in 25 per cent increments on the first, second, third and
fourth anniversaries of the date of the grant. Stock options granted in 2022 and thereafter vest in 20 per
cent increments on the first, second, third, fourth and fifth anniversaries of the date of the grant. If an
option is not exercised within 10 years, it expires and the optionee loses all rights thereunder. The holder
of the option has no rights as a shareholder until the option is exercised and shares have been issued.
The total number of stocks to be optioned to any optionee shall not exceed five per cent of the issued and
outstanding common stocks on the date the option is granted.
For stock options granted in 2021 and prior, unless a stock option has expired, vested options may be
exercised within the
27 months
 
following the option holder’s date of retirement,
six months
 
following a
termination without just cause or death, and within
sixty days
 
following the date of termination for just
cause or resignation. Commencing with the 2022 stock option grant, vested options may be exercised
during the full term of the option following the option holders date of retirement,
six months
 
following a
termination without just cause or death, and within
sixty days
 
following the date of termination for just
cause or resignation. If stock options are not exercised within such time, they expire.
The Company uses the Black-Scholes valuation model to estimate the compensation expense related to
its stock-based compensation and recognizes the expense over the vesting period on a straight-line
basis.
The following table shows the weighted average FV per stock option along with the assumptions
incorporated into the valuation models for options granted, for the year-ended December 31:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Exhibit 99.3
74
2023
2022
Weighted average FV per option
$
6.32
$
5.35
Expected term
(1)
5
 
years
5
 
years
Risk-free interest rate
(2)
 
3.53
%
 
1.79
%
Expected dividend yield
(3)
 
5.05
%
 
4.55
%
Expected volatility
(4)
 
20.07
%
 
18.87
%
(1) The expected term of the option awards is calculated based on historical exercise behaviour and represents the period
 
of time
that the options are expected to be outstanding.
(2) Based on the Bank of Canada five-year government bond yields.
(3) Incorporates current dividend rates and historical dividend increase patterns.
(4) Estimated using the five-year historical volatility.
The following table summarizes stock option information for 2023:
Total Options
Non-Vested Options
(1)
Number of
Options
 
Weighted
average exercise
price per share
Number of
Options
Weighted
average grant
date fair-value
Outstanding as at December 31, 2022
2,853,879
$
50.41
1,348,400
$
4.08
Granted
 
483,100
54.64
483,100
6.32
Exercised
(146,475)
43.94
N/A
N/A
Forfeited
(94,900)
56.32
(51,625)
3.61
Vested
N/A
N/A
(526,620)
3.58
Options outstanding December 31, 2023
3,095,604
$
51.20
1,253,255
$
5.17
Options exercisable December 31, 2023
(2)(3)
1,842,349
$
48.39
(1) As at December 31, 2023, there was $
5
 
million of unrecognized compensation related to stock options not yet vested which is
expected to be recognized over a weighted average period of approximately
3
 
years (2022 – $
4
 
million,
3
 
years).
(2) As at December 31, 2023, the weighted average remaining term of vested options was
5
 
years with an aggregate intrinsic value of
$
8
 
million (2022 –
5
 
years, $
10
 
million).
(3) As at December 31, 2023, the FV of options that vested in the year was $
2
 
million (2022 – $
2
 
million).
Compensation cost recognized for stock options for the year ended December 31, 2023 was $
2
 
million
(2022 – $
2
 
million), which was included in “OM&G” on the Consolidated Statements of Income.
 
As at December 31, 2023, cash received from option exercises was $
6
 
million (2022 – $
9
 
million). The
total intrinsic value of options exercised for the year ended December 31, 2023 was $
2
 
million (2022 – $
4
million). The range of exercise prices for the options outstanding as at December 31, 2023 was $
32.35
 
to
$
60.03
 
(2022 – $
32.35
 
to $
60.03
).
Share Unit Plans
The Company has DSU, PSU and RSU plans. The plans and the liabilities are marked-to-market at the
end of each period based on an average common share price at the end of the period.
Deferred Share Unit Plans
 
Under the Directors’ DSU plan, Directors of the Company may elect to receive all or any portion of their
compensation in DSUs in lieu of cash compensation, subject to requirements to receive a minimum
portion of their annual retainer in DSUs. Directors’ fees are paid on a quarterly basis and, at the time of
each payment of fees, the applicable amount is converted to DSUs. A DSU has a value equal to one
Emera common share. When a dividend is paid on Emera’s common shares, the Director’s DSU account
is credited with additional DSUs. DSUs cannot be redeemed for cash until the Director retires, resigns or
otherwise leaves the Board. The cash redemption value of a DSU equals the market value of a common
share at the time of redemption, pursuant to the plan. Following retirement or resignation from the Board,
the value of the DSUs credited to the participant’s account is calculated by multiplying the number of
DSUs in the participant’s account by Emera’s closing common share price on the date DSUs are
redeemed.
 
 
 
 
 
 
 
 
 
 
 
 
Exhibit 99.3
75
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.
A summary of the activity related to employee and director DSUs for the year ended December 31, 2023
is presented in the following table:
Employee
DSU
Weighted
Average
Grant Date
FV
Director
 
DSU
Weighted
Average
Grant Date
FV
Outstanding as at December 31, 2022
627,223
$
41.55
664,258
$
45.83
Granted including DRIP
85,740
47.66
117,893
49.99
Exercised
N/A
N/A
(53,093)
49.39
Outstanding and exercisable as at December 31, 2023
712,963
$
42.29
729,058
$
46.24
Compensation cost recovery recognized for employee and director DSU’s for the year ended December
31, 2023 was $
2
 
million (2022 – $
6
 
million). Tax
 
expense related to this compensation cost recovery for
share units realized for the year ended December 31, 2023 was $
1
 
million (2022 – $
2
 
million). The
aggregate intrinsic value of the outstanding shares for the year ended December 31, 2023 for employees
was $
36
 
million (2022 – $
33
 
million). The aggregate intrinsic value of the outstanding shares for the year
ended December 31, 2023 for directors was $
37
 
million (2022 – $
34
 
million). Cash payments made
during the year ended December 31, 2023 associated with the DSU plan were $
3
 
million (2022 – $
8
million).
Performance Share Unit Plan
 
Under the PSU plan, certain executive and senior employees are eligible for long-term incentives payable
through the plan. PSUs are granted annually for three-year overlapping performance cycles, resulting in a
cash payment. PSUs are granted based on the average of Emera’s stock closing price for the fifty trading
days prior to the effective grant date. Dividend equivalents are awarded and paid in the form of additional
PSUs. The PSU value varies according to the Emera common share market price and corporate
performance.
PSUs vest at the end of the three-year cycle and the payouts will be calculated and approved by the
MRCC early in the following year. The value of the payout considers actual service over the performance
cycle and may be pro-rated in certain departure scenarios. In the case of retirement, as defined in the
PSU plan, grants may continue to vest in full and payout in normal course post-retirement.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Exhibit 99.3
76
A summary of the activity related to employee PSUs for the year ended December 31, 2023 is presented
in the following table:
Employee PSU
Weighted Average
Grant Date FV
Aggregate intrinsic value
Outstanding as at December 31, 2022
690,446
$
56.24
$
40
Granted including DRIP
386,261
52.71
Exercised
(323,155)
54.62
Forfeited
(10,187)
55.15
Outstanding as at December 31, 2023
743,365
$
55.13
$
41
Compensation cost recognized for the PSU plan for the year ended December 31, 2023 was $
11
 
million
(2022 – $
18
 
million). Tax
 
benefits related to this compensation cost for share units realized for the year
ended December 31, 2023 were $
3
 
million (2022 – $
5
 
million). Cash payments made during the year
ended December 31, 2023 associated with the PSU plan were $
19
 
million (2022 – $
24
 
million).
Restricted Share Unit Plan
 
Under the RSU plan, certain executive and senior employees are eligible for long-term incentives payable
through the plan. RSUs are granted annually for three-year overlapping performance cycles, resulting in a
cash payment. RSUs are granted based on the average of Emera’s stock closing price for the fifty trading
days prior to the effective grant date. Dividend equivalents are awarded and paid in the form of additional
RSUs. The RSU value varies according to the Emera common share market price.
RSUs vest at the end of the three-year cycle and the payouts will be calculated and approved by the
MRCC early in the following year. The value of the payout considers actual service over the performance
cycle and may be pro-rated in certain departure scenarios. In the case of retirement, as defined in the
RSU plan, grants may continue to vest in full and payout in normal course post-retirement.
 
A summary of the activity related to employee RSUs for the year ended December 31, 2023 is presented
in the following table:
 
Employee RSU
Weighted Average
Grant Date FV
Aggregate intrinsic value
Outstanding as at December 31, 2022
508,468
$
56.25
$
30
Granted including DRIP
236,537
52.07
Exercised
(171,537)
54.62
Forfeited
(10,827)
54.76
Outstanding as at December 31, 2023
562,641
$
55.01
$
32
Compensation cost recognized for the RSU plan for the year ended December 31, 2023 was $
10
 
million
(2022 – $
9
 
million). Tax
 
benefits related to this compensation cost for share units realized for the year
ended December 31, 2023 were $
3
 
million (2022 – $
2
 
million). Cash payments made during the year
ended December 31, 2023 associated with the RSU plan were $
10
 
million (2022–
nil
).
32.
 
VARIABLE INTEREST ENTITIES
Emera holds a variable interest in NSPML, a VIE for which it was determined that Emera is not the
primary beneficiary since it does not have the controlling financial interest of NSPML. When the critical
milestones were achieved, Nalcor Energy was deemed the primary beneficiary of the asset for financial
reporting purposes as it has authority over the majority of the direct activities that are expected to most
significantly impact the economic performance of the Maritime Link. Thus, Emera began recording the
Maritime Link as an equity investment.
 
 
 
Exhibit 99.3
77
BLPC has established a SIF, primarily for the purpose of building a fund to cover risk against damage and
consequential loss to certain generating, transmission and distribution systems. ECI holds a variable
interest in the SIF for which it was determined that ECI was the primary beneficiary and, accordingly, the
SIF must be consolidated by ECI. In its determination that ECI controls the SIF, management considered
that, in substance, the activities of the SIF are being conducted on behalf of ECI’s subsidiary BLPC and
BLPC, alone, obtains the benefits from the SIF’s operations. Additionally, because ECI, through BLPC,
has rights to all the benefits of the SIF, it is also exposed to the risks related to the activities of the SIF.
Any withdrawal of SIF fund assets by the Company would be subject to existing regulations. Emera’s
consolidated VIE in the SIF is recorded as “Other long-term assets”, “Restricted cash” and “Regulatory
liabilities” on the Consolidated Balance Sheets. Amounts included in restricted cash represent the cash
portion of funds required to be set aside for the BLPC SIF.
The Company has identified certain long-term purchase power agreements that meet the definition of
variable interests as the Company has to purchase all or a majority of the electricity generation at a fixed
price. However, it was determined that the Company was not the primary beneficiary since it lacked the
power to direct the activities of the entity, including the ability to operate the generating facilities and make
management decisions.
The following table provides information about Emera’s portion of material unconsolidated VIEs:
As at
December 31, 2023
December 31, 2022
Maximum
Maximum
millions of dollars
Total
assets
exposure to
loss
Total
assets
 
exposure to
loss
Unconsolidated VIEs in which Emera has variable interests
NSPML (equity accounted)
$
 
489
$
 
6
$
 
501
$
 
6
33.
 
SUBSEQUENT EVENTS
These financial statements and notes reflect the Company’s evaluation of events occurring subsequent to
the balance sheet date through February 26, 2024, the date the financial statements were issued.
 

Exhibit 99.4

Consent of Independent Registered Public Accounting Firm

We consent to the reference to our Firm under the caption “Experts” in the Annual Information Form and to the use in this Annual Report on Form 40-F of our report dated February 26, 2024, with respect to the consolidated balance sheets of Emera Incorporated as at December 31, 2023 and 2022, and the consolidated statements of income, consolidated statements of comprehensive income, consolidated statements of changes in equity and consolidated statements of cash flows for the years then ended, included in this Annual Report on Form 40-F.

 

   /s/ Ernst & Young LLP
Halifax, Canada    Chartered Professional Accountants
February 26, 2024   

Exhibit 99.5

CERTIFICATION

I, Scott C. Balfour, certify that:

 

1.

I have reviewed this annual report on Form 40-F of Emera Incorporated;

 

2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

 

3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report;

 

4.

The issuer’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have:

 

  a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

 

  b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

 

  c)

Evaluated the effectiveness of the issuer’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

 

  d)

Disclosed in this report any change in the issuer’s internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuer’s internal control over financial reporting; and

 

5.

The issuer’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer’s auditors and the audit committee of the issuer’s board of directors (or persons performing the equivalent functions):

 

  a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer’s ability to record, process, summarize and report financial information; and

 

  b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer’s internal control over financial reporting.

Date: February 26, 2024

 

/s/ Scott C. Balfour

Scott C. Balfour

President & Chief Executive Officer

Exhibit 99.6

CERTIFICATION

I, Gregory W. Blunden, certify that:

 

1.

I have reviewed this annual report on Form 40-F of Emera Incorporated;

 

2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

 

3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report;

 

4.

The issuer’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have:

 

  a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

 

  b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

 

  c)

Evaluated the effectiveness of the issuer’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

 

  d)

Disclosed in this report any change in the issuer’s internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuer’s internal control over financial reporting; and

 

5.

The issuer’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer’s auditors and the audit committee of the issuer’s board of directors (or persons performing the equivalent functions):

 

  a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer’s ability to record, process, summarize and report financial information; and

 

  b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer’s internal control over financial reporting.

Date: February 26, 2024

 

/s/ Gregory W. Blunden

Gregory W. Blunden
Chief Financial Officer

Exhibit 99.7

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350

AS ENACTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the annual report of Emera Incorporated (the “Company”) on Form 40-F for the year ended December 31, 2023 (the “Report”), as filed with the U.S. Securities and Exchange Commission,

I, Scott C. Balfour, President & Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as enacted pursuant to Section 906 of the U.S. Sarbanes-Oxley Act of 2002, that to my knowledge:

 

  (i)

the Report fully complies with the requirements of Section 13(a) or 15(d) of the U.S. Securities Exchange Act of 1934; and

 

  (ii)

the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: February 26, 2024

 

/s/ Scott C. Balfour

Scott C. Balfour
President & Chief Executive Officer

Exhibit 99.8

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350

AS ENACTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the annual report of Emera Incorporated (the “Company”) on Form 40-F for the year ended December 31, 2023 (the “Report”), as filed with the U.S. Securities and Exchange Commission,

I, Gregory W. Blunden, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as enacted pursuant to Section 906 of the U.S. Sarbanes-Oxley Act of 2002, that to my knowledge:

 

  (i)

the Report fully complies with the requirements of Section 13(a) or 15(d) of the U.S. Securities Exchange Act of 1934; and

 

  (ii)

the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: February 26, 2024

 

/s/ Gregory W. Blunden

Gregory W. Blunden
Chief Financial Officer