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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, 2022
Commission File Number
000-54516
EMERA INC
ORPORATED
(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, 2022:
269,944,308
 
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, 2022, 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,
2022 and concluded that the Registrant's internal control over financial reporting is effective as at
December 31, 2022.
(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, 2022, 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 six
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, Andrea S. Rosen and Richard P. Sergel. The
Board has determined that Paula Y.
 
Gold-Williams, Kent M. Harvey, B. Lynn
 
Loewen, Ian E. Robertson, Andrea S.
Rosen and Richard P. Sergel
 
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, Andrea S. Rosen and Richard P. Sergel is included in their biographical information
contained in the Registrant’s Annual Information Form for the fiscal year ended December 31, 2022, 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, 2022 (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 16, 2022 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 2022 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 23, 2023 for the
year ended December 31, 2022, 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, 2022 and December 31, 2021, 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
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 24
th
 
day of February, 2023.
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, 2022

February 23, 2023


ANNUAL INFORMATION FORM

For the year ended December 31, 2022

Dated: February 23, 2023

TABLE OF CONTENTS

 

PRESENTATION OF INFORMATION

     4  

CAUTIONARY NOTE REGARDING FORWARD-LOOKING INFORMATION

     4  

CORPORATE STRUCTURE

     6  

Name and Incorporation

     6  

Amended Articles of Association

     6  

Intercorporate Relationships

     6  

INTRODUCTION

     7  

DESCRIPTION OF THE BUSINESS

     8  

Business Segments

     8  

Florida Electric Utility

     9  

Canadian Electric Utilities

     11  

Gas Utilities and Infrastructure

     14  

Other Electric Utilities

     17  

Other

     18  

GENERAL DEVELOPMENT OF THE BUSINESS

     19  

Florida Electric Utility

     19  

Canadian Electric Utilities

     21  

Gas Utilities and Infrastructure

     24  

Other Electric Utilities

     25  

USGAAP – Exemptive Relief

     27  

Financing Activity

     27  

RISK FACTORS

     28  

CAPITAL STRUCTURE

     28  

Common Shares

     29  

Emera First Preferred Shares

     29  

Emera Second Preferred Shares

     29  

Share Ownership Restrictions

     29  

CREDIT RATINGS

     30  

DIVIDENDS

     31  

MARKET FOR SECURITIES

     32  

Trading Price and Volume

     32  

At-The-Market Equity Program

     32  

DIRECTORS AND OFFICERS

     33  

Directors

     33  

Officers

     35  
AUDIT COMMITTEE      36  

Audit and Non-Audit Services Pre-Approval Process

     37  

 

Emera Incorporated – 2022 Annual Information Form    2


Auditors’ Fees      38  
CERTAIN PROCEEDINGS      38  
CONFLICTS OF INTEREST      39  
LEGAL PROCEEDINGS AND REGULATORY ACTIONS      39  
NO INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS      39  
MATERIAL CONTRACTS      39  
TRANSFER AGENT AND REGISTRAR      39  
EXPERTS      39  
ADDITIONAL INFORMATION      39  
APPENDIX “A” - DEFINITIONS OF CERTAIN TERMS      41  
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 2022      49  
APPENDIX “D” - EMERA INCORPORATED AUDIT COMMITTEE CHARTER      50  

 

Emera Incorporated – 2022 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, 2022. 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.sedar.com.

Certain capitalized terms used herein, and not otherwise defined herein, are defined under “Definitions of Certain Terms”, attached to this AIF as Appendix “A”. Reference 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.sedar.com.

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

 

Emera Incorporated – 2022 Annual Information Form    4


fluctuations; expected changes in electricity rates; and the impacts of planned investment by the industry of gas transportation infrastructure within the United States.

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; future dividend growth; timing and costs associated with certain capital investments; expected impacts on Emera of challenges in the global economy; estimated energy consumption rates; maintenance of adequate insurance coverage; changes in customer energy usage patterns; developments in technology that could reduce demand for electricity; global climate change; weather; unanticipated maintenance and other expenditures; system operating and maintenance risk; derivative financial instruments and hedging; interest rate risk; inflation risk; counterparty risk; disruption of fuel supply; country risks; environmental risks; foreign exchange (“FX”); regulatory and government decisions, including changes to environmental, financial reporting and tax legislation; risks associated with pension plan performance and funding requirements; loss of service area; risk of failure of information technology infrastructure and cybersecurity risks; uncertainties associated with infectious diseases, pandemics and similar public health threats, such as the COVID-19 novel coronavirus (“COVID-19”) pandemic; market energy sales prices; labour relations; and availability of labour and management resources.

Readers are cautioned not to place undue reliance on forward-looking information as actual results could differ materially from the plans, expectations, estimates or intentions and statements expressed in the forward-looking information. All forward-looking information in this 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.

 

Emera Incorporated – 2022 Annual Information Form    5


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.

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.sedar.com.

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, 2022.

 

  Subsidiaries   

    Percentage Ownership    

(%)

       Jurisdiction          

Tampa Electric Company1

   100    Florida                

Nova Scotia Power

   100    Nova Scotia     

New Mexico Gas Company

   100    Delaware     

 

  (1)

Tampa Electric Company (TEC) has historically included both its regulated electric and gas utilities, namely the Tampa Electric Division and the Peoples Gas System (PGS) 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. (PGSI), existing under the laws of the State of Florida, and a wholly-owned direct subsidiary of TECO Gas Operations, Inc.

 

Emera Incorporated – 2022 Annual Information Form    6


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

Emera’s capital investment plan is $8-9 billion over the 2023-to-2025 period (including a $240 million equity investment in the LIL in 2023), mainly focused in Florida. This results in a forecasted rate base growth of approximately 7 per cent to 8 per cent through 2025. The capital investment plan continues to include significant investments across the portfolio in renewable and cleaner generation, reliability and integrity investments, infrastructure modernization and customer-focused technologies. Emera’s capital investment plan is being funded primarily through internally generated cash flows and debt raised at the operating company level. Equity requirements in support of the Company’s capital investment plan are expected to be funded through the issuance of preferred equity and the issuance of common equity through Emera’s 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 2025. The Company targets a long-term dividend payout ratio of adjusted net income of 70 to 75 per cent and, while the payout ratio is likely to exceed that target through and beyond the forecast period, it is expected to return to that range over time. For further information on the non-GAAP measure “Dividend Payout Ratio of Adjusted Net Income”, refer to the “Non-GAAP Financial Measures and Ratios” section 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.sedar.com.

Seasonal patterns and other weather events affect demand and operating costs. Similarly, mark-to-market adjustments and foreign currency exchange can have a material impact on financial results for a specific period. Emera’s consolidated net income and cash flows are impacted by movements in the USD relative to the Canadian dollar. Emera may hedge both transactional and translational exposure. These impacts, as well as the timing of capital investments and other factors, mean results in any one quarter are not necessarily indicative of results in any other quarter, or for the year as a whole.

Energy markets worldwide are facing significant change and Emera is well positioned to respond to shifting customer demands, digitization, decarbonization, complex regulatory environments and decentralized generation.

Customers are looking for more choice, better control, and enhanced reliability in a time where costs of decentralized generation and storage have become more competitive in some regions. Advancing technologies are transforming the way utilities interact with their customers and generate and transmit energy. In addition, climate change and extreme weather are shaping how utilities operate and how they invest in infrastructure. There is also an overall need to replace aging infrastructure and further enhance reliability. Emera will play a role in all of these trends. Emera’s strategy is to fund investments in renewable energy and technology assets which protect the environment and benefit customers through fuel or operating cost savings.

For example, significant investments to facilitate the use of renewable and low-carbon energy include the Maritime Link in Atlantic Canada, modernization of the Big Bend Power Station and the ongoing construction of solar generation at Tampa Electric. Emera’s utilities are also investing in reliability projects

 

Emera Incorporated – 2022 Annual Information Form    7


and replacing aging infrastructure. All of these projects demonstrate Emera’s strategy of safely delivering cleaner, reliable, and affordable energy for its customers.

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

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

  ·  

A 55 per cent reduction in carbon dioxide emissions by 2025.

  ·  

The retirement of Emera’s last existing coal unit no later than 2040.

  ·  

An 80 per cent reduction in carbon dioxide emissions by 2040.

Achieving the above climate goals on these timelines is subject to the Company’s regulatory obligations and other external factors beyond Emera’s control.

Emera seeks to deliver on its Climate Commitment while maintaining its focus on investing in reliability and staying focused on the cost impacts for customers. Emera is also committed to identifying emerging technologies and continuing to work constructively with policymakers, regulators, partners, investors and customers to achieve these goals and realize its net-zero vision.

Emera is committed to world-class safety, operational excellence, good governance, excellent customer service, reliability, being an employer of choice, and building constructive relationships.

DESCRIPTION OF THE BUSINESS

Business Segments

Emera’s reportable segments are:

 

  ·  

Florida Electric Utility, which consists of Tampa Electric;

  ·  

Canadian Electric Utilities, which includes NSPI and ENL, a holding company with equity investments in NSPML (100 per cent) and the LIL (31.9 per cent);

  ·  

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

  ·  

Other Electric Utilities, which includes ECI, a holding company with regulated electric utilities which include BLPC, GBPC and a 19.5 per cent equity interest in Lucelec. On March 31 2022, Emera completed the sale of its 51.9 per cent interest in Domlec, which was previously included in this segment; and

  ·  

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

General

Emera and its subsidiaries had 7,122 employees as at December 31, 2022, approximately 32 per cent of whom are unionized.

Operations by Segment

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

 

Emera Incorporated – 2022 Annual Information Form    8


Florida Electric Utility

Florida Electric Utility consists of Tampa Electric, a vertically integrated regulated electric utility engaged in the generation, transmission and distribution of electricity, serving customers in West Central Florida. Tampa Electric has $12.1 billion USD of assets, approximately 827,000 customers and 2,469 employees as at December 31, 2022.

Tampa Electric is regulated by the FPSC and is also subject to regulation by the FERC. The FPSC sets rates at a level that allows utilities such as Tampa Electric to collect total revenues or revenue requirements equal to their cost of providing service, plus an appropriate return on invested capital. Base rates are determined in FPSC rate setting hearings which occur at the initiative of Tampa Electric, the FPSC or other interested parties. Tampa Electric’s approved regulated ROE range is 9.25 per cent to 11.25 per cent, based on an allowed equity capital structure of 54 per cent. An ROE of 10.20 per cent will be used for the calculation of the return on investments for clauses.

For further details on Tampa Electric’s regulatory environment, base rates and recovery mechanisms, refer to Note 7, 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.sedar.com.

Market and Sales

 

Tampa Electric Revenue and Sales Volumes by Customer Class
           Electric Revenues (%)           GWh Electric Sales Volumes (%)  
For the year ended December 31         2022               2021               2022             2021      

Residential

  54.7   53.2   48.4   49.2

Commercial

  26.4   27.7   30.2   30.4

Industrial

  7.0   7.9   10.1   10.5

Other

  11.9   11.2   11.3   9.9

Total

  100.0   100.0   100.0   100.0

Energy sources and generation

As at December 31, 2022, Tampa Electric owns 6,549 MW of generating capacity, of which 78 per cent is natural gas-fired, 15 per cent is solar and 7 per cent is coal. Tampa Electric owns 2,171 kilometres of transmission facilities and 19,916 kilometres of distribution facilities. Tampa Electric meets the planning criteria for reserve capacity established by the FPSC, which is a 20 per cent reserve margin over firm peak demand.

System Operations

Tampa Electric’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, Tampa Electric’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, Tampa Electric has immediate access to reserve generating capacity from all other group members.

 

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Contribution to Consolidated Net Income

Florida Electric Utility’s contribution to consolidated net income was $458 million USD in 2022 (2021 - $369 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 2022, capital investments (including AFUDC) in the Florida Electric Utility segment were $1.1 billion USD (2021 – $1.2 billion USD). In 2023, capital investment is expected to be approximately $1.3 billion USD, including AFUDC. Capital projects include solar investments, grid modernization and storm hardening investments.

Environmental Considerations

Tampa Electric has significant environmental considerations. Tampa Electric 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 Tampa Electric’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, Tampa Electric 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). As a result of legal challenges, a replacement rule is expected to be proposed in April 2023. Compliance with the terms of the new rule that replaces the ACE rule, once adopted and finalized, could cause an increase in costs or rates charged to customers, which could curtail sales.

Tampa Electric 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, Tampa Electric 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 Tampa Electric’s service territory. The impact of this potential new standard on the operations of Tampa Electric will depend on the standard that is ultimately adopted and on the outcome of any related litigation or other developments.

 

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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 Tampa Electric’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. Tampa Electric 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 Tampa Electric’s proposed plan for Bayside and Tampa Electric 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. Tampa Electric 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 Tampa Electric 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.

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 has announced that this rule is currently under review, and a revised rule is expected to be proposed in 2023.

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 will complete 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.

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 31.9 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 541,000 customers with $6.8 billion in assets and 2,138 employees as at December 31, 2022.

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. On January 27, 2022, NSPI filed a General Rate Application (“GRA”) with the UARB. For more details regarding GRA, refer to the General Development of the Business section below, under the heading “Canadian Electric Utilities – NSPI - General Rate Application.”

For further details on NSPI’s regulatory environment and recovery mechanisms, refer to Note 7, 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.sedar.com.

 

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Market and Sales

 

                                                                                                               
NSPI Revenue and Electricity Sales Volumes by Customer Class
         Electric Revenues (%)       GWh Electric Sales Volumes  (%)  
For the year ended December 31       2022           2021       2022   2021
Residential   50.8   54.3   46.1   45.7
Commercial   26.0   27.7   28.8   28.5
Industrial   21.5   16.2   23.7   24.3
Other   1.7   1.8   1.4   1.5
Total   100.0   100.0   100.0   100.0

Energy Sources and Generation

NSPI owns 2,420 MW of generating capacity, of which approximately 44 per cent is coal-fired, 28 per cent is natural gas and/or oil, 19 per cent is hydro and wind, 7 per cent is petcoke and 2 per cent is biomass-fueled generation. In addition, NSPI has contracts to purchase renewable energy from IPPs, including COMFIT participants, which own 546 MW of capacity. NSPI also has rights to 153 MW of Maritime Link capacity, representing Nalcor’s NS Block delivery obligations, as discussed below.

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 communication network used by system operators for remote monitoring and control of the power system assets.

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 electric bulk power 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.

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.

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 final commissioning of the LIL has experienced delays and it’s expected that final commissioning of the LIL will be completed in 2023. Nalcor’s NS Block delivery obligations commenced on August 15, 2021 and the NS Block will be delivered over the next 35 years pursuant to the project agreements. During these final stages of commissioning the LIL, there will be interruptions in supply, with any resultant delivery shortfalls being delivered on a timely basis in accordance

 

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with the Energy and Capacity Agreement. NSPI has the option of purchasing additional market-priced energy from Nalcor through the Energy Access Agreement. The Energy Access Agreement enables NSPI to access a market-priced bid from Nalcor for up to 1.8 Terawatt hours (“TWh”) of energy in any given year and, on average, 1.2 TWh of energy per year through August 31, 2041.

LIL

ENL is a limited partner with Nalcor in LIL. Construction of the LIL is complete and Nalcor is forecasting it will achieve final commissioning in 2023.

Equity earnings from the LIL investment are based upon the book value of the equity investment and the approved ROE. Emera’s current equity investment is $740 million, comprised of $410 million in equity contribution and $330 million of accumulated equity earnings. Emera’s total equity contribution in the LIL, excluding accumulated equity earnings, is estimated to be approximately $650 million after all Lower Churchill projects are completed.

Cash earnings and return of equity will begin after commissioning of the LIL by Nalcor, which is anticipated in 2023, and until that point Emera will continue to record AFUDC earnings.

Contribution to Consolidated Net Income and Adjusted Net Income

Canadian Electric Utilities contribution to consolidated net income was $215 million in 2022 (2021 - $241 million). Canadian Electric Utilities contribution to Emera’s consolidated adjusted net income was $222 million in 2022 (2021 - $241 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.sedar.com

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 2022 were $540 million (2021 - $388 million), including AFUDC. In 2023, NSPI expects to invest $375 million, including AFUDC, primarily in capital projects to support system reliability and reliable service for customers.

NSPML

NSPML’s capital investments in 2022 were $10 million (2021 – $6 million). NSPML does not anticipate any planned significant capital investment in 2023.

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

 

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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.sedar.com. Recent developments related to provincial and federal environmental laws and regulations are referred to below in the “General Developments of the Business” section.

Nova Scotia Cap-and-Trade Program Regulations

NSPI is a participant in the Nova Scotia Cap-and-Trade Program (“Cap-and-Trade Program”) and is subject to the 2019 through 2022 compliance period. NSPI received granted emissions allowances under the Cap-and-Trade Program and is permitted to purchase up to five per cent of the credits available at provincial auctions. Any remaining allowance shortfall requires the purchase of reserve credits directly from the provincial government, which are anticipated to be priced at a premium to provincial auction pricing. Compliance is forecast to be achieved through granted emissions allowances and credit purchases under the Cap-and-Trade Program, including reserve credits. Lower than forecast Muskrat Falls energy received during the compliance period has resulted in the increased deployment of higher carbon-emitting generation sources. The Province of Nova Scotia has agreed to provide approximately $165 million of relief from the 2019 through 2022 compliance costs, which was equal to the total cost of compliance forecast at the time of the fuel update submitted by NSPI to the UARB in September 2022 as part of the GRA. Discussions related to the final amount of relief and how this relief will be provided are ongoing. Further, NSPI’s regulatory framework provides for the recovery of costs prudently incurred to comply with the Cap-and-Trade Program Regulations pursuant to NSPI’s FAM.

Nova Scotia Renewable Energy Regulations

Over the past several years, the requirement to reduce Nova Scotia’s reliance upon higher carbon and greenhouse gas emitting sources of energy has resulted in NSPI making significant investments in renewable energy sources, including energy from the Maritime Link, and purchasing renewable energy from IPPs.

Under the provincially legislated Renewable Energy Regulations, 40 per cent of electric sales must be generated from renewable sources. This standard was predicated on receipt of the full NS Block. Due to the delay of the NS Block, the provincial government provided NSPI with an alternative compliance plan that requires NSPI to achieve 40 per cent of electric sales generated from renewable sources over the 2020 through 2022 period. With delivery of the NS Block commencing later than anticipated, as well as further interruptions in supply due to delays in the LIL, NSPI did not achieve the requirements of the alternative compliance plan. The Renewable Energy Regulations require NSPI to have acted in a duly diligent manner. If NSPI is found not to have acted in a duly diligent manner, it could be subject to a maximum penalty of $10 million.

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 NSPI’s 2022 Annual Information Form, a copy of which is available electronically under NSPI’s profile on SEDAR at www.sedar.com.

Gas Utilities and Infrastructure

Gas Utilities and Infrastructure includes PGS, NMGC, SeaCoast, Brunswick Pipeline and Emera’s non-consolidated investment in M&NP. PGS is a regulated gas distribution utility engaged in the purchase, distribution and sale of natural gas serving customers in Florida. NMGC is an intrastate regulated gas distribution utility engaged in the purchase, transmission, distribution and sale of natural gas serving customers in New Mexico. SeaCoast is a regulated intrastate natural gas transmission company offering

 

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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   2022   2021   2022   2021
Residential   49.2   53.1   14.4   14.6
Commercial   28.3   31.4   28.7   28.8
Industrial   5.1   5.5   49.1   51.7
Other   17.4   10.0   7.8   4.9
Total   100.0   100.0   100.0   100.0

PGS

As at December 31, 2022, PGS serves approximately 468,000 customers with $2.5 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 2022.

PGS is regulated by the FPSC. NMGC is regulated by the NMPRC. 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. As of 2022, the approved ROE range for PGS is 8.9 per cent to 11.0 per cent, based on an allowed equity capital structure of 54.7 per cent. An ROE of 9.9 per cent is used for the calculation of return on investments recovered through cost recovery clauses.

For further details on PGS’ regulatory environment and recovery mechanisms, refer to Note 7, 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.sedar.com.

NMGC

As at December 31, 2022, NMGC serves approximately 545,000 customers with $2.0 billion USD in assets and 678 employees. NMGC’s system includes 2,426 km of transmission lines and 17,781 km of distribution lines. Annual natural gas throughput was 926 million therms in 2022.

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. As of 2022, the approved ROE for NMGC 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 7, 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.sedar.com.

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

 

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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.

SeaCoast

In 2018, SeaCoast executed an agreement with Seminole Electric Cooperative, Inc. (“Seminole”) to provide long-term firm gas transportation service to Seminole’s new gas-fired generating facility in Putnam County, Florida. SeaCoast operates a 21-mile, 30-inch pipeline lateral that is treated as a sales-type lease for accounting purposes. The lease of the pipeline lateral to Seminole commenced on January 1, 2022.

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 $170 million USD in 2022 (2021 – $157 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 2022 were $436 million USD (2021 - $407 million USD). In 2023, capital investment is expected to be approximately $475 million USD, including AFUDC. PGS will make investments to expand its system and support customer growth. NMGC will continue to make investments to maintain the reliability of its system and support customer growth.

Environmental Considerations

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.

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 RECL’s payment obligations under the firm service agreement.

 

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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 interest in Lucelec on the island of St. Lucia which is accounted for on the equity basis.

On March 31, 2022, Emera completed the sale of Domlec. For further details, refer to refer to Note 4, Dispositions, in the Audited Financial Statements, which is, incorporated herein by reference, a copy of which is available electronically under Emera’s profile on SEDAR at www.emera.com

Market and Sales

Other Electric Utilities operating revenues for 2022 were $398 million USD (2020 – $355 million USD) and electric sales volumes were 1,239 GWh (2021 –1,262 GWh).

BLPC

As at December 31, 2022, BLPC serves approximately 133,000 customers with $505 million USD of assets and a workforce of 402 employees. BLPC owns 276 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 3,789 km of distribution lines which includes distribution supply substations.

BLPC currently operates pursuant to a franchise to generate, transmit and distribute electricity on the island of Barbados until 2028. In 2019, the Government of Barbados passed legislation amending the number of licenses required for the supply of electricity from a single integrated license which currently exists, to multiple licenses for Generation, Transmission and Distribution, Storage, Dispatch and Sales. In March 2021, BLPC reached commercial agreement with the Government of Barbados for each of the license types, subject to the passage of implementing legislation. For more details regarding the new licenses, refer to the General Development of the Business section below, under the heading “BLPC License Negotiations”.

BLPC is regulated by the FTC, an independent regulator. Rates are set to recover prudently incurred costs of providing electricity service to customers plus an appropriate return on capital invested. . BLPC’s approved regulated return on rate base was 10 per cent for 2022 and 2021. For further details on BLPC’s regulatory environment and recovery mechanisms, refer to Note 7, 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.sedar.com.

GBPC

As at December 31, 2022, GBPC serves approximately 19,000 customers, with $338 million USD of assets and a workforce of 201 employees. GBPC owns 98 MW of oil-fired generation, approximately 90 kilometres of transmission facilities and 670 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. For further details on GBPC’s regulatory environment and recovery mechanisms, refer to Note 7, 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.sedar.com.

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

 

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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 a loss of $35 million USD in 2022 (2021 – income of $17 million USD). Other Electric Utilities’ contribution to consolidated adjusted net income was $23 million USD in 2022 (2021 – $16 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.sedar.com.

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 2022 were $48 million USD (2021 – $88 million USD). In 2023, capital investment is expected to be approximately $65 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 ETL. Emera Energy consists of EES, a wholly owned physical energy marketing and trading business and an equity investment in a 50 per cent joint venture ownership of Bear Swamp, a 660 MW pumped storage hydroelectric facility in northwestern Massachusetts. ETL is a wholly owned technology company focused on finding ways to deliver renewable and resilient energy to customers.

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

 

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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 demand factors, can provide higher levels of margin opportunity. The business is seasonal, with Q1 and Q4 usually providing the greatest opportunity for earnings. EES is generally expected to deliver annual adjusted net income within its guidance range of $15 to $30 million USD ($45 to $70 million USD of margin).

Contribution to Consolidated Net Income and Adjusted Net Income

Other’s contribution to consolidated net income was a loss of $39 million in 2022 (2021 - loss of $412 million). Other’s contribution to consolidated adjusted net income was a loss of $218 million    in 2022 (2021 – loss of $198 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.sedar.com.

Capital Investment

Capital investments in the Other segment were $6 million in 2022 (2021 – $5 million). In 2023, capital investment in the Other segment is not expected to be significant.

GENERAL DEVELOPMENT OF THE BUSINESS

Three Year History and Changes Expected in 2023

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 Rate Adjustments – Approval of Settlement Agreement

On August 6, 2021, Tampa Electric filed with the FPSC a joint motion for approval of a settlement agreement by Tampa Electric 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 Tampa Electric. 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

 

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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. For further information, refer to the “Regulatory Environments – Florida Electric Utility – Base Rates” section of Note 7, 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.sedar.com.

On August 16, 2022, the FPSC approved Tampa Electric’s request to increase revenue and ROE due to increases in the 30-year United States Treasury bond yield rate. Effective July 1, 2022, the new mid-point ROE is 10.20 per cent, and the range is 9.25 per cent to 11.25 per cent.

Fuel and Capacity Charges

On July 19, 2021, Tampa Electric requested a mid-course adjustment of $83 million USD to its fuel and capacity charges, effective with September 2021 customer bills, due to an increase in fuel commodity and capacity costs in 2021. On August 3, 2021, the FPSC approved the request to recover the costs during the months of September through December 2021.

On January 19, 2022, Tampa Electric requested a mid-course adjustment to its fuel and capacity charges to recover an additional $169 million USD, effective April 2022, due to an increase in fuel commodity and capacity costs. This was approved on March 1, 2022 and the rate increase was spread over customer bills from April 1, 2022 through December 2022.

On January 23, 2023, Tampa Electric requested an adjustment to its fuel charges to recover the 2022 fuel under-recovery of $518 million USD over a period of 21 months. The request also included an adjustment to 2023 projected fuel costs to reflect the reduction in natural gas prices since September 2022 for a projected reduction of $170 million USD for the balance of 2023. The proposed changes will be decided by the FPSC in March 2023, and recovery is expected to begin in April 2023.

Solar Projects

In September 2017, Tampa Electric announced its intention to invest approximately $850 million USD over four years in new utility-scale solar photovoltaic projects across its service territory. As of December 31, 2021, the full amount was invested and 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.

During 2017 to 2021, Tampa Electric invested $850 million USD in 600 MW of utility-scale solar photovoltaic projects, which is recoverable through FPSC-approved 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 Power Station Modernization

Tampa Electric invested $876 million USD, including $91 million USD of AFUDC, during 2018 through 2022 to modernize the Big Bend Power Station. The modernization project repowered Big Bend Unit 1 with natural gas combined-cycle technology and eliminated coal as this unit’s fuel. As part of the modernization project, Tampa Electric retired the Unit 1 components that will not be used in the modernized plant in 2020 and Big Bend Unit 2 in 2021. Tampa Electric plans to retire Big Bend Unit 3 in 2023 as it is in the best interest of the customers from an economic, environmental risk and operational perspective.

For more information on the modernization of the Big Bend Power Station, refer to the “Regulatory Environments – Big Bend Modernization Project” section of Note 7, Regulatory Assets and Liabilities, in the

 

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Audited Financial Statements, which is hereby incorporated by reference, a copy of which is available electronically under Emera’s profile on SEDAR at www.sedar.com.

Storm Protection Cost Recovery Clause and Settlement Agreement

On October 3, 2019, the FPSC issued a rule to implement a Storm Protection Plan (“SPP”) Cost Recovery Clause. This clause provides a process for Florida investor-owned utilities, including Tampa Electric, to recover transmission and distribution storm hardening costs for incremental activities not already included in base rates. Differences between prudently incurred clause-recoverable costs and amounts recovered from customers through electricity rates in a year are deferred and recovered from or returned to customers in a subsequent year. A settlement agreement was approved on August 10, 2020, and Tampa Electric’s cost recovery began in January 2021. The current approved plan addressed the years 2020 through 2022, and in April 2022 Tampa Electric submitted a new plan to determine cost recovery in 2023, 2024 and 2025. On October 4, 2022, the FPSC approved Tampa Electric’s SPP for those years.

Storm Reserve – Hurricane Ian

In September 2022, Tampa Electric was impacted by Hurricane Ian. Total restoration costs were $126 million USD, with $119 million USD of restoration costs charged against Tampa Electric’s FPSC approved storm reserve. Total restoration costs charged to the storm reserve have exceeded the reserve balance and have been deferred as a regulatory asset for future recovery. On January 23, 2023, Tampa Electric petitioned the FPSC for recovery of the storm reserve regulatory asset and the replenishment of the balance in the reserve to the previous approved reserve level of $56 million USD, for a total of approximately $131 million USD. The proposed changes will be decided by the FPSC in March 2023 and recovery is expected to begin in April 2023 through March 2024.

For more information on the SPP, refer to the “Regulatory Environments – Storm Protection Cost Recovery Clause and Settlement Agreement” section of Note 7, 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.sedar.com.

Canadian Electric Utilities

NSPI

Environmental Legislation and Regulations

There have been several recent environmental developments in Canada at both the federal and provincial levels, as described further below. NSPI continues to work with both the provincial and federal governments on measures to address their carbon reduction goals. Future compliance with provincial and federal GHG emission caps, coal phase out requirements and targets, and renewable standards has been challenged as a result of the constraints imposed by the enactment of Bill 212, “Public Utilities Act (amended)”.

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

 

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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.

Carbon Pricing Regulations

On November 9, 2022, the Nova Scotia provincial government enacted Bill 208, “Environment Act (amended)”. The legislation provides the framework for Nova Scotia’s system to comply with the federal government’s 2023 through 2030 carbon pollution pricing regulations laid out in the Pan-Canadian Framework on Clean Growth and Climate Change. Nova Scotia’s proposed system utilizes an output-based pricing system that will implement performance standards for large industrial greenhouse gas emitters to achieve emission reduction goals. Subsequent regulations will be required to detail how the pricing system will operate. The Province of Nova Scotia’s proposed output-based pricing system is subject to the approval of the federal government. If an agreement is not reached between the federal and provincial governments on a Nova Scotia system that meets the federal compliance criteria, Nova Scotia will be subject to the federal carbon pollution pricing backstop which uses emissions performances standards that vary by fuel type, and a carbon price that will start at $65 per tonne in 2023 and increase by $15 per tonne annually, reaching $170 per tonne by 2030. NSPI’s regulatory framework provides for the recovery of costs prudently incurred to comply with carbon pricing programs pursuant to NSPI’s FAM.

General Rate Application

On November 9, 2022, the Nova Scotia provincial government enacted Bill 212, “Public Utilities Act (amended)”. The legislation limits non-fuel rate increases in NSPI’s GRA filed in 2022, excluding increases relating to demand-side management costs, to a total of 1.8 per cent between the effective date of the UARB’s decision and the end of 2024. The legislation also:

 

  ●  

requires revenue generated from the non-fuel rate increase to be used only to improve the reliability of service to ratepayers,

  ●  

limits NSPI’s return on equity to 9.25 per cent and equity ratio to 40 per cent, and

  ●  

limits the rate used to accrue interest on regulatory deferrals to the Bank of Canada policy interest rate plus 1.75 per cent, unless otherwise directed by the UARB.

Actions required to address the impact of Bill 212, “Public Utilities Act (amended)”, include a material reduction in NSPI’s planned capital investments and operating costs over the 2023 through 2024 period. Such deferral of capital investment and operating costs may result in higher customer costs in future periods. The legislation will have a direct and negative impact on the financial performance of NSPI and has had a negative impact on NSPI’s credit quality. For more information on this risk, refer to the “Risk Management and Financial Instruments – Regulatory and Political Risk” section 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.sedar.com.

 

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On November 24, 2022, NSPI filed with the UARB a comprehensive settlement agreement between NSPI, key customer representatives and participating interest groups (“NSPI Settlement Agreement”) in relation to its GRA filed in January 2022. The NSPI Settlement Agreement was structured to be consistent with the amendments to the Public Utilities Act made under Bill 212, including the 1.8 per cent cap on non-fuel rate increases for 2023 and 2024. Bill 212, “Public Utilities Act (amended)” is described further, above. The NSPI Settlement Agreement also addresses the recovery of fuel costs over the settlement period and establishes a demand-side management rider. This will result in a combined fuel and non-fuel rate increase of 6.9 per cent each year for 2023 and 2024, and annualised incremental revenue (fuel and non-fuel) of $105 million in 2023 and $115 million in 2024. In addition, any under or over recovery of fuel costs will be addressed through the UARB’s established FAM process. NSPI’s ROE range will continue to be 8.75 per cent to 9.25 per cent, based on an actual five-quarter average regulated common equity component of up to 40 per cent. The NSPI Settlement Agreement also establishes a storm rider for each of 2023, 2024 and 2025, which gives NSPI the option to apply to the UARB for recovery of costs if major storm restoration expense exceeds approximately $10 million in a given year. On February 2, 2023, NSPI received the UARB’s decision, which substantially approved the NSPI Settlement Agreement as filed. Approved rate increases will be effective as of the date of the decision.

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 kilometres per hour and peak gusts of approximately 180 kilometres per hour. This historic storm for Nova Scotia caused significant and widespread damage to NSPI’s transmission and distribution system and at the height of the storm approximately 415,000 customers lost power. The total cost of the restoration was approximately $115 million, of which $91 million was capitalized to Property, plant and equipment (“PP&E”) and $24 million deferred to Other long-term assets for future amortization, subject to UARB approval. NSPI intends to submit an application to the UARB requesting to defer the recognition of incremental operating costs related to storm restoration. If the deferral is approved, this balance will be reclassified to “Regulatory assets” and amortized over the UARB approved recognition period.

Regulatory Matters – General

NSPI operated under a three-year fuel stability plan which resulted in an average annual overall rate increase of 1.5 per cent to recover fuel costs for the period of 2020 through 2022. These rates included recovery of Maritime Link costs, as discussed below. Differences between actual fuel costs and fuel revenues recovered from customers during 2020 to 2022 will be recovered or returned to customers after 2022, as required under NSPI’s fuel stability plan. The UARB’s decision to approve NSPI’s fuel stability plan directed that annual non-fuel revenues above NSPI’s approved range of ROE are to be applied to the FAM.

Pursuant to the FAM Plan of Administration, NSPI’s Fuel Costs are subject to independent audit every two years. On April 6, 2021, the UARB’s decision on the FAM audit findings and recommendations relating to fiscal 2018 and 2019 was publicly released. The final recommendations were endorsed by the UARB and included two disallowances. The impacts of the disallowances were not material to NSPI’s financial results.

Nova Scotia Cap-and-Trade Program Regulations

NSPI is a participant in the Nova Scotia Cap-and-Trade Program and is subject to the 2019 through 2022 compliance period. For more information, refer to the “Description of the Business – Canadian Electric Utilities - Environmental Considerations” section above.

Regulatory Matters – Maritime Link

The Maritime Link entered service on January 15, 2018 and NSPI started interim assessment payments to NSPML at that time. As part of a three-year fuel stability plan, electricity rates were set to include amounts of $164 million and $162 million for 2021 and 2022, respectively. Any difference between the amounts

 

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included in the fuel stability plan and those approved by the UARB through the NSPML interim assessment application will be addressed through the FAM.

For more information, refer to the “Regulatory Assets and Liabilities – Regulatory Environments – Canadian Electric Utilities – NSPI” section of the Audited Financial Statements, which are incorporated herein by reference, a copy of which is available electronically under Emera’s profile on SEDAR at www.sedar.com.

ENL

Maritime Link Project

The Maritime Link entered service on January 15, 2018 and provides for the transmission of energy as well as improved reliability and ancillary benefits, supporting the efficiency and reliability of both provinces. The Maritime Link will transmit at greater capacity when the Lower Churchill projects (including Muskrat Falls and LIL) are complete, which is currently anticipated to take place in 2023.

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.

In December 2022, NSPML received UARB approval to collect up to $164 million from NSPI for the recovery of costs associated with the Maritime Link in 2023. This continues to be subject to a holdback up to $2 million a month, on the same terms described above. On December 22, 2022, the UARB clarified its earlier direction regarding the holdback and NSPI can now release the holdback to NSPML when 90 per cent of the NS Block deliveries, including Supplemental Energy deliveries, is achieved. This enabled NSPI to pay NSPML approximately $4 million of the 2022 holdback. As of December 31, 2022, an additional $14 million in aggregate has been held back by NSPI. Allocation of the $14 million between NSPML and NSPI will be subject to a regulatory process that is expected to commence in early 2023 to review the holdback mechanism.

Delivery of NS Block

Nalcor’s NS Block delivery obligations commenced on August 15, 2021, and delivery will continue over the next 35 years pursuant to the project agreements. For further information on the NS Block, refer to the “Business Overview and Outlook – Canadian Electric Utilities” and “Contractual Obligations” sections of the MDA, which is hereby incorporated by reference, a copy of which is available electronically under Emera’s profile on SEDAR at www.sedar.com.

Gas Utilities and Infrastructure

PGS

Settlement Agreement

On November 19, 2020, the FPSC approved a settlement agreement filed by PGS. The settlement agreement allows for an increase to base rates by $58 million USD annually effective January 1, 2021, which is a $34 million USD increase in revenue and $24 million USD increase of revenues previously recovered through the cast iron and bare steel replacement rider. It provides PGS the ability to reverse a

 

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total of $34 million USD of accumulated depreciation through 2023 and sets new depreciation rates effective January 1, 2021. During 2022, PGS reversed $14 million USD of the $34 million USD accumulated depreciation. No amounts were reversed prior to 2022.

Under the agreement base rates are frozen from January 1, 2021 to December 31, 2023, unless its earned ROE were to fall below 8.9 per cent before that time with an allowed equity in the capital structure of 54.7 per cent from investor sources of capital. The settlement agreement provides for the deferral of income taxes as a result of changes in tax laws. The changes would be reflected as a regulatory asset or liability and either result in an increase or a decrease in customer rates through a subsequent regulatory process.

Base Rate

On February 3, 2023, PGS notified the FPSC that it is planning to file a base rate proceeding in April 2023 for new rates effective January 2024. For more information refer to the “Business Overview and Outlook – Gas Utilities and Infrastructure - Gas Utilities and Infrastructure Outlook” section of the MDA, which is hereby incorporated by reference, a copy of which is available electronically under Emera’s profile on SEDAR at www.sedar.com.

NMGC

Settlement Agreements

On December 16, 2020, the NMPRC approved a settlement agreement for new rates that became effective on January 1, 2021. The new rates reflect the recovery of capital investment in pipelines and related infrastructure and resulted in an increase in revenue of approximately $5 million USD annually.

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.

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 beginning July 1, 2021.

Other Electric Utilities

Sale of Emera Maine

On March 24, 2020, Emera completed the sale of Emera Maine for a total enterprise value of $2.0 billion ($1.4 billion USD).

ECI

BLPC General Rate Review

On October 4, 2021 BLPC submitted a general rate review application to the FTC. The application seeks a rate adjustment and the implementation of a cost reflective rate structure that will facilitate the changes expected in the newly reformed electricity market and the country’s transition toward 100 per cent

 

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renewable energy generation. The application seeks recovery of capital investment in plant, equipment and related infrastructure and results in an increase in annual non-fuel revenue of approximately $23 million USD upon approval. The application includes a request for an allowed regulatory ROE of 12.50 per cent on an allowed equity capital structure of 65 per cent.

On September 16, 2022, the FTC granted BLPC interim rate relief, allowing an increase in base rates of approximately $3 million USD for the remainder of 2022 and approximately $1 million USD per month for 2023. Interim rate relief is effective from September 16, 2022 until the implementation of final rates. The hearing concluded in October 2022. On February 15, 2023, the FTC issued a decision on the BLPC rate review application which included the following significant items: an allowed regulatory ROE of 11.75 per cent, an equity capital structure of 55 per cent, a directive to update the major components of rate base to September 16, 2022, and a directive to establish regulatory liabilities of approximately $70 million USD related to the self-insurance fund, accumulated depreciation, and taxes. The impacts to BLPC’s rate base and final rates are not yet determinable but management does not expect the decision to have a material impact on Emera’s adjusted net income. BLPC will seek to clarify aspects of the FTC decision in its compliance filing and is also considering filing a submission to the FTC for a review of the decision. BLPC expects a decision on final rates from the FTC in 2023.

BLPC Licenses

BLPC is regulated by the Fair Trading Commission (“FTC”), an independent regulator, under the Utilities Regulation (Procedural) Rules 2003. BLPC currently operates pursuant to a franchise to generate, transmit and distribute electricity on the island until 2028. In 2019, the Government of Barbados passed legislation amending the number of licenses required for the supply of electricity from a single integrated license which currently exists to multiple licenses for Generation, Transmission and Distribution, Storage, Dispatch and Sales. In March 2021, BLPC reached commercial agreement with the Government of Barbados for each of the license types, subject to the passage of implementing legislation. The new licenses are expected to take effect in 2023 on completion of the legislative process. The Dispatch license will have a term of five years with the remaining licenses having terms ranging from 25-30 years. BLPC anticipates that any increased costs associated with the implementation of the new multi-licensed structure will be recoverable through BLPC’s regulatory framework. BLPC is awaiting final enactment and will work towards implementation of the licenses once received.

BLPC Fuel Hedging

On October 21, 2021 the FTC approved BLPC’s application to implement a fuel hedging program which will be incorporated into the calculation of the fuel clause adjustment. On November 10, 2021 BLPC requested the FTC review the required 50/50 cost sharing arrangement between BLPC and customers in relation to the hedging administrative costs, or any gains and losses associated with the hedging program. A decision is expected from the FTC in 2023.

GBPC Storm Restoration Costs – Hurricane Matthew

In 2017, as part of the recovery of costs incurred as a result of Hurricane Matthew, the GBPA approved a fixed per kWh fuel charge and allowed the difference between this and the actual cost of fuel to be applied to the Hurricane Matthew regulatory asset. As part of its decision on GBPC’s application for rate review, issued January 14, 2022, and effective April 1, 2022, the GBPA approved the continued amortization of the remaining regulatory asset over the three year period ending December 31, 2024.

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 new rates include a regulatory ROE of 12.84 per cent.

 

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GBPC 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 will be adjusted monthly, in-line with actual fuel costs.

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

During 2020, approximately 4.5 million common shares were issued under the ATM Program at an average price of $56.04 per share for gross proceeds of $255 million ($251 million net of after-tax issuance costs). As at December 31, 2020, an aggregate gross sales limit of $245 million remained available for issuance under the ATM 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 prevailing market price. The ATM Program was renewed pursuant to a prospectus supplement to the Company’s short form base shelf prospectus dated August 5, 2021. The ATM program is expected to remain in effect until September 5, 2023.

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.

During 2023, up to and including February 22, 2023, no common shares were issued under the ATM Program and an aggregate gross sales limit of $207 million remains available for issuance under the ATM Program.

 

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Preferred Share Issuances

On January 7, 2020, Emera announced it would not redeem the 8,000,000 Series F First Preferred Shares. The holders of the Series F First Preferred Shares had the right, at their option, to convert all or any of their Series F First Preferred Shares, on a one-for-one basis, into Series G First Preferred Shares on February 15, 2020 or to continue to hold their Series F First Preferred Shares. On February 6, 2020, Emera announced that, after having taken into account all conversion notices received from holders, no Series F First Preferred Shares would be converted into Series G First Preferred Shares.

On July 9, 2020, Emera announced it would not redeem Series A First Preferred Shares or the Series B First Preferred Shares. On August 17, 2020, Emera announced 128,610 of its 3,864,636 issued and outstanding Series A First Preferred Shares were tendered for conversion into Series B First Preferred Shares and 1,130,788 of its 2,135,364 issued and outstanding Series B First Preferred Shares were tendered for conversion into Series A First Preferred Shares, all on a one-for-one basis. As a result of the conversion, Emera has 4,866,814 Series A First Preferred Shares and 1,133,186 Series B First Preferred Shares issued and outstanding.

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.

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.

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.sedar.com.

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.sedar.com.

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.

 

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As at December 31, 2022, 269,944,308 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 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, 2022, 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, 2022, 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

 

Emera Incorporated – 2022 Annual Information Form    29


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.

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)    N/A

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

 

Emera Incorporated – 2022 Annual Information Form    30


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 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, including the recent downgrades from both S&P and DBRS of NSPI, 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.sedar.com.

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 22, 2022 Emera extended its annual dividend growth rate target of four to five per cent through 2025. 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 2022.

 

Emera Incorporated – 2022 Annual Information Form    31


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      2022        2021        2020   
       

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

       $2.6775           $2.5750           $2.4750   
       

Series A First Preferred Shares(4)

       $0.5456           $0.5456           $0.6155   
       

Series B First Preferred Shares

       $0.6869           $0.4873           $0.6965   
       

Series C First Preferred Shares(5)

       $1.18024           $1.18024           $1.18024   
       

Series E First Preferred Shares

       $1.1250           $1.1250           $1.1250   
       

Series F First Preferred Shares(6)

       $1.05052           $1.05052           $1.053515   
       

Series H First Preferred Shares(7)

       $1.2250           $1.2250           $1.2250   
       

Series J First Preferred Shares(8)

       $1.0625           $0.646965           -          
       

Series L First Preferred Shares(9)

       $1.1500           $0.1638           -          

 

  (1)

On September 16, 2020, Emera approved an increase in the annual common share dividend rate from $2.45 to $2.55. The first payment was effective November, 2020.

 
  (2)

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.

 
  (3)

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.

 
  (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 $1.0250 to $1.18024 for the five year period commencing August 15, 2018 and ending on (and inclusive of) August 14, 2023.

 
  (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 with an annual dividend rate of $1.2250 (per share) were issued May 31, 2018.

 
  (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.

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 2022 are set out In Appendix “C” of this AIF.

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 prevailing market price. The ATM Program was renewed pursuant to a prospectus supplement to the Company’s short form base shelf prospectus dated August 5, 2021. The ATM program is expected to

 

Emera Incorporated – 2022 Annual Information Form    32


remain in effect until September 5, 2023. As at December 31, 2022, an aggregate gross sales limit of approximately $207 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.

DIRECTORS AND OFFICERS

Directors

The following information is provided for each Director of Emera as at December 31, 2022(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. 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 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 Chair of the Keystone Policy Center, having been a member of both the Policy Center and its Energy Board since 2016. Board member and Treasurer of EPIcenter, an innovation think tank; incubator and accelerator; and strategic advisory organization. Energy Pillar Co-Chair of Dentons’ Global Smart Cities & Communities Initiatives and Think Tank. Advisory Board Member of iEmpower, an all-inclusive organization that optimizes the concept of community to engage and inspire women. Serves on the US Secretary of Energy’s Advisory Board.

   2022  

Member of AC and HSEC

 

 

Emera Incorporated – 2022 Annual Information Form    33


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

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, an energy company that provides gas and electric service to approximately 16 million Californians across a 70,000 square-mile service area in Northern and Central California.

   2017  

Chair of AC and Member of HSEC

 

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

Former President of Minogue Medical Inc., a healthcare organization which delivers innovative medical technologies to hospitals and clinics. President of Expertech Network Installation Inc. from 2008 to 2011. Member of the Board of Directors of National Bank of Canada, a Canadian Chartered Bank. Director of Xplore Communications Inc., a Canadian broadband service provider, and Chair of its Audit Committee.

   2013  

Member of AC, HSEC and RSC

 

Ian E. Robertson, Oakville, Ontario, Canada

Principal of the Northern Genesis group of special purpose acquisition companies 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. Member of the Board of Directors of Northern Genesis Acquisition Corp. III and a Director of Embark Technology, Inc., an autonomous vehicle company. Former Director of 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. Former Director of Hiscox Ltd., a Bermuda-incorporated specialty insurer listed on the London Stock Exchange.

   2007  

Chair of NCGC and Member of AC

 

Richard P. Sergel, Boston, Massachusetts, U.S.

Former President and Chief Executive Officer of the North American Electric Reliability Corporation (NERC). Former President and Chief Executive Officer of National Grid USA from 2000 to 2004. Also former President and Chief Executive Officer of the New England Electric System. Presently a Director of State Street Corporation. Has also served on the boards of the Edison Electric Institute and the Consortium for Energy Efficiency.

   2010  

Member of AC and NCGC

 

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 and RSC

 

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 May 26, 2022, John B. Ramil retired from the Emera Board of Directors. Effective January 1, 2023, Ms. Sheppard retired from the AIMCo Board of Directors.

 

Emera Incorporated – 2022 Annual Information Form    34


  (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.

Officers

The Officers of Emera as at December 31, 2022 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.

Richard C. Janega (2)

Chief Operating Officer, Electric Utilities, Canada and Caribbean

Halifax, Nova Scotia, Canada

  

Chief Operating Officer, Electric Utilities, Canada, US Northeast, and Caribbean of Emera since March 31, 2018. Director of NSPI since May 2018. Interim President and Chief Executive Officer of NSPI from June to October 2020. Director and President and CEO of NSPML. Former Chair of the Board of Emera Maine from March 2018 until March 2020. Chief Executive Officer of ENL since 2014. Chair and President of ECI and Chair of both GBPC and BLPC. Former Chief Operating Officer for NSPI.

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. 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.

Stephen D. Aftanas

Corporate Secretary

Halifax, Nova Scotia, Canada

  

Corporate Secretary of Emera since September 2008. Corporate Secretary of NSPI from September 2008 to December 2019.

 

  (1)

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

  (2)

Effective December 31, 2022, Mr. Janega retired from Emera and certain subsidiaries and/or subsidiary boards. Following his retirement, Mr. Janega will serve or continue to serve on the following subsidiary boards: BLPC, ECI, ENLH, GBPC and NSPI.

 

Emera Incorporated – 2022 Annual Information Form    35


As at December 31, 2022, the Directors and Officers, in total, beneficially owned or controlled, directly or indirectly, 204,365 common shares or less than 1 per cent of the issued and outstanding shares of Emera.

AUDIT COMMITTEE

The Audit Committee of Emera is composed of the following six members, all of whom are independent Directors: Kent M. Harvey (Chair), Paula Gold-Williams, B. Lynn Loewen, Ian E. Robertson, Andrea S. Rosen and Richard P. Sergel. 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, 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 – Economic Systems, 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. Chair of the Keystone Policy Center, and member of both the Policy Center and its Energy Board since 2016. Board member and Treasurer of EPIcenter, an innovation think tank; incubator and accelerator; and strategic advisory organization. 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 healthcare organization which delivers innovative medical technologies to hospitals and clinics. Fellow of the Institute of Chartered Accountants, she has served in a number of senior roles at Bell Canada, Air Canada Jazz and Air Nova, and also was the Vice President, Financial Controls for BCE. She has served as Chair of the Audit Committee on the Public Sector Pension Investment Board and was Chair of the Finance and Administration Committee of Mount Allison University. Chancellor of Mount Allison University since 2018 and was a member of the Board from 1998 to 2008. Served as Chair from 2007 to 2008.. She holds a Bachelor of Commerce from Mount Allison University. Fellow of the Chartered Professional Accountants and has received the Institute of Corporate Directors, Directors Designation.

 

Emera Incorporated – 2022 Annual Information Form    36


Ian E. Robertson

Principal of the Northern Genesis group of special purpose acquisition companies 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. Member of the Board of Directors of Northern Genesis Acquisition Corp. III and a Director of Embark Technology, Inc., an autonomous vehicle company. Former Director of 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. Since 2013, 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. From 2001 to 2002, 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. Member of the Board of Directors of the Institute of Corporate Directors.

Richard P. Sergel

Former President and Chief Executive Officer of the North American Electric Reliability Corporation (NERC), a regulatory authority for the bulk electricity system in North America. Before that he served as President and Chief Executive Officer of National Grid USA, and its predecessor, New England Electric System, from 1998 to 2004. Mr. Sergel is a Director and a member of the Examining and Audit Committee of State Street Corporation, a provider of financial services to institutional investors including investment servicing, investment management and investment research and trading. He previously served on the Boards of the Edison Electric Institute and the United Way of the Merrimac Valley. He was also Chair of the Consortium for Energy Efficiency. Mr. Sergel holds a Bachelor of Science in Mathematics from Florida State University, a Master of Science in Applied Mathematics from North Carolina State University and a Master of Business Administration from the University of Miami.

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,

 

Emera Incorporated – 2022 Annual Information Form    37


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.

Auditors’ Fees

The aggregate fees billed by Ernst & Young LLP, the Company’s external auditors, during the fiscal years ended December 31, 2022 and 2021 respectively, were as follows:

 

   Service Fee      2022 ($)              2021 ($)        

Audit Fees

                                        2,018,989                                                 2,078,760        

Audit-Related Fees

       19,600                19,600        

Tax Fees

       337,999                372,618        

All Other Fees

       -                -        

Total

       2,376,588                2,470,978        

Audit-related fees for Emera relate to fees associated with the audit of pension plans. Tax fees for Emera relate to the structuring of cross-border financing of Emera’s subsidiaries and affiliates as well as 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.

 

Emera Incorporated – 2022 Annual Information Form    38


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.

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, 2022, nor has it entered into any material contracts outside the ordinary course of business prior to the year ended December 31, 2022 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.sedar.com 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 Incorporated – 2022 Annual Information Form    39


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.sedar.com and on its corporate website at www.emera.com.

 

Emera Incorporated – 2022 Annual Information Form    40


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.sedar.com;

“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 2022 Annual Information Form of Emera;

“AMI” means advanced metering infrastructure;

“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, 2022 and December 31, 2021, together with the auditors’ report thereon, a copy of which is available electronically under Emera’s profile on SEDAR at www.sedar.com;

“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;

“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.

“COVID-19” means an infectious respiratory illness caused by the 2019 novel coronavirus;

“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;

“CSAPR” means Cross-State Air Pollution Rule;

“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;

“Domlec” means Dominica Electricity Services Limited, an integrated electric utility on the island of Dominica, incorporated under the laws of the Commonwealth of Dominica, and formerly an indirect subsidiary of Emera, through ECI;

“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

 

 

Emera Incorporated – 2021 Annual Information Form    41


an indirect subsidiary of Emera and the parent company of BLPC and GBPC;

“ECRC” means the environmental cost recovery clause;

“Electricity Plan Act” means the Electricity Plan Implementation (2015) Act (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;

“Emera Maine” means the company existing under the laws of the State of Maine and formerly a wholly-owned indirect subsidiary of Emera;

“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;

“ETL” means Emera Technologies LLC, a limited liability company incorporated under the laws of Delaware and a wholly-owned, indirect subsidiary of Emera.

“Fair Trading Commission, Barbados” or “FTC” means the independent 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;

 

 

Emera Incorporated – 2022 Annual Information Form    42


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

“IFRS” means International Financial Reporting Standards;

“Interest Reset Date” means June 15, 2026, and on every quarter thereafter that the Hybrid Notes are outstanding until their maturity on June 15, 2076;

“IMP” means integrity management programs;

“IPPs” means independent power producers;

“ISO-NE” means ISO-New England, an independent, non-profit regional transmission organization which oversees the operation of New England’s bulk electric power system and transmission lines, generated and transmitted by its member utilities;

“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 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 19.1% 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, 2022, a copy of which is available electronically under Emera’s profile on SEDAR at www.sedar.com;

“Moody’s” 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;

“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;

“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;

“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” means the Peoples Gas System Division of TEC, a regulated gas distribution utility, serving customers across Florida, which effective January 1,

 

 

Emera Incorporated – 2022 Annual Information Form    43


2023, ceased to be a division of TEC as a result of the gas utility being reorganized, resulting in a separate legal entity, PGSI;

“PGSI” means Peoples Gas System, Inc. (PGSI), the successor to PGS, existing under the laws of the State of Florida, and a wholly-owned direct subsidiary of TECO Gas Operations, Inc.;

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

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

“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;

“ROE” means return on equity;

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

“Sable Wind Project” means a 14 MW wind farm near Canso, Nova Scotia;

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

“SEDAR” means the System for Electronic Documents Analysis and Retrieval, which can be found at www.sedar.com;

“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;

“Tampa Electric” means the Tampa Electric Division of TEC, an integrated regulated electric utility, serving customers in West Central Florida;

“TEC” means Tampa Electric Company, a wholly-owned subsidiary of TECO Energy, incorporated under the laws of the State of Florida with regulated electric and gas utilities in Florida, collectively, Tampa Electric and PGS;

“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

 

 

Emera Incorporated – 2022 Annual Information Form    44


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 – 2022 Annual Information Form    45


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

As of December 31, 2022, 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 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.

 

Emera Incorporated – 2022 Annual Information Form    46


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, 2022, 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 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.

 

Emera Incorporated – 2022 Annual Information Form    47


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 – 2022 Annual Information Form    48


APPENDIX “C” - MONTHLY TRADING VOLUME AND HIGH AND LOW PRICE FOR EMERA’S SECURITIES IN 2022

 

    

  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

  54.71

51.14

19,587,632

  20.17

18.77

0

  10.09

9.39

0

  13.75

13.05

45,091

  16.00

14.60

17,212

  19.24

18.00

115,362

  17.75

16.75

90,125

  17.45

16.76

69,655

  21.20

19.62

247,927

  22.42

20.82

191,540

  18.00

16.99

173,128

November

High ($)

Low ($)

Volume

  52.87

48.80

39,025,989

  19.76

18.08

0

  9.50

9.50

5000

  13.77

13.20

30,682

  16.19

15.25

12,864

  19.19

17.87

137,332

  17.84

16.23

211,732

  17.70

16.72

156,761

  21.99

20.02

171,893

  23.17

20.70

81,698

  17.64

16.40

226,364

October

High ($)

Low ($)

Volume

  57.60

48.63

43,502,499

  21.22

17.65

0

  9.16

9.16

182

  14.60

13.21

32,029

  16.84

16.00

6,750

  19.32

18.02

109,413

  17.74

16.51

258,806

  18.25

17.16

121,392

  23.00

21.26

105,017

  23.78

22.61

59,088

  18.00

16.55

99,867

September

High ($)

Low ($)

Volume

  62.92

55.81

18,860,229

  24.24

20.36

0

  11.52

11.52

91

  15.01

13.69

64,662

  16.77

16.05

16,400

  20.65

17.75

159,037

  18.86

17.25

61,824

  19.90

17.50

92,499

  24.23

22.15

74,408

  25.05

23.15

132,314

  19.12

17.40

56,642

August

High ($)

Low ($)

Volume

  63.20

59.05

27,425,695

  24.33

22.83

0

  11.67

11.67

274

  15.60

14.17

16,091

  16.76

15.65

4,913

  21.27

19.65

152,090

  19.88

18.80

46,908

  20.41

18.63

47,430

  24.78

23.65

57,246

  25.48

24.61

53,042

  19.88

18.90

182,656

July

High ($)

Low ($)

Volume

  62.21

59.05

23,355,538

  23.86

22.90

0

  11.93

11.45

0

  15.00

13.51

4,569

  16.26

15.90

3,505

  21.56

18.67

59,348

  19.72

18.60

57,915

  19.80

17.99

34,075

  25.09

24.10

100,647

  25.59

24.80

49,494

  19.75

18.65

147,790

June

High ($)

Low ($)

Volume

  63.76

57.13

18,849,884

  25.34

21.98

0

  12.67

10.99

0

  17.00

15.22

9,784

  17.50

17.00

2,318

  23.50

20.52

95,397

  20.61

18.75

30,649

  22.92

19.56

48,315

  25.30

24.32

106,515

  25.97

25.03

68,631

  20.76

19.00

88,280

May

High ($)

Low ($)

Volume

  64.93

60.63

31,789,311

  25.29

23.66

0

  12.65

11.83

0

  16.48

15.71

4,632

  16.95

16.49

4,230

  23.40

21.54

93,901

  20.27

19.15

136,272

  22.98

21.05

72,372

  25.00

24.27

155,320

  25.96

25.00

57,205

  20.55

19.60

369,608

April

High ($)

Low ($)

Volume

  65.23

61.53

30,128,700

  26.09

24.59

0

  13.04

12.29

0

  16.97

15.46

11,622

  17.44

16.50

3,908

  23.50

21.00

321,752

  22.19

19.85

256,144

  22.96

20.87

237,026

  25.35

23.99

180,511

  25.65

24.90

168,498

  22.50

19.92

1,971,593

March

High ($)

Low ($)

Volume

  62.54

58.82

19,922,299

  24.48

23.14

0

  11.25

11.25

1000

  17.17

16.05

20,242

  17.60

17.31

4,432

  24.01

22.81

117,977

  23.90

22.28

40,237

  24.38

22.60

56,476

  25.60

24.75

102,465

  25.70

24.91

218,688

  24.44

22.51

107,549

February

High ($)

Low ($)

Volume

  60.51

57.87

22,888,998

  23.83

22.81

0

  11.92

11.40

0

  18.60

17.00

20,310

  18.10

18.02

7,716

  24.40

23.11

62,044

  24.33

23.00

45,298

  24.25

23.30

48,131

  25.83

24.83

52,126

  26.51

25.07

88,177

  24.80

23.95

64,611

January

High ($)

Low ($)

Volume

  63.49

58.57

25,752,083

  24.98

23.14

0

  12.49

11.57

0

  18.60

18.01

18,874

  19.68

18.00

22,004

  24.64

23.45

128,831

  25.04

23.85

54,888

  24.56

23.72

59,256

  26.60

25.51

80,033

  27.98

26.07

107,204

  25.54

24.40

393,203

 

(1)

The Barbados DRs trade on the BSE. During those months in 2022 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 2022 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 – 2022 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 – 2020 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 – 2022 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 – 2022 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 – 2022 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 – 2022 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 – 2022 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 – 2022 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 – 2022 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 – 2022 Annual Information Form    58
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
exhibit992p1i0
1
Management’s Discussion & Analysis
As at February 23, 2023
Management’s Discussion & Analysis (“MD&A”) provides a review of the results of operations of Emera
Incorporated and its subsidiaries and investments during the fourth quarter of 2022 relative to the same
quarter in 2021; for the full year of 2022 relative to 2021 and selected financial information for 2020; and
its financial position as at December 31, 2022 relative to December 31, 2021. Throughout this discussion,
“Emera” and “Company” refer to Emera Incorporated and all of its consolidated subsidiaries and
investments. The Company’s activities are carried out through five reportable segments: Florida Electric
Utility, Canadian Electric Utilities, Gas Utilities and Infrastructure, Other Electric Utilities, and Other.
 
This discussion and analysis should be read in conjunction with the Emera annual audited consolidated
financial statements and supporting notes as at and for the year ended December 31, 2022.
 
Emera
follows United States Generally Accepted Accounting Principles (“USGAAP” or “GAAP”).
The accounting policies used by Emera’s rate-regulated entities may differ from those used by Emera’s
non-rate-regulated businesses with respect to the timing of recognition of certain assets, liabilities,
revenues and expenses. At December 31, 2022, Emera’s rate-regulated subsidiaries and investments
include:
 
Emera Rate-Regulated Subsidiary or Equity
Investment
Accounting Policies Approved/Examined By
Subsidiary
Tampa Electric – Electric Division of Tampa
 
Electric
Company (“TEC”)
(1)
Florida Public Service Commission (“FPSC”) and the
Federal Energy Regulatory Commission (“FERC”)
Nova Scotia Power Inc. ("NSPI")
Nova Scotia Utility and Review Board (“UARB”)
 
Peoples Gas System (“PGS”) – Gas Division of TEC
 
(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 ("NLPUB")
Maritimes & Northeast Pipeline Limited Partnership and
Maritimes & Northeast Pipeline, LLC (“M&NP”)
CER and FERC
St. Lucia Electricity Services Limited (“Lucelec”)
National Utility Regulatory Commission (“NURC”)
(1) Effective January 1, 2023, Peoples Gas System ceased to be a division of TEC and the gas utility was
 
reorganized, resulting in a
separate legal entity called Peoples Gas System, Inc., a wholly-owned direct subsidiary of TECO Gas Operations,
 
Inc.
All amounts are in Canadian dollars (“CAD”), except for the Florida Electric Utility, Gas Utilities and
Infrastructure, and Other Electric Utilities sections of the MD&A, which are reported in United States dollar
(“USD”) unless otherwise stated.
Additional information related to Emera, including the Company’s Annual Information Form, can be found
on SEDAR at www.sedar.com.
2
TABLE
 
OF CONTENTS
Forward-looking Information……………………...
2
Introduction and Strategic Overview………….…
3
Non-GAAP Financial Measures and Ratios….…
4
Consolidated Financial Review……….………….
7
 
Significant Items Affecting Earnings……….....
7
 
Consolidated Financial Highlights……………
 
7
 
Consolidated Income Statement Highlights…
9
Business Overview and
Outlook…………….……
11
 
Florida Electric Utility ……………….............
11
 
Canadian Electric Utilities …..………….……
12
 
Gas Utilities and Infrastructure..…….…….…
16
 
Other Electric Utilities …………………………
17
 
Other……………………………………………
19
Consolidated Balance Sheet Highlights………
20
Other Developments……………….....................
21
Financial Highlights……………………………..
22
 
Florida Electric Utility ………….......................
22
 
Canadian Electric Utilities ……..…………..…
23
 
Gas Utilities and Infrastructure……………...
26
 
Other Electric Utilities ………………………….
28
 
Other…………………………………………….
29
Liquidity and Capital Resources………..………
31
 
Consolidated Cash Flow Highlights…..……
32
 
Working Capital
33
 
Contractual Obligations….……………………
34
 
Forecasted Gross Consolidated Capital
 
Expenditures………………………………
34
 
Debt Management……..…………………….
35
 
Credit Ratings…………………………………
 
Guaranteed Debt……………………………
 
Outstanding Stock Data……………………
37
37
38
Pension Funding………………………………
39
Off-Balance Sheet Arrangements…….………
39
Dividend Payout Ratio…………………………
40
Transactions with Related Parties….………….
40
Enterprise Risk and Risk Management…………
41
Risk Management including Financial
 
Instruments……………………………………
54
Disclosure and Internal Controls……….…….
56
Critical Accounting Estimates….………………
56
Changes in Accounting Policies and
Practices…
62
 
Future Accounting Pronouncements…………
62
Summary of Quarterly Results…….....................
62
FORWARD-LOOKING INFORMATION
This MD&A contains “forward-looking information” and statements which reflect the current view with
respect to the Company’s expectations regarding future growth, results of operations, performance,
carbon dioxide emissions reduction goals, business prospects and opportunities,
 
and may not be
appropriate for other purposes within the meaning of applicable Canadian securities laws. All such
information and statements are made pursuant to safe harbour provisions contained in applicable
securities legislation. The words “anticipates”, “believes”, “budget”, “could”, “estimates”, “expects”,
“forecast”, “intends”, “may”, “might”, “plans”, “projects”, “schedule”, “should”, “targets”, “will”, “would” and
similar expressions are often intended to identify forward-looking information, although not all forward-
looking information contains these identifying words. The forward-looking information reflects
management’s current beliefs and is based on information currently available to Emera’s management
and should not be read as guarantees of future events, performance or results, and will not necessarily
be accurate indications of whether, or the time at which, such events, performance or results will be
achieved.
 
 
3
The forward-looking information is based on reasonable assumptions and is subject to risks, uncertainties
and other factors that could cause actual results to differ materially from historical results or results
anticipated by the forward-looking information. Factors that could cause results or events to differ from
current expectations include, without limitation: regulatory and political risk; operating and maintenance
risks; changes in economic conditions; commodity price and availability risk; liquidity and capital market
risk; future dividend growth; timing and costs associated with certain capital investments; expected
impacts on Emera of challenges in the global economy; estimated energy consumption rates;
maintenance of adequate insurance coverage; changes in customer energy usage patterns;
developments in technology that could reduce demand for electricity; global climate change; weather;
unanticipated maintenance and other expenditures; system operating and maintenance risk; derivative
financial instruments and hedging; interest rate risk; inflation risk; counterparty risk; disruption of fuel
supply; country risks; environmental risks; foreign exchange (“FX”); regulatory and government decisions,
including changes to environmental, financial reporting and tax legislation; risks associated with pension
plan performance and funding requirements; loss of service area; risk of failure of information technology
(“IT”) infrastructure and cybersecurity risks; uncertainties associated with infectious diseases, pandemics
and similar public health threats, such as the COVID-19 novel coronavirus (“COVID-19”) pandemic;
market energy sales prices; labour relations; and availability of labour and management resources.
 
Readers are cautioned not to place undue reliance on forward-looking information,
 
as actual results could
differ materially from the plans, expectations, estimates or intentions and statements expressed in the
forward-looking information. All forward-looking information in this MD&A is qualified in its entirety by the
above cautionary statements and, except as required by law, Emera undertakes no obligation to revise or
update any forward-looking information as a result of new information, future events or otherwise.
INTRODUCTION AND STRATEGIC
 
OVERVIEW
Based in Halifax, Nova Scotia, Emera owns and operates cost-of-service rate-regulated electric and gas
utilities in Canada, the United States and the Caribbean. Cost-of-service utilities provide essential electric
and gas services in designated territories under franchises and are overseen by regulatory authorities.
Emera’s strategic focus continues to be safely delivering cleaner, affordable and reliable energy to its
customers.
The majority of Emera’s investment in rate-regulated businesses are located in Florida with other
investments in Nova Scotia, New Mexico and the Caribbean.
 
Emera’s portfolio of regulated utilities
provides reliable earnings, cash flow and dividends. Earnings opportunities in regulated utilities are
generally driven by the magnitude of net investment in the utility (known as “rate base”), and the amount
of equity in the capital structure and the return on that equity (“ROE”) as approved through regulation.
Earnings are also affected by sales volumes and operating expenses.
Emera’s capital investment plan is $8 – 9 billion over the 2023-to-2025 period (including a $240 million
equity investment in the LIL in 2023), mainly focused in Florida. This results in a forecasted rate base
growth of approximately 7 per cent to 8 per cent through 2025. The capital investment plan continues to
include significant investments across the portfolio in renewable and cleaner generation, reliability and
integrity investments, infrastructure modernization, and customer-focused technologies. Emera’s capital
investment plan is being funded primarily through internally generated cash flows and debt raised at the
operating company level. Equity requirements in support of the Company’s capital investment plan are
expected to be funded through the issuance of preferred equity and the issuance of common equity
through Emera’s dividend reinvestment plan (“DRIP”) and at-the-market program (“ATM program”).
Maintaining investment-grade credit ratings is a priority of the Company.
Emera has provided annual dividend growth guidance of four to five per cent through 2025. The
Company targets a long-term dividend payout ratio of adjusted net income of 70 to 75 per cent and, while
the payout ratio is likely to exceed that target through and beyond the forecast period, it is expected to
return to that range over time. For further information on the non-GAAP measure “Dividend Payout Ratio
of Adjusted Net Income”, refer to the “Non-GAAP Financial Measures and Ratios”
 
section.
4
Seasonal patterns and other weather events affect demand and operating costs. Similarly, mark-to-
market adjustments and foreign currency exchange can have a material impact on financial results for a
specific period. Emera’s consolidated net income and cash flows are impacted by movements in the USD
relative to the Canadian dollar. Emera may hedge both transactional and translational exposure. These
impacts, as well as the timing of capital investments and other factors, mean results in any one quarter
are not necessarily indicative of results in any other quarter, or for the year as a whole.
Energy markets worldwide are facing significant change and Emera is well positioned to respond to
shifting customer demands, digitization, decarbonization, complex regulatory environments, and
decentralized generation.
 
Customers are looking for more choice, better control, and enhanced reliability in a time where costs of
decentralized generation and storage have become more competitive in some regions. Advancing
technologies are transforming the way utilities interact with their customers and generate and transmit
energy. In addition, climate change and extreme weather are shaping how utilities operate and how they
invest in infrastructure. There is also an overall need to replace aging infrastructure and further enhance
reliability. Emera will play a role in all of these trends. Emera’s strategy is to fund investments in
renewable energy and technology assets which protect the environment and benefit customers through
fuel or operating cost savings.
 
For example, significant investments to facilitate the use of renewable and low-carbon energy include the
Maritime Link in Atlantic Canada, and the ongoing construction of solar generation and modernization of
the Big Bend Power Station at Tampa
 
Electric. Emera’s utilities are also investing in reliability projects
and replacing aging infrastructure. All of these projects demonstrate Emera’s strategy of safely delivering
cleaner, reliable, and affordable energy for its customers.
Building on its decarbonization progress, Emera is continuing its efforts by establishing clear carbon
reduction goals and a vision to achieve net-zero carbon dioxide emissions by 2050.
 
This vision is inspired by Emera’s strong track record, the Company’s experienced team, and a clear path
to Emera’s interim carbon goals. With existing technologies and resources,
 
and subject to supportive
government and regulatory decisions, Emera is working to achieve the following goals compared to
corresponding 2005 levels:
 
•
 
A 55 per cent reduction in carbon dioxide emissions by 2025.
•
 
The retirement of Emera’s last existing coal unit no later than 2040.
•
 
An 80 per cent reduction in carbon dioxide emissions by 2040.
 
Achieving the above climate goals on these timelines is subject to the Company's regulatory obligations
and other external factors beyond Emera's control.
Emera seeks to deliver on its Climate Commitment while maintaining its focus on investing in reliability
and staying focused on the cost impacts for customers. Emera is also committed to identifying emerging
technologies and continuing to work constructively with policymakers, regulators, partners, investors and
customers to achieve these goals and realize its net-zero vision.
Emera is committed to world-class safety, operational excellence, good governance, excellent customer
service, reliability, being an employer of choice, and building constructive relationships.
NON-GAAP FINANCIAL MEASURES AND RATIOS
Emera uses financial measures and ratios that do not have standardized meaning under USGAAP and
may not be comparable to similar measures presented by other entities. Emera calculates the non-GAAP
measures and ratios by adjusting certain GAAP measures for specific items. Management believes
excluding these items better distinguishes the ongoing operations of the business and allows investors to
better understand and evaluate the business. These measures and ratios are discussed and reconciled
below.
5
Adjusted Net Income Attributable to Common Shareholders, Adjusted Earnings (Loss) Per
Common Share (“EPS”) – Basic and Dividend Payout Ratio of Adjusted Net Income
Emera calculates an adjusted net income attributable to common shareholders (“adjusted net income”)
measure by excluding the effect of mark-to-market (“MTM”) adjustments,
 
impairment charges, the impact
of the NSPML unrecoverable costs, and the 2020 gain on sale of Emera Maine.
Management believes excluding from net income the effect of these MTM valuations and changes
thereto, until settlement, better aligns the intent and financial effect of these contracts with the underlying
cash flows, and therefore excludes these MTM adjustments for evaluation of performance and incentive
compensation. The MTM adjustments are related to the following:
●
 
held-for-trading (“HFT”) commodity derivative instruments, including adjustments related to the
price differential between the point where natural gas is sourced and where it is delivered, and
the related amortization of transportation capacity recognized as a result of certain Emera Energy
marketing and trading transactions;
●
 
the business activities of Bear Swamp Power Company LLC (“Bear Swamp”) included in Emera’s
equity income;
●
 
equity securities held in BLPC and a captive reinsurance company in the Other segment; and
●
 
FX hedges entered into to hedge USD denominated operating unit earnings exposure.
For further detail on MTM adjustments, refer to the “Consolidated Financial Review”, “Financial Highlights
– Other Electric Utilities”, and “Financial Highlights – Other” sections.
In Q4 2022, the Company recognized a $73 million non-cash goodwill impairment charge related to
GBPC due to a decline in the fair value of the reporting unit. The fair value decline was driven by the
effects of macro-economic factors on the discount rate calculation, including the risk-free rate
assumption. Management believes excluding from net income the effect of this charge better
distinguishes ongoing operations of the business and allows investors to better understand and evaluate
the Company. For further details on this GBPC impairment charge, refer to “Significant Items Impacting
Earnings”, and “Financial Highlights – Other” sections.
In February 2022, the UARB issued a decision to disallow the recovery of $9 million in costs ($7 million
after-tax) included in NSPML’s final capital cost application. The after-tax unrecoverable costs were
recognized in “Income from equity investments” in Emera’s Consolidated Statements of Income.
Management believes excluding these unrecoverable costs from the calculation of adjusted net income
better reflects the underlying operations in the period. For further details on the NSPML unrecoverable
costs, refer to the “Business Overview and Outlook – Canadian Electric Utilities” and “Financial Highlights
– Canadian Electric Utilities” sections.
In 2020, the Company recognized a gain on the sale of Emera Maine and certain non-cash impairment
charges. Management believes excluding these from net income better distinguishes ongoing operations
of the business and allows investors to better understand and evaluate the business.
Adjusted EPS – basic and dividend payout ratio of adjusted net income are non-GAAP ratios which are
calculated using adjusted net income, as described above. For further details on dividend payout ratio of
adjusted net income, see the “Dividend Payout Ratio” section.
Emera calculates adjusted net income for the Canadian Electric Utilities, Other Electric Utilities, and Other
segments. Reconciliation to the nearest GAAP measure is included in each segment. Refer to “Financial
Highlights – Canadian Electric Utilities”, “Financial Highlights – Other Electric Utilities” and “Financial
Highlights – Other” sections.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
6
The following reconciles net income attributable to common shareholders to adjusted net income:
Three months ended
Year ended
For the
December 31
December 31
millions of dollars (except per share amounts)
2022
2021
2022
2021
2020
Net income attributable to common shareholders
$
 
483
$
 
324
$
 
945
$
 
510
$
 
938
MTM gain (loss), after-tax
(1)
 
307
 
156
 
175
 
(213)
 
(10)
Impairment charges, after-tax
(2)
 
(73)
 
-
 
 
(73)
 
-
 
 
(26)
NSPML unrecoverable costs
(3)
 
-
 
 
-
 
 
(7)
 
-
 
 
-
 
Gain on sale, after tax and transaction costs
(4)
 
-
 
 
-
 
 
-
 
 
-
 
 
309
Adjusted net income attributable to common shareholders
$
 
249
$
 
168
$
 
850
$
 
723
$
 
665
EPS – basic
$
 
1.80
$
 
1.24
$
 
3.56
$
 
1.98
$
 
3.78
Adjusted EPS – basic
$
 
0.93
$
 
0.64
$
 
3.20
$
 
2.81
$
 
2.68
(1) Net of income tax expense of $124 million for the three months ended December 31, 2022 (2021 – $63 million expense)
 
and $73
million expense for the year ended December 31, 2022 (2021 – $86 million recovery) (2020 - $8 million recovery).
(2) Net of income tax expense of nil for the three months and year ended December 31, 2022 (2021 – nil) (2020 – $1 million
expense).
(3) Emera accounts for NSPML as an equity investment and therefore the after-tax unrecoverable costs were recorded
 
in “Income
from equity investments” on Emera’s Consolidated Statements of Income.
(4) Net of income tax expense of $276 million for the year ended December 31, 2020.
EBITDA and Adjusted EBITDA
Earnings before interest, income taxes, depreciation and amortization (“EBITDA”) and adjusted EBITDA
are non-GAAP financial measures used by Emera. These financial measures are used by numerous
investors and lenders to better understand cash flows and credit quality. EBITDA is useful to assess
Emera’s operating performance and indicates the Company’s ability to service or incur debt, invest in
capital, and finance working capital requirements.
Similar to adjusted net income calculations described above, adjusted EBITDA represents EBITDA
absent the income effect of MTM adjustments, impairment charges, the NSPML unrecoverable costs, and
the 2020 gain on sale of Emera Maine.
 
The following is a reconciliation of net income to EBITDA and Adjusted EBITDA:
Three months ended
Year ended
For the
December 31
December 31
millions of dollars
2022
2021
2022
2021
2020
Net income
(1)
$
 
499
$
 
338
$
 
1,009
$
 
561
$
 
984
Interest expense, net
 
206
 
151
 
709
 
611
 
679
Income tax expense (recovery)
 
154
 
85
 
185
 
(6)
 
341
Depreciation and amortization
 
254
 
227
 
952
 
902
 
881
EBITDA
$
 
1,113
$
 
801
$
 
2,855
$
 
2,068
$
 
2,885
MTM gain (loss), excluding income tax
 
431
 
219
 
248
 
(299)
 
(18)
Impairment charges, excluding income tax
 
(73)
 
-
 
 
(73)
 
-
 
 
(25)
NSPML unrecoverable costs
(2)
 
-
 
 
-
 
 
(7)
 
-
 
 
-
 
Gain on sale, net of transaction costs (excluding income tax)
 
-
 
 
-
 
 
-
 
 
-
 
 
585
Adjusted EBITDA
$
 
755
$
 
582
$
 
2,687
$
 
2,367
$
 
2,343
(1) Net income is before Non-controlling interest in subsidiaries and Preferred stock dividends.
(2) Emera accounts for NSPML as an equity investment and therefore the after-tax unrecoverable costs were recorded
 
in “Income
from equity investments” on Emera’s Consolidated Statements of Income.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
7
CONSOLIDATED
 
FINANCIAL REVIEW
Significant Items Affecting Earnings
GBPC Impairment Charge
In Q4 2022, Emera recognized a goodwill impairment charge of $73 million ($0.27 per common share) for
GBPC due to a decline in the fair value of the reporting unit. Although the cash flows of GBPC have not
changed significantly compared to previous periods, the decline in the fair value was driven by the effects
of macro-economic factors on discount rate calculations, including the risk-free rate assumption. This
non-cash charge was recorded in “Impairment charge” on the Consolidated Statements of Income and
reduced the GBPC goodwill balance to nil. For further details, refer to note 22 in the consolidated financial
statements.
TECO Guatemala Holdings (“TGH”) International Arbitration and Award
On December 15, 2022, a payment of $63 million ($45 million after tax and legal costs, or $0.17 per
common share), was made by the Republic of Guatemala to TECO Energy in satisfaction of the second
and final award issued by the International Centre of the Settlement of Investment Disputes tribunal
regarding a dispute over an investment of TGH, a wholly owned subsidiary of TECO Energy. The dispute
related to the 2007 intervention by the government of Guatemala in an ongoing independent rate-setting
process to unilaterally set a new and lower tariff. The payment was recognized in ‘Other income, net” on
the Consolidated Statements of Income. For further details, refer to note 27 in the consolidated financial
statements.
Earnings Impact of MTM Gain (Loss), After-Tax
MTM gain, after-tax increased $151 million to $307 million in Q4 2022, compared to $156 million in Q4
2021, and for the year ended December 31, increased $388 million to $175 million compared to a MTM
loss, after-tax of $213 million for the same period in 2021. These increases were due to changes in
existing positions and reversal of losses in 2022, partially offset by higher amortization in 2022 of gas
transportation assets at Emera Energy.
Consolidated Financial Highlights
For the
Three months ended
Year ended
millions of dollars
 
December 31
December 31
Adjusted net income
2022
2021
2022
2021
2020
Florida Electric Utility
$
 
124
$
 
85
$
 
596
$
 
462
$
 
501
Canadian Electric Utilities
 
46
 
67
 
222
 
241
 
221
Gas Utilities and Infrastructure
 
72
 
55
 
221
 
198
 
162
Other Electric Utilities
 
8
 
5
 
29
 
20
 
33
Other
 
(1)
 
(44)
 
(218)
 
(198)
 
(252)
Adjusted net income
$
 
249
$
 
168
$
 
850
$
 
723
$
 
665
MTM gain (loss), after-tax
 
307
 
156
 
175
 
(213)
 
(10)
Impairment charges, after-tax
 
(73)
 
-
 
 
(73)
 
-
 
 
(26)
NSPML unrecoverable costs
 
-
 
 
-
 
 
(7)
 
-
 
 
-
 
Gain on sale, after tax and transaction costs
 
-
 
 
-
 
 
-
 
 
-
 
 
309
Net income attributable to common shareholders
$
 
483
$
 
324
$
 
945
$
 
510
$
 
938
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
8
The following table highlights the significant changes in adjusted net income from 2021 to 2022:
For the
Three months ended
Year ended
millions of dollars
December 31
December 31
Adjusted net income – 2021
$
 
168
$
 
723
Operating Unit Performance
Increased earnings at Tampa Electric due to higher revenues as a result
of rate increases effective January 2022, customer growth, and the
impact of a weakening CAD. These were partially offset by higher
operating, maintenance and general expenses (OM&G"), increased
interest expense, and higher depreciation. Year-over-year also
increased due to favourable weather
 
39
 
134
Increased earnings at Emera Energy Services ("EES") due to favourable
market conditions
 
21
 
21
Increased earnings at PGS due to higher off-system sales and customer
growth, partially offset by higher OM&G. Year-over-year also increased
due to reversal of accumulated depreciation as a result of the rate case
settlement
 
2
 
10
Increased earnings at Seacoast due to commencement of a 34-year
pipeline lateral lease in 2022
 
2
 
9
Increased earnings at NMGC were primarily due to higher asset
optimization revenues. Year-over-year increased earnings were partially
offset by higher OM&G and increased depreciation
 
11
 
4
Decreased earnings at NSPI due to higher OM&G primarily due to
increased costs for storm restoration, IT, power generation, regulatory
affairs, and higher depreciation. This was partially offset by higher sales
volumes. Quarter-over-quarter also decreased due to unfavourable
weather
 
(20)
 
(10)
Corporate
TGH award, after tax and legal costs, in Q4 2022. Refer to the
"Significant Items Affecting Earnings" section
 
45
 
45
Increased income tax recovery primarily due to increased losses before
provision for income taxes
 
17
 
34
Increased OM&G, pre-tax, due to the timing of long-term compensation
and related hedges
 
(19)
 
(55)
Increased FX loss, pre-tax, primarily due to realized gains in 2021 on FX
hedges entered into to hedge USD denominated operating unit earnings
exposure
 
(9)
 
(28)
Increased interest expense, pre-tax, due to higher interest rates and
increased total debt
 
(17)
 
(27)
Increased preferred stock dividends due to issuance of preferred shares
in 2021
 
(2)
 
(13)
Other Variances
 
11
 
3
Adjusted net income – 2022
$
 
249
$
 
850
For further details of reportable segments contributions, refer to the "Financial Highlights" section.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
9
For the
Year ended December 31
millions of dollars
2022
2021
2020
Operating cash flow before changes in working capital
$
 
1,147
$
 
1,337
$
 
1,420
Change in working capital
 
(234)
 
(152)
 
217
Operating cash flow
$
 
913
$
 
1,185
$
 
1,637
Investing cash flow
$
 
(2,569)
$
 
(2,332)
$
 
(1,224)
Financing cash flow
$
 
1,555
$
 
1,311
$
 
(372)
For further discussion of cash flow, refer to the "Consolidated Cash Flow Highlights" section.
As at
 
December 31
millions of dollars
2022
2021
2020
Total assets
$
 
39,742
$
 
34,244
$
 
31,234
Total long-term
 
debt (including current portion)
$
 
16,318
$
 
14,658
$
 
13,721
Consolidated Income Statement Highlights
For the
 
Three months ended
Year ended
Year ended
millions of dollars
December 31
December 31
December 31
(except per share amounts)
2022
2021
Variance
2022
2021
Variance
2020
Operating revenues
$
 
2,358
$
 
1,868
$
 
490
$
 
7,588
$
 
5,765
$
 
1,823
$
 
5,506
Operating expenses
 
1,638
 
1,352
 
(286)
 
5,959
 
4,835
 
(1,124)
 
4,359
Income from operations
$
 
720
$
 
516
$
 
204
$
 
1,629
$
 
930
$
 
699
$
 
1,147
Net income attributable to
common shareholders
$
 
483
$
 
324
$
 
159
$
 
945
$
 
510
$
 
435
$
 
938
Adjusted net income
$
 
249
$
 
168
$
 
81
$
 
850
$
 
723
$
 
127
$
 
665
Weighted average shares of
common stock outstanding (in
millions)
(1)
 
269.0
 
260.8
 
8.2
 
265.5
 
257.2
 
8.3
 
247.8
EPS – basic
$
 
1.80
$
 
1.24
$
 
0.56
$
 
3.56
$
 
1.98
$
 
1.58
$
 
3.78
EPS – diluted
$
 
1.80
$
 
1.20
$
 
0.60
$
 
3.55
$
 
1.98
$
 
1.57
$
 
3.78
Adjusted EPS – basic
$
 
0.93
$
 
0.64
$
 
0.29
$
 
3.20
$
 
2.81
$
 
0.39
$
 
2.68
Adjusted EBITDA
$
 
755
$
 
582
$
 
173
$
 
2,687
$
 
2,367
$
 
320
$
 
2,343
Dividends per common share
declared
$
 
0.6900
$
 
0.6625
$
 
0.0275
$
 
2.6775
$
 
2.5750
$
 
0.1025
$
 
2.4750
Dividends per first preferred shares declared:
 
Series A
$
 
0.5456
$
 
0.5456
$
 
-
 
$
 
0.6155
 
Series B
$
 
0.6869
$
 
0.4873
$
 
0.1996
$
 
0.6965
 
Series C
$
 
1.1802
$
 
1.1802
$
 
-
 
$
 
1.1802
 
Series E
$
 
1.1250
$
 
1.1250
$
 
-
 
$
 
1.1250
 
Series F
$
 
1.0505
$
 
1.0505
$
 
-
 
$
 
1.0535
 
Series H
$
 
1.2250
$
 
1.2250
$
 
-
 
$
 
1.2250
 
Series J
$
 
1.0625
$
 
0.6470
$
 
0.4155
$
 
-
 
 
Series L
$
 
1.1500
$
 
0.1638
$
 
0.9862
$
 
-
 
(1) Effective February 10, 2022, deferred share units are no longer able to be settled in shares and are
 
therefore excluded from
weighted average shares of common stock outstanding.
Operating Revenues
For Q4 2022, operating revenues increased $490 million compared to Q4 2021 and, absent increased
MTM gains of $195 million, increased $295 million. For the year ended December 31, 2022, operating
revenues increased $1,823 million compared to 2021 and, absent increased MTM gains of $555 million,
increased by $1,268 million. The increases in both periods were due to: higher fuel revenues at NMGC,
Tampa
 
Electric PGS and BLPC; new rates effective January 2022 and customer growth at Tampa
Electric; the impact of a weaker CAD; higher off-system sales and customer growth at PGS; and
increased marketing and trading margin due to favourable market conditions at EES. Year-over-year also
increased due to increased sales volumes at NSPI and favourable weather at Tampa Electric.
10
Operating Expenses
For Q4 2022, operating expenses increased $286 million compared to Q4 2021 and, absent the GBPC
impairment charge of $73 million, increased by $213 million. For the year ended December 31, 2022,
operating expenses increased $1,124 million compared to 2021 and, absent the GBPC impairment
charge of $73 million, increased by $1,051 million. The increases in both periods were due to: higher
natural gas prices at NMGC and PGS; the impact of a weaker CAD; and increased OM&G at Tampa
Electric, Corporate, NSPI, NMGC and PGS. Year-over-year also increased due to higher natural gas and
fuel prices at Tampa
 
Electric and BLPC.
Other Income, Net
Other income, net increased for Q4 2022 and the year ended December 31, 2022, compared to the same
periods in 2021, primarily due to the TGH award in Q4 2022.
Net Income and Adjusted Net Income
Net income attributable to common shareholders for Q4 2022, as compared to Q4 2021, was favourably
impacted by the $151 million increase in MTM gains, after-tax and unfavourably impacted by the $73
million GBPC impairment charge. Absent these changes, adjusted net income increased $81 million. The
increase was primarily due to: the TGH award in Q4 2022; higher earnings contribution from Tampa
Electric, Emera Energy and NMGC; and the impact of a weaker CAD. These were partially offset by lower
earnings contribution from NSPI and increased corporate OM&G due to the timing of long-term
compensation and related hedges, and higher corporate interest expense.
Net income attributable to common shareholders for the year ended 2022, as compared to the same
period in 2021, was favourably impacted by the $388 million increase in MTM gains, after-tax and
unfavourably impacted by the $73 million GBPC impairment charge as well as the $7 million in NSPML
unrecoverable costs. Absent these changes, adjusted net income increased $127 million. The increase
was primarily due to: higher earnings contributions from Tampa Electric, Emera Energy,
 
PGS and
Seacoast; the TGH award in Q4 2022; and the impact of a weaker CAD. These were partially offset by
increased corporate OM&G due to the timing of long-term compensation and related hedges, higher
corporate interest expense, realized gains on corporate FX hedges in 2021, increased preferred stock
dividends and lower earnings contribution from NSPI.
EPS and Adjusted EPS – Basic
EPS and Adjusted EPS – basic were higher for Q4
2022, and for the year ended December 31, 2022,
due to the impact of higher earnings as discussed above, partially offset by the impact of the increase in
weighted average shares of common stock outstanding.
Effect of Foreign Currency Translation
Emera operates in Canada, the United States and various Caribbean countries and, as such, generates
revenues and incurs expenses denominated in local currencies which are translated into CAD for
financial reporting. Changes in translation rates, particularly in the value of the USD against the CAD, can
positively or adversely affect results.
 
In general, Emera’s earnings benefit from a weakening CAD and are adversely impacted by a
strengthening CAD. The impact in any period is driven by rate changes, the timing and percentage of
earnings from foreign operations, and the impact of FX hedges entered into to hedge USD denominated
operating unit earnings exposure.
 
 
 
 
 
 
 
 
 
 
 
 
 
11
Results of foreign operations are translated at the weighted average rate of exchange, and assets and
liabilities of foreign operations are translated at period end rates. The relevant CAD/USD exchange rates
for 2022 and 2021 are as follows:
Three months ended
 
Year ended
December 31
December 31
2022
2021
2022
2021
Weighted average CAD/USD
 
$
1.37
$
1.26
$
1.34
$
1.26
Period end CAD/USD exchange rate
$
1.35
$
1.27
$
1.35
$
1.27
The table below includes Emera’s significant segments whose contributions to adjusted net income are
recorded in USD currency.
Three months ended
Year ended
For the
 
December 31
December 31
millions of USD
2022
2021
2022
2021
Florida Electric Utility
$
91
$
67
$
458
$
369
Other Electric Utilities
7
4
23
16
Gas Utilities and Infrastructure
 
(1)
45
37
143
130
Other segment
(2)
30
(20)
(50)
(98)
Total
(3)
$
173
$
88
$
574
$
417
(1) Includes USD net income from PGS, NMGC, SeaCoast and M&NP.
(2) Includes Emera Energy's USD adjusted net income from EES, Bear Swamp and interest expense on Emera Inc.'s USD
denominated debt.
(3) Excludes $222 million USD in MTM gain, after-tax, for the three months ended December 31, 2022 (2021 – $122 million
 
USD
MTM gain, after-tax) and MTM gain, after-tax of $130 million USD for the year ended December 31, 2022 (2021 – $164
 
million USD
MTM loss, after-tax) and the GBPC impairment charge of $54 million USD for the three months and year ended December
 
31, 2022
(2021 - nil).
The impact of the weakening CAD, partially offset by
the unrealized losses on FX hedges increased net
income by $42 million in Q4 2022 and $30 million for the year ended December 31, 2022, compared to
the same periods in 2021. Weakening of the CAD increased adjusted net income by $14 million in Q4
2022 and $28 million for the year ended December 31, 2022, compared to the same periods in 2021.
Impacts of the weakening CAD include the impacts of corporate FX hedges in the Other segment.
BUSINESS OVERVIEW AND OUTLOOK
Florida Electric Utility
Florida Electric Utility consists of Tampa Electric, a vertically integrated regulated electric utility engaged
in the generation, transmission and distribution of electricity, serving customers in West Central Florida.
Tampa
 
Electric has $12.1 billion USD of assets and approximately 827,000 customers at December 31,
2022. Tampa
 
Electric owns 6,549 megawatts (“MW”) of generating capacity, of which 78 per cent is
natural gas-fired, 15 per cent is solar and 7 per cent is coal. Tampa Electric owns 2,171 kilometres of
transmission facilities and 19,916 kilometres of distribution facilities. Tampa Electric meets the planning
criteria for reserve capacity established by the FPSC, which is a 20 per cent reserve margin over firm
peak demand.
Tampa
 
Electric’s approved regulated ROE range is 9.25 per cent to 11.25 per cent, based on an allowed
equity capital structure of 54 per cent. An ROE of 10.20 per cent will be used for the calculation of the
return on investments for clauses.
Tampa
 
Electric anticipates earning within its ROE range in 2023. New base rates effective January 1,
2023, as a result of the 2021 settlement agreement, will result in higher 2023 USD earnings than in 2022.
Normalizing 2022 for weather, Tampa
 
Electric sales volumes in 2023 are projected to be higher than in
2022 due to customer growth. Tampa Electric expects customer growth rates in 2023 to be comparable to
2022, reflective of the current expected economic growth in Florida.
12
On January 23, 2023, Tampa
 
Electric requested an adjustment to its fuel charges to recover the 2022 fuel
under-recovery of $518 million USD over a period of 21 months. The request also included an adjustment
to 2023 projected fuel costs to reflect the reduction in natural gas prices since September 2022 for a
projected reduction of $170 million USD for the balance of 2023. The proposed changes will be decided
by the FPSC in March 2023, and recovery is expected to begin in April 2023.
 
On September 28, 2022, Hurricane Ian made landfall in Southwest Florida as a Category 4 hurricane
and, as a result, approximately 291,000 customers lost power. The majority of Hurricane Ian restoration
costs were charged against Tampa Electric’s
 
FPSC approved storm reserve, resulting in minimal impact
to earnings for 2022. The total cost of restoration was $126 million USD, with approximately $119 million
USD charged to the storm reserve. Total restoration costs charged to the storm reserve have exceeded
the reserve balance and have been deferred as a regulatory asset for future recovery. On January 23,
2023, Tampa
 
Electric petitioned the FPSC for recovery of the storm reserve regulatory asset and the
replenishment of the balance in the reserve to the previous approved reserve level of $56 million USD, for
a total of approximately $131 million USD.
The proposed changes will be decided by the FPSC in March
2023, and recovery is expected to begin in April 2023 through March 2024.
The mid-course fuel adjustment requested by Tampa Electric on January 19, 2022, was approved on
March 1, 2022. The rate increase, effective with the first billing cycle in April 2022, covered higher fuel
and capacity costs of $169 million USD and was spread over customer bills from April 1, 2022 through
December 2022.
In 2023, capital investment in the Florida Electric Utility segment is expected to be $1.3 billion USD (2022
– $1.1 billion USD), including allowance for funds used during construction (“AFUDC”). Capital projects
include solar investments,
 
grid modernization and storm hardening investments.
 
Canadian Electric Utilities
Canadian Electric Utilities includes NSPI and ENL. NSPI is a vertically integrated regulated electric utility
engaged in the generation, transmission and distribution of electricity and the primary electricity supplier
to customers in Nova Scotia. ENL is a holding company with equity investments in NSPML and LIL: two
transmission investments related to the development of an 824 MW hydroelectric generating facility at
Muskrat Falls on the Lower Churchill River in Labrador.
 
NSPI
With $6.8 billion of assets and approximately 541,000 customers, NSPI owns 2,420 MW of generating
capacity, of which approximately 44 per cent is coal-fired; 28 per cent is natural gas and/or oil; 19 per
cent is hydro and wind; 7 per cent is petcoke and 2 per cent is biomass-fueled generation. In addition,
NSPI has contracts to purchase renewable energy from independent power producers (“IPPs”), which
own 546 MW of capacity. NSPI also has rights to 153 MW of Maritime Link capacity,
 
representing Nalcor
Energy’s (“Nalcor”) Nova Scotia Block (“NS Block”) delivery obligations,
 
as discussed below. NSPI owns
approximately 5,000 kilometres of transmission facilities and 28,000 kilometres of distribution facilities.
NSPI’s approved regulated ROE range is 8.75 per cent to 9.25 per cent, based on an actual five-quarter
average regulated common equity component of up to 40 per cent of approved rate base.
 
NSPI anticipates earning near the low end of its allowed ROE range in 2023, and below the allowed
range in 2024. NSPI expects earnings and sales volumes to be higher in 2023 than 2022.
 
NSPI operated under a three-year fuel stability plan which resulted in an average annual overall rate
increase of 1.5 per cent to recover fuel costs for the period of 2020 through 2022. These rates include
recovery of Maritime Link costs (discussed below in the “ENL, NSPML” section).
13
On November 9, 2022, the Nova Scotia provincial government enacted Bill 212, “Public Utilities Act
(amended)”. The legislation limits non-fuel rate increases in NSPI’s 2022 General Rate Application
(“GRA”) to the UARB, excluding increases relating to demand side management (“DSM”) costs, to a total
of 1.8 per cent between the effective date of the UARB’s decision and the end of 2024. The legislation
also:
●
 
requires revenue generated from the non-fuel rate increase to be used only to improve the
reliability of service to ratepayers,
●
 
limits NSPI’s return on equity to 9.25 per cent and equity ratio to 40 per cent, and
●
 
limits the rate used to accrue interest on regulatory deferrals to the Bank of Canada policy
interest rate plus 1.75 per cent, unless otherwise directed by the UARB.
Actions required to address the impact of Bill 212, “Public Utilities Act (amended)”, include a material
reduction in NSPI’s planned capital investments and operating costs over the 2023 through 2024 period.
Such deferral of capital investment and operating costs may result in higher customer costs in future
periods. The legislation will have a direct and negative impact on the financial performance of NSPI and
has had a negative impact on NSPI’s credit quality. For more information on this risk, refer to the “Risk
Management and Financial Instruments – Regulatory and Political Risk” section.
On November 24, 2022, NSPI filed with the UARB a comprehensive settlement agreement between
NSPI, key customer representatives and participating interest groups (“NSPI Settlement Agreement”) in
relation to its GRA filed in January 2022. The NSPI Settlement Agreement was structured to be
consistent with the amendments to the Public Utilities Act made under Bill 212, which included a 1.8 per
cent cap on non-fuel rate increases for 2023 and 2024. Bill 212, “Public Utilities Act (amended),” is
described further above. The NSPI Settlement Agreement also addresses the recovery of fuel costs over
the settlement period and establishes a DSM rider. This will result in a combined fuel and non-fuel rate
increase of 6.9 per cent each year for 2023 and 2024 and annualized incremental revenue (fuel and non-
fuel) of $105 million in 2023 and $115 million in 2024. In addition, any under or over recovery of fuel costs
will be addressed through the UARB’s established FAM process. NSPI’s ROE range will continue to be
8.75 per cent to 9.25 per cent, based on an actual five-quarter average regulated common equity
component of up to 40 per cent. The NSPI Settlement Agreement also establishes a storm rider for each
of 2023, 2024 and 2025, which gives NSPI the option to apply to the UARB for recovery of costs if major
storm restoration expense exceeds approximately $10 million in a given year. On February 2, 2023, NSPI
received the UARB’s decision, which substantially approved the NSPI Settlement Agreement as filed.
Approved rate increases will be effective as of the date of the decision.
On September 24, 2022, Nova Scotia was struck by Hurricane Fiona, which made landfall as a post-
tropical storm equivalent to a Category 2 hurricane. The storm had sustained winds of over 100
kilometres per hour and peak gusts of approximately 180 kilometres per hour. This historic storm for Nova
Scotia caused significant and widespread damage to NSPI’s transmission and distribution system and at
the height of the storm approximately 415,000 customers lost power. The total cost of the restoration was
approximately $115 million, of which $91 million was capitalized to Property,
 
plant and equipment
(“PP&E”) and $24 million deferred to Other long-term assets for future amortization, subject to UARB
approval. NSPI intends to submit an application to the UARB requesting to defer the recognition of
incremental operating costs related to storm restoration. If the deferral is approved, this balance will be
reclassified to “Regulatory assets” and amortized over the UARB approved recognition period.
 
14
Energy from renewable sources has increased with Nalcor’s NS Block delivery obligations from the
Muskrat Falls hydroelectric project (“Muskrat Falls”) commencing in 2021. Nalcor is obligated to provide
NSPI with approximately 900 GWh of energy annually over 35 years. In addition, for the first five years of
the NS Block, Nalcor is obligated to provide approximately 240 GWh of additional energy from the
Supplemental Energy Block transmitted through the Maritime Link. Nalcor’s final commissioning of the LIL
has experienced delays and it’s expected that final commissioning of the LIL will be completed in 2023.
During these final stages of commissioning, there will be interruptions in supply, with any resultant
delivery shortfalls being delivered on a timely basis in accordance with the Energy and Capacity
Agreement. NSPI has the option of purchasing additional market-priced energy from Nalcor through the
Energy Access Agreement. The Energy Access Agreement enables NSPI to access a market-priced bid
from Nalcor for up to 1.8 Terawatt hours (“TWh”) of energy in any given year and, on average, 1.2 TWh of
energy per year through August 31, 2041.
Capital investment for 2023, including AFUDC, is expected to be approximately $375 million (2022 –
$540 million). NSPI is primarily investing in capital projects required to support power system reliability
and reliable service for customers.
 
Environmental Legislation and Regulations
NSPI is subject to environmental laws and regulations set by both the Government of Canada and the
Province of Nova Scotia. NSPI continues to work with both levels of government to comply with these
laws and regulations to maximize efficiency of emission control measures and minimize customer cost.
NSPI anticipates that costs prudently incurred to achieve legislated compliance will be recoverable under
NSPI’s regulatory framework. NSPI faces risks associated with achieving climate-related and
environmental legislative requirements, including the risk of non-compliance, which could adversely affect
NSPI’s operations and financial performance. For further discussion on these risks and environmental
legislation and regulations, refer to the “Enterprise Risk and Risk Management” section. Recent
developments related to provincial and federal environmental laws and regulations are outlined below.
Nova Scotia Cap-and-Trade Program Regulations:
NSPI is a participant in the Nova Scotia Cap-and-Trade Program (“Cap-and-Trade Program”) and is
subject to the 2019 through 2022 compliance period. NSPI received granted emissions allowances under
the Cap-and-Trade Program and is permitted to purchase up to five per cent of the credits available at
provincial auctions. Any remaining allowance shortfall requires the purchase of reserve credits directly
from the provincial government, which are anticipated to be priced at a premium to provincial auction
pricing. Compliance is forecast to be achieved through granted emissions allowances and credit
purchases under the Cap-and-Trade Program, including reserve credits. Lower than forecast Muskrat
Falls energy received during the compliance period has resulted in the increased deployment of higher
carbon-emitting generation sources. The Province of Nova Scotia has agreed to provide approximately
$165 million of relief from the 2019 through 2022 compliance costs, which was equal to the total cost of
compliance forecast at the time of the fuel update submitted by NSPI to the UARB in September 2022 as
part of the GRA. Discussions related to the final amount of relief and how this relief will be provided are
ongoing. Further, NSPI’s regulatory framework provides for the recovery of costs prudently incurred to
comply with the Cap-and-Trade Program Regulations pursuant to NSPI’s FAM.
15
Carbon Pricing Regulations:
On November 9, 2022, the Nova Scotia provincial government enacted Bill 208, “Environment Act
(amended)”. The legislation provides the framework for Nova Scotia’s system to comply with the federal
government’s 2023 through 2030 carbon pollution pricing regulations laid out in the Pan-Canadian
Framework on Clean Growth and Climate Change. Nova Scotia’s proposed system utilizes an output-
based pricing system that will implement performance standards for large industrial greenhouse gas
emitters to achieve emission reduction goals. Subsequent regulations will be required to detail how the
pricing system will operate. The Province of Nova Scotia’s proposed output-based pricing system is
subject to the approval of the federal government. If an agreement is not reached between the federal
and provincial governments on a Nova Scotia system that meets the federal compliance criteria, Nova
Scotia will be subject to the federal carbon pollution pricing backstop which uses emissions performances
standards that vary by fuel type, and a carbon price that will start at $65 per tonne in 2023 and increase
by $15 per tonne annually, reaching $170 per tonne by 2030. NSPI’s regulatory framework provides for
the recovery of costs prudently incurred to comply with carbon pricing programs pursuant to NSPI’s FAM.
Nova Scotia Renewable Energy Regulations:
Under the provincially legislated Renewable Energy Regulations, 40 per cent of electric sales must be
generated from renewable sources. This standard was predicated on receipt of the full NS Block. Due to
the delay of the NS Block, the provincial government provided NSPI with an alternative compliance plan
that requires NSPI to achieve 40 per cent of electric sales generated from renewable sources over the
2020 through 2022 period. With delivery of the NS Block commencing later than anticipated, as well as
further interruptions in supply due to delays in the LIL, NSPI did not achieve the requirements of the
alternative compliance plan. The Renewable Energy Regulations require NSPI to have acted in a duly
diligent manner. If NSPI is found not to have acted in a duly diligent manner, it could be subject to a
maximum penalty of $10 million.
ENL
Total
 
equity earnings from NSPML and LIL are expected to be higher in 2023, compared to 2022. Both
the NSPML and LIL investments are recorded as “Investments subject to significant influence” on
Emera’s Consolidated Balance Sheets.
NSPML
Equity earnings from the Maritime Link are dependent on the approved ROE and operational
performance of NSPML. NSPML’s approved regulated ROE range is 8.75 per cent to 9.25 per cent,
based on an actual five-quarter average regulated common equity component of up to 30 per cent.
 
The Maritime Link assets entered service on January 15, 2018, enabling the transmission of energy
between Newfoundland and Nova Scotia, improved reliability and ancillary benefits, supporting the
efficiency and reliability of energy in both provinces. Nalcor continues to advance towards completion of
the LIL, and it’s expected final commissioning will be achieved in 2023. Nalcor’s NS Block delivery
obligations commenced on August 15, 2021, and the NS Block will be delivered over the next 35 years
pursuant to the project agreements. As Nalcor is in the final stages of commissioning the LIL, there will be
commissioning related interruptions in supply with any resultant delivery shortfalls being delivered on a
timely basis in accordance with the Energy and Capacity Agreement.
In February 2022, the UARB issued its decision and Board Order approving NSPML’s requested rate
base of approximately $1.8 billion less $9 million of costs ($7 million after-tax) that would not have
otherwise been recoverable if incurred by NSPI. NSPML also received approval to collect up to $168
million (2021 – $172 million) from NSPI for the recovery of costs associated with the Maritime Link in
2022. This was subject to a holdback of up to $2 million per month, beginning April 2022, contingent on
receiving at least 90 per cent of NS Block deliveries, including Supplemental Energy deliveries.
 
16
In December 2022, NSPML received UARB approval to collect up to $164 million from NSPI for the
recovery of costs associated with the Maritime Link in 2023. This continues to be subject to a holdback of
up to $2 million a month, as discussed above. On December 22, 2022, the UARB clarified its earlier
direction regarding the holdback and NSPI can now release the holdback to NSPML when 90 per cent of
NS Block deliveries, including Supplemental
 
Energy deliveries, is achieved. This enabled NSPI to pay
NSPML approximately $4 million of the 2022 holdback. As of December 31, 2022, an additional $14
million in aggregate has been held back by NSPI. Determination of allocation of the $14 million between
NSPML and NSPI will be subject to a regulatory process that is expected to commence in early 2023 to
review the holdback mechanism.
 
NSPML does not anticipate any significant capital investment in 2023.
LIL
ENL is a limited partner with Nalcor in LIL. Construction of the LIL is complete and Nalcor is forecasting it
will achieve final commissioning in 2023.
Equity earnings from the LIL investment are based upon the book value of the equity investment and the
approved ROE. Emera’s current equity investment is $740 million, comprised of $410 million in equity
contribution and $330 million of accumulated equity earnings. Emera’s total equity contribution in the LIL,
excluding accumulated equity earnings, is estimated to be approximately $650 million after the Lower
Churchill projects are completed.
Cash earnings and return of equity will begin after commissioning of the LIL by Nalcor, which is
anticipated in 2023, and until that point Emera will continue to record AFUDC earnings.
Gas Utilities and Infrastructure
Gas Utilities and Infrastructure includes PGS, NMGC, SeaCoast, Brunswick Pipeline and Emera’s non-
consolidated investment in M&NP.
 
PGS is a regulated gas distribution utility engaged in the purchase,
distribution and sale of natural gas serving customers in Florida. NMGC is an intrastate regulated gas
distribution utility engaged in the purchase, transmission, distribution and sale of natural gas serving
customers in New Mexico. SeaCoast is a regulated intrastate natural gas transmission company offering
services in Florida. Brunswick Pipeline is a regulated 145-kilometre pipeline delivering re-gasified
liquefied natural gas from Saint John, New Brunswick, to markets in the northeastern United States.
Peoples Gas System
With $2.5 billion USD of assets and approximately 468,000 customers, the PGS system includes 24,300
kilometres of natural gas mains and 13,500 kilometres of service lines. Natural gas throughput (the
amount of gas delivered to its customers, including transportation-only service) was 2 billion therms in
2022.
 
The approved ROE range for PGS is 8.9 per cent to 11.0 per cent, based on an allowed equity capital
structure of 54.7 per cent. An ROE of 9.9 per cent is used for the calculation of return on investments for
clauses.
New Mexico Gas Company, Inc.
With $2.0 billion USD of assets and approximately 545,000 customers, NMGC’s system includes
approximately 2,426 kilometres of transmission pipelines and 17,781 kilometres of distribution pipelines.
Annual natural gas throughput was approximately 926 million therms in 2022.
The approved ROE for NMGC is 9.375 per cent, on an allowed equity capital structure of 52 per cent.
 
17
Gas Utilities and Infrastructure Outlook
Gas Utilities and Infrastructure USD earnings are anticipated to be higher in 2023 than 2022, primarily
due to a base rate increase at NMGC, effective January 2023.
 
PGS expects 2023 rate base growth and USD earnings to be consistent with 2022 as higher revenues
from customer growth offset increased interest expenses and the effect of inflation. Increased residential
and commercial sales volumes and customer growth are anticipated in 2023. PGS anticipates earning
below its allowed ROE range in 2023 primarily due to rate base growth.
 
As a result, on February 3, 2023,
PGS notified the FPSC that it is planning to file a base rate proceeding in April 2023 for new rates
effective January 2024.
 
The PGS rate case settlement, which was approved in November 2020, provides the ability to reverse a
total of $34 million USD of accumulated depreciation through 2023. Through December 31, 2022, PGS
reversed $14 million USD accumulated depreciation. The reversal of the remaining accumulated
depreciation is expected to occur over 2023.
NMGC expects 2023 rate base and USD earnings to be higher in 2023 than 2022 due to base rate
increases effective January 2023, as discussed below, and rate base growth to expand the distribution
system and to continue to reliably serve customers. NMGC anticipates earning near its authorized ROE
in 2023 and expects customer growth rates to be consistent with historical trends. NMGC’s asset
optimization revenues for 2022 were well above the historical average, and may not recur in 2023.
On December 13, 2021, NMGC filed a rate case with the NMPRC for new rates to become effective
January 2023. On May 20, 2022, NMGC filed an unopposed settlement agreement with the NMPRC for
an increase of $19 million USD in annual base revenues. The rates reflect the recovery of increased
operating costs and capital investments in pipelines and related infrastructure. The NMPRC approved the
settlement agreement on November 30, 2022.
In 2018, SeaCoast executed a 34-year agreement to provide long-term firm gas transportation service via
a 21-mile, 30-inch pipeline lateral. The lease of the pipeline lateral commenced January 1, 2022.
In 2023, capital investment in the Gas Utilities and Infrastructure segment is expected to be
approximately $475 million USD (2022 – $436 million USD), including AFUDC. PGS will make
investments to expand its system and support customer growth. NMGC will continue to make investments
to maintain the reliability of its system and support customer growth.
 
Other Electric Utilities
Other Electric Utilities includes Emera (Caribbean) Incorporated (“ECI”), a holding company with
regulated electric utilities. ECI’s regulated utilities include vertically integrated regulated electric utilities of
BLPC on the island of Barbados, GBPC on Grand Bahama Island, and a 19.5 per cent interest in Lucelec
on the island of St. Lucia, which is accounted for on the equity basis.
On March 31, 2022, Emera completed the sale of its 51.9 per cent interest in Dominica Electricity
Services Ltd. (“Domlec”) for proceeds which approximated carrying value. Domlec was included in the
Other Electric Utilities segment in Q1 2022. The sale did not have a material impact on earnings.
BLPC
With $505 million USD of assets and approximately 133,000 customers, BLPC owns 276 MW of
generating capacity, of which 96 per cent is oil-fired and four per cent is solar.
 
BLPC owns approximately
188 kilometres of transmission facilities and 3,789 kilometres of distribution facilities. BLPC’s approved
regulated return on rate base for 2022 was 10 per cent.
18
GBPC
With $338 million USD of assets and approximately 19,000 customers, GBPC owns 98 MW of oil-fired
generation, approximately 90 kilometres of transmission facilities and 670 kilometres of distribution
facilities. GBPC’s approved regulatory return on rate base for 2023 is 8.32 per cent (2022 – 8.23 per
cent).
 
Other Electric Utilities Outlook
Absent the impact of the GBPC impairment charge in Q4 2022, Other Electric Utilities’ USD earnings in
2023 are expected to increase over the prior year primarily as a result of higher earnings due to higher
base rates at BLPC.
BLPC currently operates pursuant to a franchise to generate, transmit and distribute electricity on the
island of Barbados until 2028. In 2019, the Government of Barbados passed legislation amending the
number of licenses required for the supply of electricity from a single integrated license which currently
exists, to multiple licenses for Generation, Transmission and Distribution, Storage, Dispatch and Sales. In
March 2021, BLPC reached commercial agreement with the Government of Barbados for each of the
license types, subject to the passage of implementing legislation. The new licenses are expected to take
effect in 2023 on completion of the legislative process. The Dispatch license will have a term of five years
with the remaining licenses having terms ranging from 25-30 years. BLPC anticipates that any increased
costs associated with the implementation of the new multi-licensed structure will be recoverable through
BLPC’s regulatory framework. BLPC is awaiting final enactment and will work towards implementation of
the licenses once received.
On October 4, 2021 BLPC submitted a general rate review application to the FTC. The application seeks
a rate adjustment and the implementation of a cost reflective rate structure that will facilitate the changes
expected in the newly reformed electricity market and the country’s transition toward 100 per cent
renewable energy generation. The application seeks recovery of capital investment in plant, equipment
and related infrastructure and results in an increase in annual non-fuel revenue of approximately $23
million USD upon approval. The application includes a request for an allowed regulatory ROE of 12.50
per cent on an allowed equity capital structure of 65 per cent. On September 16,
2022, the FTC granted
BLPC interim rate relief, allowing an increase in base rates of approximately $3 million USD for the
remainder of 2022 and approximately $1 million USD per month for 2023. Interim rate relief is effective
from September 16, 2022 until the implementation of final rates. The hearing concluded in October 2022.
On February 15, 2023, the FTC issued a decision on the BLPC rate review application which included the
following significant items: an allowed regulatory ROE of 11.75 per cent, an equity capital structure of 55
per cent, a directive to update the major components of rate base to September 16, 2022, and a directive
to establish regulatory liabilities of approximately $70 million USD related to the self-insurance fund,
accumulated depreciation, and taxes. The impacts to BLPC's rate base and final rates are not yet
determinable but management does not expect the decision to have a material impact on Emera’s
adjusted net income. BLPC will seek to clarify aspects of the FTC decision in its compliance filing and is
also considering filing a submission to the FTC for a review of the decision. BLPC expects a decision on
final rates from the FTC in 2023.
On January 14, 2022, the GBPA issued its decision on GBPC’s rate application. The decision, which
became effective April 1, 2022, allows for an increase in revenues of $3.5 million USD. The new rates
include a regulatory ROE of 12.84 per cent.
Effective November 1, 2022, GBPC’s fuel pass through charge was increased due to an increase in
global oil prices impacting the unhedged fuel cost. In 2023, the fuel pass through charge will be adjusted
monthly, in-line with actual fuel costs.
19
In 2023, capital investment in the Other Electric Utilities segment is expected to be approximately $65
million USD (2022 – $48 million USD), primarily in more efficient and cleaner sources of generation,
including renewables and battery storage.
 
Other
The Other segment includes those business operations that in a normal year are below the required
threshold for reporting as separate segments; and corporate expense and revenue items that are not
directly allocated to the operations of Emera’s subsidiaries and investments.
Business operations in the Other segment include Emera Energy and Emera Technologies LLC (“ETL”).
Emera Energy consists of EES, a wholly owned physical energy marketing and trading business and an
equity investment in a 50 per cent joint venture ownership of Bear Swamp, a 660 MW pumped storage
hydroelectric facility in northwestern Massachusetts. ETL is a wholly owned technology company focused
on finding ways to deliver renewable and resilient energy to customers.
Corporate items included in the Other segment are certain corporate-wide functions including executive
management, strategic planning, treasury services, legal, financial reporting, tax planning, corporate
business development, corporate governance, investor relations, risk management, insurance, acquisition
and disposition related costs, gains or losses on select assets sales, and corporate human resource
activities. It includes interest revenue on intercompany financings and interest expense on corporate debt
in both Canada and the United States. It also includes costs associated with corporate activities that are
not directly allocated to the operations of Emera’s subsidiaries and investments.
Earnings from EES are generally dependent on market conditions. In particular, volatility in natural gas
and electricity markets, which can be influenced by weather, local supply constraints and other supply
and demand factors, can provide higher levels of margin opportunity. The business is seasonal, with Q1
and Q4 usually providing the greatest opportunity for earnings. EES is generally expected to deliver
annual adjusted net income within its guidance range of $15 to $30 million USD ($45 to $70 million USD
of margin).
Absent the TGH award in Q4 2022, the adjusted net loss from the Other segment is expected to be
higher in 2023, based on EES returning to its normal earnings range in 2023 and increased interest
expense. The increase is expected to be partially offset by decreased taxes due to a higher net loss.
 
The Other segment does not anticipate any significant capital investment in 2023.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
20
CONSOLIDATED
 
BALANCE SHEET HIGHLIGHTS
Significant changes in the Consolidated Balance Sheets between December 31, 2021 and December 31,
2022 include:
millions of dollars
Increase
(Decrease)
Explanation
 
Assets
Cash and cash equivalents
$
 
(84)
Decreased due to increased investment in PP&E at regulated
utilities and dividends on common stock. These were partially
offset by proceeds from short-term debt issuance at Emera and
Tampa Electric, increased proceeds under committed credit
facilities at NSPI and Emera, cash from operations, and issuance
of common stock
Inventory
 
231
Increased due to higher commodity prices at Emera Energy and
NSPI, increased materials inventory at Tampa Electric and the
effect of the FX translation of Emera's foreign affiliates
Derivative instruments (current and
long-term)
 
95
Increased due to reversal of 2021 contracts at Emera Energy
Regulatory assets (current and long-
term)
 
1,054
Increased due to higher fuel cost recovery clauses at Tampa
Electric, increased FAM deferrals, driven mainly by increased
Cap-and Trade emissions compliance charges, and increased
deferred income tax regulatory assets at NSPI, the effect of the
FX translation of Emera's foreign affiliates, recognition of storm
reserve asset at Tampa Electric due to restoration costs from
Hurricane Ian in excess of the storm reserve liability, and
increased pension and post-retirement plan deferrals at Tampa
and NSPI. These were partially offset by recovery of gas costs
from the NMGC 2021 winter event
Receivables and other assets
(current and long-term)
 
1,165
Increased due to higher gas transportation assets and higher
trade receivables due to higher commodity prices at Emera
Energy, fuel option receivable at NMGC and the effect of the FX
translation of Emera's foreign affiliates
PP&E, net of accumulated
depreciation and amortization
 
2,643
Increased due to the effect of the FX translation of Emera's
foreign affiliates, and capital additions. These were partially offset
by reclassification of Seacoast's pipeline lateral on
commencement of the lease in 2022
Net investment in direct finance and
sales type leases
 
101
Increased due to commencement of the pipeline lease at
Seacoast in 2022
Goodwill
 
316
Increased due to the effect of the FX translation of Emera's
foreign affiliates, partially offset by the GBPC impairment
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
21
millions of dollars
Increase
(Decrease)
Explanation
 
Liabilities and Equity
Short-term debt and long-term debt
(including current portion)
$
 
2,644
Increased due to the effect of the FX translation of Emera's
foreign affiliates, issuance of short-term debt at Emera and
Tampa Electric, and net borrowings under the committed credit
facility at NSPI and Emera
 
Accounts payable
 
540
Increased due to increased commodity prices at Emera Energy,
Tampa Electric and NMGC, the effect
 
of the FX translation of
Emera's foreign affiliates, higher cash collateral position on
derivative instruments at NSPI, and timing of payments at Tampa
Electric and NSPI
Deferred income tax liabilities, net of
deferred income tax assets
 
 
386
Increased due to tax deductions in excess of accounting
depreciation related to PP&E, increase in net regulatory assets,
decrease in net derivative liabilities, and the effect of the FX
translation of Emera's foreign affiliates, partially offset by net
increase in tax loss carryforwards
Derivative instruments (current and
long-term)
 
396
Increased due to new contracts in 2022, partially offset by
reversal of 2021 contracts and changes in existing positions at
Emera Energy
Regulatory liabilities (current and
long-term)
 
218
Increased due to NMGC gas hedge settlements and the effect of
the FX translation of Emera's foreign affiliates, partially offset by
decreased storm reserve at Tampa Electric due to restoration
costs incurred from Hurricane Ian
Pension and post-retirement liabilities
 
 
(89)
Decreased due to favourable changes in actuarial assumptions,
partially offset by lower investment returns
Other liabilities (current and long-
term)
 
170
Increased due to accrued emissions compliance charges at NSPI
and the effect of the FX translation of Emera's foreign affiliates
Common stock
 
520
Increased due to Emera's ATM equity program and shares issued
under the DRIP
Accumulated other comprehensive
income
 
553
Increased due to the effect of the FX translation of Emera's
foreign affiliates
Retained earnings
 
236
Increased due to net income in excess of dividends paid.
OTHER DEVELOPMENTS
USGAAP Reporting Extension
Emera was granted exemptive relief by Canadian securities regulators on September 13, 2022, and
under the Companies Act (Nova Scotia) on October 12, 2022, each allowing Emera to continue to report
its financial results in accordance with USGAAP (collectively the “Exemptive Relief”). The Exemptive
Relief will terminate on the earliest of: (i) January 1, 2027; (ii) if the Company ceases to have rate-
regulated activities, the first day of the Company’s financial year that commences after the Company
ceases to have rate-regulated activities; and (iii) the first day of the Company’s financial year that
commences on or following the later of: (a) the effective date prescribed by the International Accounting
Standards Board (“IASB”) for the mandatory application of a standard within IFRS specific to entities with
rate-regulated activities (“Mandatory Rate-regulated Standard”); and (b) two years after the IASB
publishes the final version of a Mandatory Rate-regulated Standard. The Exemptive Relief replaces
similar relief that had been granted to Emera in 2018 and would have expired by no later than January 1,
2024.
Increase in Common Dividends
On September 22, 2022, the Emera Board of Directors approved an increase in the annual common
share dividend rate to $2.76 from $2.65. The first payment was effective November 15, 2022. Emera also
extended its dividend growth rate target of four to five per cent through 2025.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
22
Appointments
Effective July 1, 2022, Michael Barrett was appointed Executive Vice President and General Counsel for
Emera. Mr. Barrett was most recently the General Counsel for Emera.
Effective June 30, 2022, Bruce Marchand was appointed Chief Risk and Sustainability Officer for Emera.
Mr. Marchand was most recently the Chief Legal and Compliance Officer for Emera.
FINANCIAL HIGHLIGHTS
Florida Electric Utility
All amounts are reported in USD, unless otherwise stated.
Three months ended
Year ended
For the
December 31
December 31
millions of USD (except as indicated)
2022
2021
2022
2021
Operating revenues – regulated electric
$
 
597
$
 
561
$
 
2,523
$
 
2,174
Regulated fuel for generation and purchased power
$
 
201
$
 
212
$
 
832
$
 
713
Contribution to consolidated net income
 
$
 
91
$
 
67
$
 
458
$
 
369
Contribution to consolidated net income – CAD
$
 
124
$
 
85
$
 
596
$
 
462
Average fuel costs in dollars per MWh
$
 
41
$
 
44
$
 
39
$
 
34
The impact of the change in the FX rate increased CAD earnings for the three months and year ended
December 31, 2022, by $10 million and $23 million, respectively.
Net Income
Highlights of the net income changes are summarized in the following table:
For the
Three months ended
Year ended
millions of USD
December 31
December 31
Contribution to consolidated net income – 2021
$
67
$
 
369
Increased operating revenues due to higher rates effective January
2022, higher fuel recovery clause revenue as a result of increased fuel
costs, and customer growth. Year-over-year also increased due to
favourable weather
 
36
 
349
Fuel for generation and purchased power decreased in Q4 due to
lower natural gas prices quarter-over-quarter. Year
 
-over-year, fuel
increased due to higher natural gas prices
 
11
 
(119)
Increased OM&G due to timing of deferred clause recoveries. Year-
over-year the increase is also due to higher transmission and
distribution costs, higher benefit costs and higher insurance costs
 
(6)
 
(52)
Increased depreciation and amortization due to additions to facilities
and the in-service of generation projects
 
(5)
 
(15)
Increased interest expense due to higher interest rates and higher
borrowings to support Tampa Electric’s ongoing operations, including
fuel under-recoveries, and capital investments
 
(16)
 
(32)
Decreased AFUDC earnings due to timing of Big Bend modernization
and solar projects
 
(4)
 
(10)
Increased income tax expense year-over-year primarily due to
increased income before provision for income taxes
 
-
 
 
(36)
Other
 
8
 
4
Contribution to consolidated net income – 2022
$
 
91
$
 
458
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
23
Operating Revenues – Regulated Electric
Annual electric revenues and sales volumes are summarized in the following table by customer class:
Electric Revenues
Electric Sales Volumes
 
(millions of USD)
(Gigawatt hours ("GWh"))
 
2022
2021
2022
2021
Residential
$
 
1,381
$
 
1,156
 
10,109
 
9,941
Commercial
 
666
 
602
 
6,300
 
6,144
Industrial
 
176
 
172
 
2,111
 
2,122
Other
(1)
 
300
 
244
 
2,352
 
2,000
Total
$
 
2,523
$
 
2,174
 
20,872
 
20,207
(1) Other includes sales to public authorities, off-system sales to other utilities and regulatory deferrals related
 
to clauses.
Regulated Fuel for Generation and Purchased Power
Annual production volumes are summarized in the following table:
Production Volumes (GWh)
2022
2021
Natural gas
 
 
17,083
 
16,142
Purchased power
 
 
1,685
 
2,301
Solar
 
1,492
 
1,252
Coal
 
 
1,325
 
1,342
Total
 
 
21,585
 
21,037
Tampa
 
Electric’s fuel costs are affected by commodity prices and generation mix that is largely
dependent on economic dispatch of the generating fleet, bringing the lowest cost options on first
(renewable energy from solar), such that the incremental cost of production increases as sales volumes
increase. Generation mix may also be affected by plant outages, plant performance, availability of lower
priced short-term purchased power, availability of renewable solar generation, and compliance with
environmental standards and regulations.
Regulatory Environment
Tampa
 
Electric is regulated by the FPSC and is also subject to regulation by the FERC. The FPSC sets
rates at a level that allows utilities such as Tampa Electric to collect total revenues or revenue
requirements equal to their cost of providing service, plus an appropriate return on invested capital. Base
rates are determined in FPSC rate setting hearings which can occur at the initiative of Tampa Electric, the
FPSC or other interested parties. For further details on Tampa Electric’s
 
regulatory environment, base
rates and recovery mechanisms, refer to note 7 in the consolidated financial statements.
Canadian Electric Utilities
Three months ended
Year ended
For the
December 31
December 31
millions of dollars (except as indicated)
2022
2021
2022
2021
Operating revenues – regulated electric
$
 
421
$
 
389
$
 
1,675
$
 
1,501
Regulated fuel for generation and purchased power
(1)
$
 
173
$
 
263
$
 
950
$
 
817
Contribution to consolidated adjusted net income
$
 
46
$
 
67
$
 
222
$
 
241
NSPML unrecoverable costs
$
 
-
 
$
 
-
 
$
 
(7)
$
 
-
 
Contribution to consolidated net income
$
 
46
$
 
67
$
 
215
$
 
241
Average fuel costs in dollars per MWh
$
 
61
$
 
93
$
 
85
$
 
75
(1) Regulated fuel for generation and purchased power includes NSPI's FAM
 
and fixed cost deferrals on the Consolidated
Statements of Income, however it is excluded in the segment overview.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
24
Canadian Electric Utilities' contribution to consolidated adjusted net income is summarized in the following
table:
Three months ended
 
Year ended
For the
December 31
December 31
millions of dollars
2022
2021
2022
2021
NSPI
$
 
23
$
 
43
$
 
131
$
 
141
Equity investment in LIL
 
15
 
14
 
55
 
51
Equity investment in NSPML
(1)
 
8
 
10
 
36
 
49
Contribution to consolidated adjusted net income
 
$
 
46
$
 
67
$
 
222
$
 
241
(1) Excludes $7 million in NSPML unrecoverable costs, after-tax, for the year ended December 31, 2022 (2021 – nil).
Net Income
Highlights of the net income changes are summarized in the following table:
For the
Three months ended
Year ended
millions of dollars
December 31
December 31
Contribution to consolidated net income – 2021
$
 
67
$
 
241
Increased operating revenues due to increased electric revenues related
to recovery of fuel costs from an industrial customer, increased
residential and commercial class sales volumes, and increased
electricity pricing effective January 1, 2022. Quarter-over-quarter
increase partially offset by unfavourable weather
 
32
 
174
Decreased regulated fuel for generation and purchased power quarter-
over-quarter due to lower Cap-and-Trade Program provision and lower
Maritime Link assessment costs. Increased regulated fuel for generation
and purchased power year-over year due to increased Nova Scotia
Cap-and-Trade program provision, increased commodity prices and
higher sales volume, partially offset by a favourable change in
generation mix
 
90
 
(133)
Decreased FAM and fixed cost deferrals year-over-year due to
increased recovery of fuel costs, partially offset by increased Cap-and-
Trade provision. Quarter-over-quarter decreased due to increased
recovery of fuel costs and decreased Cap-and-Trade provision
 
(120)
 
(16)
Increased OM&G due to higher costs for storm restoration, IT, power
generation, and regulatory affairs
 
(20)
 
(47)
Increased depreciation and amortization due to increased PP&E in-
service
 
(5)
 
(13)
Decreased income tax expense primarily due to increased tax
deductions in excess of accounting depreciation and amortization
related to PP&E and deferrals and decreased income before provision
for income taxes. This was partially offset by the benefit of tax loss
carryforwards recognized as a deferred income tax regulatory liability
 
7
 
18
Year-over-year decrease in net income from equity investment in
NSPML primarily due to the Maritime Link holdback
 
(2)
 
(13)
NSPML unrecoverable costs
 
-
 
 
(7)
Other
 
(3)
 
11
Contribution to consolidated net income – 2022
$
 
46
$
 
215
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
25
NSPI
Operating Revenues – Regulated Electric
Annual electric revenues and sales volumes are summarized in the following tables by customer class:
Electric Revenues
Electric Sales Volumes
(millions of dollars)
(GWh)
 
2022
2021
2022
2021
Residential
$
 
834
$
 
797
 
4,822
 
4,661
Commercial
 
427
 
407
 
3,006
 
2,902
Industrial
 
353
 
237
 
2,480
 
2,480
Other
 
28
 
27
 
148
 
153
Total
$
 
1,642
$
 
1,468
 
10,456
 
10,196
Regulated Fuel for Generation and Purchased Power
Annual production volumes are summarized in the following table:
Production Volumes (GWh)
 
2022
2021
Coal
 
 
3,771
 
4,623
Natural gas
 
1,650
 
1,673
Purchased power – other
 
910
 
865
Petcoke
 
897
 
519
Oil
 
251
 
81
Total non-renewables
 
7,479
 
7,761
Purchased power
 
2,423
 
1,977
Wind and hydro
 
 
1,105
 
1,007
Biomass
 
 
127
 
160
Total renewables
 
3,655
 
3,144
Total production volumes
 
11,134
 
10,905
NSPI’s fuel costs are affected by commodity prices and generation mix, which is largely dependent on
economic dispatch of the generating fleet. NSPI brings the lowest cost options on stream first after
renewable energy from IPPs, including Community Feed-in Tariff (“COMFIT”) participants, for which NSPI
has power purchase agreements in place, and the NS Block of energy, including the Supplemental
Energy Block. NSPI pays annual assessments approved by the UARB to NSPML for use of the Maritime
Link, and therefore utilizes all transmitted NS Block and Supplemental Energy Block energy received
which carries no additional fuel cost.
NSPI-owned hydro and wind have no fuel cost component. After hydro and wind, historically, petcoke and
coal have the lowest per-unit fuel cost, followed by natural gas. Oil, biomass and purchased power have
the next lowest fuel cost, depending on the relative pricing of each. Generation mix may also be affected
by plant outages, availability of renewable generation, availability of energy from the NS Block, plant
performance, and compliance with environmental standards including the Cap-and-Trade Program.
 
The generation mix has undergone significant transformation with the addition of non-dispatchable
renewable energy sources such as wind, including from IPPs and COMFIT, which typically have a higher
cost per MWh than NSPI-owned generation or other purchased power sources.
The provision for the Cap-and-Trade program was an $18 million recovery for the three months ended
December 31, 2022 (2021 - $35 million expense) and a $134 million expense for the year ended
December 31, 2022 (2021 - $38 million expense). For further information on this non-cash accrual, the
estimated costs and the FAM regulatory balance, refer to note 7 in the consolidated financial statements.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
26
Regulatory Environment - NSPI
NSPI is a public utility as defined in the Public Utilities Act and is subject to regulation under the Public
Utilities Act by the UARB. The Public Utilities Act gives the UARB supervisory powers over NSPI’s
operations and expenditures. Electricity rates for NSPI’s customers are subject to UARB approval. NSPI
is not subject to a general annual rate review process, but rather participates in hearings held from time to
time at NSPI’s or the UARB’s request. For further details on NSPI’s regulatory environment and recovery
mechanisms, refer to note 7 in the consolidated financial statements.
Gas Utilities and Infrastructure
All amounts are reported in USD, unless otherwise stated.
Three months ended
Year ended
For the
December 31
December 31
millions of USD (except as indicated)
2022
2021
2022
2021
Operating revenues – regulated gas
(1)
$
 
372
$
 
307
$
 
1,296
$
 
1,006
Operating revenues – non-regulated
 
2
 
2
 
12
 
12
Total operating revenue
$
 
374
$
 
309
$
 
1,308
$
 
1,018
Regulated cost of natural gas
$
 
181
$
 
139
$
 
614
$
 
375
Contribution to consolidated net income
 
$
 
53
$
 
44
$
 
170
$
 
157
Contribution to consolidated net income – CAD
$
 
72
$
 
55
$
 
221
$
 
198
 
(1) Operating revenues – regulated gas includes $13 million of finance income from Brunswick Pipeline (2021 – $12 million)
 
for the
three months ended December 31, 2022 and $47 million (2021 – $46 million) for the year ended December 31 2022;
 
however, it is
excluded from the gas revenues and cost of natural gas analysis below.
Gas Utilities and Infrastructure's contribution to consolidated net income is summarized in the following
table:
Three months ended
 
Year ended
For the
December 31
December 31
millions of USD
2022
2021
2022
2021
PGS
$
 
17
$
 
17
$
 
82
$
 
77
NMGC
 
22
 
15
 
35
 
33
Other
 
14
 
12
 
53
 
47
Contribution to consolidated net income
 
$
 
53
$
 
44
$
 
170
$
 
157
The impact of the change in the FX rate increased CAD earnings for the three months and year ended
December 31, 2022, by $4 million and $6 million, respectively.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
27
Net Income
Highlights of the net income changes are summarized in the following table:
For the
Three months ended
Year ended
millions of USD
December 31
December 31
Contribution to consolidated net income – 2021
$
 
44
$
 
157
Increased gas revenues due to higher purchased gas adjustment
clause revenues at NMGC and PGS as a result of higher gas prices,
higher off-system sales, and customer growth at PGS
 
55
 
280
Increased asset optimization revenues at NMGC. In 2022, NMGC’s 30
per cent share of asset optimization revenues were well above the
historical average, and may not reoccur in 2023
 
10
 
10
Increased cost of natural gas sold due to higher gas prices at NMGC
and PGS, and higher off-system sales at PGS
 
(42)
 
(239)
Increased OM&G primarily due to higher labour and benefits costs at
NMGC and PGS, and higher contractor costs at PGS
 
(3)
 
(22)
Increased depreciation and amortization due to asset growth at PGS
and NMGC. Year-over-year,
 
the increase was more than offset by the
reversal of accumulated depreciation as a result of the rate case
settlement at PGS
 
 
(2)
 
6
Increased interest expense due to higher interest rates
 
(4)
 
(10)
Increased income tax expense primarily due to increased income
before provision for income taxes
 
(2)
 
(7)
Other
 
(3)
 
(5)
Contribution to consolidated net income – 2022
$
 
53
$
 
170
Operating Revenues – Regulated Gas
Annual gas revenues and sales volumes are summarized in the following tables by customer class:
 
Gas Revenues
Gas Volumes
(millions of USD)
(Therms)
 
2022
2021
2022
2021
Residential
$
 
614
$
 
510
 
421
 
405
Commercial
 
354
 
301
 
836
 
799
Industrial
(1)
 
64
 
53
 
1,429
 
1,434
Other
(2)
 
217
 
96
 
227
 
137
Total
(3)
$
 
1,249
$
 
960
 
2,913
 
2,775
(1) Industrial gas revenue includes sales to power generation customers.
(2) Other gas revenue includes off-system sales to other utilities and various other items.
(3) Total gas revenue
 
excludes $47 million of finance income from Brunswick Pipeline (2021 – $46 million).
Regulated Cost of Natural Gas
PGS and NMGC purchase gas from various suppliers depending on the needs of their customers. In
Florida, gas is delivered to the PGS distribution system through interstate pipelines on which PGS has
firm transportation capacity for delivery by PGS to its customers. NMGC’s natural gas is transported on
major interstate pipelines and NMGC’s intrastate transmission and distribution system for delivery to
customers.
 
In Florida, natural gas service is unbundled for non-residential customers and residential customers who
use more than 1,999 therms annually and elect the option. In New Mexico, NMGC is required, if
requested, to provide transportation-only services for all customer classes. The commodity portion of
bundled sales is included in operating revenues, at the cost of the gas on a pass-through basis, therefore
no net earnings effect when a customer shifts to transportation-only sales.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
28
Annual gas sales by type are summarized in the following table:
Gas Volumes by Type (millions of Therms)
2022
2021
Transportation
 
2,206
 
2,154
System supply
 
707
 
621
Total
 
2,913
 
2,775
Regulatory Environments
PGS is regulated by the FPSC. The FPSC sets rates at a level that allows utilities such as PGS to collect
total revenues or revenue requirements equal to their cost of providing service, plus an appropriate return
on invested capital.
NMGC is subject to regulation by the NMPRC. The NMPRC sets rates at a level that allows NMGC to
collect total revenues equal to its cost of providing service, plus an appropriate return on invested capital.
 
For further information on PGS and NMGC’s regulatory environment and recovery mechanisms, refer to
note 7 in the consolidated financial statements.
Other Electric Utilities
All amounts are reported in USD, unless otherwise stated.
 
Three months ended
Year ended
For the
December 31
December 31
millions of USD (except as indicated)
2022
2021
2022
2021
Operating revenues – regulated electric
$
 
98
$
 
98
$
 
398
$
 
355
Regulated fuel for generation and purchased power
$
 
54
$
 
52
$
 
223
$
 
175
Contribution to consolidated adjusted net income
$
 
7
$
 
4
$
 
23
$
 
16
Contribution to consolidated adjusted net income – CAD
$
 
8
$
 
5
$
 
29
$
 
20
GBPC Impairment charge
$
 
54
$
 
-
 
$
 
54
$
 
-
 
Equity securities MTM gain (loss)
$
 
1
$
 
2
$
 
(4)
$
 
1
Contribution to consolidated net income
 
$
 
(46)
$
 
6
$
 
(35)
$
 
17
Contribution to consolidated net income – CAD
$
 
(62)
$
 
7
$
 
(48)
$
 
21
Electric sales volumes (GWh)
 
301
 
330
 
1,239
 
1,262
Electric production volumes (GWh)
 
336
 
357
 
1,340
 
1,359
Average fuel cost in dollars per MWh
$
 
161
$
 
146
$
 
166
$
 
129
The impact of the change in the FX rate increased net loss by $3 million for the three months and year
ended December 31, 2022 and had a minimal impact on adjusted net income for the same periods.
Other Electric Utilities' contribution to consolidated adjusted net income is summarized in the following
table:
Three months ended
 
Year ended
For the
December 31
December 31
millions of USD
2022
2021
2022
2021
BLPC
$
 
5
$
 
6
$
 
11
$
 
11
GBPC
 
1
 
-
 
 
10
 
8
Other
 
1
 
(2)
 
2
 
(3)
Contribution to consolidated adjusted net income
 
$
 
7
$
 
4
$
 
23
$
 
16
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
29
Net Income
Highlights of the net income changes are summarized in the following table:
For the
Three months ended
Year ended
millions of USD
December 31
December 31
Contribution to consolidated net income – 2021
$
 
6
$
 
17
Increased operating revenues - regulated electric year-over-year due to
higher fuel revenue at BLPC as a result of higher fuel prices, partially
offset by the sale of Domlec in Q1 2022
 
-
 
 
43
Increased fuel for generation and purchased power as a result of
higher fuel prices at BLPC
 
(2)
 
(48)
Decreased OM&G due to the sale of Domlec in Q1 2022 and lower
generation costs at GBPC, partially offset by the recognition of
Hurricane Dorian insurance proceeds at GBPC in 2021
 
11
 
17
Goodwill impairment charge at GBPC
 
(54)
 
(54)
Decreased MTM gain on equity securities held in BLPC
 
 
(1)
 
(5)
Other
 
(6)
 
(5)
Contribution to consolidated net income – 2022
$
 
(46)
$
 
(35)
Regulatory Environments
BLPC is regulated by the FTC, an independent regulator. Rates are set to recover prudently incurred
costs of providing electricity service to customers plus an appropriate return on capital invested.
 
GBPC is regulated by the GBPA. Rates are set to recover prudently incurred costs of providing electricity
service to customers plus an appropriate return on rate base.
 
For further details on BLPC and GBPC’s regulatory environments and recovery mechanisms, refer to note
7 in the consolidated financial statements.
Other
Three months ended
Year ended
For the
December 31
December 31
millions of dollars
2022
2021
2022
2021
Marketing and trading margin
(1) (2)
$
 
72
$
 
39
$
 
143
$
 
102
Other non-regulated operating revenue
 
3
 
5
 
16
 
30
Total operating revenues – non-regulated
$
 
75
$
 
44
$
 
159
$
 
132
Contribution to consolidated adjusted net income (loss)
$
 
(1)
$
 
(44)
$
 
(218)
$
 
(198)
MTM gain (loss), after-tax
(3)
 
304
 
154
 
179
 
(214)
Contribution to consolidated net income (loss)
$
 
303
$
 
110
$
 
(39)
$
 
(412)
(1) Marketing and trading margin represents EES's purchases and sales of natural gas and electricity,
 
pipeline and storage capacity
costs and energy asset management services’ revenues.
(2) Marketing and trading margin excludes a MTM gain, pre-tax of $430 million in Q4 2022 (2021 – $212 million gain) and a gain
 
of
$281 million for the year ended December 31, 2022 (2021 – $289 million loss).
 
(3) Net of income tax expense of $124 million for the three months ended December 31, 2022 (2021 – $63 million expense)
 
and $73
million expense for the year ended December 31, 2022 (2021 – $86 million recovery).
Other's contribution to consolidated adjusted net income is summarized in the following table:
Three months ended
 
Year ended
For the
December 31
December 31
millions of dollars
2022
2021
2022
2021
Emera Energy
$
 
41
$
 
17
$
 
70
$
 
54
Corporate – see breakdown of adjusted contribution below
 
(37)
 
(57)
 
(267)
 
(231)
Emera Technologies
 
(5)
 
(4)
 
(18)
 
(17)
Other
 
-
 
 
-
 
 
(3)
 
(4)
Contribution to consolidated adjusted net income (loss)
$
 
(1)
$
 
(44)
$
 
(218)
$
 
(198)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
30
MTM Adjustments
Emera Energy’s “Marketing and trading margin”, “Non-regulated fuel for generation and purchased
power”, “Income from equity investments” and “Income tax expense (recovery)” are affected by MTM
adjustments. Management believes excluding the effect of MTM valuations, and changes thereto, from
income until settlement better matches the financial effect of these contracts with the underlying cash
flows. Variance explanations of the MTM changes for this quarter and for the year are explained in the
chart below.
 
Emera Energy has a number of asset management agreements (“AMA”) with counterparties, including
local gas distribution utilities, power utilities and natural gas producers in North America. The AMAs
involve Emera Energy buying or selling gas for a specific term, and the corresponding release of the
counterparties’ gas transportation/storage capacity to Emera Energy. MTM adjustments on these AMAs
arise on the price differential between the point where gas is sourced and where it is delivered. At
inception, the MTM adjustment is offset fully by the value of the corresponding gas transportation asset,
which is amortized over the term of the AMA contract.
 
Subsequent changes in gas price differentials, to the extent they are not offset by the accounting
amortization of the gas transportation asset, will result in MTM gains or losses recorded in income. MTM
adjustments may be substantial during the term of the contract, especially in the winter months of a
contract when delivered volumes and market pricing are usually at peak levels. As a contract is realized,
and volumes reduce, MTM volatility is expected to decrease. Ultimately, the gas transportation asset and
the MTM adjustment reduce to zero at the end of the contract term. As the business grows, and AMA
volumes increase, MTM volatility resulting in gains and losses may also increase.
Emera Corporate has FX forwards to manage the cash flow risk of forecasted USD cash inflows.
Fluctuations in the FX rate result in MTM gains or losses recorded in income.
Net Income
Highlights of the net income changes are summarized in the following table:
For the
Three months ended
 
Year ended
millions of dollars
December 31
December 31
Contribution to consolidated net income (loss) – 2021
$
 
110
$
 
(412)
Increased marketing and trading margin due to weather driven market
conditions that increased pricing and volatility, which created profitable
opportunities for Emera Energy. Year
 
-over-year increase also reflected
sustained higher pricing and volatility
 
33
 
41
Increased OM&G, pre-tax, primarily due to the timing of long-term
compensation and related hedges
 
(19)
 
(55)
Increased interest expense, pre-tax, due to increased interest rates
and increased total debt
 
(17)
 
(27)
Increased FX loss, pre-tax, primarily due to realized gains in 2021 on
FX hedges entered into to hedge USD denominated operating unit
earnings exposure
 
(9)
 
(28)
Increased income tax recovery primarily due to increased losses before
provision for income taxes
 
5
 
25
Increased preferred stock dividends due to issuance of preferred
shares in 2021
 
 
(2)
 
(13)
TGH award, after tax and legal costs
 
45
 
45
Increased MTM gain, after-tax, due to change in existing positions and
larger reversal of MTM losses in 2022, partially offset by higher
amortization of gas transportation assets in 2022 at Emera Energy
 
150
 
393
Other
 
 
7
 
(8)
Contribution to consolidated net income (loss) – 2022
$
 
303
$
 
(39)
 
 
 
 
 
 
 
 
 
 
 
 
31
Emera Energy
 
EES derives revenue and earnings from the wholesale marketing and trading of natural gas and
electricity within the Company’s risk tolerances, including those related to value-at-risk (“VaR”) and credit
exposure. EES purchases and sells physical natural gas and electricity, the related transportation and
transmission capacity rights, and provides energy asset management services. The primary market area
for the natural gas and power marketing and trading business is northeastern North America, including
the Marcellus and Utica shale supply areas. EES also participates in the Florida, United States Gulf Coast
and Midwest/Central Canadian natural gas markets. Its counterparties include electric and gas utilities,
natural gas producers, electricity generators and other marketing and trading entities. EES operates in a
competitive environment, and the business relies on knowledge of the region’s energy markets,
understanding of pipeline and transmission infrastructure, a network of counterparty relationships and a
focus on customer service. EES manages its commodity risk by limiting open positions, utilizing financial
products to hedge purchases and sales, and investing in transportation capacity rights to enable
movement across its portfolio.
Corporate
Corporate's adjusted loss is summarized in the following table:
 
Three months ended
 
Year ended
For the
December 31
December 31
millions of dollars
2022
2021
2022
2021
Operating expenses
 
(1)
 
$
 
20
$
 
1
$
 
83
$
 
28
Interest expense
 
83
 
65
 
291
 
264
Income tax recovery
 
 
(35)
 
(18)
 
(109)
 
(75)
Preferred dividends
 
16
 
14
 
63
 
50
TGH award, after tax and legal costs
 
(45)
 
-
 
 
(45)
 
-
 
Other
 
(2)(3)
 
(2)
 
(5)
 
(16)
 
(36)
Corporate adjusted net loss
 
(4)
$
 
(37)
$
 
(57)
$
 
(267)
$
 
(231)
(1) Operating expenses include OM&G and depreciation. In Q4 2021, OM&G and depreciation were offset by
 
a decrease in long-
term incentive compensation. The value of long-term incentive compensation and related hedges are impacted by changes
 
in
Emera's period end share price.
 
(2) Other includes realized FX gains and losses on FX hedges entered into to hedge USD denominated operating unit earnings
exposure.
 
(3) Includes a realized, pre-tax net loss of $5 million (2021 – $5 million gain) quarter-to-date and a $6 million
 
loss for the year ended
December 31, 2022 (2021 – $18 million gain) on FX hedges, as discussed above.
(4) Excludes a MTM gain, after-tax of $9 million for the three months ended December 31, 2022 (2021 – $3 million loss) and a MTM
loss, after-tax of $12 million for the year ended December 31, 2023 (2021 – $14 million loss)
LIQUIDITY AND CAPITAL RESOURCES
The Company generates internally sourced cash from its various regulated and non-regulated energy
investments. Utility customer bases are diversified by both sales volumes and revenues among customer
classes. Emera’s non-regulated businesses provide diverse revenue streams and counterparties to the
business. Circumstances that could affect the Company’s ability to generate cash include changes to
global macro-economic conditions, downturns in markets served by Emera, impact of fuel commodity
price changes on collateral requirements and timely recoveries of fuel costs from customers, the loss of
one or more large customers, regulatory decisions affecting customer rates and the recovery of regulatory
assets, and changes in environmental legislation. Emera’s subsidiaries are generally in a financial
position to contribute cash dividends to Emera provided they do not breach their debt covenants, where
applicable, after giving effect to the dividend payment, and maintain their credit metrics.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
32
Emera’s future liquidity and capital needs will be predominately for working capital requirements, ongoing
rate base investment, business acquisitions, greenfield development, dividends and debt servicing.
Emera has an $8 – 9 billion capital investment plan over the 2023-to-2025 period (including a $240 million
equity investment in the LIL in 2023), mainly focused in Florida. This plan includes significant rate base
investments across the portfolio in renewable and cleaner generation, infrastructure modernization and
customer-focused technologies. Capital investments at the regulated utilities are subject to regulatory
approval.
Emera plans to use cash from operations and debt raised at the utilities to support normal operations,
repayment of existing debt, and capital requirements. Debt raised at certain of the Company’s utilities is
subject to applicable regulatory approvals. Equity requirements in support of the Company’s capital
investment plan are expected to be funded through the issuance of preferred equity and the issuance of
common equity through Emera’s DRIP and ATM program.
 
Emera has credit facilities with varying maturities that cumulatively provide $4.7 billion of credit, with
approximately $1.1 billion undrawn and available at December 31, 2022. The Company was holding a
cash balance of $332 million at December 31, 2022. For further discussion, refer to the “Debt
Management” section below. For additional information regarding the credit facilities, refer to notes 23
and 25 in the consolidated financial statements.
Consolidated Cash Flow Highlights
Significant changes in the Consolidated Statements of Cash Flows between the years ended December
31, 2022 and 2021 include:
millions of dollars
2022
2021
$ Change
Cash, cash equivalents and restricted cash, beginning of period
$
 
417
$
 
254
$
 
163
Provided by (used in):
 
Operating cash flow before changes in working capital
 
1,147
 
1,337
 
(190)
 
Change in working capital
 
(234)
 
(152)
 
(82)
Operating activities
$
 
913
$
 
1,185
$
 
(272)
Investing activities
 
(2,569)
 
(2,332)
 
(237)
Financing activities
 
1,555
 
1,311
 
244
Effect of exchange rate changes on cash, cash equivalents and restricted cash
 
16
 
(1)
 
17
Cash, cash equivalents, and restricted cash, end of period
$
 
332
$
 
417
$
 
(85)
Cash Flow from Operating Activities
Net cash provided by operating activities decreased
$272 million to $913 million for the year ended
December 31, 2022, compared to $1,185 million in 2021.
Cash from operations before changes in working capital decreased
$190 million for the year ended
December 31, 2022. This decrease was due to under-recovery of clause-related costs primarily due to
higher natural gas prices at Tampa Electric, unfavourable changes in Tampa
 
Electric’s storm reserve
balance as a result of Hurricane Ian, increased fuel for generation and purchased power at NSPI, and
decreased long-term payables due to the Nova Scotia Cap-and-Trade accrued emissions compliance
charges being reclassified to other current liabilities as the liability is anticipated to be settled in 2023.
This was partially offset by the 2021 deferral of gas costs at NMGC resulting from the extreme cold
weather event, increased revenues at Tampa Electric and NSPI, favourable changes in regulatory
liabilities due to the NMGC gas hedge settlement, TGH award, and increased marketing and trading
margin at Emera Energy.
33
Changes in working capital decreased operating cash flows by $82 million for the year ended December
31, 2022. This decrease was due to unfavourable changes in accounts receivable at NMGC due to the
gas hedge settlement, unfavourable changes in accounts receivable at NSPI, unfavourable changes in
cash collateral positions on derivative instruments at NSPI, and the required prepayment of income taxes
and related interest at NSPI. This was partially offset by the Nova Scotia Cap-and-Trade accrued
emissions compliance charges, favourable changes in cash collateral positions at Emera Energy, and
favourable changes in accounts payable at Tampa Electric and NMGC.
Cash Flow used in Investing Activities
Net cash used in investing activities increased $237 million to $2,569 million for the year ended
December 31, 2022, compared to $2,332 million in 2021. The increase was due to higher capital
investment in 2022.
Capital expenditures for the year ended December 31, 2022, including AFUDC, were $2,646 million
compared to $2,420 million in 2021. Details of 2022 capital spending by segment are shown below:
 
●
 
$1,481 million – Florida Electric Utility (2021 – $1,408 million);
●
 
$518 million – Canadian Electric Utilities (2021 – $374 million);
●
 
$578 million – Gas Utilities and Infrastructure (2021 – $522 million);
 
●
 
$63 million – Other Electric Utilities (2021 – $111
 
million); and
●
 
$6 million – Other (2021 – $5 million).
Cash Flow from Financing Activities
Net cash provided by financing activities increased $244 million to $1,555 million for the year ended
December 31, 2022, compared to $1,311 million in 2021. This increase was due to higher proceeds of
short-term debt at Tampa Electric, proceeds from committed credit facilities at NSPI, and term loan
issuance at Emera in 2022. These were partially offset by the issuance of preferred shares in 2021, lower
proceeds of long-term debt at Tampa Electric, and net proceeds of long-term debt at NMGC in 2021.
Working Capital
As at December 31, 2022, Emera’s cash and cash equivalents were $310 million (2021 – $394 million)
and Emera’s investment in non-cash working capital was $1,173 million (2021 – $491 million). Of the
cash and cash equivalents held at December 31, 2022, $250 million was held by Emera’s foreign
subsidiaries (2021 – $194 million). A portion of these funds are invested in countries that have certain
exchange controls, approvals, and processes for repatriation. Such funds are available to fund local
operating and capital requirements unless repatriated.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
34
Contractual Obligations
As at December 31, 2022, contractual commitments for each of the next five years and in aggregate
thereafter consisted of the following:
millions of dollars
2023
2024
2025
2026
2027
Thereafter
Total
Long-term debt principal
$
 
574
$
 
1,613
$
 
262
$
 
3,110
$
 
946
$
 
9,937
$
 
16,442
Interest payment obligations
(1)
 
720
 
699
 
653
 
566
 
472
 
6,995
 
10,105
Transportation
(2)
 
693
 
516
 
423
 
383
 
367
 
2,817
 
5,199
Purchased power
(3)
 
269
 
243
 
237
 
228
 
243
 
2,145
 
3,365
Fuel, gas supply and storage
 
1,161
 
282
 
138
 
40
 
5
 
1
 
1,627
Capital projects
 
264
 
89
 
4
 
1
 
-
 
 
-
 
 
358
Asset retirement obligations
 
15
 
2
 
2
 
1
 
1
 
415
 
436
Pension and post-retirement
obligations
(4)
 
38
 
31
 
31
 
82
 
59
 
178
 
419
Equity investment commitments
(5)
 
240
 
-
 
 
-
 
 
-
 
 
-
 
 
-
 
 
240
Other
 
154
 
142
 
132
 
49
 
42
 
189
 
708
$
 
4,128
$
 
3,617
$
 
1,882
$
 
4,460
$
 
2,135
$
 
22,677
$
 
38,899
(1) Future interest payments are calculated based on the assumption that all debt is outstanding until maturity.
 
For debt instruments
with variable rates, interest is calculated for all future periods using the rates in effect at December 31,
 
2022, including any expected
required payment under associated swap agreements.
(2) Purchasing commitments for transportation of fuel and transportation capacity on various pipelines.
 
Includes a commitment of
$144 million related to a gas transportation contract between PGS and SeaCoast through 2040.
(3) Annual requirement to purchase electricity production from IPPs or other utilities over varying contract lengths.
(4) The estimated contractual obligation is calculated as the current legislatively required contributions to the registered
 
funded
pension plans (excluding the possibility of wind-up), plus the estimated costs of further benefit accruals contracted under
 
NSPI's
Collective Bargaining Agreement and estimated benefit payments related to other unfunded benefit plans.
(5) Emera has a commitment to make a final equity contribution to the LIL upon its commissioning. Once commissioned, the
commercial agreements between Emera and Nalcor require true ups to finalize the respective investment obligations
 
of the parties
in relation to the Maritime Link and LIL.
NSPI has a contractual obligation to pay NSPML for use of the Maritime Link over approximately 38 years
from its January 15, 2018 in-service date. In February 2022, the UARB issued its decision and Board
Order approving NSPML’s requested rate base of approximately $1.8 billion. In December 2022, the
UARB approved the collection of $164 million from NSPI for the recovery of Maritime Link costs in 2023.
The timing and amounts payable to NSPML for the remainder of the 38-year commitment period are
subject to UARB approval.
 
Emera has committed to obtain certain transmission rights for Nalcor, if requested, to enable it to transmit
energy which is not otherwise used in Newfoundland and Labrador or Nova Scotia. Nalcor has the right to
transmit this energy from Nova Scotia to New England energy markets effective August 15, 2021, the
date the NS Block delivery obligation commenced, and continuing for 50 years. As transmission rights are
contracted, the obligations are included within “Other” in the above table.
Forecasted Gross Consolidated Capital Expenditures
The 2023 forecasted gross consolidated capital expenditures are as follows:
millions of dollars
Florida
Electric
Utility
Canadian
Electric
Utilities
Gas Utilities
and
Infrastructure
Other
Electric
Utilities
Other
Total
Generation
$
 
276
$
 
120
$
 
-
 
$
 
36
$
 
-
 
$
 
432
New renewable generation
 
402
 
-
 
 
-
 
 
4
 
-
 
 
406
Transmission
 
100
 
74
 
-
 
 
-
 
 
-
 
 
174
Distribution
 
479
 
121
 
-
 
 
34
 
-
 
 
634
Gas transmission and distribution
 
-
 
 
-
 
 
639
 
-
 
 
-
 
 
639
Facilities, equipment, vehicles, and other
 
516
 
60
 
-
 
 
17
 
11
 
604
$
 
1,773
$
 
375
$
 
639
$
 
91
$
 
11
$
 
2,889
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
35
Debt Management
In addition to funds generated from operations, Emera and its subsidiaries have, in aggregate, access to
committed syndicated revolving and non-revolving bank lines of credit in either CAD or USD per the table
below.
 
Undrawn
Credit
and
millions of dollars
Maturity
Facilities
Utilized
Available
Emera – Unsecured committed revolving credit facility
June 2027
$
 
900
$
 
403
$
 
497
TEC (in USD) – Unsecured committed revolving credit facility
(1)
December 2026
 
800
 
620
 
180
NSPI – Unsecured committed revolving credit facility
December 2027
 
800
 
497
 
303
Emera – Unsecured non-revolving facility
 
December 2023
 
400
 
400
 
-
 
Emera – Unsecured non-revolving facility
August 2023
 
400
 
400
 
-
 
TEC (in USD) – Unsecured non-revolving facility
(2)
December 2023
 
400
 
400
 
-
 
TECO Finance (in USD) – Unsecured committed revolving credit
facility
December 2026
 
400
 
355
 
45
NSPI – Unsecured non-revolving facility
July 2024
 
400
 
400
 
-
 
NMGC (in USD) – Unsecured revolving credit facility
December 2026
 
125
 
45
 
80
NMGC (in USD) – Unsecured non-revolving facility
March 2024
 
80
 
80
 
-
 
Other (in USD) – Unsecured committed revolving credit facilities
Various
 
21
 
7
 
14
(1) This facility is available for use by Tampa
 
Electric and PGS. At December 31, 2022, $554 million USD was used by Tampa
Electric and $66 million USD was used by PGS.
(2) This facility is available for use by Tampa
 
Electric and PGS. At December 31, 2022, $300 million USD was used by Tampa
Electric and $100 million USD was used by PGS.
Emera and its subsidiaries have certain financial and other covenants associated with their debt and
credit facilities. Covenants are tested regularly, and the Company is in compliance with covenant
requirements as at December 31, 2022.
 
Emera’s significant covenant is listed below:
As at
Financial Covenant
Requirement
December 31, 2022
Emera
Syndicated credit facilities
Debt to capital ratio
Less than or equal to 0.70 to 1
0.57 : 1
Recent significant financing activity for Emera and its subsidiaries are discussed below by segment:
Florida Electric Utilities
On December 13, 2022, TEC amended its 364-day non-revolving credit facility to extend the maturity date
from December 16, 2022 to December 13, 2023 and reduced the facility amount from $500 million USD
to $400 million USD. There were no other significant changes in commercial terms from the prior
agreement.
 
On September 15, 2022, TEC repaid a $250 million USD note upon maturity. The note was repaid using
existing credit facilities.
 
On July 12, 2022, TEC completed an issuance of $600 million USD senior notes. The issuance included
$300 million USD senior notes that bear an interest rate of 3.875 per cent with a maturity date of July 12,
2024, and $300 million USD senior notes that bear an interest rate of 5 per cent with a maturity date of
July 15, 2052. Proceeds from the issuance were used to repay TEC’s $470 million USD commercial
paper, due in 2022, and for general corporate purposes.
36
Canadian Electric Utilities
On December 16, 2022, NSPI amended its revolving operating credit facility to extend the maturity date
from December 16, 2026 to December 16, 2027 and increase the amount of the facility from $600 million
to $800 million. There were no other significant changes in commercial terms from the prior agreement.
 
On July 15, 2022, NSPI entered into a $400 million non-revolving term credit facility which matures on
July 15, 2024. The credit facility contains customary representation and warranties, events of default and
financial and other covenants, and bears interest at Bankers’ Acceptances or prime rate advances, plus a
margin. Proceeds from this facility were used for general corporate purposes.
 
Gas Utilities and Infrastructure
On September 23, 2022, NMGC amended its $80 million USD, unsecured, non-revolving term credit
facility to extend the maturity from September 23, 2022, to March 22, 2024. There were no other changes
in commercial terms from the prior agreement.
 
On June 30, 2022, Brunswick Pipeline amended its non-revolving credit agreement to extend the maturity
from June 30, 2025 to June 30, 2026. There were no other changes in commercial terms from the prior
agreement.
 
Other Electric Utilities
 
On March 25, 2022, ECI amended its amortizing floating rate notes to extend the maturity from March 25,
2022 to March 25, 2027. There were no other changes in commercial terms from the prior agreement.
 
Other
On December 16, 2022, Emera amended its $900 million revolving operating credit facility to extend the
maturity date from June 30, 2026 to June 30, 2027. There were no other significant changes in
commercial terms from the prior agreement.
 
On December 16, 2022, Emera amended its $400 million non-revolving term credit facility to extend the
maturity from December 16, 2022 to December 16, 2023. There were no other significant changes in
commercial terms from the prior agreement.
 
On August 2, 2022, Emera entered into a $400 million non-revolving term facility which matures on
August 2, 2023. The credit agreement contains customary representation and warranties, events of
default and financial and other covenants and bears interest at Bankers’ Acceptances or prime rate
advances, plus a margin. Proceeds from this facility were used for general corporate purposes.
 
 
 
 
 
 
 
 
 
 
 
 
37
Credit Ratings
Emera and its subsidiaries have been assigned the following senior unsecured debt ratings:
Fitch
 
(1)
S&P
(2)(3)
Moody's
 
(4)(5)
DBRS
 
(6)
Emera Inc.
BBB (Negative)
BBB- (Negative)
Baa3 (Negative)
N/A
TECO Energy/TECO Finance
N/A
N/A
N/A
N/A
TEC
A (Negative)
BBB+ (Negative)
A3 (Negative)
N/A
NMGC
BBB+ (Negative)
N/A
N/A
N/A
NSPI
N/A
BBB- (Negative)
N/A
BBB (high)(stable)
(1) On November 21, 2022, Fitch Ratings ("Fitch") affirmed its BBB issuer rating for Emera Inc. Fitch also
 
affirmed the A- issuer and
A unsecured debt ratings for TEC and BBB+ for NMGC. Emera and subsidiaries’ outlook was changed to negative from stable.
(2) On November 21, 2022, S&P Global Ratings (“S&P”) affirmed its BBB issuer rating for Emera Inc. and TECO
 
Energy, while
affirming the BBB+ issuer credit ratings for TEC. S&P downgraded NSPI's issue-level and senior unsecured
 
debt ratings to BBB-.
Emera and subsidiaries’ outlook remained at negative.
(3) On October 24, 2022, S&P affirmed its BBB issuer rating for Emera Inc. S&P also affirmed
 
ratings on NSPI, TECO Energy, and
TEC affirming the BBB+ issuer credit ratings for NSPI and TEC. Emera and subsidiaries’ outlook was changed
 
to negative from
stable.
(4) On November 2, 2022, Moody’s Investor Services (“Moody’s”) affirmed
 
its Baa3 issuer rating for Emera Inc. Moody’s also
affirmed ratings on TECO Finance and TEC, affirming the TECO Finance Baa1 issuer
 
rating and A3 issuer rating for TEC. Emera
and subsidiaries’ outlook was changed to negative from stable.
(5) On June 2, 2022, Moody’s affirmed its Baa1 issuer rating for TECO Finance. Moody’s
 
also affirmed TEC’s A3 issuer rating and
changed the outlook to stable from positive.
(6) On December 20, 2022, DBRS (“Dominion Bond Rating Service”) downgraded its issuer credit and senior unsecured rating
 
for
NSPI to BBB (high). NSPI’s outlook remained unchanged at stable.
 
The downgrades from both S&P and DBRS of NSPI were attributed to their view of the enactment of Bill
212, “Public Utilities Act (amended)”, as a political intervention in the regulatory process that resulted in
an increase in political risk and a reduction in the stability and predictability of NSPI’s regulatory
environment.
 
Guaranteed Debt
As of December 31, 2022, the Company had $2.75 billion USD senior unsecured notes ("U.S. Notes”)
outstanding.
 
The U.S. Notes are fully and unconditionally guaranteed, on a joint and several basis, by Emera and
Emera US Holdings Inc. (in such capacity, the “Guarantor Subsidiaries”). Emera owns, directly or
indirectly, all of the limited and general partnership interests in Emera US Finance LP.
 
Other subsidiaries
of the Company do not guarantee the U.S. Notes (such subsidiaries are referred to as the "Non-
Guarantor Subsidiaries") however, Emera has unrestricted access to the assets of consolidated entities.
 
In compliance with Rule 13-01 of Regulation S-X, the Company is including summarized financial
information for Emera, Emera US Holdings Inc., and Emera US Finance LP (together, the "Obligor
Group"), on a combined basis after transactions and balances between the combined entities have been
eliminated. Investments in and equity earnings of the Non-Guarantor Subsidiaries have been excluded
from the summarized financial information.
 
The Obligor Group was not determined using geographic, service line or other similar criteria and, as a
result the summarized financial information includes portions of Emera’s domestic and international
operations. Accordingly, this basis of presentation is not intended to present Emera’s financial condition
or results of operations for any purpose other than to comply with the specific requirements for guarantor
reporting.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
38
Summarized Statement of Income (loss)
 
The Company recognized income related to guaranteed debt under the following categories:
For the
Year ended December 31
millions of dollars
2022
2021
Loss from operations
$
 
(73)
$
 
(21)
Net losses
(1)
$
 
(131)
$
 
(86)
(1) Includes $262 million in interest and dividend income, net, from non-guarantor subsidiaries.
Summarized Balance Sheet
The Company has the following categories on the balance sheet related to guaranteed debt:
As at
December 31
millions of dollars
2022
2021
Current assets
 
(1)
$
 
172
$
 
329
Goodwill
 
6,012
 
5,628
Other assets
(2)
 
6,402
 
6,027
Total assets
 
(3)
$
 
12,586
$
 
11,984
Current liabilities
(4)
$
 
1,903
$
 
888
Long-term liabilities
(5)
 
6,431
 
6,403
Total liabilities
$
 
8,334
$
 
7,291
(1) Includes $144 million (2021 – $140 million) in amounts due from non-guarantor subsidiaries.
(2) Includes $6,058 million (2021 – $5,749 million) in amounts due from non-guarantor subsidiaries.
(3) Excludes investments in non-guarantor subsidiaries. Consolidated Emera total assets are $39,742 million
 
(2021 – $34,244
million).
(4) Includes $392 million (2021 – $346 million) due to non-guarantor subsidiaries.
(5) Includes $769 million (2021 – $776 million) due to non-guarantor subsidiaries.
Outstanding Stock Data
Common Stock
millions of
millions of
Issued and outstanding:
shares
dollars
Balance, December 31, 2021
261.07
$
7,242
Issuance of common stock under ATM program
(1)
4.07
248
Issued under the DRIP,
 
net of discounts
4.21
238
Senior management stock options exercised and Employee Share Purchase Plan
0.60
34
Balance, December 31, 2022
269.95
$
7,762
(1)
 
In Q4 2022, 278,545 common shares were issued under Emera's ATM
 
program at an average price of $54.06 per share for
gross proceeds of $15 million ($15 million net of after-tax issuance costs). For the year ended December 31, 2022, 4,072,469
common shares were issued under Emera's ATM
 
program at an average price of $61.31 per share for gross proceeds of $250
million ($248 million net of after-tax issuance costs). As at December 31, 2022, an aggregate gross sales limit
 
of $207 million
remained available for issuance under the ATM program.
As at February 16, 2023, the amount of issued and outstanding common shares was 271.4 million.
If all outstanding stock options were converted as at February 16, 2023, an additional 2.9 million common
shares would be issued and outstanding.
Preferred Stock
 
As at February 16, 2023, Emera had the following preferred shares issued and outstanding: Series A –
4.9 million; Series B – 1.1 million; Series C – 10.0 million; Series E – 5.0 million; Series F – 8.0 million;
Series H – 12.0 million; Series J – 8.0 million, and Series L – 9.0 million. Emera’s preferred shares do not
have voting rights unless the Company fails to pay, in aggregate, eight quarterly dividends.
 
 
 
 
 
 
 
 
39
PENSION FUNDING
For funding purposes, Emera determines required contributions to its largest defined benefit pension
plans based on smoothed asset values. This reduces volatility in the cash funding requirement as the
impact of investment gains and losses are recognized over a three-year period. The cash required in
2023 for defined benefit pension plans is expected to be $44 million (2022 – $45 million). All pension plan
contributions are tax deductible and will be funded with cash from operations.
Emera’s defined benefit pension plans employ a long-term strategic approach with respect to asset
allocation, real return and risk. The underlying objective is to earn an appropriate return, given the
Company’s goal of preserving capital with an acceptable level of risk for the pension fund investments.
 
To
 
achieve the overall long-term asset allocation, pension assets are managed by external investment
managers per the pension plan’s investment policy and governance framework. The asset allocation
includes investments in the assets of Canadian and global equities, domestic and global bonds and short-
term investments. Emera reviews investment manager performance on a regular basis and adjusts the
plans’ asset mixes as needed in accordance with the pension plans’ investment policy.
Emera’s projected contributions to defined contribution pension plans are $44 million for 2023 (2022 –
$41 million).
 
Defined Benefit Pension Plan Summary
in millions of dollars
Plans by region
TECO Energy
NSPI
Caribbean
 
Total
Assets as at December 31, 2022
$
 
880
$
 
1,273
$
 
10
$
 
2,163
Accounting obligation at December 31, 2022
$
 
902
$
 
1,240
$
 
16
$
 
2,158
Accounting expense during fiscal 2022
$
 
10
$
 
(3)
$
 
1
$
 
8
Off-Balance Sheet Arrangements
Defeasance
Upon privatization in 1992, NSPI became responsible for managing a portfolio of defeasance securities
that provide principal and interest streams to match the related defeased debt, which at December 31,
2022 totalled $200 million (2021 – $200 million). The securities are held in trust for an affiliate of the
Province of Nova Scotia. Approximately 66 per cent of the defeasance portfolio consists of investments in
the related debt, eliminating all risk associated with this portion of the portfolio; the remaining defeasance
portfolio has a market value higher than the related debt, reducing the future risk of this portion of the
portfolio.
Guarantees and Letters of Credit
Emera has guarantees and letters of credit on behalf of third parties outstanding. The following significant
guarantees and letters of credit are not included within the Consolidated Balance Sheets as at December
31, 2022:
TECO Energy has issued a guarantee in connection with SeaCoast’s performance of obligations under a
gas transportation precedent agreement. The guarantee is for a maximum potential amount of $45 million
USD if SeaCoast fails to pay or perform under the contract. The guarantee expires five years after the
gas transportation precedent agreement termination date, which was terminated on January 1, 2022. In
the event that TECO Energy’s and Emera’s long-term senior unsecured credit ratings are downgraded
below investment grade by Moody’s or S&P,
 
TECO Energy would be required to provide its counterparty
a letter of credit or cash deposit of $27 million USD.
40
TECO Energy issued a guarantee in connection with SeaCoast’s performance obligations under a firm
service agreement, which expires on December 31, 2055, subject to two extension terms at the option of
the counterparty with a final expiration date of December 31, 2071. The guarantee is for a maximum
potential amount of $13 million USD if SeaCoast fails to pay or perform under the firm service agreement.
In the event that TECO Energy’s long-term senior unsecured credit ratings are downgraded below
investment grade by Moody’s or S&P,
 
TECO Energy would need to provide either a substitute guarantee
from an affiliate with an investment grade credit rating or a letter of credit or cash deposit of $13 million
USD.
Emera Inc. has issued a guarantee of up to $35 million USD relating to outstanding notes of GBPC. The
guarantee for the notes will expire in May 2023.
Emera Inc. has issued a guarantee of $66 million USD relating to outstanding notes of ECI. This
guarantee will automatically terminate on the date upon which the obligations have been repaid in full.
NSPI has issued guarantees on behalf of its subsidiary, NS Power Energy Marketing Incorporated
(“NSPEMI”), in the amount of $119 million USD (2021 – $118
 
million USD) with terms of varying lengths.
The Company has standby letters of credit and surety bonds in the amount of $145 million USD
(December 31, 2021 – $148 million USD) to third parties that have extended credit to Emera and its
subsidiaries. These letters of credit and surety bonds typically have a one-year term and are renewed
annually as required.
Emera Inc., on behalf of NSPI, has a standby letter of credit to secure obligations under a supplementary
retirement plan. The expiry date of this letter of credit was extended to June 2023. The amount committed
as at December 31, 2022 was $63 million (December 31, 2021 – $64 million).
DIVIDEND PAYOUT
 
RATIO
Emera has provided annual dividend growth guidance of four to five per cent through 2025. The
Company targets a long-term dividend payout ratio of adjusted net income of 70 to 75 per cent, and while
the payout ratio is likely to exceed that target through and beyond the forecast period, it is expected to
return to that range over time. Emera’s common share dividends paid in 2022 were $2.6775 ($0.6625 in
Q1, Q2, and Q3 and $0.6900 in Q4) per common share and $2.5750 ($0.6375 in Q1, Q2, and Q3 and
$0.6625 in Q4) per common share for 2021, representing a dividend payout ratio of 75 per cent in 2022
(2021 – 129 per cent) and a dividend payout ratio of adjusted net income of 83 per cent in 2022 (2021 –
91 per cent).
 
On September 22, 2022, the Emera Board of Directors approved an increase in the annual common
share dividend rate to $2.76 from $2.65. The first quarterly dividend payment at the increased rate was
paid on November 15, 2022.
 
TRANSACTIONS WITH RELATED
 
PARTIES
In the ordinary course of business, Emera provides energy and other services and enters into
transactions with its subsidiaries, associates and other related companies on terms similar to those
offered to non-related parties. Intercompany balances and intercompany transactions have been
eliminated on consolidation, except for the net profit on certain transactions between non-regulated and
regulated entities in accordance with accounting standards for rate-regulated entities. All material
amounts are under normal interest and credit terms.
 
41
Significant transactions between Emera and its associated companies are as follows:
●
 
Transactions between NSPI and NSPML related to the Maritime Link assessment are reported in the
Consolidated Statements of Income. NSPI’s expense is reported in Regulated fuel for generation and
purchased power, totalling $157 million for the year ended December 31, 2022 (2021 – $149 million).
NSPML is accounted for as an equity investment and therefore, the corresponding earnings related to
this revenue are reflected in Income from equity investments. For further details, refer to the
“Business Overview and Outlook - Canadian Electric Utilities – ENL” and “Contractual Obligations”
sections.
●
Natural gas transportation capacity purchases from M&NP are reported in the Consolidated
Statements of Income. Purchases from M&NP reported net in Operating revenues, Non-regulated,
totalled $9 million for the year ended December 31, 2022 (2021
– $19 million).
There were no significant receivables or payables between Emera and its associated companies reported
on Emera’s Consolidated Balance Sheets as at December 31, 2022 and at December 31, 2021.
ENTERPRISE RISK AND RISK MANAGEMENT
Emera has an enterprise-wide risk management process, overseen by its Enterprise Risk Management
Committee (“ERMC”) and monitored by the Board of Directors, to ensure an effective, consistent and
coherent approach to risk management. Certain risk management activities for Emera are overseen by
the ERMC to ensure such risks are appropriately identified, assessed, monitored and subject to
appropriate controls.
 
The Board of Directors established a Risk and Sustainability Committee (“RSC”) in September 2021. The
mandate of the RSC is to assist the Board in carrying out its risk and sustainability oversight
responsibilities. The RSC’s mandate includes oversight of the Company’s Enterprise Risk Management
framework, including the identification, assessment, monitoring and management of enterprise risks. It
also includes oversight of the Company’s approach to sustainability and its performance relative to its
sustainability objectives.
The Company’s financial risk management activities are focused on those areas that most significantly
impact profitability, quality and consistency of income, and cash flow. Emera’s
 
risk management focus
extends to key operational risks including safety and environment, which represent core values of Emera.
In this section, Emera describes the principal risks that management believes could materially affect its
business, revenues, operating income, net income, net assets, liquidity or capital resources. The nature
of risk is such that no list is comprehensive, and other risks may arise or risks not currently considered
material may become material in the future.
Regulatory and Political Risk
The Company’s rate-regulated subsidiaries and certain investments subject to significant influence are
subject to risk of the recovery of costs and investments. Regulatory and political risk can include changes
in regulatory frameworks, shifts in government policy, legislative changes, and regulatory decisions.
As cost-of-service utilities with an obligation to serve customers, Emera’s utilities operate under formal
regulatory frameworks, and must obtain regulatory approval to change or add rates and/or riders. Emera
also holds investments in entities in which it has significant influence, and which are subject to regulatory
and political risk including NSPML, LIL, and M&NP.
 
As a regulated Group II pipeline, the tolls of
Brunswick Pipeline are regulated by the CER on a complaint basis, as opposed to the regulatory approval
process described above. In the absence of a complaint, the CER does not normally undertake a detailed
examination of Brunswick Pipeline’s tolls, which are subject to a firm service agreement, expiring in 2034,
with Repsol Energy North America Canada Partnership. The agreement provides for a predetermined toll
increase in the fifth and fifteenth year of the contract.
42
Regulators administer legislation covering material aspects of the utilities’ businesses, including customer
rates and/or riders, the underlying allowed ROEs, deemed capital structures, capital investment, the
terms and conditions for the provision of service, performance standards, and affiliate transactions. Costs
and investments can be recovered upon approval by the respective regulator as an adjustment to rates
and/or riders, which normally require a public hearing process or may be mandated by other
governmental bodies.
 
During public hearing processes, consultants and customer representatives
scrutinize the costs, actions and plans of these rate-regulated companies, and their respective regulators
determine whether to allow recovery and to adjust rates based upon the evidence and any contrary
evidence from other parties. In some circumstances, other government bodies may influence the setting
of rates. Regulatory decisions, legislative changes, and prolonged delays in the recovery of costs or
regulatory assets could result in decreased rate affordability for customers and could materially affect
Emera and its utilities.
 
Emera’s utilities generally manage this risk through transparent regulatory disclosure, ongoing
stakeholder and government consultation, and multi-party engagement on aspects such as utility
operations, regulatory audits, rate filings and capital plans. The subsidiaries employ a collaborative
regulatory approach through technical conferences and, where appropriate, negotiated settlements.
 
Changes in government and shifts in government policy and legislation can impact the commercial and
regulatory frameworks under which Emera and its subsidiaries operate. This includes initiatives regarding
deregulation or restructuring of the energy industry. Deregulation or restructuring of the energy industry
may result in increased competition and unrecovered costs that could adversely affect operations, net
income and cash flows. State and local policies in some United States jurisdictions have sought to
prevent or limit the ability of utilities to provide customers the choice to use natural gas while in other
jurisdictions policies have been adopted to prevent limitations on the use of natural gas. Changes in
applicable state or local laws and regulations, including electrification legislation, could adversely impact
PGS and NMGC.
Emera cannot predict future legislative, policy, or regulatory changes, whether caused by economic,
political or other factors, or its ability to respond in an effective and timely manner or the resulting
compliance costs. Government interference in the regulatory process can undermine regulatory stability,
predictability, and independence, and could have a material adverse effect on the Company.
Global Climate Change Risk
The Company is subject to risks that may arise from the impacts of climate change. There is increasing
public concern about climate change and growing support for reducing carbon dioxide emissions.
Municipal, state, provincial and federal governments have been setting policies and enacting laws and
regulations to deal with climate change impacts in a variety of ways, including decarbonization initiatives
and promotion of cleaner energy and renewable energy generation of electricity. Refer to “Changes in
Environmental Legislation” risk below. Insurance companies have begun to limit their exposure to coal-
fired electricity generation and are evaluating the medium and long-term impacts of climate change which
may result in fewer insurers, more restrictive coverage and increased premiums. Refer to the “Markets”
section below and “Uninsured Risk”.
Climate change may lead to increased frequency and intensity of weather events and related impacts
such as storms, ice storms, hurricanes, cyclones, heavy rainfall, extreme winds, wildfires, flooding and
storm surge. The potential impacts of climate change, such as rising sea levels and larger storm surges
from more intense hurricanes, can combine to produce even greater damage to coastal generation and
other facilities. Climate change is also characterized by rising global temperatures. Increased air
temperatures may bring increased frequency and severity of wildfires within the Company’s service
territories. Refer to “Weather Risk” and “System Operating and Maintenance Risks”.
43
The Company has made significant investments to facilitate the use of renewable and lower-carbon
energy including wind generation, the Maritime Link in Atlantic Canada, and in Florida, solar generation
and modernization of the Big Bend Power Station. Tampa Electric has taken significant steps to reduce
overall emissions at its facilities as a result of its capital investment plan which has and will continue to
reduce carbon dioxide emissions.
In 2022, NSPI achieved reductions of carbon dioxide emissions of
approximately 45 per cent from 2005 levels. NSPI expects to exceed the Canadian target of 40-45 per
cent reduction by 2030, as set out in the Canadian Net-Zero Emissions Accountability Act. Both the
Government of Nova Scotia and the Government of Canada have enacted or introduced legislation that
includes goals of net-zero GHG emissions by 2050. The Province of Nova Scotia has established targets
with respect to the percentage of renewable energy in NSPI’s generation mix, reductions in GHG
emissions, as well as the goal to phase out coal-fired electricity generation by 2030. Failure to meet such
goals by 2030 could result in material fines, penalties, other sanctions and adverse reputational impacts.
NSPI continues to work with both the provincial and federal governments on measures to seek to address
their carbon reduction goals. Future compliance with provincial and federal GHG emission caps, coal
phase out requirements and targets, and renewable standards has been challenged as a result of the
constraints imposed by the enactment of Bill 212, “Public Utilities Act (amended)”. Within Emera’s natural
gas utilities, there are ongoing efforts to reduce methane and carbon dioxide emissions through
replacement of aging infrastructure, more efficient operations, operational and supply chain optimization,
and support of public policy initiatives that address the effects of climate change.
The Company’s long-term capital investment plan includes significant investment across the portfolio in
renewable and cleaner generation, infrastructure modernization, storm hardening, energy storage and
customer-focused technologies. All these initiatives contribute toward mitigating the potential impacts of
climate change. The Company continues to engage with government, regulators, industry partners and
stakeholders to share information and participate in the development of climate change related policies
and initiatives.
 
Physical Impacts
The Company is subject to physical risks that arise, or may arise, from global climate change, including
damage to operating assets from more frequent and intense weather events and from wildfires due to
warming air temperatures and increasing drought conditions. Substantially all of the Company’s fossil
fueled generation assets are located at or near coastal sites and, as such, are exposed to the separate
and combined effects of rising sea levels and increasing storm intensity, including storm surges and
flooding. Refer to “Weather Risk” for further information.
These risks are mitigated to an extent through features such as flood walls at certain plants and through
the location of plants on higher ground. Planned investments in under-grounding parts of the electricity
infrastructure contribute to risk mitigation, as does insurance coverage (for assets other than electricity
transmission and distribution assets). In addition, implementation of regulatory mechanisms for recovery
of costs, such as storm reserves and regulatory deferral accounts, help smooth out the recovery of storm
restoration costs over time.
 
Reputation
Failure to address issues related to climate change could affect Emera’s reputation with stakeholders, its
ability to operate and grow, and the Company’s access to, and cost of, capital. Refer to “Liquidity and
Capital Market Risk”. The Company seeks to mitigate this in part by moving away from higher-carbon
generation in favour of lower-carbon generation and non-emitting renewable generation.
44
Markets
Changing carbon-related costs, policy and regulatory changes and shifts in supply and demand factors
could lead to more expensive or more scarce products and services that are required by the Company in
its operations. This could lead to supply shortages, delivery delays and the need to source alternate
products and services. The Company seeks to mitigate these risks through close monitoring of such
developments and adaptive changes to supply chain procurement strategies.
Given concerns regarding carbon-emitting generation, those assets and businesses may, over time,
become difficult (or uneconomic) to insure in commercial insurance markets. In the short term, this may
be mitigated through increased investment in engineered protection or alternative risk financing (such as
funded self-insurance or regulatory structures, including storm reserves). Longer-term mitigation may be
achieved through infrastructure siting decisions and further engineered protections. This risk may also be
mitigated through the continued transition away from high-carbon generation sources to sources with low
or zero carbon dioxide emissions.
Policy
Government and regulatory initiatives, including greenhouse gas emissions standards, air emissions
standards and generation mix standards, are being proposed and adopted in many jurisdictions in
response to concerns regarding the effects of climate change. In some jurisdictions, government policy
has included timelines for mandated shutdowns of coal generating facilities, percentage of electricity
generation from renewables, carbon pricing, emissions limits and cap and trade mechanisms. Over the
medium and longer terms, this could potentially lead to a significant portion of hydrocarbon infrastructure
assets being subject to additional regulation and limitations in respect of GHG emissions and operations.
 
The Company is subject to climate-related and environmental legislative and regulatory requirements.
Such legislative and regulatory initiatives could adversely affect Emera’s operations and financial
performance. Refer to “Regulatory and Political Risk” and “Changes in Environmental Legislation” risk.
The Company seeks to mitigate these risks through active engagement with governments and regulators
to pursue transition strategies that meet the needs of customers, stakeholders and the Company. This
has included NSPI’s participation in negotiated equivalency agreements in Nova Scotia to provide for an
affordable transition to lower-carbon generation. Equivalency agreements allow NSPI to achieve
compliance with federal GHG emissions regulations by meeting provincial legislative and regulatory
requirements as they are deemed to be equivalent. There is no guarantee that such equivalency
agreements will be renewed or remain in force in the future.
Regulatory
Depending on the regulatory response to government legislation and regulations, the Company may be
exposed to the risk of reduced recovery through rates in respect of the affected assets. Valuation
impairments could result from such regulatory outcomes. Mitigation efforts in respect of these risks
include active engagement with policy makers and regulators to find mechanisms to avoid such impacts
while being responsive to customers’ and stakeholders’ objectives.
Legal
The Company could face litigation or regulatory action related to environmental harms from carbon
dioxide emissions or climate change public disclosure issues. The Company addresses these risks
through compliance with all relevant laws, emissions reduction strategies, and public disclosure of climate
change risks.
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Water Resources
For thermal plants requiring cooling water, reduced availability of water resulting from climate change
could adversely impact operations or the costs of operations. The Company seeks ways to reduce and
recycle water as it does in its Polk power plant in Florida, where recovered and treated wastewater is
used in operations to reduce reliance on fresh water supplies in an area where water is not as abundant
as in other markets.
 
The Company operates hydroelectric generation in certain of its markets. Such generation depends on
availability of water and the hydrological profile of water sources. Changes in precipitation patterns, water
temperatures and air temperatures could adversely affect the availability of water and consequently the
amount of electricity that may be produced from such facilities. The Company is reinvesting in the
efficiency of certain hydroelectric generation facilities to increase generation capacity and continues to
monitor changing hydrology patterns. Such issues may also affect the availability of third-party owned
hydroelectricity purchased power sources.
Weather Risk
The Company is subject to risks that arise or may arise from weather including seasonal variations
impacting energy sales, more frequent and intense weather events, changing air temperatures, wildfires
and extreme weather conditions associated with climate change. Refer to “Global Climate Change Risk”.
Fluctuations in the amount of electricity or natural gas used by customers can vary significantly in
response to seasonal changes in weather and could impact the operations, results of operations, financial
condition, and cash flows of the Company’s utilities. For example, Tampa Electric could see lower
demand in summer months if temperatures are cooler than expected. Further, extreme weather
conditions such as hurricanes and other severe weather conditions which may be associated with climate
change could cause these seasonal fluctuations to be more pronounced. In the absence of a regulatory
recovery mechanism for unanticipated costs, such events could influence the Company’s results of
operations, financial conditions or cash flows.
Extreme weather events create a risk of physical damage to the Company’s assets. High winds can
impact structures and cause widespread damage to transmission and distribution infrastructure, solar
generation, and wind powered generation. Increased frequency and severity of weather events increases
the likelihood that the duration of power outages and fuel supply disruptions could increase. Increased
frequency and intensity of flooding and storm surge could adversely affect the operations of utilities and in
particular generation assets. The impact of extreme weather events would be amplified if the same
events affect multiple utilities.
Each of Emera’s regulated electric utilities have programs for storm hardening of transmission and
distribution facilities to minimize damage, but there can be no assurance that these measures will fully
mitigate the risk. This risk to transmission and distribution facilities is typically not insured, and as such
the restoration cost is generally recovered through regulatory processes, either in advance through
reserves or designated self-insurance funds, or after the fact through the establishment of regulatory
assets. Recovery is not assured and is subject to prudency review. The risk to generation assets is, in
part, mitigated through the design, siting, construction and maintenance of such facilities, regular risk
assessments, engineered mitigation, emergency storm response plans, and insurance.
 
The risk of wildfires is addressed primarily through asset management programs for natural gas
transmission and distribution operations, and vegetation management programs for electric transmission
and distribution facilities. If it is found to be responsible for such a fire, the Company could suffer costs,
losses and damages, all or some of which may not be recoverable through insurance, legal, regulatory
cost recovery or other processes. If not recovered through these means, they could materially affect
Emera’s business and financial results including its reputation with customers, regulators, governments
and financial markets. Resulting costs could include fire suppression costs, regeneration, timber value,
increased insurance costs and costs arising from damages and losses incurred by third parties.
 
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Changes in Environmental Legislation
 
Emera is subject to regulation by federal, provincial, state, regional and local authorities regarding
environmental matters, primarily related to its utility operations. This includes laws setting GHG emissions
standards and air emissions standards. Emera is also subject to laws regarding waste management,
wastewater discharges and aquatic and terrestrial habitats.
Changes to GHG emissions standards and air emissions standards could adversely affect Emera’s
operations and financial performance. Legislative or regulatory changes could influence decisions
regarding early retirement of generation facilities and may result in stranded costs if the Company is not
able to fully recover the costs and investment in the affected generation assets. Recovery is not assured
and is subject to prudency review. Legislative or regulatory changes may curtail sales of natural gas to
new customers, which could reduce future customer growth in Emera’s natural gas businesses. Stricter
environmental laws and enforcement of such laws in the future could increase Emera’s exposure to
additional liabilities and costs. These changes could also affect earnings and strategy by changing the
nature and timing of capital investments.
In addition to imposing continuing compliance obligations, there are permit requirements, laws and
regulations authorizing the imposition of penalties for non-compliance, including fines, injunctive relief,
and other sanctions. The cost of complying with current and future environmental requirements is, and
may be, material to Emera. Failure to comply with environmental requirements or to recover
environmental costs in a timely manner through rates, could have a material adverse effect on Emera. In
addition, Emera’s business could be materially affected by changes in government policy, utility
regulation, and environmental and other legislation that could occur in response to environmental and
climate change concerns.
 
Emera manages its environmental risk by operating in a manner that is respectful and protective of the
environment and in compliance with applicable legal requirements and Company policy. Emera has
implemented this policy through the development and application of environmental management systems
in its operating subsidiaries. Comprehensive audit programs are in place to regularly test compliance.
 
Cybersecurity Risk
Emera is exposed to potential risks related to cyberattacks and unauthorized access. The Company
increasingly relies on IT systems network, and cloud infrastructure to manage its business and safely
operate its assets, including controls for interconnected systems of generation, distribution and
transmission as well as financial, billing and other business systems. Emera also relies on third-party
service providers to conduct business. As the Company operates critical infrastructure, it may be at
greater risk of cyberattacks by third parties, which could include nation-state-controlled parties. This risk
may be further elevated by geo-political risks such as the ongoing conflict between Russia and Ukraine.
Cyberattacks can reach the Company’s assets and information via their interfaces with third parties or the
public internet and gain access to critical infrastructures. Cyberattacks can also occur via personnel with
direct access to critical assets or trusted networks. Methods used to attack critical assets could include
general purpose or energy-sector-specific malware delivered via network transfer, removable media,
viruses, attachments, or links in e-mails. The methods used by attackers are continuously evolving and
can be difficult to predict and detect.
Despite security measures in place, that are described below, the Company’s systems, assets and
information could experience security breaches that could cause system failures, disrupt operations, or
adversely affect safety. Such breaches could compromise customer, employee-related or other
information systems and could result in loss of service to customers, unavailability of critical assets, safety
issues, or the release, destruction, or misuse of critical, sensitive or confidential information. These
breaches could also delay delivery or result in contamination or degradation of hydrocarbon products the
Company transports, stores or distributes.
 
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Cyberattacks or unauthorized accesses may cause costs, losses and damages all, or some of which, may
not be recoverable (through insurance, legal, regulatory cost recovery or other processes). This could
materially adversely affect Emera’s business and financial results including its reputation with customers,
regulators, governments and financial markets. Resulting costs could include, amongst others, response,
recovery and remediation costs, increased protection or insurance costs and costs arising from damages
and losses incurred by third parties. If any such security breaches occur, there is no assurance they can
be adequately addressed in a timely manner.
The Company seeks to manage these risks by aligning to a common set of cybersecurity standards and
policies derived, in part, on the National Institute of Standards and Technology’s Cyber Security
Framework, periodic security testing, program maturity objectives, cybersecurity incident readiness
program, and employee communication and training. With respect to certain of its assets, the Company is
required to comply with rules and standards relating to cybersecurity and IT including, but not limited to,
those mandated by bodies such as the North American Electric Reliability Corporation,
 
Northeast Power
Coordinating Council, and the United States Department of Homeland Security. The status of key
elements of the Company’s cybersecurity program is reported to the RSC.
Public Health Risk
An outbreak of infectious disease, a pandemic or a similar public health threat, such as the COVID-19
pandemic, or a fear of any of the foregoing, could adversely impact the Company, including causing
operating, supply chain and project development delays and disruptions, labour shortages and shutdowns
(including as a result of government regulation and prevention measures), which could have a negative
impact on the Company’s operations.
Any adverse changes in general economic and market conditions arising as a result of a public health
threat could negatively impact demand for electricity and natural gas, revenue, operating costs, timing
and extent of capital expenditures, results of financing efforts, or credit risk and counterparty risk; which
could result in a material adverse effect on the Company’s business. The Company maintains pandemic
and business contingency plans in each of its operations to manage and help mitigate the impact of any
such public health threat.
 
Energy Consumption Risk
Emera’s rate-regulated utilities are affected by demand for energy based on changing customer patterns
due to fluctuations in a number of factors including general economic conditions, weather events,
customers’ focus on energy efficiency, changes in rates, and advancements in new technologies such as
rooftop solar, electric vehicles and battery storage. Government policies promoting distributed generation,
and new technology developments that enable those policies, have the potential to impact how electricity
enters the system and how it is bought and sold. In addition, increases in distributed generation may
impact demand resulting in lower load and revenues. These changes could negatively impact Emera’s
operations, rate base, net earnings, and cash flows. The Company’s rate-regulated utilities are focused
on understanding customer demand, energy efficiency, and government policy to ensure that the impact
of these activities benefit customers, that they do not negatively impact the reliability of the energy service
and that they are addressed through regulations.
Foreign Exchange Risk
 
The Company is exposed to foreign currency exchange rate changes. Emera operates internationally,
with an increasing amount of the Company’s net income earned outside of Canada. As such, Emera is
exposed to movements in exchange rates between the CAD and, particularly, the USD, which could
positively or adversely affect results.
48
Consistent with the Company’s risk management policies, Emera manages currency risks through
matching United States denominated debt to finance its Unites States operations and may use foreign
currency derivative instruments to hedge specific transactions and earnings exposure. The Company may
enter FX forward and swap contracts to limit exposure on certain foreign currency transactions such as
fuel purchases, revenue streams and capital expenditures, and on net income earned outside of Canada.
The regulatory framework for the Company’s rate-regulated subsidiaries permits the recovery of prudently
incurred costs, including FX.
The Company does not utilize derivative financial instruments for foreign currency trading or speculative
purposes or to hedge the value of its investments in foreign subsidiaries. Exchange gains and losses on
net investments in foreign subsidiaries do not impact net income as they are reported in Accumulated
Other Comprehensive Income (Loss) ("AOCI”) (“AOCL”).
Liquidity and Capital Market Risk
Liquidity risk relates to Emera’s ability to ensure sufficient funds are available to meet its financial
obligations. Emera manages this risk by forecasting cash requirements on a continuous basis to
determine whether sufficient funds are available. Liquidity and capital needs could be financed through
internally generated cash flows, asset sales, short-term credit facilities, and ongoing access to capital
markets. The Company reasonably expects liquidity sources to exceed capital needs.
Emera’s access to capital and cost of borrowing is subject to several risk factors, including financial
market conditions, market disruptions and ratings assigned by credit rating agencies. Disruptions in
capital markets could prevent Emera from issuing new securities or cause the Company to issue
securities with less than preferred terms and conditions. Emera’s growth plan requires significant capital
investments in PP&E and the risk associated with changes in interest rates could have an adverse effect
on the cost of financing. The Company’s future access to capital and cost of borrowing may be impacted
by various market disruptions. The inability to access cost-effective capital could have a material impact
on Emera’s ability to fund its growth plan.
 
Emera is subject to financial risk associated with changes in its credit ratings. There are a number of
factors that rating agencies evaluate to determine credit ratings, including the Company’s business, its
regulatory framework and legislative environment, political interference in the regulatory process, the
ability to recover costs and earn returns, diversification, leverage, liquidity and increased exposure to
climate change-related impacts, including increased frequency and severity of hurricanes and other
severe weather events. A decrease in a credit rating could result in higher interest rates in future
financings, increased borrowing costs under certain existing credit facilities, limit access to the
commercial paper market, or limit the availability of adequate credit support for subsidiary operations. For
certain derivative instruments, if the credit ratings of the Company were reduced below investment grade,
the full value of the net liability of these positions could be required to be posted as collateral. Emera
manages these risks by actively monitoring and managing key financial metrics with the objective of
sustaining investment grade credit ratings.
The Company has exposure to its own common share price through the issuance of various forms of
stock-based compensation, which affect earnings through revaluation of the outstanding units every
period. The Company uses equity derivatives to reduce the earnings volatility derived from stock-based
compensation.
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General Economic Risk
The Company has exposure to the macro-economic conditions in North America and in other geographic
regions in which Emera operates. Like most utilities, economic factors such as consumer income,
employment and housing affect demand for electricity and natural gas and, in turn, the Company’s
financial results. Adverse changes in general economic conditions and inflation may impact the ability of
customers to afford rate increases arising from increases to fuel, operating, capital, environmental
compliance, and other costs, and therefore could materially affect Emera and its utilities. This may also
result in higher credit and counterparty risk, adverse shifts in government policy and legislation, and/or
increased risk to full and timely recovery of costs and regulatory assets.
Interest Rate Risk
Emera utilizes a combination of fixed and floating rate debt financing for operations and capital
expenditures, resulting in an exposure to interest rate risk. Emera seeks to manage interest rate risk
through a portfolio approach that includes the use of fixed and floating rate debt with staggered
maturities. The Company will, from time to time, issue long-term debt or enter interest rate hedging
contracts to limit its exposure to fluctuations in floating interest rate debt.
 
For Emera’s regulated subsidiaries, the cost of debt is a component of rates and prudently incurred debt
costs are recovered from customers. Regulatory ROE will generally follow the direction of interest rates,
such that regulatory ROEs are likely to fall in times of reducing interest rates and rise in times of
increasing interest rates, albeit not directly and generally with a lag period reflecting the regulatory
process. Rising interest rates may also negatively affect the economic viability of project development
and acquisition initiatives.
As with most other utilities and other similar yield-returning investments, Emera’s share price may be
affected by changes in interest rates and could underperform the market in an environment of rising
interest rates.
Inflation Risk
 
The Company may be exposed to changes in inflation that may result in increased operating and
maintenance costs, capital investment, and fuel costs compared to the revenues provided by customer
rates. Emera’s utilities have budgeting and forecasting processes to identify inflationary risk factors and
measure operating performance, as well as collective bargaining agreements that mitigate the short-term
impact of inflation on labour costs.
Project Development and Land Use Rights Risk
The Company’s capital plan includes significant investment in generation, infrastructure modernization,
and customer-focused technologies. Any projects planned or currently in construction, particularly
significant capital projects, may be subject to risks including, but not limited to, impact on costs from
schedule delays, risk of cost overruns, ensuring compliance with operating and environmental
requirements and other events within or beyond the Company’s control. The Company’s projects may
also require approvals and permits at the federal, provincial, state, regional and local levels. There is no
assurance that Emera will be able to obtain the necessary project approvals or applicable permits or
receive regulatory approval to recover the costs in rates.
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Some of the Company’s assets are located on land owned by third parties, including Indigenous Peoples,
and may be subject to land claims. Present or future assets may be located on lands that have been used
for traditional purposes and therefore subject to specific consultations, consents, or conditions for
development or operation. If the Company’s rights to locate and operate its assets on any such lands are
subject to expiry or become invalid, it may incur material costs to renew rights or obtain such rights. If
reasonable terms for land-use rights cannot be negotiated, the Company may incur significant costs to
remove and relocate its assets and restore the land. Additional costs incurred could cause projects to be
uneconomical to proceed with.
Emera manages these project development and land use rights risks by deploying robust project and risk
management approaches, led by teams with extensive experience in large projects. The Company
consults with Indigenous Peoples in obtaining approvals, constructing, maintaining and operating such
facilities, consistent with laws and public policy frameworks. Emera maintains relationships through on-
going communications with stakeholders, including Indigenous Peoples, landowners and governments.
Counterparty Risk
Emera is exposed to risk related to its reliance on certain key partners, suppliers, and customers, any of
which may endure financial challenges resulting from commodity price and market volatility, economic
instability or adversity, adverse political or regulatory changes and other causes which may cause or
contribute to such parties’ insolvency, bankruptcy,
 
restructuring or default on their contractual obligations
to Emera.
 
Emera is also exposed to potential losses related to amounts receivable from customers,
energy marketing collateral deposits and derivative assets due to a counterparty’s non-performance
under an agreement.
Emera manages this counterparty risk through due diligence and third-party risk assessment processes
prior to signing contracts, contractual rights and remedies, regulatory frameworks, and by monitoring
significant developments with its customers, partners and suppliers. The Company also manages credit
risk with policies and procedures for counterparty analysis, exposure measurement, and exposure
monitoring and mitigation. Credit assessments may be conducted on new customers and counterparties,
and deposits or collateral may be requested on certain accounts. There is no assurance that
management strategies will be effective,
 
and significant counterparty defaults could have a material effect
on the Company.
Country Risk
The majority of Emera’s earnings are from outside of Canada, mostly concentrated in the United States.
Emera’s investments are currently in regions where political and economic risks are considered by the
Company to be acceptable. For more information, refer to the “Regulatory and Political Risk” and
“General Economic Risk” sections above. Emera’s operations in some countries may be subject to
changes in economic growth, restrictions on the repatriation of income or capital exchange controls,
inflation, the effect of global health, safety and environmental matters, including climate change, or
economic conditions and market conditions, and change in financial policy and availability of credit. The
Company mitigates this risk through a rigorous approval process for investment, and by forecasting cash
requirements on a continuous basis to determine whether sufficient funds are available in all affiliates.
 
Commodity Price Risk
The Company’s utility fuel supply is subject to commodity price risk. In addition, Emera Energy is subject
to commodity price risk through its portfolio of commodity contracts and arrangements.
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The Company manages this risk through established processes and practices to identify, monitor, report
and mitigate these risks. These include the Company’s commercial arrangements, such as the
combination of supply and purchase agreements, asset management agreements, pipeline transportation
agreements, and financial hedging instruments. In addition, its credit policies, counterparty credit
assessments, market and credit position reporting, and other risk management and reporting practices,
are also used to manage and mitigate this risk.
Regulated Utilities
The Company’s utility fuel supply is exposed to broader global conditions, which may include impacts on
delivery reliability and price, despite contracted terms. Supply and demand dynamics in fuel markets can
be affected by a wide range of factors which are difficult to predict and may change rapidly, including but
not limited to, currency fluctuations, changes in global economic conditions, natural disasters,
transportation or production disruptions, and geo-political risks, such as political instability, conflicts,
changes to international trade agreements, trade sanctions or embargos. The Company seeks to manage
this risk using financial hedging instruments and physical contracts and through contractual protection
with counterparties, where applicable.
 
The majority of Emera’s regulated electric and gas utilities have adopted and implemented fuel
adjustment mechanisms and purchased gas adjustment mechanisms respectively, which further helps
manage commodity price risk, as the regulatory framework for the Company’s rate-regulated subsidiaries
permits the recovery of prudently incurred fuel and gas costs. There is no assurance that such
mechanisms and regulatory frameworks will continue to exist in the future. Prolonged and substantial
increases in fuel prices could result in decreased rate affordability, increased risk of recovery of costs or
regulatory assets, and/or negative impacts on customer consumption patterns and sales.
Emera Energy Marketing and Trading
Emera Energy has employed further measures to manage commodity risk. The majority of Emera
Energy’s portfolio of electricity and gas marketing and trading contracts and, in particular, its natural gas
asset management arrangements, are contracted on a back-to-back basis, avoiding any material long or
short commodity positions. However, the portfolio is subject to commodity price risk, particularly with
respect to basis point differentials between relevant markets in the event of an operational issue or
counterparty default. Changes in commodity prices can also result in increased collateral requirements
associated with physical contracts and financial hedges, resulting in higher liquidity requirements and
increased costs to the business.
To
 
measure commodity price risk exposure, Emera Energy employs a number of controls and processes,
including an estimated VaR analysis of its exposures. The VaR
 
amount represents an estimate of the
potential change in fair value that could occur from changes in Emera Energy’s portfolio or changes in
market factors within a given confidence level, if an instrument or portfolio is held for a specified time
period. The VaR calculation is used to quantify exposure to market risk associated with physical
commodities, primarily natural gas and power positions.
52
Future Employee Benefit Plan Performance and Funding Risk
Emera subsidiaries have both defined benefit and defined contribution employee pension plans that cover
their employees and retirees. All defined benefit plans are closed to new entrants, except for the TECO
Energy Group Retirement Plan. The cost of providing these benefit plans varies depending on plan
provisions, interest rates, inflation, investment performance and actuarial assumptions concerning the
future. Actuarial assumptions include earnings on plan assets, discount rates (interest rates used to
determine funding levels, contributions to the plans and the pension and post-retirement liabilities) and
expectations around future salary growth, inflation and mortality. Three of the largest drivers of cost are
investment performance, interest rates and inflation, which are affected by global financial and capital
markets. Depending on future interest rates and future inflation and actual versus expected investment
performance, Emera could be required to make larger contributions in the future to fund these plans,
which could adversely affect Emera’s cash flows, financial condition and operations.
Each of Emera’s employee defined benefit pension plans are managed according to an approved
investment policy and governance framework. Emera employs a long-term approach with respect to asset
allocation and each investment policy outlines the level of risk which the Company is prepared to accept
with respect to the investment of the pension funds in achieving both the Company’s fiduciary and
financial objectives. Studies are routinely undertaken approximately every five years with the objective
that the plans’ asset allocations are appropriate for meeting Emera’s long-term pension objectives.
Labour Risk
Emera’s ability to deliver service to its customers and to execute its growth plan depends on attracting,
developing and retaining a skilled workforce. Utilities are faced with demographic challenges related to
trades, technical staff and engineers with an increasing number of employees expected to retire over the
next several years. Failure to attract, develop and retain an appropriately qualified workforce could
adversely affect the Company’s operations and financial results. Emera seeks to manage this risk through
maintaining competitive compensation programs, a dedicated talent acquisition team, human resources
programs and practices, including ethics and diversity training, employee engagement surveys,
succession planning for key positions and apprenticeship programs.
Approximately 32 per cent of Emera’s labour force is represented by unions and subject to collective
labour agreements. The inability to maintain or negotiate future agreements on acceptable terms could
result in higher labour costs and work disruptions, which could adversely affect service to customers and
have an adverse effect on the Company’s earnings, cash flow and financial position. Emera seeks to
manage this risk through ongoing discussions and working to maintain positive relationships with local
unions. The Company maintains contingency plans in each of its operations to manage and reduce the
effect of any potential labour disruption.
IT Risk
Emera relies on various IT systems to manage operations. This subjects Emera to inherent costs and
risks associated with maintaining, upgrading, replacing and changing these systems. This includes
impairment of its IT, potential disruption of internal control systems, substantial capital expenditures,
demands on management time and other risks of delays, difficulties in upgrading existing systems,
transitioning to new systems or integrating new systems into its current systems. Emera’s digital
transformation strategy, including investment in infrastructure modernization and customer focused
technologies, is driving increased investment in IT solutions, resulting in increased project risks
associated with the implementation of these solutions.
 
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Emera manages these risks through IT asset lifecycle planning and management, governance, internal
auditing and testing of systems, and executive oversight. Employees with extensive subject matter
expertise assist in risk identification and mitigation, project management, implementation, change
management and training. System resiliency, formal disaster recovery and backup processes, combined
with critical incident response practices, table-top exercises, and simulations, help mitigate operational
disruptions.
 
Income Tax Risk
The computation of the Company’s provision for income taxes is impacted by changes in tax legislation in
Canada, the United States and the Caribbean. Any such changes could affect the Company’s future
earnings, cash flows, and financial position. The value of Emera’s existing deferred tax assets and
liabilities are determined by existing tax laws and could be negatively impacted by changes in laws.
Emera monitors the status of existing tax laws to ensure that changes impacting the Company are
appropriately reflected in the Company’s tax compliance filings and financial results.
System Operating and Maintenance Risks
The safe and reliable operation of electric generation and electric and natural gas transmission and
distribution systems is critical to Emera’s operations. There are a variety of hazards and operational risks
inherent in operating electric utilities and natural gas transmission and distribution pipelines. Electric
generation, transmission and distribution operations can be impacted by risks such as mechanical
failures, supply chain issues impacting timely access to critical equipment, activities of third parties,
terrorism, cyberattacks, damage to facilities, solar panels and infrastructure caused by hurricanes,
storms, falling trees, lightning strikes, floods, fires and other natural disasters. Natural gas pipeline
operations can also be impacted by risks such as leaks, explosions, mechanical failures, activities of third
parties, terrorism, cyberattacks, and damage to the pipeline facilities and equipment caused by
hurricanes, storms, floods, fires and other natural disasters. Refer to “Global Climate Change Risk” and
“Weather Risk”. Electric utility and natural gas transmission and distribution pipeline operation interruption
could negatively affect revenue, earnings, and cash flows as well as customer and public confidence, and
public safety.
Emera manages these risks by investing in a highly skilled workforce, operating prudently, preventative
maintenance, safety and operations management systems, third-party risk program, and making effective
capital investments. Insurance, warranties, or recovery through regulatory mechanisms may not cover
any or all these losses, which could adversely affect the Company’s results of operations and cash flows.
 
Fuel Supply Disruptions
Emera’s electric and natural gas utilities are also exposed to the risk of fuel supply chain disruptions, both
within and outside their service territories, which may be caused by severe weather or natural disasters.
This may also be caused by damage to, operational issues with, terrorist or cyberattacks on, third party
fuel production, storage, pipeline, and distribution facilities. The risk of fuel supply disruptions is managed
through contractual protections, maintaining a diversity of fuel suppliers and transportation contracts, and
contracting for access to third-party storage facilities. Significant unanticipated fuel supply disruptions,
such as those which arose from Winter Storm Uri in February 2021, could result in increased exposure to
commodity price risk for Emera’s regulated electric and gas utilities and Emera Energy, and these could
have adverse effects on service to utility customers and on the Company’s reputation, earnings, cash flow
and financial position.
 
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Uninsured Risk
Emera and its subsidiaries maintain insurance to cover accidental loss suffered to its facilities and to
provide indemnity in the event of liability to third parties. This is consistent with Emera’s risk management
policies. Certain facilities, in particular coal and other thermal generation, may, over time, become more
difficult (or uneconomic) to insure as a result of the impact of global climate change. Refer to “Global
Climate Change Risk – Markets”. There are certain elements of Emera’s operations which are not
insured. These include a significant portion of its electric utilities’ transmission and distribution assets, as
is customary in the industry. The cost of this coverage is not economically viable. In addition, Emera
accepts deductibles and self-insured retentions under its various insurance policies. Insurance is subject
to coverage limits as well as time sensitive claims discovery and reporting provisions and there can be no
assurance that the types of liabilities or losses that may be incurred by the Company and its subsidiaries
will be covered by insurance.
The occurrence of significant uninsured claims, claims in excess of the insurance coverage limits
maintained by Emera and its subsidiaries, or claims that fall within a significant self-insured retention
could have a material adverse effect on Emera’s results of operations, cash flows and financial position, if
regulatory recovery is not available.
The Company mitigates its uninsured risk by ensuring insurance limits align with risk exposures, and for
uninsured assets and operations, that appropriate risk assessments and mitigation measures are in
place. The regulatory framework for the Company’s rate-regulated subsidiaries permits the recovery of
prudently incurred costs, including uninsured losses.
 
RISK MANAGEMENT INCLUDING FINANCIAL
INSTRUMENTS
 
Emera’s risk management policies and procedures provide a framework through which management
monitors various risk exposures. The risk management policies and practices are overseen by the Board
of Directors. The Company has established a number of processes and practices to identify, monitor,
report on and mitigate material risks to the Company. This includes establishment of the ERMC, whose
responsibilities include preparing an updated risk dashboard and heat map presented at regular meetings
of the Board’s Risk and Sustainability Committee. Furthermore, a corporate team independent from
operations is responsible for tracking and reporting on market and credit risks.
The Company manages its exposure to normal operating and market risks relating to commodity prices,
FX, interest rates and share prices through contractual protections with counterparties where practicable,
and by using financial instruments consisting mainly of FX forwards and swaps, interest rate options and
swaps, equity derivatives, and coal, oil and gas futures, options, forwards and swaps. In addition, the
Company has contracts for the physical purchase and sale of natural gas. These physical and financial
contracts are classified as held-for-trading (“HFT”). Collectively, these contracts and financial instruments
are considered derivatives.
The Company recognizes the fair value of all its derivatives on its balance sheet, except for non-financial
derivatives that meet the normal purchases and normal sales (“NPNS”) exception. Physical contracts that
meet the NPNS exception are not recognized on the balance sheet; these contracts are recognized in
income when they settle. A physical contract generally qualifies for the NPNS exception if the transaction
is reasonable in relation to the Company’s business needs, the counterparty owns or controls resources
within the proximity to allow for physical delivery, the Company intends to receive physical delivery of the
commodity, and the Company deems the counterparty creditworthy.
 
The Company continually assesses
contracts designated under the NPNS exception and will discontinue the treatment of these contracts
under this exemption where the criteria are no longer met.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
55
Derivatives qualify for hedge accounting if they meet stringent documentation requirements and can be
proven to effectively hedge the identified risk both at the inception and over the term of the instrument.
Specifically, for cash flow hedges, the change in the fair value of derivatives is deferred to AOCI and
recognized in income in the same period the related hedged item is realized. Where the documentation or
effectiveness requirements are not met, the derivatives are recognized at fair value with any changes in
fair value recognized in net income in the reporting period, unless deferred as a result of regulatory
accounting.
Derivatives entered into by NSPI, NMGC and GBPC that are documented as economic hedges or for
which the NPNS exception has not been taken, are subject to regulatory accounting treatment. The
change in fair value of the derivatives is deferred to a regulatory asset or liability. The gain or loss is
recognized in the hedged item when the hedged item is settled. Management believes any gains or
losses resulting from settlement of these derivatives related to fuel for generation and purchased power
will be refunded to or collected from customers in future rates. Tampa Electric has no derivatives related
to hedging as a result of a FPSC approved five-year moratorium on hedging of natural gas purchases
which ended on December 31, 2022. Tampa Electric’s moratorium on hedging of natural gas purchases
will continue through December 31, 2024, as a result of Tampa Electric’s 2021 rate case settlement
agreement.
Derivatives that do not meet any of the above criteria are designated as HFT, with changes in fair value
normally recorded in net income of the period. The Company has not elected to designate any derivatives
to be included in the HFT category where another accounting treatment would apply.
Derivative Assets and Liabilities Recognized on the Balance Sheet
As at
December 31
December 31
millions of dollars
2022
2021
Regulatory Deferral:
Derivative instrument assets
(1)
$
 
238
$
 
237
Derivative instrument liabilities
(2)
 
(25)
 
(20)
Regulatory assets
(1)
 
30
 
23
Regulatory liabilities
 
(2)
 
(230)
 
(241)
Net asset (liability)
$
 
13
$
 
(1)
HFT Derivatives:
 
Derivative instrument assets
 
(1)
$
 
153
$
 
53
Derivatives instruments liabilities
(2)
 
(1,025)
 
(662)
Net liability
$
 
(872)
$
 
(609)
Other Derivatives:
Derivative instrument assets
(1)
$
 
5
$
 
11
Derivatives instruments liabilities
 
(2)
 
(28)
 
-
 
Net asset (liability)
$
 
(23)
$
 
11
(1) Current and other assets.
(2) Current and long-term liabilities.
 
 
 
 
 
 
 
 
56
Realized and Unrealized Gains (Losses) Recognized in Net Income
For the
Year ended December 31
millions of dollars
2022
2021
Regulatory Deferral:
Regulated fuel for generation and purchased power
(1)
$
 
210
$
 
34
HFT Derivatives:
Non-regulated operating revenues
$
 
64
$
 
(138)
Other Derivatives:
OM&G
$
 
(22)
$
 
26
Other income, net
 
(24)
 
3
Net gains (losses)
$
 
(46)
$
 
29
Total net gains (losses)
$
 
228
$
 
(75)
(1)
 
Realized gains (losses) on derivative instruments settled and consumed in the period, hedging relationships
 
that have been
terminated or the hedged transaction is no longer probable. Realized gains (losses) recorded in inventory will be recognized
 
in
“Regulated fuel for generation and purchased power” when the hedged item is consumed.
As of December 31, 2022, the unrealized gain in AOCI was $16 million, net of tax (2021 – $18 million, net
of tax). For the year ended December 31, 2022, unrealized gains of $2 million (2021 – $1 million), have
been reclassified into interest expense.
 
DISCLOSURE AND INTERNAL CONTROLS
Management is responsible for establishing and maintaining adequate disclosure controls and
procedures (“DC&P”) and internal control over financial reporting (“ICFR”), as defined in National
Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings (“NI 52-109”). The
Company’s internal control framework is based on the criteria published in the Internal Control -
Integrated Framework (2013), a report issued by the Committee of Sponsoring Organizations (“COSO”) of
the Treadway Commission. Management, including the Chief Executive Officer and Chief Financial
Officer, evaluated the design and effectiveness of the Company’s DC&P and ICFR as at December 31,
2022 to provide reasonable assurance regarding the reliability of financial reporting in accordance with
USGAAP.
Management recognizes the inherent limitations in internal control systems, no matter how well designed.
Control systems determined to be appropriately designed can only provide reasonable assurance with
respect to the reliability of financial reporting and may not prevent or detect all misstatements.
There were no changes in the Company’s ICFR, during the year ended December 31, 2022, that have
materially affected, or are reasonably likely to materially affect, the Company’s internal control over
financial reporting.
CRITICAL ACCOUNTING ESTIMATES
The preparation of consolidated financial statements in accordance with USGAAP requires management
to make estimates and assumptions. These may affect the reported amounts of assets and liabilities at
the date of the financial statements and reported amounts of revenues and expenses during the reporting
periods. Significant areas requiring use of management estimates relate to rate-regulated assets and
liabilities, accumulated reserve for cost of removal, pension and post-retirement benefits, unbilled
revenue, useful lives for depreciable assets, goodwill and long-lived assets impairment assessments,
income taxes, asset retirement obligations (“ARO”), and valuation of financial instruments. Management
evaluates the Company’s estimates on an ongoing basis based upon historical experience, current and
expected conditions and assumptions believed to be reasonable at the time the assumption is made, with
any adjustments recognized in income in the year they arise.
57
Rate Regulation
The rate-regulated accounting policies of Emera’s rate-regulated subsidiaries and regulated equity
investments are subject to examination and approval by their respective regulators and may differ from
the accounting policies of non-rate-regulated companies. Differences occur when regulators render their
decisions on rate applications or other matters, and generally involve a difference in the timing of revenue
and expense recognition. The accounting for these items is based on expectations of the future actions of
the regulators. Assumptions and judgments used by regulatory authorities continue to have an impact on
the recovery of costs, the rate earned on invested capital, and the timing and amount of assets to be
recovered. The application of regulatory accounting guidance is a critical accounting policy as a change in
these assumptions may result in a material impact on reported assets, liabilities and the results of
operations.
As at December 31, 2022, the Company has recorded $3,620 million (2021 – $2,566 million) of regulatory
assets and $2,273 million (2021 – $2,055 million) of regulatory liabilities.
Accumulated Reserve – Cost of Removal
Tampa
 
Electric, PGS, NMGC and NSPI recognize non-ARO costs of removal (“COR”) as regulatory
liabilities. The non-ARO COR represent estimated funds received from customers through depreciation
rates to cover future COR of PP&E upon retirement that are not legally required. The companies accrue
for COR over the life of the related assets based on depreciation studies approved by their respective
regulators. The costs are estimated based on historical experience and future expectations, including
expected timing and estimated future cash outlays. As at December 31, 2022, the balance of the
Accumulated reserve – COR within regulatory liabilities was $895 million (2021 – $819 million).
Pension and Other Post-Retirement Employee Benefits
The Company provides post-retirement benefits to employees, including defined benefit pension plans.
The cost of providing these benefits is dependent upon many factors that result from actual plan
experience and assumptions of future expectations.
The accounting related to employee post-retirement benefits is a critical accounting estimate. Changes in
the estimated benefit obligation, affected by employee demographics, including age, compensation
levels, employment periods, contribution levels and earnings, could have a material impact on reported
assets, liabilities, accumulated other comprehensive income and results of operations. Changes in key
actuarial assumptions, including anticipated rates of return on plan assets and discount rates used in
determining the accrued benefit obligation and benefit costs, could change annual funding requirements.
This could have a significant impact on the Company’s annual earnings and cash requirements.
The pension plan assets are comprised primarily of equity and fixed income investments. Fluctuations in
actual equity market returns and changes in interest rates may result in changes to pension costs in
future periods.
The Company’s accounting policy is to amortize the net actuarial gain or loss that exceeds 10 per cent of
the greater of the projected benefit obligation / accumulated post-retirement benefit obligation (“PBO”)
and the market-related value of assets, over active plan members’ average remaining service period. For
the largest plans this is currently 8.3 years (8.7 years for 2022 benefit cost) for the Canadian plans and a
weighted average of 11.4 years for the United States plans). The Company’s use of smoothed asset
values reduces volatility related to the amortization of actuarial investment experience. As a result, the
main cause of volatility in reported pension cost is the discount rate used to determine the PBO.
 
 
 
 
 
 
 
 
 
 
 
58
The discount rate used to determine benefit costs is based on the yield of high quality long-term corporate
bonds in each operating entity’s country and is determined with reference to bonds which have the same
duration as the PBO as at January 1 of the fiscal year. The following table shows the discount rate for
benefit cost purposes and the expected return on plan assets for each plan:
2022
2021
Discount rate for
benefit cost
purposes
Expected
return on
 
plan assets
Discount rate for
benefit cost purposes
Expected
return on
plan assets
TECO Energy Group Retirement
Plan
2.78%
6.50%
2.38%
6.70%
TECO Energy Group Supplemental
Executive Retirement Plan
(1)
2.35/5.33%
N/A
1.84%
N/A
TECO Energy Group Benefit
Restoration Plan (1)
2.27/4.19/5.48%
N/A
1.71%
N/A
TECO Energy Post-retirement
Health and Welfare Plan
2.84%
N/A
2.47%
N/A
New Mexico Gas Company Retiree
Medical Plan
2.85%
1.50%
2.49%
4.00%
NSPI
 
3.25%, 3.48%
5.75%
2.59%, 2.85%
5.25%
GBPC Salaried
5.75%
6.00%
4.25%
6.00%
GBPC Union
5.75%
5.35%
5.65%
5.65%
(1) The discount rate and expected return on assets for benefit cost purposes is updated throughout the year as special events
occur, such as settlements and curtailments.
Based on management’s estimate, the reported benefit cost for defined benefit and defined contribution
plans was $64 million in 2022 (2021 – $85 million). The reported benefit cost is impacted by numerous
assumptions, including the discount rate and asset return assumptions. A 0.25 per cent change in the
discount rate and asset return assumptions would have had +/- impact on the 2022 benefit cost of $0.5
million and $1 million respectively (2021 – $1 million and $3 million).
 
Unbilled Revenue
Electric and gas revenues are billed on a systematic basis over a one or two-month period for NSPI and a
one-month period for other Emera utilities. At the end of each month, the Company must make an
estimate of energy delivered to customers since the date their meter was last read and determine related
revenues earned but not yet billed. The unbilled revenue is estimated based on several factors, including
current month’s generation, estimated customer usage by class, weather, line losses, inter-period
changes to customer classes and applicable customer rates. Based on the extent of estimates included in
the determination of unbilled revenue, actual results may differ from the estimate. At December 31, 2022,
unbilled revenues totalled $424 million (2021 – $318 million) on total regulated operating revenues of
$7,154 million (2021 – $5,926 million).
Property, Plant and Equipment
PP&E represents 58 per cent of total assets on the Company’s balance sheet and include the generation,
transmission and distribution, and other assets of the Company.
Depreciation is determined by the straight-line method, based on the estimated remaining service lives of
the depreciable assets in each category. The service lives of regulated PP&E are determined based on
depreciation studies and require appropriate regulatory approval. Due to the magnitude of the Company’s
PP&E, changes in estimated depreciation rates can have a material impact on depreciation expense and
accumulated depreciation.
Depreciation expense was $927 million for the year ended December 31, 2022 (2021 – $877 million).
59
Goodwill Impairment Assessments
Goodwill is calculated as the excess of the purchase price of an acquired entity over the estimated fair
values of identifiable assets acquired, and liabilities assumed at the acquisition date. Goodwill is carried
at initial cost less any write-down for impairment and is adjusted for the impact of foreign exchange.
Under the applicable accounting guidance, goodwill is subject to assessment for impairment at the
reporting unit level annually, or if an event or change in circumstances indicates that the fair value of a
reporting unit may be below its carrying value. Application of the goodwill impairment test requires
management judgment on significant assumptions and estimates. When assessing goodwill for
impairment, the Company has the option of first performing a qualitative assessment to determine
whether a quantitative assessment is necessary. In performing a qualitative assessment management
considers, among other factors, macroeconomic conditions, industry and market considerations and
overall financial performance.
If the Company performs the qualitative assessment and determines that it is more likely than not that its
fair value is less than its carrying amount, or if the Company chooses to bypass the qualitative
assessment, a quantitative test is performed. The quantitative test compares the fair value of the
reporting unit to its carrying amount, including goodwill. If the carrying amount of the reporting unit
exceeds its fair value, an impairment loss is recorded. Significant assumptions used in estimating the fair
value include discount and growth rates, rate case assumptions including future cost of capital, valuation
of the reporting units' net operating loss (“NOL”) and projected operating and capital cash flows. Adverse
changes in these assumptions could result in a future material impairment of the goodwill assigned to
Emera’s reporting units.
As of December 31, 2022, $6,009 million of Emera’s goodwill represents the excess of the acquisition
purchase price for TECO Energy (Tampa Electric, PGS and NMGC reporting units) over the fair values
assigned to identifiable assets acquired and liabilities assumed. In Q4 2022, qualitative assessments
were performed for Tampa Electric and PGS given the significant excess of fair value over carrying
amounts calculated during the last quantitative test in Q4 2019. Management concluded it was more likely
than not that the fair value of these reporting units exceeded their respective carrying amounts, including
goodwill. As such, no quantitative testing was required. For the NMGC reporting unit, Emera elected to
bypass a qualitative assessment and performed a quantitative impairment assessment using a
combination of the income and market approach. This assessment estimated that the fair value of the
NMGC reporting unit exceeded its carrying amount, including goodwill. As a result of this assessment, no
impairment charges were recognized.
In Q4 2022, the Company elected to bypass a qualitative assessment and performed a quantitative
impairment assessment for GBPC, using the income approach, as this reporting unit is sensitive to
changes in assumptions due to limited excess of fair value over the carrying value, including goodwill.
Although the cash flows of GBPC have not changed significantly compared to previous periods, it was
determined that the carrying value, including goodwill, exceeded the fair value, due to an increase in
discount rates. The discount rate for the reporting unit was negatively impacted by changes in the macro-
economic environment, including the risk-free rate assumption. As a result of this assessment, a goodwill
impairment charge of $73 million was recorded in 2022, reducing the GBPC goodwill balance to nil as at
December 31, 2022. No impairment was recorded in 2021. For further detail, refer to note 22.
As of December 31, 2022, the Company had goodwill with a total carrying amount of $6,012 million
(December 31, 2021 – $5,696 million). The change in the carrying value of goodwill from 2021 to 2022
was a result of the effect of the FX translation of Emera’s foreign affiliates, partially offset by the GBPC
impairment.
60
Long-Lived Assets Impairment Assessments
In accordance with accounting guidance for long-lived assets, the Company assesses whether there has
been an impairment of long-lived assets and intangibles when a triggering event occurs, such as a
significant market disruption or the sale of a business. The assessment involves comparing the
undiscounted expected future cash flows, to the carrying value of the asset. When the undiscounted cash
flow analysis indicates a long-lived asset is not recoverable, the amount of the impairment loss is
determined by measuring the excess of the carrying amount of the long-lived asset over its estimated fair
value.
The Company believes accounting estimates related to asset impairments are critical estimates, as they
are highly susceptible to change and the impact of an impairment on reported assets and earnings could
be material. Management is required to make assumptions based on expectations regarding the results
of operations for significant/indefinite future periods and the current and expected market conditions in
such periods. Markets can experience significant uncertainties. Estimates based on the Company’s
assumptions relating to future results of operations or other recoverable amounts are based on a
combination of historical experience, fundamental economic analysis, observable market activity and
independent market studies. The Company’s expectations regarding uses and holding periods of assets
are based on internal long-term budgets and projections, which consider external factors and market
forces, as of the end of each reporting period. Assumptions made by management are consistent with
generally accepted industry approaches and assumptions used for valuation and pricing activities.
As at December 31, 2022, there were no indications of impairment of Emera’s long-lived assets. No
impairment charges were recognized in either 2022 or 2021.
Income Taxes
 
Income taxes are determined based on the expected tax treatment of transactions recorded in the
consolidated financial statements. In determining income taxes, tax legislation is interpreted in a variety of
jurisdictions, the likelihood that deferred tax assets will be realized is assessed and assumptions about
the expected timing of the reversal of deferred tax assets and liabilities are made. Uncertainty associated
with application of tax statutes and regulations and the outcomes of tax audits and appeals, requires that
judgments and estimates be made in the accrual process and in the calculation of effective tax rates.
Only income tax benefits that meet the “more likely than not” threshold may be recognized or continue to
be recognized. Unrecognized tax benefits are evaluated quarterly and changes are recorded based on
new information, including issuance of relevant guidance by the courts or tax authorities and
developments in examinations of the Company’s tax returns.
The Company believes the accounting estimates related to income taxes are critical estimates. The
realization of deferred tax assets is dependent upon the generation of sufficient taxable income, both
operating and capital, in future periods. A change in the estimated valuation allowance could have a
material impact on reported assets and results of operations. Administrative actions of the tax authorities,
changes in tax law or regulation, and the uncertainty associated with the application of tax statutes and
regulations, could change the Company’s estimate of income taxes, including the potential for elimination
or reduction of the Company’s ability to realize tax benefits and to utilize deferred tax assets.
 
Asset Retirement Obligations
Measurement of the fair value of AROs requires the Company to make reasonable estimates concerning
the method and timing of settlement associated with the legally obligated costs. There are uncertainties in
estimating future asset-retirement costs due to potential events, such as changing legislation or
regulations, and advances in remediation technologies. Emera has AROs associated with the remediation
of generation, transmission, distribution and pipeline assets.
 
61
An ARO represents the fair value of the estimated cash flows necessary to discharge the future obligation
using the Company’s credit-adjusted risk-free rate. The amounts are reduced by actual expenditures
incurred. Estimated future cash flows are based on completed depreciation studies, remediation reports,
prior experience, estimated useful lives, and governmental regulatory requirements. The present value of
the liability is recorded and the carrying amount of the related long-lived asset is correspondingly
increased. The amount capitalized at inception is depreciated in the same manner as the related long-
lived asset. Over time, the liability is accreted to its estimated future value. Accretion expense is included
as part of “Depreciation and amortization expense”. Any accretion expense not yet approved by the
regulator is recorded in “PP&E” and included in the next depreciation study. Accordingly,
 
changes to the
ARO or cost recognition attributable to changes in the factors discussed above, should not impact the
results of operations of the Company.
Some of the Company’s transmission and distribution assets may have conditional AROs which are not
recognized in the consolidated financial statements as the fair value of these obligations could not be
reasonably estimated given there is insufficient information to do so. A conditional ARO refers to a legal
obligation to perform an asset retirement activity in which the timing and/or method of settlement are
conditional on a future event that may or may not be within the control of the entity. Management
monitors these obligations and a liability is recognized at fair value when an amount can be determined.
As at December 31, 2022, AROs recorded on the balance sheet were $174 million (2021 – $174 million).
The Company estimates the undiscounted amount of cash flow required to settle the obligations is
approximately $429 million (2021 – $422 million), which will be incurred between 2023 and 2061. The
majority of these costs will be incurred between 2028 and 2050.
Financial Instruments
The Company is required to determine the fair value of all derivatives except those which qualify for the
normal purchase, normal sale exception. Fair value is the price that would be received for the sale of an
asset or paid to transfer a liability in an orderly arms-length transaction between market participants at the
measurement date. Fair value measurements are required to reflect assumptions that market participants
would use in pricing an asset or liability based on the best available information, including the risks
inherent in a particular valuation technique, such as a pricing model, and the risks inherent in the inputs to
the model.
Level Determinations and Classifications
The Company uses Level 1, 2, and 3 classifications in the fair value hierarchy. The fair value
measurement of a financial instrument is included in only one of the three levels and is based on the
lowest level input significant to the derivation of the fair value. Fair values are determined, directly or
indirectly, using inputs that are observable for the asset or liability.
 
Only in limited circumstances does the
Company enter into commodity transactions involving non-standard features where market observable
data is not available or have contract terms that extend beyond five years.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
62
CHANGES IN ACCOUNTING POLICIES AND
PRACTICES
The new USGAAP accounting policy that is applicable to, and adopted by the Company in 2022, is
described as follows:
 
Facilitation of the Effects of Reference Rate Reform on Financial Reporting
The Company adopted Accounting Standard Update (“ASU”) 2022-06,
Reference Rate Reform (Topic
848): Deferral of the Sunset Date of Topic 848
 
in Q4 2022. The update extends the period of time
preparers can utilize the reference rate reform relief guidance issued under ASU 2020-04, which was
adopted by the Company in Q4 2020. The guidance in ASU 2022-06 was effective as of the date of
issuance and entities may elect to apply the guidance prospectively through to December 31, 2024. The
Company has applied the guidance permitted by ASU 2020-04 to certain debt agreements that were
amended during the current period. The Company’s transition from reference rates will not have a
material impact on the consolidated financial statements.
Future Accounting Pronouncements
The Company considers the applicability and impact of all ASUs issued by the Financial Accounting
Standards Board (“FASB”). ASUs issued by FASB, but which are not yet effective, were assessed and
determined to be either not applicable to the Company or to have an insignificant impact on the
consolidated financial statements.
SUMMARY OF QUARTERLY
 
RESULTS
For the quarter ended
millions of dollars
 
Q4
Q3
Q2
Q1
Q4
Q3
Q2
Q1
(except per share amounts)
2022
2022
2022
2022
2021
2021
2021
2021
Operating revenues
$
 
2,358
$
 
1,835
$
 
1,380
$
 
2,015
$
 
1,868
$
 
1,148
$
 
1,137
$
 
1,612
Net income (loss) attributable to
common shareholders
$
 
483
$
 
167
$
 
(67)
$
 
362
$
 
324
$
 
(70)
$
 
(17)
$
 
273
Adjusted net income
$
 
249
$
 
203
$
 
156
$
 
242
$
 
168
$
 
175
$
 
137
$
 
243
EPS – basic
$
1.80
$
 
0.63
$
 
(0.25)
$
 
1.38
$
 
1.24
$
 
(0.27)
$
 
(0.07)
$
 
1.08
EPS – diluted
$
1.80
$
 
0.63
$
 
(0.25)
$
 
1.38
$
 
1.20
$
 
(0.27)
$
 
(0.07)
$
 
1.08
Adjusted EPS – basic
$
0.93
$
 
0.76
$
 
0.59
$
 
0.92
$
 
0.64
$
 
0.68
$
 
0.54
$
 
0.96
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.
EX-99.3
25 25 P3Y P3Y P3Y P3Y 25.5 5 3 25.5 5 3 50 August 15, 2025 August 15, 2023 February 15, 2025 August 15, 2025 August 15, 2023 May 15, 2026 November 15, 2026 five
1
EMERA INCORPORATED
Consolidated
Financial Statements
December 31, 2022 and 2021
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 23, 2023
“Scott Balfour”
“Gregory Blunden”
President and Chief Executive Officer
 
President and Chief Executive Officer
 
Chief Financial Officer
 
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, 2022 and 2021, the related Consolidated Statements of Income,
Consolidated Statements of Comprehensive Income, Consolidated Statements of Changes in Equity and
Consolidated Statements of Cash Flows for the years then ended, and the related notes (collectively
referred to as the “consolidated financial statements“). In our opinion, the consolidated financial
statements present fairly, in all material respects, the consolidated financial position of the Company as of
December 31, 2022 and 2021, and the consolidated results of its operations and its consolidated cash
flows for each of the two years in the period ended December 31, 2022, in conformity with United States
generally accepted accounting principles.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company‘s management. Our
responsibility is to express an opinion on the Company‘s consolidated financial statements based on our
audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board
(United States) (“PCAOB”) and are required to be independent with respect to the Company in
accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities
and Exchange Commission and the PCAOB.
 
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that
we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial
statements are free of material misstatement, whether due to error or fraud. The Company is not required
to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part
of our audits we are required to obtain an understanding of internal control over financial reporting but not
for the purpose of expressing an opinion on the effectiveness of the Company's internal control over
financial reporting. Accordingly, we express no such opinion.
 
Our audits included performing procedures to assess the risks of material misstatement of the
consolidated financial statements, whether due to error or fraud, and performing procedures that respond
to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and
disclosures in the consolidated financial statements. Our audits also included evaluating the accounting
principles used and significant estimates made by management, as well as evaluating the overall
presentation of the consolidated financial statements. We believe that our audits provide a reasonable
basis for our opinion.
 
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.
4
Accounting for the effects of rate regulation
Description of the
Matter
As disclosed in note 7 of the consolidated financial statements, the
Company has $3.6 billion in regulatory assets and $2.3 billion in regulatory
liabilities. The Company’s rate-regulated subsidiaries are subject to
regulation by various federal, state and provincial regulatory authorities in
the geographic regions in which they operate. The regulatory rates are
designed to recover the prudently incurred costs of providing the regulated
products or services and provide a reasonable return on the equity invested
or assets, as applicable. In addition to regulatory assets and liabilities, rate
regulation impacts multiple financial statement line items, including, but not
limited to, property, plant and equipment (“PP&E”), operating revenues and
expenses, income taxes, and depreciation expense.
Auditing the impact of rate regulation on the Company’s financial
statements is complex and highly judgmental due to the significant
judgments made by the Company to support its accounting and disclosure
for regulatory matters when final regulatory decisions or orders have not yet
been obtained or when regulatory formulas are complex. There is also
subjectivity involved in assessing the potential impact of future regulatory
decisions on the financial statements. Although the Company expects to
recover costs from customers through rates, there is a risk that the regulator
will not approve full recovery of the costs incurred. The Company’s
judgments include making an assessment of the probability of recovery of
and return on costs incurred, of the potential disallowance of part of the cost
incurred, or of the probable refund to customers through future rates.
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 in future rates based on the regulator’s
treatment of similar costs under similar circumstances. We obtained and
evaluated an analysis from the Company and corroborated that analysis
with letters from legal counsel, when appropriate, regarding cost recoveries
or future changes in rates. We also assessed the methodology, accuracy
and completeness of the Company’s calculations of regulatory asset and
liability balances based on provisions and formulas outlined in rate orders
and other correspondence with the regulators. We evaluated the
Company's disclosures related to the impacts of rate regulation.
Fair value measurement of derivative financial instruments
Description of the
Matter
Held-for-trading (“HFT”) derivative assets of $429 million and liabilities of
$1,301 million, disclosed in note 15 to the consolidated financial statements,
are measured at fair value. The Company recognized $64 million in realized
and unrealized gains during the year with respect to HFT derivatives.
Auditing the Company’s valuation of HFT derivatives is complex and highly
judgmental due to the complexity of the contract terms and valuation
models, and the significant estimation required in determining the fair value
of the contracts. In determining the fair value of HFT derivatives, significant
assumptions about future economic and market assumptions with uncertain
outcomes are used, including third-party sourced forward commodity pricing
5
curves based on illiquid markets, internally developed correlation factors
and basis differentials. These assumptions have a significant impact on the
fair value of the HFT derivatives.
 
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 fair value hierarchy disclosures in note 16 to the
consolidated financial statements were consistent with the source of the
significant inputs and assumptions used in determining the fair value of
derivatives.
 
/s/ Ernst & Young LLP
Chartered Professional Accountants
We have served as the Company‘s auditor since 1998.
Halifax, Canada
February 23, 2023
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
6
Emera Incorporated
Consolidated Statements of Income
 
For the
Year ended December 31
millions of dollars (except per share amounts)
2022
2021
Operating revenues
 
Regulated electric
$
 
5,473
$
 
4,665
 
Regulated gas
 
1,681
 
1,261
 
Non-regulated
 
434
(161)
 
Total operating revenues (note 6)
 
7,588
 
5,765
Operating expenses
 
Regulated fuel for generation and purchased power
 
2,171
 
1,763
 
Regulated cost of natural gas
 
800
 
472
 
Operating, maintenance and general expenses ("OM&G")
 
1,596
 
1,368
 
Provincial, state, and municipal taxes
 
 
367
 
330
 
Depreciation and amortization
 
952
 
902
 
Impairment charge (note 22)
 
73
-
 
 
Total operating expenses
 
5,959
 
4,835
Income from operations
 
1,629
 
930
Income from equity investments (note 8)
 
129
 
143
Other income, net (note 9)
 
145
 
93
Interest expense, net
 
 
709
 
611
Income before provision for income taxes
 
1,194
 
555
Income tax expense (recovery) (note 10)
 
185
(6)
Net income
 
 
1,009
 
561
Non-controlling interest in subsidiaries
 
1
 
1
Preferred stock dividends
 
63
 
50
Net income attributable to common shareholders
$
 
945
$
 
510
Weighted average shares of common stock outstanding (in millions) (note 12)
 
Basic
 
266
 
257
 
Diluted
 
266
 
258
Earnings per common share (note 12)
 
Basic
$
 
3.56
$
 
1.98
 
Diluted
$
 
3.55
$
 
1.98
Dividends per common share declared
$
 
2.6775
$
 
2.5750
The accompanying notes are an integral part of these consolidated financial statements.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
7
Emera Incorporated
Consolidated Statements of Comprehensive Income
 
For the
Year ended December 31
millions of dollars
2022
2021
Net income
 
$
 
1,009
$
 
561
Other comprehensive income (loss), net of tax
Foreign currency translation adjustment
(1)
 
629
(42)
Unrealized (losses) gains on net investment hedges
(2) (3)
(97)
 
5
Cash flow hedges
 
Net derivative gains
 
(4)
-
 
 
18
 
Less: reclassification adjustment for gains included in income
(2)
(1)
 
Net effects of cash flow hedges
(2)
 
17
Unrealized losses on available-for-sale investment
(1)
-
 
Net change in unrecognized pension and post-retirement benefit obligation
(5)
 
 
24
 
124
Other comprehensive income
(6)
 
 
553
 
104
Comprehensive income
 
1,562
 
665
Comprehensive income attributable to non-controlling interest
 
1
 
1
Comprehensive Income of Emera Incorporated
$
 
1,561
$
 
664
The accompanying notes are an integral part of these consolidated financial statements.
1) Net of tax expense of $
7
 
million for the year ended December 31, 2022 (2021 – $
5
 
million expense).
2) The Company has designated $
1.2
 
billion United States dollar (USD) denominated Hybrid Notes as a hedge of the foreign
currency exposure of its net investment in USD denominated operations.
 
3) Net of tax recovery of $
6
 
million for the year ended December 31, 2022 (2021 – $
1
 
million expense).
4) Net of tax recovery of $
1
 
million for the year ended December 31, 2022 (2021 – $
6
 
million expense).
5) Net of tax expense of $
1
 
million for the year ended December 31, 2022 (2021 – $
2
 
million expense).
6) Net of tax expense of $
1
 
million for the year ended December 31, 2022 (2021 – $
14
 
million expense).
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
8
Emera Incorporated
Consolidated Balance Sheets
As at
December 31
December 31
millions of dollars
2022
2021
Assets
Current assets
 
Cash and cash equivalents
$
 
310
$
 
394
 
Restricted cash (note 32)
 
22
 
23
 
Inventory (note 14)
 
769
 
538
 
Derivative instruments (notes 15 and 16)
 
296
 
195
 
Regulatory assets (note 7)
 
602
 
253
 
Receivables and other current assets (note 18)
 
2,897
 
1,733
 
4,896
 
3,136
Property, plant and equipment ("PP&E"),
net of accumulated depreciation
and amortization of $
9,574
 
and $
8,739
, respectively (note 20)
 
22,996
 
20,353
Other assets
 
Deferred income taxes (note 10)
 
237
 
295
 
Derivative instruments (notes 15 and 16)
 
100
 
106
 
Regulatory assets (note 7)
 
3,018
 
2,313
 
Net investment in direct finance and sales type leases (note 19)
 
604
 
503
 
Investments subject to significant influence (note 8)
 
1,418
 
1,382
 
Goodwill (note 22)
 
6,012
 
5,696
 
Other long-term assets (note 32)
 
461
 
460
 
11,850
 
10,755
Total assets
$
 
39,742
$
 
34,244
Liabilities and Equity
Current liabilities
 
Short-term debt (note 23)
$
 
2,726
$
 
1,742
 
Current portion of long-term debt (note 25)
 
574
 
462
 
Accounts payable
 
 
2,025
 
1,485
 
Derivative instruments (notes 15 and 16)
 
888
 
533
 
Regulatory liabilities (notes 7 and 32)
 
495
 
290
 
Other current liabilities (note 24)
 
579
 
366
 
7,287
 
4,878
Long-term liabilities
 
Long-term debt (note 25)
 
15,744
 
14,196
 
Deferred income taxes (note 10)
 
2,196
 
1,868
 
Derivative instruments (notes 15 and 16)
 
190
 
149
 
Regulatory liabilities (note 7)
 
1,778
 
1,765
 
Pension and post-retirement liabilities (note 21)
 
281
 
370
 
Other long-term liabilities (notes 8 and 26)
 
825
 
868
 
21,014
 
19,216
Equity
 
Common stock (note 11)
 
7,762
 
7,242
 
Cumulative preferred stock (note 28)
 
1,422
 
1,422
 
Contributed surplus
 
81
 
79
 
Accumulated other comprehensive income ("AOCI') (note 13)
 
578
 
25
 
Retained earnings
 
 
1,584
 
1,348
 
Total Emera Incorporated equity
 
11,427
 
10,116
 
Non-controlling interest in subsidiaries (note 29)
 
14
 
34
 
Total equity
 
11,441
 
10,150
Total liabilities and equity
$
 
39,742
$
 
34,244
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
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
9
Emera Incorporated
Consolidated Statements of Cash Flows
 
For the
 
Year ended December 31
Year ended December 31
millions of dollars
2022
2021
Operating activities
Net income
 
$
 
1,009
$
 
561
Adjustments to reconcile net income to net cash provided by operating activities:
 
Depreciation and amortization
 
959
 
915
 
Income from equity investments, net of dividends
(61)
(69)
 
Allowance for equity funds used during construction
(52)
(61)
 
Deferred income taxes, net
 
152
(37)
 
Net change in pension and post-retirement liabilities
(48)
(23)
 
Fuel adjustment mechanism ("FAM")
(162)
(166)
 
Net change in fair value of derivative instruments
 
206
 
404
 
Net change in regulatory assets and liabilities
 
(471)
(176)
 
Net change in capitalized transportation capacity
(445)
(107)
 
Impairment charge
 
73
-
 
 
Other operating activities, net
(13)
 
96
Changes in non-cash working capital (note 30)
(234)
(152)
Net cash provided by operating activities
 
913
 
1,185
Investing activities
 
Additions to PP&E
(2,596)
(2,359)
 
Other investing activities
 
27
 
27
Net cash used in investing activities
(2,569)
(2,332)
Financing activities
 
Change in short-term debt, net
 
1,028
(155)
 
Proceeds from short-term debt with maturities greater than 90 days
 
544
 
640
 
Repayment of short-term debt with maturities greater than 90 days
(680)
(377)
 
Proceeds from long-term debt, net of issuance costs
 
784
 
2,554
 
Retirement of long-term debt
(367)
(1,660)
 
Net proceeds under committed credit facilities
 
511
 
82
 
Issuance of common stock, net of issuance costs
 
277
 
317
 
Issuance of preferred stock, net of issuance costs (note 28)
-
 
 
416
 
Dividends on common stock
(472)
(443)
 
Dividends on preferred stock
(63)
(50)
 
Other financing activities
 
(7)
(13)
Net cash provided by financing activities
 
1,555
 
1,311
Effect of exchange rate changes on cash, cash equivalents, and restricted cash
 
16
(1)
Net increase (decrease) in cash, cash equivalents, and restricted cash
(85)
 
163
Cash, cash equivalents, and restricted cash, beginning of year
 
417
 
254
Cash, cash equivalents, and restricted cash, end of year
$
 
332
$
 
417
Cash, cash equivalents, and restricted cash consists of:
Cash
$
 
302
$
 
237
Short-term investments
 
8
 
157
Restricted cash
 
22
 
23
Cash, cash equivalents, and restricted cash
$
 
332
$
 
417
Supplementary Information to Consolidated Statements of Cash Flows (note 30)
The accompanying notes are an integral part of these consolidated financial statements.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
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, 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 at-the-market
program ("ATM"), net of after-tax
issuance costs
 
248
-
 
-
 
-
 
-
 
-
 
 
248
Issued under the Dividend
Reinvestment Program ("DRIP"), net of
discount
 
238
-
 
-
 
-
 
-
 
-
 
 
238
Senior management stock options
exercised and Employee Share
Purchase Plan
 
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
Balance, December 31, 2020
$
 
6,705
$
 
1,004
$
 
79
$
(79)
$
 
1,495
$
 
34
$
 
9,238
Net income of Emera Inc.
-
 
-
 
-
 
-
 
 
560
 
1
 
561
Other comprehensive income, net of tax
expense of $
14
 
million
-
 
-
 
-
 
 
104
-
 
-
 
 
104
Issuance of preferred stock, net of after-
tax issuance costs
-
 
 
418
-
 
-
 
-
 
-
 
 
418
Dividends declared on preferred stock
(note 28)
-
 
-
 
-
 
-
 
(50)
-
 
(50)
Dividends declared on common stock
($
2.5750
/share)
-
 
-
 
-
 
-
 
(657)
-
 
(657)
Issued under the ATM, net of after-tax
issuance costs
 
284
-
 
-
 
-
 
-
 
-
 
 
284
Issued under the DRIP,
 
net of discount
 
215
-
 
-
 
-
 
-
 
-
 
 
215
Senior management stock options
exercised and Employee Share
Purchase Plan
 
38
-
 
-
 
-
 
-
 
-
 
 
38
Other
-
 
-
 
-
 
-
 
-
 
(1)
(1)
Balance, December 31, 2021
$
 
7,242
$
 
1,422
$
 
79
$
 
25
$
 
1,348
$
 
34
$
 
10,150
The accompanying notes are an integral part of these consolidated financial statements.
11
Emera Incorporated
Notes to the Consolidated Financial Statements
As at December 31, 2022 and 2021
1.
 
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Nature of Operations
Emera Incorporated (“Emera” or the “Company”) is an energy and services company which invests in
electricity generation, transmission and distribution, and gas transmission and distribution.
 
At December 31, 2022, Emera’s reportable segments include the following:
 
●
 
Florida Electric Utility, which consists of Tampa
 
Electric,
 
a vertically integrated regulated electric
utility, serving approximately
827,000
 
customers in West Central Florida;
●
 
Canadian Electric Utilities, which includes:
●
 
Nova Scotia Power Inc. (“NSPI”), a vertically integrated regulated electric utility and the
primary electricity supplier in Nova Scotia, serving approximately
541,000
 
customers; and
●
 
Emera Newfoundland & Labrador Holdings Inc. (“ENL”), consisting of two transmission
investments related to an
824
 
megawatt (“MW”) hydroelectric generating facility at Muskrat
Falls on the Lower Churchill River in Labrador, owned and constructed by Nalcor Energy.
ENL’s two investments are:
●
 
a
100
 
per cent investment in NSP Maritime Link Inc. (“NSPML”), which developed the
Maritime Link Project, a $
1.8
 
billion (including allowance for funds used during
construction (“AFUDC”)) transmission project; and
●
 
a
31.9
 
per cent investment in the partnership capital of Labrador-Island Link Limited
Partnership (“LIL”), a $
3.7
 
billion electricity transmission project in Newfoundland and
Labrador.
 
●
 
Gas Utilities and Infrastructure, which includes:
●
 
Peoples Gas System (“PGS”), a regulated gas distribution utility, serving approximately
468,000
 
customers across Florida;
 
●
 
New Mexico Gas Company, Inc. (“NMGC”), a regulated gas distribution utility,
 
serving
approximately
545,000
 
customers in New Mexico;
 
●
 
Emera Brunswick Pipeline Company Limited (“Brunswick Pipeline”), a
145
-kilometre pipeline
delivering re-gasified liquefied natural gas (“LNG”) from Saint John, New Brunswick to the
United States border under a
25
-year firm service agreement with Repsol Energy North
America Canada Partnership, which expires in 2034;
 
●
 
SeaCoast Gas Transmission, LLC (“SeaCoast”), a regulated intrastate natural gas
transmission company in Florida; and
●
 
a
12.9
 
per cent interest in Maritimes & Northeast Pipeline (“M&NP”), a
1,400
-kilometre
pipeline that transports natural gas throughout markets in Atlantic Canada and the
northeastern United States.
 
●
 
Other Electric Utilities, which includes Emera (Caribbean) Incorporated (“ECI”), a holding company
with regulated electric utilities that include:
●
 
The Barbados Light & Power Company Limited (“BLPC”), a vertically integrated regulated
electric utility on the island of Barbados, serving approximately
133,000
 
customers;
 
●
 
Grand Bahama Power Company Limited (“GBPC”), a vertically integrated regulated electric
utility on Grand Bahama Island, serving approximately
19,000
 
customers; and
●
 
a
19.5
 
per cent equity interest in St. Lucia Electricity Services Limited (“Lucelec”), a vertically
integrated regulated electric utility on the island of St. Lucia.
12
●
 
Emera’s other reportable segment includes investments in energy-related non-regulated companies
which includes:
●
 
Emera Energy, which consists of:
●
 
Emera Energy Services (“EES”), a physical energy business that purchases and sells
natural gas and electricity and provides related energy asset management services;
 
●
 
Brooklyn Power Corporation (“Brooklyn Energy”), a
30
 
MW biomass co-generation
electricity facility in Brooklyn, Nova Scotia; and
●
 
a
50.0
 
per cent joint venture interest in Bear Swamp Power Company LLC (“Bear
Swamp”), a
660
 
MW pumped storage hydroelectric facility in northwestern
Massachusetts.
 
●
 
Emera US Finance LP (“Emera Finance”) and TECO Finance, Inc. (“TECO Finance”),
financing subsidiaries of Emera;
●
 
Emera Technologies LLC, a wholly owned technology company focused on finding ways to
deliver renewables and resilient energy to customers;
●
 
Emera US Holdings Inc., a wholly owned holding company for certain of Emera’s assets
located in the United States; and
●
 
Other investments.
Basis of Presentation
These consolidated financial statements are prepared and presented in accordance with United States
Generally Accepted Accounting Principles (“USGAAP”) and in the opinion of management, include all
adjustments that are of a recurring nature and necessary to fairly state the financial position of Emera.
 
 
All dollar amounts are presented in Canadian dollars (“CAD”), unless otherwise indicated.
Principles of Consolidation
These consolidated financial statements include the accounts of Emera Incorporated, its majority-owned
subsidiaries, and a variable interest entity (“VIE”) in which Emera is the primary beneficiary. Emera uses
the equity method of accounting to record investments in which the Company has the ability to exercise
significant influence, and for VIEs in which Emera is not the primary beneficiary.
The Company performs ongoing analysis to assess whether it holds any VIEs or whether any
reconsideration events have arisen with respect to existing VIEs. To identify potential VIEs, management
reviews contractual and ownership arrangements such as leases, long-term purchase power agreements,
tolling contracts, guarantees, jointly owned facilities and equity investments. VIEs of which the Company
is deemed the primary beneficiary must be consolidated. The primary beneficiary of a VIE has both the
power to direct the activities of the entity that most significantly impacts its economic performance and the
obligation to absorb losses of the entity that could potentially be significant to the entity. In circumstances
where Emera has an investment in a VIE but is not deemed the primary beneficiary, the VIE is accounted
for using the equity method. For further details on VIEs, refer to note 32.
Intercompany balances and transactions have been eliminated on consolidation, except for the net profit
on certain transactions between certain non-regulated and regulated entities in accordance with
accounting standards for rate-regulated entities. The net profit on these transactions, which would be
eliminated in the absence of the accounting standards for rate-regulated entities, is recorded in non-
regulated operating revenues. An offset is recorded to PP&E, regulatory assets, regulated fuel for
generation and purchased power, or OM&G, depending on the nature of the transaction.
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 the reported amounts of assets and liabilities at
the date of the financial statements and reported amounts of revenues and expenses during the reporting
periods. Significant areas requiring use of management estimates relate to rate-regulated assets and
liabilities, accumulated reserve for cost of removal, pension and post-retirement benefits, unbilled
revenue, useful lives for depreciable assets, goodwill and long-lived assets impairment assessments,
income taxes, asset retirement obligations (“ARO”), and valuation of financial instruments. Management
evaluates the Company’s estimates on an ongoing basis based upon historical experience, current and
expected conditions and assumptions believed to be reasonable at the time the assumption is made, with
any adjustments recognized in income in the year they arise.
Regulatory Matters
Regulatory accounting applies where rates are established by, or subject to approval by, an
 
independent
third-party regulator. The rates are designed to recover prudently incurred costs of providing the regulated
products or services and provide an opportunity for a reasonable rate of return on invested capital, as
applicable. For further detail, refer to note 7.
Foreign Currency Translation
 
Monetary assets and liabilities denominated in foreign currencies are converted to CAD at the rates of
exchange prevailing at the balance sheet date. The resulting differences between the translation at the
original transaction date and the balance sheet date are included in income.
Assets and liabilities of foreign operations whose functional currency is not the Canadian dollar are
translated using exchange rates in effect at the balance sheet date and the results of operations at the
average exchange rate in effect for the period. The resulting exchange gains and losses on the assets
and liabilities are deferred on the balance sheet in AOCI.
The Company designates certain USD denominated debt held in CAD functional currency companies as
hedges of net investments in USD denominated foreign operations. The change in the carrying amount of
these investments, measured at the exchange rates in effect at the balance sheet date is recorded in
Other Comprehensive Income (“OCI”).
Revenue Recognition
Regulated Electric and Gas Revenue:
Electric and gas revenues, including energy charges, demand charges, basic facilities charges and
clauses and riders, are recognized when obligations under the terms of a contract are satisfied, which is
when electricity and gas are delivered to customers over time as the customer simultaneously receives
and consumes the benefits. Electric and gas revenues are recognized on an accrual basis and include
billed and unbilled revenues. Revenues related to the sale of electricity and gas are recognized at rates
approved by the respective regulator and recorded based on metered usage, which occurs on a periodic,
systematic basis, generally monthly or bi-monthly. At the end of each reporting period, the electricity and
gas delivered to customers, but not billed, is estimated and the corresponding unbilled revenue is
recognized. The Company’s estimate of unbilled revenue at the end of the reporting period is calculated
by estimating the number of megawatt hours (“MWh”) or therms delivered to customers at the established
rates expected to prevail in the upcoming billing cycle. This estimate includes assumptions as to the
pattern of energy demand, weather, line losses and inter-period changes to customer classes.
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 the terms of the contract are satisfied and are presented on a net
basis, reflecting the nature of the contractual relationships with customers and suppliers.
Energy sales are recognized when obligations under the terms of the contracts are satisfied, which is
when electricity is delivered to customers over time.
 
Other non-regulated revenues are recorded when obligations under the terms of the contract are
satisfied.
Other:
Sales, value add, and other taxes, except for gross receipts taxes discussed below, collected by the
Company concurrent with revenue-producing activities are excluded from revenue.
Leases
The Company determines whether a contract contains a lease at inception by evaluating if the contract
conveys the right to control the use of an identified asset for a period of time in exchange for
consideration.
 
Emera has leases with independent power producers (“IPP”) and other utilities with annual requirements
to purchase wind and hydro energy over varying contract lengths that are classified as finance leases.
These finance leases are not recorded on the Company’s Consolidated Balance Sheets, as payments
associated with the leases are variable in nature and there are no minimum fixed lease payments. Lease
expense associated with these leases is recorded as “Regulated fuel for generation and purchased
power” on the Consolidated Statements of Income.
Operating lease liabilities and right-of-use assets are recognized on the Consolidated Balance Sheets
based on the present value of the future minimum lease payments over the lease term at commencement
date. As most of Emera’s leases do not provide an implicit rate, the incremental borrowing rate at
commencement of the lease is used in determining the present value of future lease payments. Lease
expense is recognized on a straight-line basis over the lease term and is recorded as “Operating,
maintenance and general” on the Consolidated Statements of Income.
Where the Company is the lessor, a lease is a sales-type lease if certain criteria are met and the
arrangement transfers control of the underlying asset to the lessee. For arrangements where the criteria
are met due to the presence of a third-party residual value guarantee, the lease is a direct financing
lease.
 
For direct finance leases, a net investment in the lease is recorded that consists of the sum of the
minimum lease payments and residual value, net of estimated executory costs and unearned income.
The difference between the gross investment and the cost of the leased item is recorded as unearned
income at the inception of the lease. Unearned income is recognized in income over the life of the lease
using a constant rate of interest equal to the internal rate of return on the lease.
 
For sales-type leases, the accounting is similar to the accounting for direct finance leases, however the
difference between the fair value and the carrying value of the leased item is recorded at lease
commencement rather than deferred over the term of the lease.
 
Emera has certain contractual agreements that include lease and non-lease components, which
management has elected to account for as a single lease component.
15
Franchise Fees and Gross Receipts
Tampa
 
Electric and PGS recover from customers certain costs incurred, on a dollar-for-dollar basis,
through prices approved by the Florida Public Service Commission (“FPSC”). The amounts included in
customers’ bills for franchise fees and gross receipt taxes are included as “Regulated electric” and
“Regulated gas” revenues in the Consolidated Statements of Income. Franchise fees and gross receipt
taxes payable by Tampa Electric and PGS are included as an expense on the Consolidated Statements
of Income in “Provincial, state and municipal taxes”.
NMGC is an agent in the collection and payment of franchise fees and gross receipt taxes and is not
required by a tariff to present the amounts on a gross basis. Therefore, NMGC’s franchise fees and gross
receipt taxes are presented net with no line item impact on the Consolidated Statements of Income.
Property, Plant and Equipment
 
PP&E are recorded at original cost, including AFUDC or capitalized interest, net of contributions received
in aid of construction.
The cost of additions, including betterments and replacements of units are included in “Property, plant
and equipment”. When units of regulated PP&E are replaced, renewed or retired, their cost, plus removal
or disposal costs, less salvage proceeds, is charged to accumulated depreciation, with no gain or loss
reflected in income. Where a disposition of non-regulated PP&E occurs, gains and losses are included in
income as the dispositions occur.
The cost of PP&E represents the original cost of materials, contracted services, direct labour, AFUDC for
regulated property or interest for non-regulated property, ARO, and overhead attributable to the capital
project. Overhead includes corporate costs such as finance, information technology and labour costs,
along with other costs related to support functions, employee benefits, insurance, procurement, and fleet
operating and maintenance. Expenditures for project development are capitalized if they are expected to
have a future economic benefit.
Normal maintenance projects and major maintenance projects that do not increase the overall life of the
related assets are expensed as incurred. When a major maintenance project increases the life or value of
the underlying asset, the cost is capitalized.
 
Depreciation is determined by the straight-line method, based on the estimated remaining service lives of
the depreciable assets in each functional class of depreciable property. For some of Emera’s rate-
regulated subsidiaries, depreciation is calculated using the group remaining life method, which is applied
to the average investment, adjusted for anticipated costs of removal less salvage, in functional classes of
depreciable property. The service lives of regulated assets require regulatory approval.
Intangible assets, which are included in “Property, plant and equipment,” consist primarily of computer
software and land rights. Amortization is determined by the straight-line method, based on the estimated
remaining service lives of the asset in each category. For some of Emera’s rate-regulated subsidiaries,
amortization is calculated using the amortizable life method which is applied to the net book value to date
over the remaining life of those assets. The service lives of regulated intangible assets require regulatory
approval.
16
Goodwill
Goodwill is calculated as the excess of the purchase price of an acquired entity over the estimated fair
values of identifiable assets acquired and liabilities assumed at the acquisition date. Goodwill is carried at
initial cost less any write-down for impairment and is adjusted for the impact of foreign exchange. Under
the applicable accounting guidance, goodwill is subject to assessment for impairment at the reporting unit
level annually, or if an event or change in circumstances indicates that the fair value of a reporting unit
may be below its carrying value. When assessing goodwill for impairment, the Company has the option of
first performing a qualitative assessment to determine whether a quantitative assessment is necessary. In
performing a qualitative assessment management considers, among other factors, macroeconomic
conditions, industry and market considerations and overall financial performance.
If the Company performs the qualitative assessment and determines that it is more likely than not that its
fair value is less than its carrying amount, or if the Company chooses to bypass the qualitative
assessment, a quantitative test is performed. The quantitative test compares the fair value of the
reporting unit to its carrying amount, including goodwill. If the carrying amount of the reporting unit
exceeds its fair value, an impairment loss is recorded. Management estimates the fair value of the
reporting unit by using the income approach, or a combination of the income and market approach. The
income approach is applied using a discounted cash flow analysis which relies on management’s best
estimate of the reporting units’ projected cash flows. The analysis includes an estimate of terminal values
based on these expected cash flows using a methodology which derives a valuation using an assumed
perpetual annuity based on the reporting unit’s residual cash flows. The discount rate used is a market
participant rate based on a peer group of publicly traded comparable companies and represents the
weighted average cost of capital of comparable companies. When using the market approach,
management estimates fair value based on comparable companies and transactions within the utility
industry. Significant assumptions used in estimating the fair value include discount and growth rates, rate
case assumptions including future cost of capital, valuation of the reporting units' net operating loss
(“NOL”) and projected operating and capital cash flows. Adverse changes in these assumptions could
result in a future material impairment of the goodwill assigned to Emera’s reporting units.
 
As of December 31, 2022, $
6,009
 
million of Emera’s goodwill represents the excess of the acquisition
purchase price for TECO Energy (Tampa Electric, PGS and NMGC reporting units) over the fair values
assigned to identifiable assets acquired and liabilities assumed. In Q4 2022, qualitative assessments
were performed for Tampa Electric and PGS given the significant excess of fair value over carrying
amounts calculated during the last quantitative test in Q4 2019. Management concluded it was more likely
than not that the fair value of these reporting units exceeded their respective carrying amounts, including
goodwill. As such, no quantitative testing was required. For the NMGC reporting unit, Emera elected to
bypass a qualitative assessment and performed a quantitative impairment assessment using a
combination of the income and market approach. This assessment estimated that the fair value of the
NMGC reporting unit exceeded its carrying amount, including goodwill. As a result of this assessment,
no
impairment charges were recognized.
In Q4 2022, the Company elected to bypass a qualitative assessment and performed a quantitative
impairment assessment for GBPC, using the income approach, as this reporting unit is sensitive to
changes in assumptions due to limited excess of fair value over the carrying value, including goodwill.
Although the cash flows of GBPC have not changed significantly compared to previous periods, it was
determined that the carrying amount, including goodwill, exceeded the fair value, due to an increase in
discount rates. The discount rate for the reporting unit was negatively impacted by changes in the macro-
economic environment, including the risk-free rate assumption. As a result of this assessment, a goodwill
impairment charge of $
73
 
million was recorded in 2022, reducing the GBPC goodwill balance to
nil
 
as at
December 31, 2022. No impairment was recorded in 2021. For further detail, refer to note 22.
17
Income Taxes and Investment Tax
 
Credits
Emera recognizes deferred income tax assets and liabilities for the future tax consequences of events
that have been included in the financial statements or income tax returns. Deferred income tax assets
and liabilities are determined based on the difference between the carrying value of assets and liabilities
on the Consolidated Balance Sheets, and their respective tax bases using enacted tax rates in effect for
the year in which the differences are expected to reverse. The effect of a change in income tax rates on
deferred income tax assets and liabilities is recognized in earnings in the period when the change is
enacted, unless required to be offset to a regulatory asset or liability by law or by order of the regulator.
Emera recognizes the effect of income tax positions only when it is more likely than not that they will be
realized. Management reviews all readily available current and historical information, including forward-
looking information, and the likelihood that deferred tax assets will be recovered from future taxable
income is assessed and assumptions about the expected timing of the reversal of deferred tax assets and
liabilities are made. If management subsequently determines that it is likely that some or all of a deferred
income tax asset will not be realized, then a valuation allowance is recorded to reflect the amount of
deferred income tax asset expected to be realized.
 
Generally, investment tax credits are recorded as a reduction to income tax expense in the current or
future periods to the extent that realization of such benefit is more likely than not. Investment tax credits
earned by Tampa
 
Electric, PGS and NMGC on regulated assets are deferred and amortized over the
estimated service lives of the related properties, as required by regulatory practices.
Tampa
 
Electric, PGS, NMGC and BLPC collect income taxes from customers based on current and
deferred income taxes. NSPI, ENL and Brunswick Pipeline collect income taxes from customers based on
income tax that is currently payable except for the deferred income taxes on certain regulatory balances
specifically prescribed by the regulator. For the balance of regulated deferred income taxes, NSPI, ENL
and Brunswick Pipeline recognize regulatory assets or liabilities where the deferred income taxes are
expected to be recovered from or returned to customers in future years. These regulated assets or
liabilities are grossed up using the respective income tax rate to reflect the income tax associated with
future revenues that are required to fund these deferred income tax liabilities, and the income tax benefits
associated with reduced revenues resulting from the realization of deferred income tax assets. GBPC is
not subject to income taxes.
Emera classifies interest and penalties associated with unrecognized tax benefits as interest and
operating expense, respectively. For further detail, refer to note 10.
Derivatives and Hedging Activities
The Company manages its exposure to normal operating and market risks relating to commodity prices,
foreign exchange, interest rates and share prices through contractual protections with counterparties
where practicable, and by using financial instruments consisting mainly of foreign exchange forwards and
swaps, interest rate options and swaps, equity derivatives, and coal, oil and gas futures, options, forwards
and swaps. In addition, the Company has contracts for the physical purchase and sale of natural gas.
These physical and financial contracts are classified as held-for-trading (“HFT”). Collectively, these
contracts and financial instruments are considered derivatives.
The Company recognizes the fair value of all its derivatives on its balance sheet, except for non-financial
derivatives that meet the normal purchases and normal sales (“NPNS”) exception. Physical contracts that
meet the NPNS exception are not recognized on the balance sheet; these contracts are recognized in
income when they settle. A physical contract generally qualifies for the NPNS exception if the transaction
is reasonable in relation to the Company’s business needs, the counterparty owns or controls resources
within the proximity to allow for physical delivery, the Company intends to receive physical delivery of the
commodity, and the Company deems the counterparty creditworthy.
 
The Company continually assesses
contracts designated under the NPNS exception and will discontinue the treatment of these contracts
under this exemption where the criteria are no longer met.
 
18
Derivatives qualify for hedge accounting if they meet stringent documentation requirements and can be
proven to effectively hedge the identified risk both at the inception and over the term of the instrument.
Specifically, for cash flow hedges, the change in the fair value of derivatives is deferred to AOCI and
recognized in income in the same period the related hedged item is realized. Where the documentation or
effectiveness requirements are not met, the derivatives are recognized at fair value with any changes in
fair value recognized in net income in the reporting period, unless deferred as a result of regulatory
accounting.
Derivatives entered into by NSPI, NMGC and GBPC that are documented as economic hedges or for
which the NPNS exception has not been taken, are subject to regulatory accounting treatment. The
change in fair value of the derivatives is deferred to a regulatory asset or liability. The gain or loss is
recognized in the hedged item when the hedged item is settled. Management believes any gains or
losses resulting from settlement of these derivatives related to fuel for generation and purchased power
will be refunded to or collected from customers in future rates. Tampa Electric has no derivatives related
to hedging as a result of a FPSC approved five-year moratorium on hedging of natural gas purchases
which ends on December 31, 2022. Tampa Electric’s
 
moratorium on hedging of natural gas purchases
will continue through December 31, 2024, as a result of Tampa Electric’s 2021 rate case settlement
agreement.
Derivatives that do not meet any of the above criteria are designated as HFT, with changes in fair value
normally recorded in net income of the period. The Company has not elected to designate any derivatives
to be included in the HFT category where another accounting treatment would apply.
Emera classifies gains and losses on derivatives as a component of fuel for generation and purchased
power, other expenses, inventory,
 
OM&G and PP&E, depending on the nature of the item being
economically hedged. Transportation capacity arising as a result of marketing and trading derivative
transactions is recognized as an asset in “Receivables and other current assets” and amortized over the
period of the transportation contract term. Cash flows from derivative activities are presented in the same
category as the item being hedged within operating or investing activities on the Consolidated Statements
of Cash Flows. Non-hedged derivatives are included in operating cash flows on the Consolidated
Statements of Cash Flows.
Derivatives, as reflected on the Consolidated Balance Sheets, are not offset by the fair value amounts of
cash collateral with the same counterparty. Rights to reclaim cash collateral are recognized in
“Receivables and other current assets” and obligations to return cash collateral are recognized in
“Accounts payable”.
Cash, Cash Equivalents and Restricted Cash
Cash equivalents consist of highly liquid short-term investments with original maturities of three months or
less at acquisition.
Receivables and Allowance for Credit Losses
Utility customer receivables are recorded at the invoiced amount and do not bear interest. Standard
payment terms for electricity and gas sales are approximately 30 days. A late payment fee may be
assessed on account balances after the due date. The Company recognizes allowances for credit losses
to reduce accounts receivable for amounts expected to be uncollectable. Management estimates credit
losses related to accounts receivable by considering historical loss experience, customer deposits,
current events, the characteristics of existing accounts and reasonable and supportable forecasts that
affect the collectability of the reported amount. Provisions for credit losses on receivables are expensed
to maintain the allowance at a level considered adequate to cover expected losses. Receivables are
written off against the allowance when they are deemed uncollectible.
19
Inventory
Fuel and materials inventories are valued at the lower of weighted-average cost or net realizable value,
unless evidence indicates that the weighted-average cost will be recovered in future customer rates.
 
Asset Impairment
Long-Lived Assets:
Emera assesses whether there has been an impairment of long-lived assets and intangibles when a
triggering event occurs, such as a significant market disruption or sale of a business.
 
The assessment involves comparing the undiscounted expected future cash flows to the carrying value of
the asset. When the undiscounted cash flow analysis indicates a long-lived asset is not recoverable, the
amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-
lived asset over its estimated fair value. The Company’s assumptions relating to future results of
operations or other recoverable amounts, are based on a combination of historical experience,
fundamental economic analysis, observable market activity and independent market studies. The
Company’s expectations regarding uses and holding periods of assets are based on internal long-term
budgets and projections, which consider external factors and market forces, as of the end of each
reporting period. The assumptions made are consistent with generally accepted industry approaches and
assumptions used for valuation and pricing activities.
As at December 31, 2022, there are no indications of impairment of Emera’s long-lived assets.
No
impairment charges related to long-lived assets were recognized in 2022 or 2021.
 
Equity Method Investments:
The carrying value of investments accounted for under the equity method are assessed for impairment by
comparing the fair value of these investments to their carrying values, if a fair value assessment was
completed, or by reviewing for the presence of impairment indicators. If an impairment exists, and it is
determined to be other-than-temporary, a charge is recognized in earnings equal to the amount the
carrying value exceeds the investment’s fair value.
No
 
impairment of equity method investments was
required in either 2022 or 2021.
Financial Assets:
Equity investments, other than those accounted for under the equity method, are measured at fair value,
with changes in fair value recognized in the Consolidated Statements of Income. Equity investments that
do not have readily determinable fair values are recorded at cost minus impairment, if any, plus or minus
changes resulting from observable price changes in orderly transactions for the identical or similar
investments.
No
 
impairment of financial assets was required in either 2022 or 2021.
 
Asset Retirement Obligations
An ARO is recognized if a legal obligation exists in connection with the future disposal or removal costs
resulting from the permanent retirement, abandonment or sale of a long-lived asset. A legal obligation
may exist under an existing or enacted law or statute, written or oral contract, or by legal construction
under the doctrine of promissory estoppel.
20
An ARO represents the fair value of the estimated cash flows necessary to discharge the future
obligation, using the Company’s credit adjusted risk-free rate. The amounts are reduced by actual
expenditures incurred. Estimated future cash flows are based on completed depreciation studies,
remediation reports, prior experience, estimated useful lives, and governmental regulatory requirements.
The present value of the liability is recorded and the carrying amount of the related long-lived asset is
correspondingly increased. The amount capitalized at inception is depreciated in the same manner as the
related long-lived asset. Over time, the liability is accreted to its estimated future value. AROs are
included in “Other long-term liabilities” and accretion expense is included as part of “Depreciation and
amortization”. Any regulated accretion expense not yet approved by the regulator is recorded in
“Property, plant and equipment” and included in the next depreciation study.
Some of the Company’s transmission and distribution assets may have conditional AROs which are not
recognized in the consolidated financial statements, as the fair value of these obligations could not be
reasonably estimated, given there is insufficient information to do so. A conditional ARO refers to a legal
obligation to perform an asset retirement activity in which the timing and/or method of settlement are
conditional on a future event that may or may not be within the control of the entity. Management
monitors these obligations and a liability is recognized at fair value in the period in which an amount can
be determined.
Cost of Removal
Tampa
 
Electric, PGS, NMGC and NSPI recognize non-ARO costs of removal (“COR”) as regulatory
liabilities. The non-ARO COR represent funds received from customers through depreciation rates to
cover estimated future non-legally required COR of PP&E upon retirement. The companies accrue for
COR over the life of the related assets based on depreciation studies approved by their respective
regulators. The costs are estimated based on historical experience and future expectations, including
expected timing and estimated future cash outlays.
Stock-Based Compensation
The Company has several stock-based compensation plans: a common share option plan for senior
management; an employee common share purchase plan; a deferred share unit (“DSU”) plan; a
performance share unit (“PSU”) plan; and a restricted share unit (“RSU”) plan. The Company accounts for
its plans in accordance with the fair value-based method of accounting for stock-based compensation.
Stock-based compensation cost is measured at the grant date, based on the calculated fair value of the
award, and is recognized as an expense over the employee’s or director’s requisite service period using
the graded vesting method. Stock-based compensation plans recognized as liabilities are initially
measured at fair value and re-measured at fair value at each reporting date, with the change in liability
recognized in income.
Employee Benefits
The costs of the Company’s pension and other post-retirement benefit programs for employees are
expensed over the periods during which employees render service. The Company recognizes the funded
status of its defined-benefit and other post-retirement plans on the balance sheet and recognizes
changes in funded status in the year the change occurs. The Company recognizes the unamortized gains
and losses and past service costs in AOCI or regulatory assets. The components of net periodic benefit
cost other than the service cost component are included in “Other income, net” on the Consolidated
Statements of Income. For further detail, refer to note 21.
21
2.
CHANGE IN ACCOUNTING POLICY
The new USGAAP accounting policy that is applicable to, and adopted by the Company in 2022, is
described as follows:
 
Facilitation of the Effects of Reference Rate Reform on Financial Reporting
The Company adopted Accounting Standard Update (“ASU”) 2022-06,
Reference Rate Reform (Topic
848): Deferral of the Sunset Date of Topic 848
 
in Q4 2022. The update extends the period of time
preparers can utilize the reference rate reform relief guidance issued under ASU 2020-04, which was
adopted by the Company in Q4 2020. The guidance in ASU 2022-06 was effective as of the date of
issuance and entities may elect to apply the guidance prospectively through to December 31, 2024. The
Company has applied the guidance permitted by ASU 2020-04 to certain debt agreements that were
amended during the current period. The Company’s transition from reference rates will not have a
material impact on the consolidated financial statements.
3.
 
FUTURE ACCOUNTING PRONOUNCEMENTS
The Company considers the applicability and impact of all ASUs issued by the Financial Accounting
Standards Board (“FASB”). ASUs issued by FASB, but which are not yet effective, were assessed and
determined to be either not applicable to the Company or to have an insignificant impact on the
consolidated financial statements.
4.
 
DISPOSITIONS
On March 31, 2022, Emera completed the sale of its
51.9
 
per cent interest in Domlec for proceeds which
approximated its carrying value. Domlec was included in the Company’s Other Electric reportable
segment up to its date of sale. The sale did not have a material impact on earnings.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
22
5.
 
SEGMENT INFORMATION
Emera manages its reportable segments separately due in part to their different operating, regulatory and
geographical environments. Segments are reported based on each subsidiary’s contribution of revenues,
net income attributable to common shareholders and total assets, as reported to the Company’s chief
operating decision maker.
Florida
 
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 (expense), net
 
68
 
24
 
13
-
 
 
23
 
17
 
145
Interest expense, net
(2)
 
185
 
136
 
81
 
19
 
288
-
 
 
709
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.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
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, 2021
 
Operating revenues from
external customers
(1)
$
 
2,718
$
 
1,501
$
 
1,276
$
 
445
$
(175)
$
 
-
 
$
 
5,765
Inter-segment revenues
(1)
 
6
-
 
 
4
-
 
 
18
(28)
 
-
 
 
Total operating revenues
 
2,724
 
1,501
 
1,280
 
445
(157)
(28)
 
5,765
Regulated fuel for generation
and purchased power
 
894
 
654
-
 
 
218
-
 
(3)
 
1,763
Regulated cost of natural gas
-
 
-
 
 
472
-
 
-
 
-
 
 
472
OM&G
 
536
 
291
 
325
 
140
 
106
(30)
 
1,368
Provincial, state and municipal
taxes
 
212
 
43
 
69
 
4
 
2
-
 
 
330
Depreciation and amortization
 
469
 
246
 
121
 
58
 
8
-
 
 
902
Income from equity investments
-
 
 
103
 
20
 
4
 
16
-
 
 
143
Other income (expenses), net
 
59
 
12
 
11
 
15
 
1
(5)
 
93
Interest expense, net
(2)
 
138
 
132
 
64
 
21
 
256
-
 
 
611
Income tax expense (recovery)
 
72
 
9
 
62
 
1
(150)
-
 
(6)
Non-controlling interest in
subsidiaries
-
 
-
 
-
 
 
1
-
 
-
 
 
1
Preferred stock dividends
-
 
-
 
-
 
-
 
 
50
-
 
 
50
Net income (loss) attributable to
common shareholders
$
 
462
$
 
241
$
 
198
$
 
21
$
(412)
$
-
 
$
 
510
Capital expenditures
$
 
1,331
$
 
366
$
 
515
$
 
111
$
 
5
$
-
 
$
 
2,328
As at December 31, 2021
Total assets
$
 
17,903
$
 
7,418
$
 
6,666
$
 
1,402
$
 
2,034
$
(1,179)
$
 
34,244
Investments subject to
significant influence
$
-
 
$
 
1,215
$
 
123
$
 
44
$
-
 
$
-
 
$
 
1,382
Goodwill
$
 
4,436
$
-
 
$
 
1,189
$
 
68
$
 
3
$
-
 
$
 
5,696
(1) All significant inter-company balances and transactions have been eliminated on consolidation except for certain transactions
between non-regulated and regulated entities. Management believes the elimination of these transactions would understate PP&E,
OM&G, or regulated fuel for generation and purchased power. Inter-company
 
transactions that have not been eliminated are
measured at the amount of consideration established and agreed to by the related parties. Eliminated transactions are
 
included in
determining reportable segments.
(2) Segment net income is reported on a basis that includes internally allocated financing costs of $
13
 
million for the year ended
December 31, 2021, between the Gas Utilities and Infrastructure and Other segments.
Geographical Information
Revenues (based on country of origin of the product or service sold)
For the
Year ended December 31
millions of dollars
2022
2021
United States
$
 
5,346
$
 
3,754
Canada
 
1,725
 
1,566
Barbados
 
384
 
292
The Bahamas
 
122
 
110
Dominica
 
11
 
43
$
 
7,588
$
 
5,765
Property Plant and Equipment:
As at
 
December 31
December 31
millions of dollars
2022
2021
United States
$
 
17,382
$
 
14,978
Canada
 
4,689
 
4,440
Barbados
 
583
 
535
The Bahamas
 
342
 
322
Dominica
-
 
 
78
$
 
22,996
$
 
20,353
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
24
6.
 
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, 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 regulatory deferrals
 
371
 
28
 
12
-
 
-
 
-
 
 
411
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 Revenue
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
For the year ended December 31, 2021
 
Regulated Revenue
Residential
$
 
1,449
$
 
797
$
 
165
$
 
642
$
-
 
$
-
 
$
 
3,053
Commercial
 
754
 
407
 
232
 
379
-
 
-
 
 
1,772
Industrial
 
215
 
237
 
26
 
65
-
 
(2)
 
541
Other regulatory deferrals
 
289
 
27
 
7
-
 
-
 
-
 
 
323
Other (1)
 
 
17
 
33
 
15
 
122
-
 
(8)
 
179
Finance income (2)(3)
-
 
-
 
-
 
 
58
-
 
-
 
 
58
 
Regulated revenue
$
 
2,724
$
 
1,501
$
 
445
$
 
1,266
$
-
 
$
(10)
 
5,926
Non-Regulated
 
Marketing and trading margin (4)
-
 
-
 
-
 
-
 
 
102
-
 
 
102
Other non-regulated operating
revenue
-
 
-
 
-
 
 
14
 
30
(21)
 
23
Mark-to-market (3)
-
 
-
 
-
 
-
 
(289)
 
3
(286)
 
Non-regulated revenue
$
-
 
$
-
 
$
-
 
$
 
14
$
(157)
$
(18)
(161)
Total operating revenues
$
 
2,724
$
 
1,501
$
 
445
$
 
1,280
$
(157)
$
(28)
$
 
5,765
(1) Other includes rental revenues, which do not represent revenue from contracts with customers.
(2) Revenue related to Brunswick Pipeline's service agreement with Repsol Energy Canada.
(3) Revenue which does not represent revenues from contracts with customers.
(4) Includes gains (losses) on settlement of energy related derivatives, which do not represent revenue from contracts
 
with
customers.
Remaining Performance Obligations
Remaining performance obligations primarily represent gas transportation contracts, lighting contracts
and long-term steam supply arrangements with fixed contract terms. As of December 31, 2022, the
aggregate amount of the transaction price allocated to remaining performance obligations was $
450
million (2021 – $
437
 
million). This amount includes $
144
 
million of future performance obligations related
to a gas transportation contract between SeaCoast and PGS through 2040. This amount excludes
contracts with an original expected length of one year or less and variable amounts for which Emera
recognizes revenue at the amount to which it has the right to invoice for services performed. Emera
expects to recognize revenue for the remaining performance obligations through
2042
.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
25
7. REGULATORY
 
ASSETS AND LIABILITIES
 
Regulatory assets represent prudently incurred costs that have been deferred because it is probable they
will be recovered through future rates or tolls collected from customers. Management believes existing
regulatory assets are probable for recovery either because the Company received specific approval from
the applicable regulator, or due to regulatory precedent established for similar circumstances. If
management no longer considers it probable that an asset will be recovered, the deferred costs are
charged to income.
 
Regulatory liabilities represent obligations to make refunds to customers or to reduce future revenues for
previous collections. If management no longer considers it probable that a liability will be settled, the
related amount is recognized in income.
For regulatory assets and liabilities that are amortized, the amortization is as approved by the respective
regulator.
As at
December 31
December 31
millions of dollars
 
2022
2021
Regulatory assets
Deferred income tax regulatory assets
$
 
1,166
$
 
1,045
Cost recovery clauses
 
707
 
114
Tampa Electric capital cost recovery for early retired assets
 
 
674
 
657
Pension and post-retirement medical plan
 
369
 
291
FAM
 
307
 
145
Storm reserve
 
 
103
-
 
NMGC winter event gas cost recovery
 
69
 
117
Storm restoration
 
35
 
35
Deferrals related to derivative instruments
 
30
 
23
Environmental remediations
 
27
 
27
Stranded cost recovery
 
27
 
26
Other
 
106
 
86
$
 
3,620
$
 
2,566
Current
$
 
602
$
 
253
Long-term
 
3,018
 
2,313
Total regulatory assets
 
$
 
3,620
$
 
2,566
Regulatory liabilities
Accumulated reserve - cost of remova
l
 
895
 
819
Deferred income tax regulatory liabilities
 
877
 
863
Deferrals related to derivative instruments
 
230
 
241
NMGC gas hedge settlements (note 18)
 
162
-
 
Cost recovery clauses
 
 
70
 
35
Self-insurance fund (note 32)
 
30
 
28
Storm reserve
-
 
 
58
Other
 
9
 
11
$
 
2,273
$
 
2,055
Current
$
 
495
$
 
290
Long-term
 
1,778
 
1,765
Total regulatory liabilities
$
 
2,273
$
 
2,055
Deferred Income Tax Regulatory Assets and Liabilities
To
 
the extent deferred income taxes are expected to be recovered from or returned to customers in future
years, a regulatory asset or liability is recognized as appropriate.
 
26
Cost Recovery Clauses
 
These assets and liabilities are related to Tampa Electric, PGS and NMGC clauses and riders. They are
recovered or refunded through cost-recovery mechanisms approved by the FPSC or New Mexico Public
Regulation Commission (“NMPRC”), as applicable, on a dollar-for-dollar basis in a subsequent period.
Tampa Electric Capital Cost Recovery for Early Retired Assets
This regulatory asset is related to the remaining net book value of Big Bend Power Station Units 1
through 3 and smart meter assets that were retired. The balance earns a rate of return as permitted by
the FPSC and will be recovered as a separate line item on customer bills for a period of
15 years
. This
recovery mechanism is authorized by and survives the term of the settlement agreement approved by the
FPSC in 2021. For further information, refer to “Big Bend Modernization Project” in the Tampa Electric
section below.
Pension and Post-Retirement Medical Plan
 
This asset is primarily related to the deferred costs of pension and post-retirement benefits at Tampa
Electric, PGS and NMGC. It is included in rate base and earns a rate of return as permitted by the FPSC
and NMPRC as applicable. It is amortized over the remaining service life of plan participants.
FAM
This regulated asset is the difference between actual fuel costs and amounts recovered from NSPI
customers through electricity rates in a given year and deferred to a FAM regulatory asset or liability and
recovered from or returned to customers in subsequent periods. For the years 2020 through 2022,
differences between actual fuel costs and fuel revenues recovered from customers will be recovered from
customers in future periods. The Nova Scotia Utility and Review Board’s (“UARB”) decision to approve
the fuel stability plan directed that any annual non-fuel revenues above NSPI’s approved range of ROE
are to be applied to the FAM.
Storm Reserve
The storm reserve is for hurricanes and other named storms that cause significant damage to Tampa
Electric and PGS systems. As allowed by the FPSC, if the charges to the storm reserve exceed the storm
liability, the excess is to be carried as a regulatory asset. Tampa
 
Electric and PGS can petition the FPSC
to seek recovery of restoration costs over a 12-month period, or longer, as determined by the FPSC, as
well as replenish the reserve.
 
In September 2022, Tampa
 
Electric and PGS were impacted by Hurricane
Ian. For further information, refer to “Storm Reserve – Hurricane Ian” in both Tampa Electric and PGS
sections below.
NMGC Winter Event Gas Cost Recovery
In February 2021, the State of New Mexico experienced an extreme cold weather event that resulted in
an incremental $
108
 
million USD for gas costs above what it would normally have paid during this period.
NMGC normally recovers gas supply and related costs through a purchased gas adjustment clause
(“PGAC”). On April 16, 2021, NMGC filed a Motion for Extraordinary Relief, as permitted by the NMPRC
rules, to extend the terms of the repayment of the incremental gas costs and to recover a carrying charge.
On June 15, 2021, the NMPRC approved the recovery of $
108
 
million USD and related borrowing costs
over a period of 30 months beginning July 1, 2021.
 
Storm Restoration
This asset represents storm restoration costs incurred by GBPC. GBPC maintains insurance for its
generation facilities and, as with most utilities, its transmission and distribution networks are not covered
by commercial insurance.
 
27
In January 2020, the Grand Bahama Port Authority (“GBPA”) approved the recovery of $
15
 
million USD
of costs related to Hurricane Dorian in 2019, over a
five-year
 
period. The recovery was implemented
through rates on January 1, 2021.
Restoration costs associated with Hurricane Matthew in 2016 are being recovered through an approved
fuel charge. For further information, refer to “Storm Restoration Costs – Hurricane Matthew” in the GBPC
section below.
 
Deferrals Related to Derivative Instruments
This asset is primarily related to NSPI deferring changes in fair value of derivatives that are documented
as economic hedges or that do not qualify for NPNS exemption, as a regulatory asset or liability as
approved by its regulator. The realized gain or loss is recognized when the hedged item settles in
regulated fuel for generation and purchased power, inventory,
 
other income, OM&G or PP&E, depending
on the nature of the item being economically hedged.
Environmental Remediations
This asset is primarily related to PGS costs associated with environmental remediation at Manufactured
Gas Plant sites. The balance is included in rate base, partially offsetting the related liability, and earns a
rate of return as permitted by the FPSC. The timing of recovery is based on a settlement agreement
approved by the FPSC.
Stranded Cost Recovery
Due to the decommissioning of a GBPC steam turbine in 2012, the GBPA approved the recovery of a $
21
million USD stranded cost through electricity rates; it is included in rate base and is expected to be
included in rates in future years.
 
Accumulated Reserve – Cost of Removal (“COR”)
This regulatory liability represents the non-ARO COR reserve in Tampa Electric, PGS, NMGC and NSPI.
AROs represent the fair value of estimated cash flows associated with the Company’s legal obligation to
retire its PP&E.
 
Non-ARO COR represent estimated funds received from customers through depreciation
rates to cover future COR of PP&E value upon retirement that are not legally required. This reduces rate
base for ratemaking purposes. This liability is reduced as COR are incurred and increased as
depreciation is recorded for existing assets and as new assets are put into service.
NMGC Gas Hedge Settlements
This regulatory liability represents the regulatory deferral of gas options exercised above strike price but
will settle in cash in Q1 2023. The value from the cash settlement of this options will flow through to
customers via the PGAC.
Regulatory Environments and Updates
Florida Electric Utility
Tampa Electric is regulated by the FPSC and is also subject to regulation by the Federal Energy
Regulatory Commission (“FERC”). The FPSC sets rates at a level that allows utilities such as Tampa
Electric to collect total revenues or revenue requirements equal to their cost of providing service, plus an
appropriate return on invested capital. Base rates are determined in FPSC rate setting hearings which
can occur at the initiative of Tampa Electric, the FPSC or other interested parties.
28
Tampa
 
Electric’s approved regulated return on equity (“ROE”) range for 2022 and 2021 was
9.25
 
per cent
to
11.25
 
per cent based on an allowed equity capital structure of
54
 
per cent. An ROE of
10.20
 
per cent
(2021 -
10.25
 
per cent) is used for the calculation of the return on investments for clauses.
Fuel Recovery and Other Cost Recovery Clauses:
Tampa
 
Electric has a fuel recovery clause approved by the FPSC, allowing the opportunity to recover
fluctuating fuel expenses from customers through annual fuel rate adjustments. The FPSC annually
approves cost-recovery rates for purchased power, capacity, environmental and conservation costs,
including a return on capital invested. Differences between the prudently incurred fuel costs and the cost-
recovery rates and amounts recovered from customers through electricity rates in a year are deferred to a
regulatory asset or liability and recovered from or returned to customers in subsequent periods.
 
On January 23, 2023, Tampa
 
Electric requested an adjustment to its fuel charges to recover the 2022 fuel
under-recovery of $
518
 
million USD over a period of
21 months
. The request also included an adjustment
to 2023 projected fuel costs to reflect the reduction in natural gas prices since September 2022 for a
projected reduction of $
170
 
million USD for the balance of 2023. The proposed changes will be decided
by the FPSC in March 2023, and recovery is expected to begin in April 2023.
 
The mid-course fuel adjustment requested by Tampa Electric on January 19, 2022, was approved on
March 1, 2022. The rate increase, effective with the first billing cycle in April 2022, covered higher fuel
and capacity costs of $
169
 
million USD, and was spread over customer bills from April 1, 2022 through
December 2022.
Base Rates:
On October 21, 2021, the FPSC approved a settlement agreement filed by Tampa Electric. The
settlement agreement allows for an increase to rates of $
191
 
million USD annually effective January
2022. This increase consisted of $
123
 
million USD in base rate charges and $
68
 
million USD to recover
the costs of retiring assets including, Big Bend coal generation assets Units 1 through 3 and meter
assets. The settlement agreement further includes two subsequent year adjustments of $
90
 
million USD
and $
21
 
million USD, effective January 2023 and January 2024, respectively related to the recovery of
future investments in the Big Bend Modernization project and solar generation. The allowed equity in the
capital structure will continue to be
54
 
per cent from investor sources of capital. The settlement
agreement includes an allowed regulated ROE range of
9.0
 
per cent to
11.0
 
per cent with a
9.95
 
per cent
midpoint. It also provides for a
25
 
basis point increase in the allowed ROE range and mid-point, and $
10
million USD of additional revenue, if United States Treasury Bond yields exceed a specific threshold set
on the date the FPSC approved the agreement. Under the agreement base rates are frozen from January
1, 2022 to December 31, 2024, unless Tampa Electric’s
 
earned ROE were to fall below the bottom of the
range during that time. The settlement agreement provides for the deferral of income taxes as a result of
changes in tax laws. The changes would be reflected as a regulatory asset or liability and either result in
an increase or a decrease in customer rates through a subsequent regulatory process. The settlement
agreement further creates a mechanism to recover the costs of retiring coal generation units and meter
assets over a period of
15 years
 
which survives the term of that agreement. The settlement agreement
sets new depreciation and dismantlement rates effective January 1, 2022 and contains the provisions that
Tampa
 
Electric will not have to file another depreciation study during the term of the agreement but will
file a new depreciation study no more than
one year
, nor less than
90 days
, before the filing of its next
general base rate proceeding. Tampa Electric agreed not to hedge natural gas through the period ending
on December 31, 2024.
On August 16, 2022, the FPSC approved Tampa Electric’s
 
request to increase revenue and ROE due to
increases in the 30-year United States Treasury bond yield rate. Effective July 1, 2022, the new mid-point
ROE is
10.20
 
per cent, and the range is
9.25
 
per cent to
11.25
 
per cent.
29
Storm Reserve – Hurricane Ian:
In September 2022, Tampa
 
Electric was impacted by Hurricane Ian. Total restoration costs were $
126
million USD, with $
119
 
million USD of restoration costs charged against Tampa Electric’s FPSC approved
storm reserve. Total restoration costs charged to the storm reserve have exceeded the reserve balance
and have been deferred as a regulatory asset for future recovery. On January 23, 2023, Tampa
 
Electric
petitioned the FPSC for recovery of the storm reserve regulatory asset and the replenishment of the
balance in the reserve to the previous approved reserve level of $
56
 
million USD, for a total of
approximately $
131
 
million USD. The proposed changes will be decided by the FPSC in March 2023 and
recovery is expected to begin in April 2023 through March 2024.
Solar Base Rate Adjustments Included in Base Rates:
During 2017 to 2021, Tampa
 
Electric invested $
850
 
million USD in
600
 
MW of utility-scale solar
photovoltaic projects, which is recoverable through FPSC-approved solar base rate adjustments
(“SoBRAs”). AFUDC was earned on these projects during construction. The FPSC has approved SoBRAs
representing a total of
600
 
MW or $
104
 
million USD annually in estimated revenue requirements for in-
service projects.
 
On October 12, 2021, the FPSC approved the true-up filing for SoBRA tranche 3, included in base rates
as of January 2020. A $
4
 
million USD true-up was returned to customers during 2021. No true-up for
SoBRA tranche 4 was required.
Storm Protection Cost Recovery Clause and Settlement Agreement:
On October 3, 2019, the FPSC issued a rule to implement a Storm Protection Plan (“SPP”) Cost
Recovery Clause. This clause provides a process for Florida investor-owned utilities, including Tampa
Electric, to recover transmission and distribution storm hardening costs for incremental activities not
already included in base rates. Differences between prudently incurred clause-recoverable costs and
amounts recovered from customers through electricity rates in a year are deferred and recovered from or
returned to customers in a subsequent year. A settlement agreement was approved on August 10, 2020,
and Tampa
 
Electric’s cost recovery began in January 2021. The current approved plan addressed the
years 2020 through 2022, and in April 2022 Tampa Electric submitted a new plan to determine cost
recovery in 2023, 2024 and 2025. On October 4, 2022, the FPSC approved Tampa Electric’s SPP.
Big Bend Modernization Project:
Tampa
 
Electric invested $
876
 
million USD, including $
91
 
million USD of AFUDC, during 2018 through
2022 to modernize the Big Bend Power Station. The modernization project repowered Big Bend Unit 1
with natural gas combined-cycle technology and eliminated coal as this unit’s fuel. As part of the
modernization project, Tampa Electric retired the Unit 1 components that will not be used in the
modernized plant in 2020 and Big Bend Unit 2 in 2021. Tampa Electric plans to retire Big Bend Unit 3 in
2023 as it is in the best interest of the customers from an economic, environmental risk and operational
perspective.
 
At December 31, 2021, the balance sheet included $
636
 
million USD in electric utility plant and $
267
million USD in accumulated depreciation related to Unit 1 components and Unit 2 and Unit 3 assets. In
accordance with Tampa Electric’s
 
2017 settlement agreement approved by the FPSC, Tampa Electric
continued to account for its existing investment in Unit 1, 2 and 3 in electric utility plant and depreciated
the assets using the current depreciation rates until December 31, 2021, at which point they were
reclassified to a regulatory asset on the balance sheet.
 
30
Tampa
 
Electric’s 2021 settlement agreement provides recovery for the Big Bend Modernization project in
two phases. The first phase was a revenue increase to cover the costs of the assets in service during
2022, among other items. The remainder of the project costs will be recovered as part of the 2023
subsequent year adjustment. The settlement agreement also includes a new charge to recover the
remaining costs of the retiring Big Bend coal generation assets, Units 1 through 3, which will be spread
over
15 years
 
and will survive the termination of the settlement agreement. The special capital recovery
schedule for all three units was applied beginning January 1, 2022. This recovery mechanism is
authorized by and survives the term of the settlement agreement approved by the FPSC in 2021.
Canadian Electric Utilities
NSPI
NSPI is a public utility as defined in the Public Utilities Act of Nova Scotia (“Public Utilities Act”) and is
subject to regulation under the Public Utilities Act by the UARB. The Public Utilities Act gives the UARB
supervisory powers over NSPI’s operations and expenditures. Electricity rates for NSPI’s customers are
also subject to UARB approval. NSPI is not subject to a general annual rate review process, but rather
participates in hearings held from time to time at NSPI’s or the UARB’s request.
NSPI is regulated under a cost-of-service model, with rates set to recover prudently incurred costs of
providing electricity service to customers and provide a reasonable return to investors. NSPI’s approved
regulated ROE range for 2022 and 2021 was
8.75
 
per cent to
9.25
 
per cent based on an actual five
quarter average regulated common equity component of up to
40
 
per cent of approved rate base.
NSPI has a FAM, approved by the UARB, allowing NSPI to recover fluctuating fuel costs from customers
through regularly scheduled fuel rate adjustments. Differences between prudently incurred fuel costs and
amounts recovered from customers through electricity rates in a year are deferred to a FAM regulatory
asset or liability and recovered from or returned to customers in subsequent periods.
 
For the period of 2020 through 2022, NSPI operated under a
three-year
 
fuel stability plan which resulted
in an average annual overall rate increase of
1.5
 
per cent to recover fuel costs. These rates included
recovery of Maritime Link costs.
General Rate Application (“GRA”):
On November 9, 2022, the Nova Scotia provincial government enacted Bill 212, “Public Utilities Act
(amended)”. The legislation limits non-fuel rate increases in NSPI’s 2022 GRA to the UARB, excluding
increases relating to demand side management (“DSM”) costs, to a total of
1.8
 
per cent between the
effective date of the UARB’s decision and the end of 2024. The legislation also:
 
●
requires revenue generated from the non-fuel rate increase to be used only to improve the
reliability of service to ratepayers,
●
limits NSPI’s return on equity to
9.25
 
per cent and equity ratio to
40
 
per cent, and
●
limits the rate used to accrue interest on regulatory deferrals to the Bank of Canada policy
interest rate plus
1.75
 
per cent, unless otherwise directed by the UARB.
31
On November 24, 2022, NSPI filed with the UARB a comprehensive settlement agreement between
NSPI, key customer representatives and participating interest groups (“NSPI Settlement Agreement”) in
relation to its GRA filed in January 2022. The NSPI Settlement Agreement was structured to be
consistent with the amendments to the Public Utilities Act made under Bill 212, including the
1.8
 
per cent
cap on non-fuel rate increases for 2023 and 2024. The NSPI Settlement Agreement also addresses the
recovery of fuel costs over the settlement period and establishes a DSM rider. This will result in a
combined fuel and non-fuel rate increase of
6.9
 
per cent each year for 2023 and 2024, and annualised
incremental revenue (fuel and non-fuel) of $
105
 
million in 2023 and $
115
 
million in 2024. In addition, any
under or over recovery of fuel costs will be addressed through the UARB’s established FAM process.
NSPI’s ROE range will continue to be
8.75
 
per cent to
9.25
 
per cent, based on an actual five-quarter
average regulated common equity component of up to
40
 
per cent. The NSPI Settlement Agreement also
establishes a storm rider for each of 2023, 2024 and 2025, which gives NSPI the option to apply to the
UARB for recovery of costs if major storm restoration expense exceeds approximately $
10
 
million in a
given year. On February 2, 2023, NSPI received the UARB’s decision, which substantially approved the
Settlement Agreement as filed. Approved rate increases will be effective as of the date of the decision.
Maritime Link:
The Maritime Link is a $
1.8
 
billion (including AFUDC) transmission project including
two
170
-kilometre
sub-sea cables, connecting the island of Newfoundland and Nova Scotia. The Maritime Link entered
service on January 15, 2018 and NSPI started interim assessment payments to NSPML at that time.
 
As part of a
three-year
 
fuel stability plan, electricity rates were set to include amounts of $
164
 
million and
$
162
 
million for 2021 and 2022, respectively. Any difference between the amounts included in the fuel
stability plan and those approved by the UARB through the NSPML interim assessment application will be
addressed through the FAM.
 
Nova Scotia Cap-and-Trade (“Cap-and-Trade”)
 
Program:
As at December 31, 2022, the FAM includes a recovery of $
172
 
million (December 31, 2021 – $
38
million) non-cash accrual representing the estimated future cost of acquiring emissions credits for the
2019 through 2022 Cap-and-Trade compliance period. Emissions for the compliance period will not be
finalized until the completion of the environmental audit which begins in March 2023. Emissions are
currently based upon audited actual emissions from 2019 through 2021 and unaudited actuals for 2022.
The total cost of compliance with the Cap-and-Trade program compliance period could change
depending on the price paid for both credits at remaining provincial auctions and reserve credits
purchased from the provincial government, and the results of the 2022 environmental emissions audit.
Lower than forecast Muskrat Falls energy received during the compliance period has resulted in the
increased deployment of higher carbon-emitting generation sources. The Province of Nova Scotia has
agreed to provide approximately $
165
 
million of relief from the 2019 through 2022 compliance costs,
which was equal to the total cost of compliance forecast at the time of the fuel update submitted by NSPI
to the UARB in September 2022 as part of the GRA. Discussions related to the final amount of relief and
how this relief will be provided are ongoing. Further, NSPI’s regulatory framework provides for the
recovery of costs prudently incurred to comply with the Cap-and-Trade Program Regulations pursuant to
NSPI’s FAM.
NSPML
Equity earnings from the Maritime Link are dependent on the approved ROE and operational
performance of NSPML. NSPML’s approved regulated ROE range is
8.75
 
per cent to
9.25
 
per cent,
based on an actual five-quarter average regulated common equity component of up to
30
 
per cent.
 
Nalcor’s Nova Scotia Block (“NS Block”) delivery obligations commenced on August 15, 2021 and
delivery will continue over the next
35 years
 
pursuant to the agreements.
 
32
In February 2022, the UARB issued its decision and Board Order approving NSPML’s requested rate
base of approximately $
1.8
 
billion less $
9
 
million of costs ($
7
 
million after-tax) that would not have
otherwise been recoverable if incurred by NSPI. NSPML also received approval to collect up to $
168
million (2021 – $
172
 
million) from NSPI for the recovery of costs associated with the Maritime Link in
2022. This was subject to a holdback of up to $
2
 
million a month, beginning April 2022, contingent on
receiving at least
90
 
per cent of NS Block deliveries, including Supplemental Energy deliveries.
 
In December 2022, NSPML received UARB approval to collect up to $
164
 
million from NSPI for the
recovery of costs associated with the Maritime Link in 2023. This continues to be subject to a holdback of
up to $
2
 
million a month, as discussed above. On December 22, 2022, the UARB clarified its earlier
direction regarding the holdback and NSPI can now release the holdback to NSPML when
90
 
per cent of
NS Block deliveries, including Supplemental Energy deliveries, is achieved. This enabled NSPI to pay
NSPML approximately $
4
 
million of the 2022 holdback. As of December 31, 2022, an additional $
14
million in aggregate has been held-back by NSPI. Determination of the allocation of the $
14
 
million
between NSPML and NSPI will be subject to a regulatory process that is expected to commence in early
2023 to review the holdback mechanism.
 
Gas Utilities and Infrastructure
PGS
PGS is regulated by the FPSC. The FPSC sets rates at a level that allows utilities such as PGS to collect
total revenues or revenue requirements equal to their cost of providing service, plus an appropriate return
on invested capital.
PGS’s approved ROE range for 2022 and 2021 was
8.9
 
per cent to
11.0
 
per cent with a
9.9
 
per cent
midpoint, based on an allowed equity capital structure of
54.7
 
per cent.
 
Fuel Recovery:
PGS recovers the costs it pays for gas supply and interstate transportation for system supply through its
PGAC. This clause is designed to recover actual costs incurred by PGS for purchased gas, gas storage
services, interstate pipeline capacity, and other related items associated with the purchase, distribution,
and sale of natural gas to its customers. These charges may be adjusted monthly based on a cap
approved annually by the FPSC.
Recovery of Energy Conservation and Pipeline Replacement Programs:
The FPSC annually approves a conservation charge that is intended to permit PGS to recover prudently
incurred expenditures in developing and implementing cost effective energy conservation programs which
are required by Florida law and approved and monitored by the FPSC. PGS also has a Cast Iron/Bare
Steel Pipe Replacement clause to recover the cost of accelerating the replacement of cast iron and bare
steel distribution lines in the PGS system. In February 2017, the FPSC approved expansion of the Cast
Iron/Bare Steel clause to allow recovery of accelerated replacement of certain obsolete plastic pipe. The
majority of cast iron and bare steel pipe has been removed from its system, with replacement of obsolete
plastic pipe continuing until 2028 under the rider.
 
Storm Reserve – Hurricane Ian:
In September 2022, Hurricane Ian impacted PGS’s operations in Fort Myers and Sarasota. The
restoration costs were approximately $
2
 
million USD and $
1
 
million was charged against PGS’s FPSC-
approved storm reserve.
 
33
Base Rates:
On November 19, 2020, the FPSC approved a settlement agreement filed by PGS.
 
The settlement
agreement allows for an increase to base rates by $
58
 
million USD annually, effective January 1 2021,
which is a $
34
 
million USD increase in revenue and $
24
 
million USD increase of revenues previously
recovered through the cast iron and bare steel replacement rider. It provides PGS the ability to reverse a
total of $
34
 
million USD of accumulated depreciation through 2023. During 2022, PGS reversed $
14
million USD of the $
34
 
million USD accumulated depreciation. No amounts were reversed prior to 2022.
In addition, the agreement sets new depreciation rates effective January 1, 2021. Under the agreement
base rates are frozen from January 1, 2021 to December 31, 2023, unless its earned ROE were to fall
below
8.9
 
per cent before that time with an allowed equity in the capital structure of
54.7
 
per cent from
investor sources of capital. The settlement agreement provides for the deferral of income taxes as a
result of changes in tax laws. The changes would be reflected as a regulatory asset or liability and either
result in an increase or a decrease in customer rates through a subsequent regulatory process.
NMGC
NMGC is subject to regulation by the NMPRC. The NMPRC sets rates at a level that allows NMGC to
collect total revenues equal to its cost of providing service, plus an appropriate return on invested capital.
 
NMGC’s approved ROE for 2022 and 2021 was
9.375
 
per cent on an allowed equity capital structure of
52
 
per cent.
 
Fuel Recovery:
NMGC recovers gas supply costs through a PGAC. This clause recovers actual costs for purchased gas,
gas storage services, interstate pipeline capacity, and other related items associated with the purchase,
transmission, distribution, and sale of natural gas to its customers. On a monthly basis, NMGC can adjust
the charges based on the next month’s expected cost of gas and any prior month under-recovery or over-
recovery. The NMPRC requires that NMGC annually file a reconciliation of the PGAC period costs and
recoveries. NMGC must file a PGAC Continuation Filing with the NMPRC every four years to establish
that the continued use of the PGAC is reasonable and necessary. In December 2020, NMGC received
approval of its PGAC Continuation Filing for the four-year period ending December 2024.
Base Rates:
On December 13, 2021, NMGC filed a rate case with the NMPRC for new rates to become effective
January 2023. On May 20, 2022, NMGC filed an unopposed settlement agreement with the NMPRC for
an increase of $
19
 
million USD in annual base revenues. The rates reflect the recovery of increased
operating costs and capital investments in pipelines and related infrastructure. The NMPRC approved the
settlement agreement on November 30, 2022.
Weather Normalization Mechanism:
 
In July 2019, the NMPRC approved changes to the company’s rate design to include a five-year pilot of
Weather Normalization Mechanism. This clause is designed to lower the variability of weather impacts
during the October through April heating seasons. The Weather Normalization Mechanism allows
customer rates and company revenue to be more predictable by partially removing the impact of warmer
than usual or colder than usual weather. Weather-related revenue increases or decreases experienced
from October to April are adjusted annually in October of the following heating season.
 
34
Integrity Management Programs (“IMP”) Regulatory Asset:
A portion of NMGC’s annual spending on infrastructure is for IMP,
 
or the replacement and update of
legacy systems. These programs are driven both by NMGC integrity management plans and federal and
state mandates. In December 2020, NMGC received approval through its rate case to defer costs through
an IMP regulatory asset for certain of its IMP capital investments occurring between January 1, 2022 and
December 31, 2023 and petitioned recovery of the regulatory asset in its rate case filed on December 13,
2021. On November 30, 2022, the NMPRC issued a Final Order that included approval of recovery of the
IMP regulatory asset.
 
Brunswick Pipeline
 
Brunswick Pipeline is a
145
-kilometre pipeline delivering natural gas from the Saint John LNG import
terminal near Saint John, New Brunswick to markets in the northeastern United States. Brunswick
Pipeline entered into a
25
-year firm service agreement commencing in July 2009 with Repsol Energy
North America Canada Partnership. The agreement provides for a predetermined toll increase in the fifth
and fifteenth year of the contract. The pipeline is considered a Group II pipeline regulated by the Canada
Energy Regulator (“CER”). The CER Gas Transportation Tariff
 
is filed by Brunswick Pipeline in
compliance with the requirements of the CER Act and sets forth the terms and conditions of the
transportation rendered by Brunswick Pipeline.
Other Electric Utilities
BLPC
 
BLPC is regulated by the Fair Trading Commission (“FTC”), an independent regulator, under the Utilities
Regulation (Procedural) Rules 2003. BLPC is regulated under a cost-of-service model, with rates set to
recover prudently incurred costs of providing electricity service to customers plus an appropriate return on
capital invested. BLPC’s approved regulated return on rate base was
10
 
per cent for 2022 and 2021.
Licenses:
The Government of Barbados has granted BLPC a franchise to generate, transmit and distribute
electricity on the island until 2028. In 2019, the Government of Barbados passed legislation amending the
number of licenses required for the supply of electricity from a single integrated license which currently
exists to multiple licenses for Generation, Transmission and Distribution, Storage, Dispatch and Sales. In
March 2021, BLPC reached commercial agreement with the Government of Barbados for each of the
license types, subject to the passage of implementing legislation. The new licenses are expected to take
effect in 2023 on completion of the legislative process. The Dispatch license will have a term of
5 years
with the remaining licenses having terms ranging from
25
-
30 years
. BLPC anticipates that any increased
costs associated with the implementation of the new multi-licensed structure will be recoverable through
BLPC’s regulatory framework. BLPC is awaiting final enactment and will work towards implementation of
the licenses once received.
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.
35
On October 4, 2021 BLPC submitted a general rate review application to the FTC. The application seeks
a rate adjustment and the implementation of a cost reflective rate structure that will facilitate the changes
expected in the newly reformed electricity market and the country’s transition towards 100 per cent
renewable energy generation. The application seeks recovery of capital investment in plant, equipment
and related infrastructure and results in an increase in annual non-fuel revenue of approximately $
23
million USD upon approval. The application includes a request for allowed regulatory ROE of
12.50
 
per
cent on an allowed equity capital structure of
65
 
per cent. On September 16, 2022, the FTC granted
BLPC interim rate relief, allowing an increase in base rates of approximately $
3
 
million USD for the
remainder of 2022 and approximately $
1
 
million USD per month for 2023. Interim rate relief is effective
from September 16, 2022 until the implementation of final rates. The hearing concluded in October 2022.
On February 15, 2023, the FTC issued a decision on the BLPC rate review application which included the
following significant items: an allowed regulatory ROE of
11.75
 
per cent, an equity capital structure of
55
per cent, a directive to update the major components of rate base to September 16, 2022, and a directive
to establish regulatory liabilities of approximately $
70
 
million USD related to the self-insurance fund,
accumulated depreciation, and taxes. The impacts to BLPC's rate base and final rates are not yet
determinable. BLPC will seek to clarify aspects of the FTC decision in its compliance filing and is also
considering filing a submission to the FTC for a review of the decision. BLPC expects a decision on final
rates from the FTC in 2023.
Fuel Hedging:
On October 21, 2021, the FTC approved BLPC’s application to implement a fuel hedging program which
will be incorporated into the calculation of the fuel clause adjustment. On November 10, 2021, BLPC
requested the FTC review the required
50
/50 cost sharing arrangement between BLPC and customers in
relation to the hedging administrative costs, or any gains and losses associated with the hedging
program. A decision is expected from the FTC in 2023.
GBPC
GBPC is regulated by the GBPA. The GBPA
 
has granted GBPC a licensed, regulated and exclusive
franchise to produce, transmit and distribute electricity on the island until 2054. Rates are set to recover
prudently incurred costs of providing electricity service to customers plus an appropriate return on rate
base. GBPC’s approved regulated return on rate base was
8.23
 
per cent for 2022 (2021 –
8.37
 
per cent).
Fuel Recovery:
GBPC’s fuel costs flow through a fuel pass-through mechanism which provides the opportunity to recover
all prudently incurred fuel costs from customers in a timely manner.
Effective November 1, 2022, GBPC’s fuel pass through charge was increased due to an increase in
global oil prices impacting the unhedged fuel cost. In 2023, the fuel pass through charge will be adjusted
monthly, in-line with actual fuel costs.
Base Rates:
There is a fuel pass-through mechanism and tariff review policy with new rates submitted every three
years. On January 14, 2022, the GBPA issued its decision on GBPC’s application for rate review that was
filed with the GBPA on September 23, 2021. The decision, which became effective April 1, 2022, allows
for an increase in revenues of $
3.5
 
million USD. The new rates include a regulatory ROE of
12.84
 
per
cent.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
36
Storm Restoration Costs – Hurricane Matthew:
In 2017, as part of the recovery of costs incurred as a result of Hurricane Matthew, the GBPA approved a
fixed per kWh fuel charge and allowed the difference between this and the actual cost of fuel to be
applied to the Hurricane Matthew regulatory asset. As part of its decision on GBPC’s application for rate
review, issued January 14, 2022, and effective April 1, 2022, the GBPA
 
approved the continued
amortization of the remaining regulatory asset over the three year period ending December 31, 2024.
8.
 
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
2022
2021
2022
2021
2022
LIL
(1)
$
 
740
$
 
682
$
 
58
$
 
54
 
31.9
NSPML
 
501
 
533
 
29
 
49
 
100.0
M&NP
 
(2)
 
128
 
123
 
21
 
20
 
12.9
Lucelec
(2)
 
49
 
44
 
4
 
4
 
19.5
Bear Swamp
 
(3)
-
 
-
 
 
17
 
16
 
50.0
$
 
1,418
$
 
1,382
$
 
129
$
 
143
(1) Emera indirectly owns
100
 
per cent of the Class B units, which comprises
24.5
 
per cent of the total units issued. Percentage
ownership in LIL is subject to change, based on the balance of capital investments required from Emera and Nalcor Energy
 
to
complete construction of the LIL. Emera’s ultimate percentage investment in LIL will be determined upon
 
final costing of
 
all transmission projects related to the Muskrat Falls development, including the LIL, Labrador Transmission
 
Assets and Maritime
Link Projects, such that Emera’s total investment in the Maritime Link and LIL will equal
49
 
per cent of the cost of all of these
transmission developments.
(2) Although Emera’s ownership percentage of these entities is relatively low,
 
it is considered to have significant influence over the
operating and financial decisions of these companies through Board representation. Therefore, Emera records its investment
 
in
these entities using the equity method.
 
(3) The investment balance in Bear Swamp is in a credit position primarily as a result of a $
179
 
million distribution received in 2015.
Bear Swamp's credit investment balance of $
95
 
million (2021 – $
104
 
million) is recorded in Other long-term liabilities on the
Consolidated Balance Sheets.
 
Equity investments include a $
9
 
million difference between the cost and the underlying fair value of the
investees' assets as at the date of acquisition. The excess is attributable to goodwill.
Emera accounts for its variable interest investment in NSPML as an equity investment (note 32).
NSPML's consolidated summarized balance sheets are illustrated as follows:
As at
December 31
millions of dollars
2022
2021
Balance Sheets
Current assets
$
 
17
$
 
25
PP&E
 
1,517
 
1,587
Regulatory assets
 
265
 
247
Non-current assets
 
29
 
31
Total assets
$
 
1,828
$
 
1,890
Current liabilities
$
 
48
$
 
50
Long-term debt
(1)
 
1,149
 
1,189
Non-current liabilities
 
130
 
118
Equity
 
501
 
533
Total liabilities and equity
$
 
1,828
$
 
1,890
(1) The project debt has been guaranteed by the Government of Canada.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
37
9.
 
OTHER INCOME, NET
For the
Year ended December 31
millions of dollars
2022
2021
TECO Guatemala Holdings award
(1)
$
 
63
$
-
 
AFUDC
 
52
 
61
Other
 
 
30
 
32
$
 
145
$
 
93
(1) Refer to note 27 for further detail related to the TECO Guatemala Holdings award.
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
2022
2021
Income before provision for income taxes
$
 
1,194
$
 
555
Statutory income tax rate
29.0%
29.0%
Income taxes, at statutory income tax rate
 
346
 
161
Deferred income taxes on regulated income recorded as regulatory assets and
regulatory liabilities
(70)
(62)
Foreign tax rate variance
(44)
(42)
Amortization of deferred income tax regulatory liabilities
(33)
(33)
GBPC impairment charge
 
 
21
-
 
Tax effect
 
of equity earnings
(10)
(16)
Tax credits
(18)
(13)
Other
(7)
(1)
Income tax expense (recovery)
 
$
 
185
$
(6)
Effective income tax rate
15%
(1%)
On August 16, 2022, the United States Inflation Reduction Act (“IRA”) was signed into legislation. The
IRA includes numerous tax incentives for clean energy, such as the extension and modification of existing
investment and production tax credits for projects placed in service through 2024 and introduces new
technology-neutral clean energy related tax credits beginning in 2025. During 2022, the Company
recorded a $
9
 
million regulatory liability in recognition of its obligation to pass the incremental tax benefits
realized to customers.
The following table reflects the composition of taxes on income from continuing operations presented in
the Consolidated Statements of Income for the years ended December 31:
millions of dollars
2022
2021
Current income taxes
 
Canada
$
 
25
$
 
20
 
United States
 
8
 
11
Deferred income taxes
 
Canada
 
120
(33)
 
United States
 
252
 
118
 
Other
-
 
 
2
Investment tax credits
 
United States
(7)
(11)
Operating loss carryforwards
 
Canada
(92)
(64)
 
United States
(121)
(49)
Income tax expense (recovery)
$
 
185
$
(6)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
38
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
2022
2021
Canada
$
 
173
$
 
244
United States
 
1,063
 
289
Other
(42)
 
22
Income before provision for income taxes
$
 
1,194
$
 
555
The deferred income tax assets and liabilities presented in the Consolidated Balance Sheets as at
December 31 consisted of the following:
millions of dollars
2022
2021
Deferred income tax assets:
Tax loss carryforwards
$
 
1,207
$
 
873
Tax credit carryforwards
 
415
 
375
Regulatory liabilities - cost of removal
 
177
 
170
Derivative instruments
 
45
 
188
Other
 
428
 
434
Total deferred income tax assets before valuation allowance
 
2,272
 
2,040
Valuation allowance
(312)
(256)
Total deferred income tax assets after valuation allowance
$
 
1,960
$
 
1,784
Deferred income tax (liabilities):
PP&E
$
(2,981)
$
(2,622)
Regulatory assets
(219)
(78)
Derivative instruments
(125)
(197)
Other
(594)
(460)
Total deferred income tax liabilities
 
$
(3,919)
$
(3,357)
Consolidated Balance Sheets presentation:
Long-term deferred income tax assets
$
 
237
$
 
295
Long-term deferred income tax liabilities
(2,196)
(1,868)
Net deferred income tax liabilities
$
(1,959)
$
(1,573)
Considering all evidence regarding the utilization of the Company’s deferred income tax assets, it has
been determined that Emera is more likely than not to realize all recorded deferred income tax assets,
except for certain loss carryforwards and unrealized capital losses on long-term debt and investments. A
valuation allowance of $
312
 
million has been recorded as at December 31, 2022 (2021 – $
256
 
million)
related to the loss carryforwards, long-term debt and investments.
The Company intends to indefinitely reinvest earnings from certain foreign operations. Accordingly, as at
December 31, 2022, $
3.8
 
billion (2021 – $
2.9
 
billion) in cumulative temporary differences for which
deferred taxes might otherwise be required, have not been recognized. It is impractical to estimate the
amount of income and withholding tax that might be payable if a reversal of temporary differences
occurred.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
39
Emera’s NOL, capital loss and tax credit carryforwards and their expiration periods as at December 31,
2022 consisted of the following:
Subject to
Tax
Valuation
Net Tax
Expiration
millions of dollars
Carryforwards
Allowance
Carryforwards
Period
Canada
 
NOL
$
 
2,372
$
(977)
$
 
1,395
2026 - 2042
 
Capital loss
 
79
(79)
-
 
Indefinite
United States
 
Federal NOL
$
 
2,082
$
-
 
$
 
2,082
2032 - Indefinite
 
State NOL
 
1,489
-
 
 
1,489
2032 - Indefinite
 
Tax credit
 
415
-
 
 
415
2025 - 2042
Other
 
NOL
$
 
73
$
(33)
$
 
40
2023 - 2029
The following table provides details of the change in unrecognized tax benefits for the years ended
December 31 as follows:
millions of dollars
2022
2021
Balance, January 1
$
 
28
$
 
30
Increases due to tax positions related to current year
 
5
 
4
Increases due to tax positions related to a prior year
 
2
 
1
Decreases due to tax positions related to a prior year
(2)
(1)
Decreases due to settlement with tax authorities
-
 
(6)
Balance, December 31
$
 
33
$
 
28
The total amount of unrecognized tax benefits as at December 31, 2022 was $
33
 
million (2021 - $
28
million), which would affect the effective tax rate if recognized. The total amount of accrued interest with
respect to unrecognized tax benefits was $
7
 
million (2021 – $
6
 
million) with $
1
 
million interest expense
recognized in the Consolidated Statements of Income (2021 –
nil
).
No
 
penalties have been accrued. The
balance of unrecognized tax benefits could change in the next 12 months as a result of resolving Canada
Revenue Agency (“CRA”) and Internal Revenue Service audits. A reasonable estimate of any change
cannot be made at this time.
During 2022, the CRA issued notices of reassessment to NSPI for the 2013 through 2016 taxation years.
NSPI and the CRA are currently in a dispute with respect to the timing of certain tax deductions for
its 2006 through 2010 and 2013 through 2016 taxation years. The ultimate permissibility of the tax
deductions is not in dispute; rather, it is the timing of those deductions. The cumulative net amount in
dispute to date is $
126
 
million (2021 – $
62
 
million), including interest. NSPI has prepaid $
55
 
million (2021
– $
23
 
million) of the amount in dispute, as required by CRA.
On November 29, 2019, NSPI filed a Notice of Appeal with the Tax Court of Canada with respect to its
dispute of the 2006 through 2010 taxation years. Should NSPI be successful in defending its position, all
payments including applicable interest will be refunded. If NSPI is unsuccessful in defending any portion
of its position, the resulting taxes and applicable interest will be deducted from amounts previously paid,
with the difference, if any, either owed to, or refunded from, the CRA. The related tax deductions will be
available in subsequent years.
Should NSPI be similarly reassessed by the CRA for years not currently in dispute, further payments will
be required; however, the ultimate permissibility of these deductions would be similarly not in dispute.
NSPI and its advisors believe that NSPI has reported its tax position appropriately. NSPI continues to
assess its options to resolving the dispute; however, the outcome of the Notice of Appeal process is not
determinable at this time.
 
 
 
 
 
 
 
 
 
 
 
 
40
Emera files a Canadian federal income tax return, which includes its Nova Scotia provincial income tax.
Emera’s subsidiaries file Canadian, US, Barbados, and St. Lucia income tax returns. As at December 31,
2022, the Company’s tax years still open to examination by taxing authorities include 2005 and
subsequent years.
 
11.
 
COMMON STOCK
Authorized
:
 
Unlimited number of non-par value common shares.
2022
2021
Issued and outstanding:
millions
of shares
 
millions of
dollars
millions of
shares
 
millions of
dollars
Balance, December 31, 2021
 
261.07
$
 
7,242
 
251.43
$
 
6,705
Issuance of common stock under ATM program
(1)(2)
 
4.07
 
248
 
4.99
 
284
Issued under the DRIP,
 
net of discounts
 
4.21
 
238
 
3.90
 
215
Senior management stock options exercised and Employee Share
Purchase Plan
 
0.60
 
34
 
0.75
 
38
Balance, December 31, 2022
 
269.95
$
 
7,762
 
261.07
$
 
7,242
(1) As at December 31, 2021, a total of
4,987,123
 
common shares were issued under Emera's ATM
 
program at an average price of
$
57.63
 
per share for gross proceeds of $
287
 
million ($
284
 
million net of after-tax issuance costs).
(2) For the year ended December 31, 2022,
4,072,469
 
common shares were issued under Emera's ATM
 
program at an average price
of $
61.31
 
per share for gross proceeds of $
250
 
million ($
248
 
million net of after-tax issuance costs).
On August 12, 2021, Emera renewed its ATM Program that allows the Company to issue up to $
600
million of common shares from treasury to the public from time to time, at the Company's discretion, at
the prevailing market price. The ATM Program was renewed pursuant to a prospectus supplement to the
Company's short form base shelf prospectus dated August 5, 2021. The ATM program is expected to
remain in effect until September 5, 2023. As at December 31, 2022, an aggregate gross sales limit of
$
207
 
million remains available for issuance under the ATM program.
As at December 31, 2022, the following common shares were reserved for issuance:
6
 
million (2021 –
6.2
million) under the senior management stock option plan,
2.7
 
million (2021 –
3.1
 
million) under the
employee common share purchase plan and
10
 
million (2021 –
14.2
 
million) under the DRIP.
 
The issuance of common shares under the common share compensation arrangements does not allow
the plans to exceed
10
 
per cent of Emera's outstanding common shares. As at December 31, 2022,
Emera is in compliance with this requirement.
 
12.
 
EARNINGS PER SHARE
Basic earnings per share is determined by dividing net income attributable to common shareholders by
the weighted average number of common shares outstanding during the period. Diluted EPS is computed
by dividing net income attributable to common shareholders by the weighted average number of common
shares outstanding during the period, adjusted for the exercise and/or conversion of all potentially dilutive
securities. Such dilutive items include Company contributions to the senior management stock option
plan, convertible debentures and shares issued under the DRIP.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
41
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)
2022
2021
Numerator
Net income attributable to common shareholders
$
 
945.1
$
 
510.5
Diluted numerator
 
945.1
 
510.5
Denominator
Weighted average shares of common stock outstanding
 
 
265.5
 
255.9
Weighted average deferred share units outstanding
 
(1)
-
 
 
1.3
Weighted average shares of common stock outstanding – basic
 
265.5
 
257.2
Stock-based compensation
 
 
0.4
 
0.4
Weighted average shares of common stock outstanding – diluted
 
265.9
 
257.6
Earnings per common share
Basic
 
$
 
3.56
$
 
1.98
Diluted
$
 
3.55
$
 
1.98
(1) Effective February 10, 2022, deferred share units are no longer able to be settled in shares and are
 
therefore no longer included
in the calculation of earnings per common share.
13.
 
ACCUMULATED OTHER COMPREHENSIVE INCOME
The components of AOCI are as follows:
millions of dollars
Unrealized gain
(loss) on
translation of
self-sustaining
foreign
operations
Net change in
net investment
hedges
Gains on
derivatives
recognized
 
as cash flow
hedges
Net change
on available-
for-sale
investments
Net change in
unrecognized
pension and
post-retirement
benefit costs
Total
 
AOCI
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
For the year ended December 31, 2021
Balance, January 1, 2021
$
 
52
$
 
30
$
 
1
$
(1)
$
(161)
$
(79)
 
Other comprehensive (loss)
 
 
income before
 
 
reclassifications
(42)
 
5
 
18
-
 
-
 
(19)
 
Amounts reclassified from
 
 
AOCI
-
 
-
 
(1)
-
 
 
124
 
123
Net current period other
comprehensive income (loss)
(42)
 
5
 
17
-
 
 
124
 
104
Balance, December 31, 2021
$
 
10
$
 
35
$
 
18
$
(1)
$
(37)
$
 
25
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
42
The reclassifications out of accumulated other comprehensive income (loss) are as follows:
For the
Year ended December 31
millions of dollars
2022
2021
Affected line item in the Consolidated Financial Statements
Gains on derivatives recognized as cash flow hedges
 
Interest rate hedge
Interest expense, net
$
(2)
$
(1)
Net change in unrecognized pension and post-retirement benefit costs
 
Actuarial losses
Other income, net
$
 
10
$
 
24
 
Amounts reclassified into obligations
Pension and post-retirement benefits
 
15
 
102
Total before tax
 
25
 
126
Income tax expense
(1)
(2)
Total net of tax
$
 
24
$
 
124
Total reclassifications out of AOCI, net of tax, for the period
$
 
22
$
 
123
14.
 
INVENTORY
As at
December 31
December 31
millions of dollars
 
2022
2021
Fuel
 
$
 
404
$
 
255
Materials
 
 
365
 
283
Total
$
 
769
$
 
538
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
2022
2021
2022
2021
Regulatory deferral:
 
Commodity swaps and forwards
$
 
186
$
 
146
$
 
42
$
 
16
 
FX forwards
 
18
 
7
 
1
 
8
 
Physical natural gas purchases and sales
 
52
 
88
-
 
-
 
 
256
 
241
 
43
 
24
HFT derivatives:
 
Power swaps and physical contracts
 
89
 
33
 
77
 
32
 
Natural gas swaps, futures, forwards, physical
 
 
contracts
 
340
 
208
 
1,224
 
818
 
429
 
241
 
1,301
 
850
Other derivatives:
 
Equity derivatives
 
-
 
 
11
 
5
-
 
 
FX forwards
 
5
-
 
 
23
-
 
 
5
 
11
 
28
-
 
Total gross current derivatives
 
690
 
493
 
1,372
 
874
Impact of master netting agreements:
 
Regulatory deferral
(18)
(4)
(18)
(4)
 
HFT derivatives
(276)
(188)
(276)
(188)
Total impact of master netting agreements
(294)
(192)
(294)
(192)
Total derivatives
$
 
396
$
 
301
$
 
1,078
$
 
682
Current
(1)
 
296
 
195
 
888
 
533
Long-term
(1)
 
100
 
106
 
190
 
149
Total derivatives
$
 
396
$
 
301
$
 
1,078
$
 
682
(1) Derivative assets and liabilities are classified as current or long-term based upon the maturities of the underlying contracts.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
43
Cash Flow Hedges
On May 26, 2021, the treasury lock was settled for a gain of $
19
 
million that is being amortized through
interest expense over
10 years
 
as the underlying hedged item settles. As of December 31, 2022, the
unrealized gain in AOCI was $
16
 
million, net of tax (2021 – $
18
 
million, net of tax). For the year ended
December 31, 2022, unrealized gains of $
2
 
million (2021 – $
1
 
million) have been reclassified from AOCI
into interest expense. The Company expects $
2
 
million of unrealized gains currently in AOCI to be
reclassified into net income within the next twelve months
.
Regulatory Deferral
The Company has recorded the following changes in realized and unrealized gains (losses) 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
2022
2021
Unrealized gain (loss) in regulatory
assets
$
-
 
$
(69)
$
 
1
$
-
 
$
(7)
$
 
9
Unrealized gain (loss) in regulatory
liabilities
 
28
 
343
 
16
 
88
 
218
(3)
Realized loss in regulatory assets
-
 
 
48
-
 
-
 
-
 
-
 
Realized gain in regulatory liabilities
-
 
(41)
-
 
-
 
(3)
-
 
Realized (gain) loss in inventory
(1)
-
 
(121)
 
1
-
 
(8)
 
5
Realized (gain) loss in regulated fuel
for generation and purchased power
(2)
(64)
(146)
-
 
-
 
(39)
 
5
Total change in derivative instruments
$
(36)
$
 
14
$
 
18
$
 
88
$
 
161
$
 
16
(1) Realized (gains) losses will be recognized in fuel for generation and purchased power when the hedged item is consumed.
(2) Realized (gains) losses on derivative instruments settled and consumed in the period and hedging relationships that have been
terminated or the hedged transaction is no longer probable.
As at December 31, 2022, the Company had the following notional volumes designated for regulatory
deferral that are expected to settle as outlined below:
millions
2023
2024-2026
Physical natural gas purchases:
Natural gas (Mmbtu)
 
6
-
 
Commodity swaps and forwards purchases:
Natural gas (Mmbtu)
 
18
 
12
Power (MWh)
 
1
 
1
FX swaps and forwards:
FX contracts (millions of USD)
$
 
206
$
 
123
Weighted average rate
 
1.2832
 
1.3064
% of USD requirements
50%
28%
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
2022
2021
Power swaps and physical contracts in non-regulated operating revenues
$
 
17
$
 
4
Natural gas swaps, forwards, futures and physical contracts in non-regulated
operating revenues
 
47
(142)
Total gains (losses) in net income
$
 
64
$
(138)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
44
As at December 31, 2022, the Company had the following notional volumes of outstanding HFT
derivatives that are expected to settle as outlined below:
2027 and
 
millions
 
2023
2024
2025
2026
thereafter
Natural gas purchases (Mmbtu)
 
319
 
92
 
42
 
36
 
131
Natural gas sales (Mmbtu)
 
492
 
205
 
105
 
6
 
19
Power purchases (MWh)
 
2
-
 
-
 
-
 
-
 
Power sales (MWh)
 
2
-
 
-
 
-
 
-
 
Other Derivatives
As at December 31, 2022, the Company had equity derivatives in place to manage the cash flow risk
associated with forecasted future cash settlements of deferred compensation obligations and FX forwards
in place to manage cash flow risk associated with forecasted USD cash inflows.
The equity derivatives
hedge the return on
2.8
 
million shares and extends until December 2023. The FX forwards have a
combined notional amount of $
448
 
million USD and expire throughout 2023, 2024, and 2025.
The Company has recognized the following realized and unrealized gains (losses) with respect to other
derivatives:
For the
Year ended December 31
millions of dollars
2022
2021
FX
Equity
FX
Equity
Forwards
Derivatives
Forwards
Derivatives
Unrealized gain (loss) in OM&G
$
-
 
$
(5)
$
-
 
$
 
11
Unrealized loss in other income, net
(18)
-
 
(15)
-
 
Realized gain (loss) in OM&G
-
 
(17)
-
 
 
15
Realized gain (loss) in other income, net
(6)
-
 
 
18
-
 
Total gains (losses) in net income
$
(24)
$
(22)
$
 
3
$
 
26
Credit Risk
The Company is exposed to credit risk with respect to amounts receivable from customers, energy
marketing collateral deposits and derivative assets. Credit risk is the potential loss from a counterparty’s
non-performance under an agreement. The Company manages credit risk with policies and procedures
for counterparty analysis, exposure measurement, and exposure monitoring and mitigation. Credit
assessments are conducted on all new customers and counterparties, and deposits or collateral are
requested on any high-risk accounts.
 
The Company assesses the potential for credit losses on a regular basis and, where appropriate,
maintains provisions. With respect to counterparties, the Company has implemented procedures to
monitor the creditworthiness and credit exposure of counterparties and to consider default probability in
valuing the counterparty positions. The Company monitors counterparties’ credit standing, including those
that are experiencing financial problems, have significant swings in default probability rates, have credit
rating changes by external rating agencies, or have changes in ownership. Net liability positions are
adjusted based on the Company’s current default probability. Net asset positions are adjusted based on
the counterparty’s current default probability. The Company assesses credit risk internally for
counterparties that are not rated.
As at December 31, 2022, the maximum exposure the Company had to credit risk was $
1.9
 
billion (2021
– $
1.3
 
billion), which includes accounts receivable net of collateral/deposits and assets related to
derivatives.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
45
It is possible that volatility in commodity prices could cause the Company to have material credit risk
exposures with one or more counterparties. If such counterparties fail to perform their obligations under
one or more agreements, the Company could suffer a material financial loss. The Company transacts with
counterparties as part of its risk management strategy for managing commodity price, FX and interest
rate risk. Counterparties that exceed established credit limits can provide a cash deposit or letter of credit
to the Company for the value in excess of the credit limit where contractually required. The total cash
deposits/collateral on hand as at December 31, 2022 was $
386
 
million (2021 – $
341
 
million), which
mitigates the Company’s maximum credit risk exposure. The Company uses the cash as payment for the
amount receivable or returns the deposit/collateral to the customer/counterparty where it is no longer
required by the Company.
The Company enters into commodity master arrangements with its counterparties to manage certain
risks, including credit risk to these counterparties. The Company generally enters into International Swaps
and Derivatives Association agreements, North American Energy Standards Board agreements and, or
Edison Electric Institute agreements. The Company believes entering into such agreements offers
protection by creating contractual rights relating to creditworthiness, collateral, non-performance and
default.
As at December 31, 2022, the Company had $
131
 
million (2021 – $
114
 
million) in financial assets,
considered to be past due, which have been outstanding for an average
60
 
days. The fair value of these
financial assets is $
114
 
million (2021 – $
93
 
million), the difference of which is included in the allowance
for credit losses. These assets primarily relate to accounts receivable from electric and gas revenue.
 
Concentration Risk
The Company's concentrations of risk consisted of the following:
As at
December 31, 2022
December 31, 2021
millions of
dollars
% of total
exposure
millions of
dollars
% of total
exposure
Receivables, net
Regulated utilities:
Residential
$
 
455
19%
$
 
384
24%
Commercial
 
192
8%
 
167
10%
Industrial
 
121
5%
 
54
3%
Other
 
122
5%
 
91
6%
 
890
37%
 
696
43%
Trading group:
Credit rating of A- or above
 
125
5%
 
66
4%
Credit rating of BBB- to BBB+
 
75
3%
 
107
7%
Not rated
 
307
13%
 
132
8%
 
507
21%
 
305
19%
Other accounts receivable
 
585
25%
 
329
20%
 
1,982
83%
 
1,330
82%
Derivative Instruments
(current and long-term)
Credit rating of A- or above
 
202
9%
 
155
9%
Credit rating of BBB- to BBB+
 
8
0%
 
22
1%
Not rated
 
186
8%
 
124
8%
 
396
17%
 
301
18%
$
 
2,378
100%
$
 
1,631
100%
 
 
 
 
 
46
Cash Collateral
The Company’s cash collateral positions consisted of the following:
As at
December 31
December 31
millions of dollars
2022
2021
Cash collateral provided to others
$
 
224
$
 
212
Cash collateral received from others
$
 
112
$
 
100
Collateral is posted in the normal course of business based on the Company’s creditworthiness, including
its senior unsecured credit rating as determined by certain major credit rating agencies. Certain
derivatives contain financial assurance provisions that require collateral to be posted if a material adverse
credit-related event occurs. If a material adverse event resulted in the senior unsecured debt falling below
investment grade, the counterparties to such derivatives could request ongoing full collateralization.
As at December 31, 2022, the total fair value of derivatives in a liability position was $
1,078
 
million
(December 31, 2021
–
 
$
682
 
million). If the credit ratings of the Company were reduced below investment
grade, the full value of the net liability position could be required to be posted as collateral for these
derivatives.
16.
 
FAIR VALUE
 
MEASUREMENTS
The Company is required to determine the fair value of all derivatives except those which qualify for the
NPNS exemption (see note 1) and uses a market approach to do so. The three levels of the fair value
hierarchy are defined as follows:
Level 1 - Where possible, the Company bases the fair valuation of its financial assets and liabilities on
quoted prices in active markets (“quoted prices”) for identical assets and liabilities.
Level 2 - Where quoted prices for identical assets and liabilities are not available, the valuation of certain
contracts must be based on quoted prices for similar assets and liabilities with an adjustment related to
location differences. Also, certain derivatives are valued using quotes from over-the-counter clearing
houses.
Level 3 - Where the information required for a Level 1 or Level 2 valuation is not available, derivatives
must be valued using unobservable or internally-developed inputs. The primary reasons for a Level 3
classification are as follows:
●
 
While valuations were based on quoted prices, significant assumptions were necessary to reflect
seasonal or monthly shaping and locational basis differentials.
●
 
The term of certain transactions extends beyond the period when quoted prices are available and,
accordingly, assumptions were made to extrapolate prices from the last quoted period through the
end of the transaction term.
●
 
The valuations of certain transactions were based on internal models, although quoted prices were
utilized in the valuations.
Derivative assets and liabilities are classified in their entirety based on the lowest level of input that is
significant to the fair value measurement.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
47
The following tables set out the classification of the methodology used by the Company to fair value its
derivatives
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
-
 
-
 
 
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
 
5
 
23
-
 
 
28
Total liabilities
 
73
 
179
 
826
 
1,078
Net assets (liabilities)
 
$
 
59
$
(5)
$
(736)
$
(682)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
48
As at
December 31, 2021
millions of dollars
Level 1
Level 2
Level 3
Total
Assets
Regulatory deferral:
 
Commodity swaps and forwards
$
 
101
$
 
41
$
-
 
$
 
142
 
FX forwards
-
 
 
7
-
 
 
7
 
Physical natural gas purchases and sales
-
 
-
 
 
88
 
88
 
101
 
48
 
88
 
237
HFT derivatives:
 
Power swaps and physical contracts
 
4
 
5
 
4
 
13
 
Natural gas swaps, futures, forwards, physical
 
 
contracts and related transportation
(1)
 
29
 
12
 
40
 
3
 
34
 
16
 
53
Other derivatives:
 
Equity derivatives
 
11
-
 
-
 
 
11
Total assets
 
115
 
82
 
104
 
301
Liabilities
Regulatory deferral:
 
Commodity swaps and forwards
 
7
 
5
-
 
 
12
 
FX forwards
-
 
 
8
-
 
 
8
 
7
 
13
-
 
 
20
HFT derivatives:
 
Power swaps and physical contracts
 
4
 
5
 
3
 
12
 
Natural gas swaps, futures, forwards and physical
 
 
contracts
 
13
 
122
 
515
 
650
 
17
 
127
 
518
 
662
Total liabilities
 
24
 
140
 
518
 
682
Net assets (liabilities)
$
 
91
$
(58)
$
(414)
$
(381)
The change in the fair value of the Level 3 financial assets for the year ended December 31, 2022 was as
follows:
Regulatory Deferral
HFT Derivatives
Physical natural
Natural
 
millions of dollars
gas purchases
Power
 
gas
Total
Balance, January 1, 2022
$
 
88
$
 
4
$
 
12
$
 
104
Realized gains included in fuel for generation and
purchased power
(64)
-
 
-
 
(64)
Unrealized gains included in regulatory liabilities
 
28
-
 
-
 
 
28
Total realized and unrealized gains included in non-
regulated operating revenues
-
 
-
 
 
22
 
22
Balance, December 31, 2022
$
 
52
$
 
4
$
 
34
$
 
90
The change in the fair value of the Level 3 financial liabilities for the year ended December 31, 2022 was
as follows:
 
HFT Derivatives
Natural
millions of dollars
Power
 
gas
Total
Balance, January 1, 2022
$
 
3
$
 
515
$
 
518
Total realized and unrealized gains (losses) included
in non-regulated operating revenues
(2)
 
310
 
308
Balance, December 31, 2022
 
$
 
1
$
 
825
$
 
826
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
49
Significant unobservable inputs used in the fair value measurement of Emera’s natural gas and power
derivatives include third-party sourced pricing for instruments based on illiquid markets. Significant
increases (decreases) in any of these inputs in isolation would result in a significantly lower (higher) fair
value measurement. Other unobservable inputs used include internally developed correlation factors and
basis differentials; own credit risk; and discount rates. Internally developed correlations and basis
differentials are reviewed on a quarterly basis based on statistical analysis of the spot markets in the
various illiquid term markets. Discount rates may include a risk premium for those long-term forward
contracts with illiquid future price points to incorporate the inherent uncertainty of these points. Any risk
premiums for long-term contracts are evaluated by observing similar industry practices and in discussion
with industry peers.
 
The Company uses a modelled pricing valuation technique for determining the fair value of Level 3
derivative instruments. The following table outlines quantitative information about the significant
unobservable inputs used in the fair value measurements categorized within Level 3 of the fair value
hierarchy:
December 31, 2022
As at
 
Significant
Weighted
 
millions of dollars
Fair Value
Unobservable Input
Low
High
average
(1)
Assets
Liabilities
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 fair value of the instruments.
December 31, 2021
As at
Significant
Weighted
millions of dollars
Fair Value
Unobservable Input
Low
High
average
(1)
Assets
Liabilities
Regulatory deferral –
Physical
$
88
$
-
Third-party pricing
$4.51
$26.09
$9.74
natural gas purchases
HFT derivatives – Power
 
4
3
Third-party pricing
$37.05
$213.00
$99.34
swaps and physical contracts
HFT derivatives – Natural
 
12
515
Third-party pricing
$1.90
$21.53
$8.80
gas swaps, futures, forwards
 
and physical contracts
 
Total
$
104
$
518
Net liability
$
414
(1) Unobservable inputs were weighted by the relative fair value of the instruments.
Long-term debt is a financial liability not measured at fair value on the Consolidated Balance Sheets. The
balance consisted of the following:
As at
Carrying
millions of dollars
Amount
Fair Value
Level 1
Level 2
Level 3
Total
December 31, 2022
$
 
16,318
$
 
14,670
$
-
 
$
 
14,284
$
 
386
$
 
14,670
December 31, 2021
$
 
14,658
$
 
16,775
$
-
 
$
 
16,308
$
 
467
$
 
16,775
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
50
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, 2022, the fair value of the Hybrid
Notes was $
1.1
 
billion (2021 – $
1.7
 
billion). An after-tax foreign currency loss of $
97
 
million was recorded
in AOCI for the year ended December 31, 2022 (2021 – $
5
 
million after-tax gain).
17.
 
RELATED PARTY
 
TRANSACTIONS
In the ordinary course of business, Emera provides energy and other services and enters into
transactions with its subsidiaries, associates and other related companies on terms similar to those
offered to non-related parties. Intercompany balances and intercompany transactions have been
eliminated on consolidation, except for the net profit on certain transactions between non-regulated and
regulated entities in accordance with accounting standards for rate-regulated entities. All material
amounts are under normal interest and credit terms.
 
Significant transactions between Emera and its associated companies are as follows:
●
 
Transactions between NSPI and NSPML related to the Maritime Link assessment are reported in the
Consolidated Statements of Income. NSPI’s expense is reported in Regulated fuel for generation and
purchased power, totalling $
157
 
million for the year ended December 31, 2022 (2021 – $
149
 
million).
NSPML is accounted for as an equity investment and therefore, the corresponding earnings related to
this revenue are reflected in Income from equity investments.
●
Natural gas transportation capacity purchases from M&NP are reported in the Consolidated
Statements of Income. Purchases from M&NP reported net in Operating revenues, Non-regulated,
totalled $
9
 
million for the year ended December 31, 2022 (2021
– $
19
 
million).
There were no significant receivables or payables between Emera and its associated companies reported
on Emera’s Consolidated Balance Sheets as at December 31, 2022 and at December 31, 2021.
18.
 
RECEIVABLES AND OTHER CURRENT ASSETS
As at
December 31
December 31
millions of dollars
 
2022
2021
Customer accounts receivable – billed
$
 
1,096
$
 
767
Customer accounts receivable – unbilled
 
424
 
318
Allowance for credit losses
(17)
(21)
Capitalized transportation capacity
(1)
 
781
 
316
NMGC gas hedge settlement receivable
(2)
 
162
-
 
Income tax receivable
 
9
 
8
Prepaid expenses
 
82
 
65
Other
 
360
 
280
Total receivables and other current assets
$
 
2,897
$
 
1,733
(1) Capitalized transportation capacity represents the value of transportation/storage received by EES on asset management
agreements at the inception of the contracts. The asset is amortized over the term of each contract.
(2) Related amount is included in regulatory liabilities for NMGC as gas hedges are part of the PGAC. Refer to note 7.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
51
19.
 
LEASES
Lessee
The Company has operating leases for buildings, land, telecommunication services, and rail cars.
Emera’s leases have remaining lease terms of 1 year to 63 years, some of which include options to
extend the leases for up to 65 years. These options are included as part of the lease term when it is
considered reasonably certain that they will be exercised.
 
As at
December 31
December 31
millions of dollars
 
Classification
2022
2021
Right-of-use asset
Other long-term assets
$
58
$
 
58
Lease liabilities
 
Current
Other current liabilities
3
 
3
 
Long-term
Other long-term liabilities
59
 
58
Total lease liabilities
$
62
$
 
61
The Company has recorded lease expense of $
138
 
million for the year ended December 31, 2022 (2021
– $
150
 
million), of which $
131
 
million (2021 – $
142
 
million) relates to variable costs for power generation
facility finance leases, recorded in “Regulated fuel for generation and purchased power” in the
Consolidated Statements of Income.
 
Future minimum lease payments under non-cancellable operating leases for each of the next five years
and in aggregate thereafter are as follows:
millions of dollars
2023
2024
2025
2026
2027
Thereafter
Total
Minimum lease payments
$
 
6
$
 
6
$
 
5
$
 
3
$
 
3
$
 
116
$
 
139
Less imputed interest
(77)
Total
$
 
62
Additional information related to Emera's leases is as follows:
Year ended December 31
For the
2022
2021
Cash paid for amounts included in the measurement of lease liabilities:
 
Operating cash flows for operating leases (millions of dollars)
$
 
8
$
 
7
Right-of-use assets obtained in exchange for lease obligations:
 
Operating leases (millions of dollars)
$
 
1
$
-
 
Weighted average remaining lease term (years)
 
44
 
44
Weighted average discount rate- operating leases
3.98%
3.98%
Lessor
The Company’s net investment in direct finance and sales-type leases primarily relates to Brunswick
Pipeline, Seacoast, compressed natural gas (“CNG”) stations and heat pumps.
The Company manages its risk associated with the residual value of the Brunswick Pipeline lease
through proper routine maintenance of the asset.
Customers have the option to purchase CNG station assets by paying a make-whole payment at the date
of the purchase based on a targeted internal rate of return or may take possession of the CNG station
asset at the end of the lease term for no cost. Customers have the option to purchase heat pumps at the
end of the lease term for a nominal fee.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
52
Commencing in January 2022, the Company leased a Seacoast pipeline, a 21-mile, 30-inch lateral that is
classified as a sales-type lease. The term of the pipeline lateral lease is
34
 
years with a net investment of
$
100
 
million USD. The lessee of the new pipeline lateral has renewal options for an additional
16
 
years.
These renewal options have not been included as part of the pipeline lateral lease term as it is not
reasonably certain that they will be exercised.
Direct finance and sales-type lease unearned income is recognized in income over the life of the lease
using a constant rate of interest equal to the internal rate of return on the lease and is recorded as
“Operating revenues – regulated gas” and “Other income, net” on the Consolidated Statements of
Income.
The total net investment in direct finance and sales-type leases consist of the following:
 
As at
December 31
December 31
millions of dollars
 
2022
2021
Total minimum lease payment to be received
$
 
1,393
$
 
947
Less: amounts representing estimated executory costs
(205)
(165)
Minimum lease payments receivable
$
 
1,188
$
 
782
Estimated residual value of leased property (unguaranteed)
 
183
 
183
Less: unearned finance lease income
(733)
(443)
Net investment in direct finance and sales-type leases
$
 
638
$
522
Principal due within one year (included in "Receivables and other
current assets")
 
34
 
19
Net Investment in direct finance and sales type leases - long-term
$
604
$
503
As at December 31, 2022, future minimum lease payments to be received for each of the next five years
and in aggregate thereafter are as follows:
millions of dollars
2023
2024
2025
2026
2027
Thereafter
Total
Minimum lease payments to be
received
$
 
90
$
 
92
$
 
95
$
 
94
$
 
92
$
 
930
$
 
1,393
Less: executory costs
(205)
Total
$
 
1,188
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
2022
2021
Generation
2
 
to
131
$
 
13,083
$
 
11,173
Transmission
10
 
to
80
 
2,731
 
2,532
Distribution
10
 
to
65
 
6,978
 
6,305
Gas transmission and distribution
13
 
to
83
 
5,061
 
4,385
General plant and other
 
(1)
2
 
to
71
 
2,723
 
2,473
Total cost
 
30,576
 
26,868
Less: Accumulated depreciation
(1)
(9,574)
(8,739)
 
21,002
 
18,129
Construction work in progress
(1)
 
1,994
 
2,224
Net book value
$
 
22,996
$
 
20,353
(1) SeaCoast owns a
50
% undivided ownership interest in a jointly owned
26
-mile pipeline lateral located in Florida, which went into
service in 2020. At December 31, 2022, SeaCoast’s share of plant in service was $
27
 
million USD (2021 - $
27
 
million USD), and
accumulated depreciation of $
1
 
million USD (2021 - $
1
 
million USD). SeaCoast’s undivided ownership interest is financed with its
funds and all operations are accounted for as if such participating interest were a wholly owned facility.
 
SeaCoast’s share of direct
expenses of the jointly owned pipeline is included in OM&G in the Consolidated Statements of Income.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
53
21.
 
EMPLOYEE BENEFIT PLANS
Emera maintains a number of contributory defined-benefit and defined-contribution pension plans, which
cover substantially all of its employees. In addition, the Company provides non-pension benefits for its
retirees. These plans cover employees in Nova Scotia, New Brunswick, Newfoundland and Labrador,
Florida, New Mexico, Barbados, and Grand Bahama Island.
Emera’s net periodic benefit cost included the following:
Benefit Obligation and Plan Assets
The changes in benefit obligation and plan assets, and the funded status for all plans were as follows:
For the
 
Year ended December 31
millions of dollars
2022
2021
Change in Projected Benefit Obligation
("PBO") and Accumulated Post-
retirement Benefit Obligation ("APBO")
Defined benefit
pension plans
Non-pension
benefit plans
Defined benefit
pension plans
Non-pension
benefit plans
Balance, January 1
$
 
2,624
$
 
318
$
 
2,759
$
 
339
Service cost
 
41
 
4
 
43
 
5
Plan participant contributions
 
6
 
6
 
6
 
4
Interest cost
 
80
 
9
 
67
 
8
Benefits paid
 
(174)
(31)
(160)
(27)
Actuarial gains
(480)
(79)
(89)
(10)
Settlements and curtailments
(6)
-
 
-
 
-
 
Foreign currency translation adjustment
 
67
 
16
(2)
(1)
Balance, December 31
$
 
2,158
$
 
243
$
 
2,624
$
 
318
Change in plan assets
Balance, January 1
$
 
2,702
$
 
51
$
 
2,605
$
 
52
Employer contributions
 
45
 
24
 
42
 
21
Plan participant contributions
 
 
6
 
6
 
6
 
4
Benefits paid
(174)
(31)
(160)
(27)
Actual return on assets, net of expenses
(489)
(7)
 
214
 
2
Settlements and curtailments
(6)
-
 
-
 
-
 
Foreign currency translation adjustment
 
79
 
3
(5)
(1)
Balance, December 31
$
 
2,163
$
 
46
$
 
2,702
$
 
51
Funded status, end of year
 
$
 
5
$
(197)
$
 
78
$
(267)
The actuarial gains recognized in the period are primarily due to changes in the discount rate and
compensation-related assumption changes. This was partially offset by losses associated with member
experience and indexation.
Plans with PBO/APBO
in Excess of Plan Assets
The aggregate financial position for all pension plans where the PBO or APBO (for post-retirement benefit
plans) exceeds the plan assets for the years ended December 31 is as follows:
millions of dollars
2022
2021
Defined benefit
pension plans
Non-pension
benefit plans
Defined benefit
pension plans
Non-pension
benefit plans
PBO/APBO
$
 
1,006
$
 
221
$
 
140
$
 
290
Fair value of plan assets
 
914
-
 
 
35
-
 
Funded status
$
(92)
$
(221)
$
(105)
$
(290)
Plans with Accumulated Benefit Obligation (“ABO”)
in Excess of Plan Assets
The ABO for the defined benefit pension plans was $
2,080
 
million as at December 31, 2022 (2021 –
$
2,507
 
million). The aggregate financial position for those plans with an ABO in excess of the plan assets
for the years ended December 31 is as follows:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
54
millions of dollars
2022
2021
Defined benefit
pension plans
Defined benefit
pension plans
ABO
$
 
111
$
 
133
Fair value of plan assets
 
33
 
35
Funded status
$
(78)
$
(98)
Balance Sheet
The amounts recognized in the Consolidated Balance Sheets consisted of the following:
As at
December 31
December 31
millions of dollars
2022
2021
Defined benefit
pension plans
Non-pension
benefit plans
Defined benefit
pension plans
Non-pension
benefit plans
Other current liabilities
$
(13)
$
(20)
$
(7)
$
(20)
Long-term liabilities
(80)
(201)
(100)
(270)
Other long-term assets
 
98
 
24
 
185
 
23
AOCI, net of tax and regulatory assets
 
358
 
22
 
230
 
90
Less: Deferred income tax (expense)
recovery in AOCI
(7)
(1)
(8)
 
1
Net amount recognized
$
 
356
$
(176)
$
 
300
$
(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
millions of dollars
Defined Benefit Pension Plans
Balance, January 1, 2022
$
 
192
$
 
30
Amortized in current period
(21)
(10)
Current year addition to AOCI or regulatory assets
 
147
(5)
Change in FX rate
 
18
-
 
Balance, December 31, 2022
$
 
336
$
 
15
Non-pension benefits plans
Balance, January 1, 2022
$
 
91
$
-
 
Amortized in current period
(2)
-
 
Current year addition to AOCI or regulatory assets
(62)
(10)
Change in FX rate
 
4
-
 
Balance, December 31, 2022
$
 
31
$
(10)
As at
December
31
December
31
millions of dollars
2022
2021
Defined benefit
pension plans
Non-pension
benefit plans
Defined benefit
pension plans
Non-pension
benefit plans
Actuarial losses (gains)
$
 
15
$
(10)
$
 
30
$
-
 
Deferred income tax expense (recovery)
 
7
 
1
 
8
(1)
AOCI, net of tax
 
22
(9)
 
38
(1)
Regulatory assets
 
336
 
31
 
192
 
91
AOCI, net of tax and regulatory assets
$
 
358
$
 
22
$
 
230
$
 
90
Benefit Cost Components
Emera's net periodic benefit cost included the following:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
55
As at
Year ended December 31
millions of dollars
2022
2021
Defined benefit
pension plans
Non-pension
benefit plans
Defined benefit
pension plans
Non-pension
benefit plans
Service cost
$
 
41
$
 
4
$
 
43
$
 
5
Interest cost
 
80
 
9
 
67
 
8
Expected return on plan assets
(144)
-
 
(132)
(1)
Current year amortization of:
 
Actuarial losses
 
8
-
 
 
21
 
3
 
Regulatory assets (liability)
 
21
 
2
 
24
 
2
Settlement, curtailments
 
2
-
 
-
 
-
 
Total
$
 
8
$
 
15
$
 
23
$
 
17
The expected return on plan assets is determined based on the market-related value of plan assets of
$
2,482
 
million as at January 1, 2022 (2021 – $
2,151
 
million), adjusted for interest on certain cash flows
during the year.
The market-related value of assets is based on a
five-year
smoothed asset value. Any
investment gains (or losses) in excess of (or less than) the expected return on plan assets are recognized
on a straight-line basis into the market-related value of assets over a five-year period.
Pension Plan Asset Allocations
Emera’s investment policy includes discussion regarding the investment philosophy, the level of risk
which the Company is prepared to accept with respect to the investment of the Pension Funds, and the
basis for measuring the performance of the assets. Central to the policy is the target asset allocation by
major asset categories. The objective of the target asset allocation is to diversify risk and to achieve asset
returns that meet or exceed the plan’s actuarial assumptions. The diversification of assets reduces the
inherent risk in financial markets by requiring that assets be spread out amongst various asset classes.
Within each asset class, a further diversification is undertaken through the investment in a broad range of
investment and non-investment grade securities. Emera’s target asset allocation is as follows:
Canadian Pension Plans
Asset Class
Target Range at Market
Short-term securities
0%
to
5%
Fixed income
35%
to
50%
Equities:
 
Canadian
7%
to
17%
 
Non-Canadian
36%
to
60%
Non-Canadian Pension Plans
Asset Class
Target Range at Market
Weighted average
Fixed income
30%
to
50%
Equities
50%
to
70%
Pension Plan assets are overseen by the respective Management Pension Committees in the sponsoring
companies. All pension investments are in accordance with policies approved by the respective Board of
Directors of each sponsoring company.
The following tables set out the classification of the methodology used by the Company to fair value its
investments:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
56
millions of dollars
NAV
Level 1
Level 2
Total
Percentage
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
%
As at
December 31, 2021
Cash and cash equivalents
$
-
$
60
$
-
$
60
2
%
Net in-transits
-
(84)
-
(84)
(3)
%
Equity securities:
 
Canadian equity
-
97
-
97
4
%
 
United States equity
 
-
366
-
366
14
%
 
Other equity
-
215
-
215
8
%
Fixed income securities:
 
Government
-
-
132
132
5
%
 
Corporate
-
-
117
117
4
%
 
Other
-
8
3
11
-
%
Mutual funds
-
86
-
86
3
%
Other
-
1
(1)
-
-
%
Open-ended investments
measured at NAV
 
(1)
952
-
-
952
35
%
Common collective trusts
measured at NAV
(2)
750
-
-
750
28
%
Total
 
$
 
1,702
$
 
749
$
 
251
$
 
2,702
100
%
(1) NAV investments are open-ended registered
 
and non-registered mutual funds, collective investment trusts, or pooled funds.
NAV’s are calculated at least monthly
 
and the funds honor subscription and redemption activity regularly.
(2) The common collective trusts are private funds valued at NAV.
 
The NAVs are calculated based on bid prices
 
of the underlying
securities. Since the prices are not published to external sources, NAV
 
is used as a practical expedient. Certain funds invest
primarily in equity securities of domestic and foreign issuers while others invest in long duration U.S. investment grade fixed
income assets and seeks to increase return through active management of interest rate and credit risks. The funds honor
subscription and redemption activity regularly.
Refer to note 16 for more information on the fair value hierarchy and inputs used to measure fair value.
Post-Retirement Benefit Plans
There are no assets set aside to pay for most of the Company’s post-retirement benefit plans. As is
common practice, post-retirement health benefits are paid from general accounts as required. The
primary exceptions to this is the NMGC Retiree Medical Plan, which is fully funded.
Investments in Emera
As at December 31, 2022 and 2021, the assets related to the pension funds and post-retirement benefit
plans did not hold any material investments in Emera or its subsidiaries securities. However, as a
significant portion of assets for the benefit plan are held in pooled assets, there may be indirect
investments in these securities.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
57
Cash Flows
The following table shows the expected cash flows for defined benefit pension and other post-retirement
benefit plans:
millions of dollars
Defined benefit
pension plans
Non-pension
benefit plans
Expected employer contributions
2023
$
 
44
$
 
20
Expected benefit payments
2023
 
164
 
22
2024
 
161
 
23
2025
 
168
 
23
2026
 
172
 
22
2027
 
178
 
22
2028 – 2032
 
919
 
105
Assumptions
The following table shows the assumptions that have been used in accounting for defined benefit
pension and other post-retirement benefit plans:
2022
2021
(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
5.33
%
5.31
%
3.05
%
2.81
%
Discount rate - future service
5.34
%
5.32
%
3.18
%
2.92
%
Rate of compensation increase
3.62
%
3.61
%
3.31
%
3.29
%
Health care trend
 
- initial (next year)
-
5.40
%
-
5.09
%
 
- ultimate
 
-
3.77
%
-
3.77
%
 
- year ultimate reached
2043
2042
Benefit cost for year ended December 31:
Discount rate - past service
3.05
%
2.81
%
2.49
%
2.48
%
Discount rate - future service
3.18
%
2.92
%
2.64
%
2.51
%
Expected long-term return on plan assets
6.07
%
1.32
%
5.86
%
-
%
Rate of compensation increase
3.31
%
3.29
%
2.89
%
3.04
%
Health care trend
 
- initial (current year)
-
5.09
%
-
5.64
%
 
- ultimate
 
-
3.77
%
-
4.35
%
 
- year ultimate reached
2042
2038
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 defined contribution pension plan for certain employees. The Company’s
contribution for the year ended December 31, 2022 was $
41
 
million (2021 – $
45
 
million).
 
 
 
 
 
 
 
 
 
58
22.
 
GOODWILL
The change in goodwill for the year ended December 31 is due to the following:
millions of dollars
 
2022
2021
Balance, January 1
$
 
5,696
$
 
5,720
GBPC impairment charge
(1)
(73)
-
 
Change in FX rate
 
389
(24)
Balance, December 31
$
 
6,012
$
 
5,696
(1) At the beginning of the period, Emera's accumulated impairment charges related to GBPC were $
30
 
million.
Goodwill is subject to an annual assessment for impairment at the reporting unit level. The goodwill on
Emera’s Consolidated Balance Sheets at December 31, 2022, primarily relates to TECO Energy. Emera’s
reporting units with goodwill are Tampa Electric, PGS, NMGC, and GBPC.
 
In 2022, Emera performed a qualitative impairment assessment for Tampa Electric and PGS, concluding
that the fair value of the reporting units exceeded their respective carrying amounts, and as such, no
quantitative assessments were performed and
no
 
impairment charges were recognized. For the NMGC
reporting unit, Emera elected to bypass a qualitative assessment and performed a quantitative
impairment assessment using a combination of the income approach and market approach. This
assessment estimated that the fair value of the NMGC reporting unit exceeded its carrying amount,
including goodwill. As a result of this assessment,
no
 
impairment charges were recognized.
In 2022, the Company elected to bypass a qualitative assessment and performed a quantitative
impairment assessment for GBPC, using the income approach, as this reporting unit is sensitive to
changes in assumptions due to limited excess of fair value over carrying amount, including goodwill.
Although the cash flows of GBPC have not changed significantly compared to previous periods, it was
determined that the fair value did not exceed its carrying amount, including goodwill, primarily due to an
increase in discount rates. The discount rate for the reporting unit was negatively impacted by changes in
the macro-economic environment, including the risk-free rate assumption. As a result of this assessment,
a goodwill impairment charge of $
73
 
million was recorded in 2022, reducing the GBPC goodwill balance
to nil as at December 31, 2022. This non-cash charge is included in “Impairment charge” on the
Consolidated Statements of Income.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
59
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
 
2022
Weighted
average
 
interest rate
2021
Weighted
average
 
interest rate
Tampa Electric Company ("TEC")
Advances on term, revolving and accounts receivable facilities
$
 
1,380
5.00
%
$
 
945
0.58
%
Emera
Non-revolving term facilities
 
796
5.19
%
 
400
0.96
%
Bank indebtedness
 
-
 
-
%
 
6
-
%
TECO Finance
 
Advances on revolving credit and term facilities
 
481
5.47
%
 
355
1.20
%
NMGC
Advances on revolving credit facilities
 
59
5.15
%
 
25
1.20
%
GBPC
Advances on revolving credit facilities
 
10
5.25
%
 
10
5.25
%
NSPI
Bank indebtedness
 
-
 
-
%
 
1
-
%
Short-term debt
$
 
2,726
$
 
1,742
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
2022
2021
TEC - Unsecured committed revolving credit facility
2026
$
 
1,084
$
 
1,014
TECO Energy/TECO Finance - revolving credit facility
2026
 
542
 
507
Emera - non-revolving term facility
2023
 
400
 
400
Emera - non-revolving term facility
2023
 
400
-
 
TEC - Unsecured non-revolving facility
2023
 
542
 
634
NMGC - revolving credit facility
2026
 
169
 
158
GBPC - revolving credit facility
on demand
 
18
 
16
Total
$
 
3,155
$
 
2,729
Less:
Advances under revolving credit and term facilities
 
2,731
 
1,735
Letters of credit issued within the credit facilities
 
4
 
4
Total advances under available facilities
 
2,735
 
1,739
Available capacity under existing agreements
$
 
420
$
 
990
The weighted average interest rate on outstanding short-term debt at December 31, 2022 was
5.01
 
per
cent (2021 –
0.83
 
per cent).
Recent Significant Financing Activity by Segment
Florida Electric Utilities
 
On December 13, 2022, TEC amended its 364-day non-revolving term credit facility to extend the
maturity date from
December 16, 2022
 
to
December 13, 2023
 
and reduced the facility amount from $
500
million USD to $
400
 
million USD. There were no other significant changes in commercial terms from the
prior agreement.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
60
Other
On December 16, 2022, Emera amended its $
400
 
million non-revolving term credit facility to extend the
maturity from
December 16, 2022
 
to
December 16, 2023
. There were no other significant changes in
commercial terms from the prior agreement.
 
On August 2, 2022, Emera entered into a $
400
 
million non-revolving term facility which matures on
August 2, 2023
. The credit agreement contains customary representation and warranties, events of
default and financial and other covenants and bears interest at Bankers’ Acceptances or prime rate
advances, plus a margin.
24.
 
OTHER CURRENT LIABILITIES
As at
December 31
December 31
millions of dollars
 
2022
2021
Accrued charges
$
 
174
$
 
157
Nova Scotia Cap-and-Trade Program provision (note 7)
 
172
-
 
Accrued interest on long-term debt
 
97
 
75
Pension and post-retirement liabilities (note 21)
 
33
 
27
Sales and other taxes payable
 
14
 
6
Income tax payable
 
9
 
6
Other
 
80
 
95
$
 
579
$
 
366
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
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
2022
2021
Maturity
2022
2021
Emera
 
Bankers acceptances, LIBOR loans
 
Variable
Variable
2027
$
 
403
$
 
378
Unsecured fixed rate notes
2.90%
2.90%
2023
 
500
 
500
Fixed to floating subordinated notes (USD)
(2)
6.75%
6.75%
2076
 
1,625
 
1,521
$
 
2,528
$
 
2,399
Emera Finance
 
Unsecured senior notes (USD)
 
3.65%
3.65%
2024 - 2046
$
 
3,725
$
 
3,487
Tampa Electric
(3)
Fixed rate notes and bonds (USD)
4.15%
4.15%
2024 - 2052
$
 
4,341
$
 
3,683
PGS
Fixed rate notes and bonds (USD)
3.78%
3.78%
2024 - 2052
$
 
772
$
 
660
NMGC
Fixed rate notes and bonds (USD)
3.11%
3.11%
2026 - 2051
$
 
521
$
 
488
Non-revolving term facility, floating rate
Variable
Variable
2024
 
108
 
101
$
 
629
$
 
589
NMGI
Fixed rate notes and bonds (USD)
3.64%
3.64%
2024
$
 
203
$
 
190
NSPI
Discount notes
Variable
Variable
2024 - 2027
$
 
881
$
 
376
Medium term fixed rate notes
5.14%
5.14%
2025 - 2097
 
2,665
 
2,665
$
 
3,546
$
 
3,041
EBP
Senior secured credit facility
Variable
Variable
2026
$
 
249
$
 
249
ECI
Secured senior notes (USD)
 
Variable
Variable
2026
$
 
86
$
 
84
Amortizing fixed rate notes (USD)
3.97%
3.97%
2024 - 2026
 
100
$
 
104
Non-revolving term facility, floating rate
Variable
Variable
2027
 
30
$
 
28
Non-revolving term facility, fixed rate
2.05%
2.36%
2025 - 2026
 
91
$
 
101
Secured fixed rate senior notes
(4)
3.06%
4.43%
2023 - 2029
 
142
$
 
161
$
 
449
$
 
478
Adjustments
Fair market value adjustment - TECO Energy acquisition
(5)
$
 
2
$
 
3
Debt issuance costs
(126)
(121)
Amount due within one year
(574)
(462)
$
(698)
$
(580)
Long-Term Debt
$
 
15,744
$
 
14,196
(1) Weighted average interest rate of fixed rate long-term debt.
(2) In 2022, the Company recognized $
110
 
million in interest expense (2021 – $
102
 
million) related to its fixed to floating
subordinated notes.
(3) A substantial part of Tampa
 
Electric’s tangible assets are pledged as collateral to secure its first mortgage bonds. There
 
are
currently no bonds outstanding under Tampa
 
Electric’s first mortgage bond indenture.
(4) Notes are issued and payable in either USD or BBD.
 
(5) On acquisition of TECO Energy, Emera recorded
 
a fair market value adjustment on the unregulated long-term debt acquired.
The fair market value adjustment is amortized over the remaining term of the debt.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
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
2022
2021
Emera – revolving credit facility
(1)
June 2027
$
 
900
$
 
900
NSPI - revolving credit facility
(1)
December 2027
 
800
 
600
NSPI - non-revolving credit facility
July 2024
 
400
-
 
NMGC - non-revolving credit facility
March 2024
 
108
-
 
ECI – revolving credit facilities
2023-2032
 
11
 
27
Total
$
 
2,219
$
 
1,527
Less:
Borrowings under credit facilities
 
1,396
 
770
Letters of credit issued inside credit facilities
 
12
 
124
Use of available facilities
$
 
1,408
$
 
894
Available capacity under existing agreements
$
 
811
$
 
633
(1) Advances on the revolving credit facility can be made by way of overdraft on accounts up to $
50
 
million.
Debt Covenants
Emera and its subsidiaries have debt covenants associated with their credit facilities. Covenants are
tested regularly and the Company is in compliance with covenant requirements. Emera’s significant
covenants are listed below:
As at
Financial Covenant
Requirement
December 31, 2022
Emera
Syndicated credit facilities
Debt to capital ratio
Less than or equal to
0.70
 
to 1
0.57
 
: 1
Recent Significant Financing Activity by Segment
Florida Electric Utilities
On September 15, 2022, TEC repaid a $
250
 
million USD note upon maturity. The note was repaid using
existing credit facilities.
 
On July 12, 2022, TEC completed an issuance of $
600
 
million USD senior notes. The issuance included
$
300
 
million USD senior notes that bear an interest rate of
3.875
 
per cent with a maturity date of
July 12,
2024
, and $
300
 
million USD senior notes that bear an interest rate of
5
 
per cent with a maturity date of
July 15, 2052
.
 
Canadian Electric Utilities
On December 16, 2022, NSPI amended its revolving operating credit facility to extend the maturity date
from
December 16, 2026
 
to
December 16, 2027
 
and increase the amount of the facility from $
600
 
million
to $
800
 
million. There were no other significant changes in commercial terms from the prior agreement.
 
On July 15, 2022, NSPI entered into a $
400
 
million non-revolving term credit facility which matures on
July 15, 2024
. The credit facility contains customary representation and warranties, events of default and
financial and other covenants, and bears interest at Bankers’ Acceptances or prime rate advances, plus a
margin.
 
Gas Utilities and Infrastructure
On September 23, 2022, NMGC amended its $
80
 
million USD, unsecured, non-revolving term credit
facility to extend the maturity from
September 23, 2022
, to
March 22, 2024
. There were no other changes
in commercial terms from the prior agreement.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
63
On June 30, 2022, Brunswick Pipeline amended its non-revolving credit agreement to extend the maturity
from
June 30, 2025
 
to
June 30, 2026
. There were no other changes in commercial terms from the prior
agreement.
 
Other Electric Utilities
 
On March 25, 2022, ECI amended its amortizing floating rate notes to extend the maturity from
March 25,
2022
 
to
March 25, 2027
. There were no other changes in commercial terms from the prior agreement.
Other
 
On December 16, 2022, Emera amended its $
900
 
million revolving operating credit facility to extend the
maturity date from
June 30, 2026
 
to
June 30, 2027
. There were no other significant changes in
commercial terms from the prior agreement.
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
2023
2024
2025
2026
2027
Thereafter
Total
Emera
$
 
500
$
-
 
$
-
 
$
 
1,625
$
 
403
$
-
 
$
 
2,528
Emera US Finance LP
-
 
 
407
-
 
 
1,016
-
 
 
2,302
 
3,725
Tampa Electric
-
 
 
356
-
 
-
 
-
 
 
3,985
 
4,341
PGS
-
 
 
51
-
 
-
 
-
 
 
721
 
772
NMGC
-
 
 
108
-
 
 
95
-
 
 
426
 
629
NMGI
-
 
 
203
-
 
-
 
-
 
-
 
 
203
NSPI
-
 
 
398
 
125
 
40
 
483
 
2,500
 
3,546
EBP
-
 
-
 
-
 
 
249
-
 
-
 
 
249
ECI
 
74
 
90
 
137
 
85
 
60
 
3
 
449
Total
$
 
574
$
 
1,613
$
 
262
$
 
3,110
$
 
946
$
 
9,937
$
 
16,442
26.
 
ASSET RETIREMENT OBLIGATIONS
AROs mostly relate to reclamation of land at the thermal, hydro and combustion turbine sites; and the
disposal of polychlorinated biphenyls in transmission and distribution equipment and a pipeline site.
Certain hydro, transmission and distribution assets may have additional AROs that cannot be measured
as these assets are expected to be used for an indefinite period and, as a result, a reasonable estimate of
the fair value of any related ARO cannot be made.
 
The change in ARO for the years ended December 31 is as follows:
millions of dollars
2022
2021
Balance, January 1
$
 
174
$
 
178
Accretion included in depreciation expense
 
9
 
10
Change in FX rate
 
3
(1)
Additions
 
1
 
1
Accretion deferred to regulatory asset (included in PP&E)
 
1
(2)
Liabilities settled
(1)
(1)
(13)
Revisions in estimated cash flows
(13)
-
 
Other
-
 
 
1
Balance, December 31
$
 
174
$
 
174
(1) Tampa Electric
 
produced ash and other by-products, collectively known as CCR's, at its Big Bend and Polk power stations. The
decrease in ARO in 2021 was due to the closure of CCR management facilities.
 
 
 
 
 
 
 
 
 
 
 
 
64
27.
 
COMMITMENTS AND CONTINGENCIES
 
A.
Commitments
As at December 31, 2022, contractual commitments (excluding pensions and other post-retirement
obligations, long-term debt and asset retirement obligations) for each of the next five years and in
aggregate thereafter consisted of the following:
millions of dollars
2023
2024
2025
2026
2027
Thereafter
Total
Transportation
(1)
$
 
693
$
 
516
$
 
423
$
 
383
$
 
367
$
 
2,817
$
 
5,199
Purchased power
(2)
 
269
 
243
 
237
 
228
 
243
 
2,145
 
3,365
Fuel, gas supply and storage
 
1,161
 
282
 
138
 
40
 
5
 
1
 
1,627
Capital projects
 
264
 
89
 
4
 
1
-
 
-
 
 
358
Equity investment commitments
(3)
 
240
-
 
-
 
-
 
-
 
-
 
 
240
Other
 
149
 
142
 
132
 
49
 
42
 
189
 
703
$
 
2,776
$
 
1,272
$
 
934
$
 
701
$
 
657
$
 
5,152
$
 
11,492
(1) Purchasing commitments for transportation of fuel and transportation capacity on various pipelines.
 
Includes a commitment of
$
144
 
million related to a gas transportation contract between PGS and SeaCoast through 2040.
(2) Annual requirement to purchase electricity production from IPPs or other utilities over varying contract lengths.
(3) Emera has a commitment to make a final equity contribution to the LIL upon its commissioning. Once commissioned, the
commercial agreements between Emera and Nalcor require true ups to finalize the respective investment obligations
 
of the parties in
relation to the Maritime Link and LIL.
NSPI has a contractual obligation to pay NSPML for use of the Maritime Link over approximately
38
 
years
from its January 15, 2018 in-service date. In February 2022, the UARB issued its decision and Board
Order approving NSPML’s requested rate base of approximately $
1.8
 
billion. In December 2022, the
UARB approved the collection of $
164
 
million from NSPI for the recovery of Maritime Link costs in 2023.
The timing and amounts payable to NSPML for the remainder of the
38
-year commitment period are
subject to UARB approval.
 
Emera has committed to obtain certain transmission rights for Nalcor, if requested, to enable it to transmit
energy which is not otherwise used in Newfoundland and Labrador or Nova Scotia. Nalcor has the right to
transmit this energy from Nova Scotia to New England energy markets effective August 15, 2021, the
date the NS Block delivery obligation commenced, and continuing for
50 years
. As transmission rights are
contracted, the obligations are included within “Other” in the above table.
B.
Legal Proceedings
TECO Guatemala Holdings (“TGH”)
Prior to Emera’s acquisition of TECO Energy in 2016, TGH, a wholly owned subsidiary of TECO Energy,
divested of its indirect investment in the Guatemala electricity sector, but retained certain claims against
the Republic of Guatemala (“Guatemala”). In 2013, TGH asserted an arbitration claim against Guatemala
with the International Centre for the Settlement of Investment Disputes (“ICSID”) under the Dominican
Republic Central America – United States Free Trade Agreement. The arbitration concerned TGH’s
allegation that Guatemala unfairly set the distribution tariff for a local distribution company which harmed
TGH’s investment in that company. A tribunal established by the ICSID ruled in favour of TGH (the “First
Award”) and, in November 2020, Guatemala made a payment of approximately $
38
 
million USD in full
and final satisfaction of the First Award.
 
65
On September 23, 2016, TGH had filed a request for resubmission to arbitration seeking damages in
addition to those awarded in the First Award. On May 13, 2020, an ICSID tribunal awarded TGH
additional damages and costs against Guatemala of more than $
35
 
million USD plus interest (the
“Second Award”). TGH subsequently requested a reconsideration of the interest quantum awarded in
connection with the Second Award. On October 16, 2020, the tribunal granted TGH’s request for
additional interest. The additional amount was approximately $
2
 
million USD. On February 12, 2021,
Guatemala filed an application with ICSID for annulment of the Second Award. On March 31, 2021, ICSID
constituted an ad hoc Committee to oversee the annulment proceeding. A three-day hearing was held
before the ad hoc Committee beginning on July 27, 2022.
On November 28, 2022, TGH and Guatemala entered into a settlement agreement with respect to the
Second Award. Pursuant to the settlement agreement, on December 15, 2022, Guatemala paid TGH $
46
million USD and the parties agreed to settle all outstanding disputes, concluding this matter. This amount
was recognized in “Other Income, net” on the Consolidated Statements of Income.
Superfund and Former Manufactured Gas Plant Sites
TEC, through its Tampa
 
Electric and PGS divisions, is a potentially responsible party (“PRP”) for certain
superfund sites and, through its PGS division, for certain former manufactured gas plant sites. While the
joint and several liability associated with these sites presents the potential for significant response costs,
as at December 31, 2022, TEC estimated its financial liability to be $
17
 
million ($
13
 
million USD),
primarily at PGS. This estimate assumes that other involved PRPs are credit-worthy entities. This amount
has been accrued and is primarily reflected in the long-term liability section under “Other long-term
liabilities” on the Consolidated Balance Sheets. The environmental remediation costs associated with
these sites are expected to be paid over many years.
 
The estimated amounts represent only the portion of the cleanup costs attributable to TEC. The estimates
to perform the work are based on TEC’s experience with similar work, adjusted for site-specific conditions
and agreements with the respective governmental agencies. The estimates are made in current dollars,
are not discounted and do not assume any insurance recoveries.
 
In instances where other PRPs are involved, most of those PRPs are believed to be currently credit-
worthy and are likely to continue to be credit-worthy for the duration of the remediation work. However, in
those instances that they are not, TEC could be liable for more than TEC’s actual percentage of the
remediation costs. Other factors that could impact these estimates include additional testing and
investigation which could expand the scope of the cleanup activities, additional liability that might arise
from the cleanup activities themselves or changes in laws or regulations that could require additional
remediation. Under current regulations, these costs are recoverable through customer rates established
in base rate proceedings.
Other Legal Proceedings
Emera and its subsidiaries may, from time to time, be involved in other legal proceedings, claims and
litigation that arise in the ordinary course of business which the Company believes would not reasonably
be expected to have a material adverse effect on the financial condition of the Company.
C.
Principal Financial Risks and Uncertainties
Emera believes the following principal financial risks could materially affect the Company in the normal
course of business. Risks associated with derivative instruments and fair value measurements are
discussed in note 15 and note 16.
 
66
Sound risk management is an essential discipline for running the business efficiently and pursuing the
Company’s strategy successfully. Emera has an enterprise-wide risk management process, overseen by
its Enterprise Risk Management Committee (“ERMC”) and monitored by the Board of Directors, to ensure
an effective, consistent and coherent approach to risk management. The Board of Directors established a
Risk and Sustainability Committee (‘RSC”) in September 2021. The RSC’s mandate includes oversight of
the Company’s Enterprise Risk Management framework, including the identification, assessment,
monitoring and management of enterprise risks. It also includes oversight of the Company’s approach to
sustainability and its performance relative to its sustainability objectives.
Regulatory and Political Risk
The Company’s rate-regulated subsidiaries and certain investments subject to significant influence are
subject to risk of the recovery of costs and investments. Regulatory and political risk can include changes
in regulatory frameworks, shifts in government policy, legislative changes, and regulatory decisions.
As cost-of-service utilities with an obligation to serve customers, Emera’s utilities operate under formal
regulatory frameworks, and must obtain regulatory approval to change or add rates and/or riders. Emera
also holds investments in entities in which it has significant influence, and which are subject to regulatory
and political risk including NSPML, LIL, and M&NP.
 
As a regulated Group II pipeline, the tolls of
Brunswick Pipeline are regulated by the CER on a complaint basis, as opposed to the regulatory approval
process described above. In the absence of a complaint, the CER does not normally undertake a detailed
examination of Brunswick Pipeline’s tolls, which are subject to a firm service agreement expiring in 2034,
with Repsol Energy North America Canada Partnership. The agreement provides for a predetermined toll
increase in the fifth and fifteenth year of the contract.
Regulators administer legislation covering material aspects of the utilities’ businesses, including customer
rates and/or riders, the underlying allowed ROEs, deemed capital structures, capital investment, the
terms and conditions for the provision of service, performance standards, and affiliate transactions. Costs
and investments can be recovered upon approval by the respective regulator as an adjustment to rates
and/or riders, which normally requires a public hearing process or may be mandated by other
governmental bodies. During public hearing processes, consultants and customer representatives
scrutinize the costs, actions and plans of these rate-regulated companies, and their respective regulators
determine whether to allow recovery and to adjust rates based upon the evidence and any contrary
evidence from other parties. In some circumstances, other government bodies may influence the setting
of rates. Regulatory decisions, legislative changes, and prolonged delays in the recovery of costs or
regulatory assets could result in decreased rate affordability for customers and could materially affect
Emera and its utilities.
 
Emera’s utilities generally manage this risk through transparent regulatory disclosure, ongoing
stakeholder and government consultation and multi-party engagement on aspects such as utility
operations, regulatory audits, rate filings and capital plans. The subsidiaries employ a collaborative
regulatory approach through technical conferences and, where appropriate, negotiated settlements.
 
Changes in government and shifts in government policy and legislation can impact the commercial and
regulatory frameworks under which Emera and its subsidiaries operate. This includes initiatives regarding
deregulation or restructuring of the energy industry. Deregulation or restructuring of the energy industry
may result in increased competition and unrecovered costs that could adversely affect operations, net
income and cash flows. State and local policies in some United States jurisdictions have sought to
prevent or limit the ability of utilities to provide customers the choice to use natural gas while in other
jurisdictions policies have been adopted to prevent limitations on the use of natural gas. Changes in
applicable state or local laws and regulations, including electrification legislation, could adversely impact
PGS and NMGC.
67
Emera cannot predict future legislative, policy, or regulatory changes, whether caused by economic,
political or other factors, or its ability to respond in an effective and timely manner or the resulting
compliance costs. Government interference in the regulatory process can undermine regulatory stability,
predictability, and independence, and could have a material adverse effect on the Company.
Foreign Exchange Risk
 
The Company is exposed to foreign currency exchange rate changes. Emera operates internationally,
with an increasing amount of the Company’s net income earned outside of Canada. As such, Emera is
exposed to movements in exchange rates between the CAD and, particularly, the USD, which could
positively or adversely affect results.
 
 
Consistent with the Company’s risk management policies, Emera manages currency risks through
matching United States denominated debt to finance its United States operations and may use foreign
currency derivative instruments to hedge specific transactions and earnings exposure. The Company may
enter FX forward and swap contracts to limit exposure on certain foreign currency transactions such as
fuel purchases, revenue streams and capital expenditures, and on net income earned outside of Canada.
The regulatory framework for the Company’s rate-regulated subsidiaries permits the recovery of prudently
incurred costs, including FX.
The Company does not utilize derivative financial instruments for foreign currency trading or speculative
purposes or to hedge the value of its investments in foreign subsidiaries. Exchange gains and losses on
net investments in foreign subsidiaries do not impact net income as they are reported in AOCI.
Liquidity and Capital Market Risk
Liquidity risk relates to Emera’s ability to ensure sufficient funds are available to meet its financial
obligations. Emera manages this risk by forecasting cash requirements on a continuous basis to
determine whether sufficient funds are available. Liquidity and capital needs could be financed through
internally generated cash flows, asset sales, short-term credit facilities, and ongoing access to capital
markets.
 
Emera’s access to capital and cost of borrowing is subject to several risk factors, including financial
market conditions, market disruptions, and ratings assigned by credit rating agencies. Disruptions in
capital markets could prevent Emera from issuing new securities or cause the Company to issue
securities with less than preferred terms and conditions. Emera’s growth plan requires significant capital
investments in PP&E and the risk associated with changes in interest rates could have an adverse effect
on the cost of financing. The Company’s future access to capital and cost of borrowing may be impacted
by various market disruptions. The inability to access cost-effective capital could have a material impact
on Emera’s ability to fund its growth plan.
 
Emera is subject to financial risk associated with changes in its credit ratings. There are a number of
factors that rating agencies evaluate to determine credit ratings, including the Company’s business, its
regulatory framework and the legislative environment, political interference in the regulatory process, the
ability to recover costs and earn returns, diversification, leverage, liquidity and increased exposure to
climate change-related impacts, including increased frequency and severity of hurricanes and other
severe weather events. A decrease in a credit rating could result in higher interest rates in future
financings, increased borrowing costs under certain existing credit facilities, limit access to the
commercial paper market or limit the availability of adequate credit support for subsidiary operations. For
certain derivative instruments, if the credit ratings of the Company were reduced below investment grade,
the full value of the net liability of these positions could be required to be posted as collateral. Emera
manages these risks by actively monitoring and managing key financial metrics with the objective of
sustaining investment grade credit ratings.
68
The Company has exposure to its own common share price through the issuance of various forms of
stock-based compensation, which affect earnings through revaluation of the outstanding units every
period. The Company uses equity derivatives to reduce the earnings volatility derived from stock-based
compensation.
General Economic Risk
The Company has exposure to the macro-economic conditions in North America and in other geographic
regions in which Emera operates. Like most utilities, economic factors such as consumer income,
employment and housing affect demand for electricity and natural gas, and in turn the Company’s
financial results. Adverse changes in general economic conditions and inflation may impact the ability of
customers to afford rate increases arising from increases to fuel, operating, capital, environmental
compliance, and other costs, and therefore could materially affect Emera and its utilities. This may also
result in higher credit and counterparty risk, adverse shifts in government policy and legislation, and/or
increased risk to full and timely recovery of costs and regulatory assets.
Interest Rate Risk
Emera utilizes a combination of fixed and floating rate debt financing for operations and capital
expenditures, resulting in an exposure to interest rate risk. Emera seeks to manage interest rate risk
through a portfolio approach that includes the use of fixed and floating rate debt with staggered
maturities. The Company will, from time to time, issue long-term debt or enter interest rate hedging
contracts to limit its exposure to fluctuations in floating interest rate debt.
 
For Emera’s regulated subsidiaries, the cost of debt is a component of rates and prudently incurred debt
costs are recovered from customers. Regulatory ROE will generally follow the direction of interest rates,
such that regulatory ROE’s are likely to fall in times of reducing interest rates and rise in times of
increasing interest rates, albeit not directly and generally with a lag period reflecting the regulatory
process. Rising interest rates may also negatively affect the economic viability of project development
and acquisition initiatives.
As with most other utilities and other similar yield-returning investments, Emera’s share price may be
affected by changes in interest rates and could underperform the market in an environment of rising
interest rates.
Inflation Risk
 
The Company may be exposed to changes in inflation that may result in increased operating and
maintenance costs, capital investment, and fuel costs compared to the revenues provided by customer
rates. Emera’s utilities have budgeting and forecasting processes to identify inflationary risk factors and
measure operating performance, as well as collective bargaining agreements that mitigate the short-term
impact of inflation on labour costs.
Commodity Price Risk
The Company’s utility fuel supply is subject to commodity price risk. In addition, Emera Energy is subject
to commodity price risk through its portfolio of commodity contracts and arrangements.
The Company manages this risk through established processes and practices to identify, monitor, report
and mitigate these risks. These include the Company’s commercial arrangements, such as the
combination of supply and purchase agreements, asset management agreements, pipeline transportation
agreements and financial hedging instruments. In addition, its credit policies, counterparty credit
assessments, market and credit position reporting, and other risk management and reporting practices,
are also used to manage and mitigate this risk.
69
Regulated Utilities
The Company’s utility fuel supply is exposed to broader global conditions, which may include impacts on
delivery reliability and price, despite contracted terms. Supply and demand dynamics in fuel markets can
be affected by a wide range of factors which are difficult to predict and may change rapidly, including but
not limited to currency fluctuations, changes in global economic conditions, natural disasters,
transportation or production disruptions, and geo-political risks such as political instability, conflicts,
changes to international trade agreements, trade sanctions or embargos. The Company seeks to manage
this risk using financial hedging instruments and physical contracts and through contractual protection
with counterparties, where applicable.
 
The majority of Emera’s regulated electric and gas utilities have adopted and implemented fuel
adjustment mechanisms and purchased gas adjustment mechanisms respectively, which has further
helped manage commodity price risk, as the regulatory framework for the Company’s rate-regulated
subsidiaries permits the recovery of prudently incurred fuel and gas costs. There is no assurance that
such mechanisms and regulatory frameworks will continue to exist in the future. Prolonged and
substantial increases in fuel prices could result in decreased rate affordability, increased risk of recovery
of costs or regulatory assets, and/or negative impacts on customer consumption patterns and sales.
Emera Energy Marketing and Trading
Emera Energy has employed further measures to manage commodity risk. The majority of Emera
Energy’s portfolio of electricity and gas marketing and trading contracts and, in particular, its natural gas
asset management arrangements, are contracted on a back-to-back basis, avoiding any material long or
short commodity positions. However, the portfolio is subject to commodity price risk, particularly with
respect to basis point differentials between relevant markets in the event of an operational issue or
counterparty default. Changes in commodity prices can also result in increased collateral requirements
associated with physical contracts and financial hedges, resulting in higher liquidity requirements and
increased costs to the business.
To
 
measure commodity price risk exposure, Emera Energy employs a number of controls and processes,
including an estimated VaR analysis of its exposures. The VaR
 
amount represents an estimate of the
potential change in fair value that could occur from changes in Emera Energy’s portfolio or changes in
market factors within a given confidence level, if an instrument or portfolio is held for a specified time
period. The VaR calculation is used to quantify exposure to market risk associated with physical
commodities, primarily natural gas and power positions.
Income Tax Risk
The computation of the Company’s provision for income taxes is impacted by changes in tax legislation in
Canada, the United States and the Caribbean. Any such changes could affect the Company’s future
earnings, cash flows, and financial position. The value of Emera’s existing deferred tax assets and
liabilities are determined by existing tax laws and could be negatively impacted by changes in laws.
Emera monitors the status of existing tax laws to ensure that changes impacting the Company are
appropriately reflected in the Company’s tax compliance filings and financial results.
 
D.
Guarantees and Letters of Credit
Emera has guarantees and letters of credit on behalf of third parties outstanding. The following significant
guarantees and letters of credit are not included within the Consolidated Balance Sheets as at December
31, 2022
:
70
TECO Energy has issued a guarantee in connection with SeaCoast’s performance of obligations under a
gas transportation precedent agreement. The guarantee is for a maximum potential amount of $
45
 
million
USD if SeaCoast fails to pay or perform under the contract. The guarantee expires five years after the
gas transportation precedent agreement termination date, which was terminated on January 1, 2022. In
the event that TECO Energy’s and Emera’s long-term senior unsecured credit ratings are downgraded
below investment grade by Moody’s Investor Services (“Moody’s”) or S&P Global Ratings (“S&P”). TECO
Energy would be required to provide its counterparty a letter of credit or cash deposit of $
27
 
million USD.
TECO Energy issued a guarantee in connection with SeaCoast’s performance obligations under a firm
service agreement, which expires on December 31, 2055, subject to two extension terms at the option of
the counterparty with a final expiration date of December 31, 2071. The guarantee is for a maximum
potential amount of $
13
 
million USD if SeaCoast fails to pay or perform under the firm service agreement.
In the event that TECO Energy’s long-term senior unsecured credit ratings are downgraded below
investment grade by Moody’s or S&P,
 
TECO Energy would need to provide either a substitute guarantee
from an affiliate with an investment grade credit rating or a letter of credit or cash deposit of $
13
 
million
USD.
Emera Inc. has issued a guarantee of up to $
35
 
million USD
relating to outstanding notes of GBPC
. The
guarantee for the notes will
expire in May 2023
.
Emera Inc. has issued a guarantee of $
66
 
million USD relating to outstanding notes of ECI. This
guarantee will automatically terminate on the date upon which the obligations have been repaid in full.
NSPI has issued guarantees on behalf of its subsidiary, NS Power Energy Marketing Incorporated
(“NSPEMI”), in the amount of $
119
 
million USD (2021 – $
118
 
million USD) with terms of varying lengths.
The Company has standby letters of credit and surety bonds in the amount of $
145
 
million USD
(December 31, 2020 – $
148
 
million USD) to third parties that have extended credit to Emera and its
subsidiaries. These letters of credit and surety bonds typically have a one-year term and are renewed
annually as required.
Emera Inc., on behalf of NSPI, has a standby letter of credit to secure obligations under a supplementary
retirement plan. The expiry date of this letter of credit was extended to June 2023. The amount committed
as at December 31, 2022 was $
63
 
million (December 31, 2021 – $
64
 
million).
Collaborative Arrangements
For the years ended December 31, 2022 and 2021, the Company has identified the following material
collaborative arrangements:
Through NSPI, the Company is a participant in three wind energy projects in Nova Scotia. The
percentage ownership of the wind project assets is based on the relative value of each party’s project
assets by the total project assets. NSPI has power purchase arrangements to purchase the entire net
output of the projects and, therefore, NSPI’s portion of the revenues are recorded net within regulated fuel
for generation and purchased power. NSPI’s portion of operating expenses is recorded in OM&G. In
2022, NSPI recognized $
12
 
million net expense (2021 – $
18
 
million) in “Regulated fuel for generation and
purchased power” and $
3
 
million (2021 – $
3
 
million) in OM&G.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
71
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, 2022
December 31, 2021
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
$
1.1802
$
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
$
1.2250
$
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
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
4.100
1.1802
2.65
August 15, 2023
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
4.900
1.2250
4.90
August 15, 2023
25.00
 
Series I
 
Series J
4.250
1.0625
4.25
May 15, 2026
25.00
 
Series K
Perpetual fixed rate
 
Series E
 
(5)
4.500
1.1250
25.00
 
 
Series L
(6)
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
4.9
0 per cent) and for Series B equals the Government of Treasury Bill Rate on the applicable
 
reset date, plus
1.84
 
per cent.
(4) On each conversion option date, the holders have the option, subject to certain conditions, to convert any or all of their
 
Shares
into an equal number of Cumulative Redeemable First Preferred Shares of a specified series. The Company has the right
 
to redeem
 
the outstanding Preferred Shares, Series D, Series G and Series I shares without the consent of the holder every five years
 
thereafter
for cash, in whole or in part at a price of $
25.00
 
per share plus all accrued and unpaid dividends up to but excluding the date fixed for
redemption and $
25.50
 
per share plus all accrued and unpaid dividends up to but excluding the date fixed for redemption in the case
of redemptions on any other date after August 15, 2023, February 15, 2025 and August 15, 2023, respectively.
 
The reset dividend
yield for Series I equals the Government of Treasury Bill Rate on the applicable reset date, plus
2.54
 
per cent.
(5) First Preferred Shares, Series E are redeemable at $
25.00
 
per share.
(6) First Preferred Shares, Series L are redeemable at $
26.00
 
on or after November 15, 2026 to November 15, 2027, decreasing
$
0.25
 
each year until November 15, 2030 and $
25.00
 
per share thereafter.
First Preferred Shares are neither redeemable at the option of the shareholder nor have a mandatory
redemption date. They are classified as equity and the associated dividends are deducted on the
Consolidated Statements of Income before arriving at “Net income attributable to common shareholders”
and shown on the Consolidated Statement of Equity as a deduction from retained earnings.
 
 
 
 
 
 
 
 
 
 
 
 
72
The First Preferred Shares of each series rank on a parity with the First Preferred Shares of every other
series and are entitled to a preference over the Second Preferred Shares, the Common Shares, and any
other shares ranking junior to the First Preferred Shares with respect to the payment of dividends and the
distribution of the remaining property and assets or return of capital of the Company in the liquidation,
dissolution or wind-up, whether voluntary or involuntary.
In the event the Company fails to pay, in aggregate, eight quarterly dividends on any series of the First
Preferred Shares, the holders of the First Preferred Shares, for only so long as the dividends remain in
arrears, will be entitled to attend any meeting of shareholders of the Company at which directors are to be
elected and to vote for the election of two directors out of the total number of directors elected at any such
meeting.
29.
 
NON-CONTROLLING INTEREST IN SUBSIDIARIES
As at
December 31
December 31
millions of dollars
 
2022
2021
Preferred shares of GBPC
 
$
 
14
$
 
14
Domlec
(1)
-
 
 
20
$
 
14
$
 
34
(1) On March 31, 2022, Emera disposed its interest in Domlec. For further details, refer to note 4.
Preferred shares of GBPC:
Authorized:
10,000
 
non-voting cumulative redeemable variable perpetual preferred shares.
2022
2021
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.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
73
30. SUPPLEMENTARY
 
INFORMATION TO
 
CONSOLIDATED STATEMENTS
 
OF
CASH FLOWS
For the
 
Year ended December 31
millions of dollars
2022
2021
Changes in non-cash working capital:
 
Inventory
$
(214)
$
(84)
 
Receivables and other current assets
(1)
(636)
(364)
 
Accounts payable
 
423
 
289
 
Other current liabilities
(2)
 
193
 
7
Total non-cash working capital
 
$
(234)
$
(152)
(1) Includes $(
162
) million related to the January 2023 settlement of NMGC gas hedges. Offsetting regulatory liability is included
 
in
operating cash flow before working capital resulting in no impact to net cash provided by operating activities.
(2) Includes $
172
 
million related to the Nova Scotia Cap-and-Trade program. For further detail, refer to note 7.
 
Offsetting regulatory
asset (FAM) balance is included in operating cash flow before working
 
capital resulting in no impact to net cash provided by
operating activities.
Supplemental disclosure of cash paid (received):
Interest
$
 
699
$
 
603
Income taxes
$
 
67
$
 
24
Supplemental disclosure of non-cash activities:
Common share dividends reinvested
$
 
237
$
 
214
Reclassification of long-term debt to short-term debt
$
 
500
$
-
 
Decrease in accrued capital expenditures
$
(13)
$
(45)
Supplemental disclosure of operating activities:
Net change in short-term regulatory assets and liabilities
$
(157)
$
(108)
31.
 
STOCK-BASED COMPENSATION
Employee Common Share Purchase Plan and Common Shareholders Dividend
Reinvestment and Share Purchase Plan
Eligible employees may participate in Emera’s Employee Common Share Purchase Plan. As of
December 31, 2022, the plan allows employees to make cash contributions of a minimum of $25 to a
maximum of $20,000 CAD or $15,000 USD per year for the purpose of purchasing common shares of
Emera. The Company also contributes 20 per cent of the employees’ contributions to the plan.
The plan allows the reinvestment of dividends for all participants except for where it is prohibited by law.
The maximum aggregate number of Emera common shares reserved for issuance under this plan is
7
million common shares. As at December 31, 2022, Emera is in compliance with this requirement.
Compensation cost for shares issued under the Employee Common Share Purchase Plan for the year
ended December 31, 2022 was $
3
 
million (2021 – $
3
 
million) and is included in OM&G on the
Consolidated Statements of Income.
 
The Company also has a Common Shareholders Dividend Reinvestment and Share Purchase Plan
(“Dividend Reinvestment Plan”), which provides an opportunity for shareholders to reinvest dividends and
purchase common shares. This plan provides for a discount of up to 5 per cent from the average market
price of Emera’s common shares for common shares purchased in connection with the reinvestment of
cash dividends. The discount was 2 per cent in 2022.
 
 
 
 
 
 
 
 
 
 
 
 
 
74
Stock-Based Compensation Plans
Stock Option Plan
The Company has a stock option plan that grants options to senior management of the Company for a
maximum term of 10 years. The option price of the stock options is the closing price of the Company’s
common shares on the Toronto Stock Exchange on the last business day on which such shares were
traded before the date on which the option is granted. The maximum aggregate number of shares
issuable under this plan is 14.7 million shares. As at December 31, 2022, Emera is in compliance with
this requirement.
Stock options granted in 2021 and prior vest in 25 per cent increments on the first, second, third and
fourth anniversaries of the date of the grant. Stock options granted in 2022 vest in 20 per cent increments
on the first, second, third, fourth and fifth anniversaries of the date of the grant. If an option is not
exercised within 10 years, it expires and the optionee loses all rights thereunder. The holder of the option
has no rights as a shareholder until the option is exercised and shares have been issued. The total
number of stocks to be optioned to any optionee shall not exceed five per cent of the issued and
outstanding common stocks on the date the option is granted.
For stock options granted in 2021 and prior, unless a stock option has expired, vested options may be
exercised within the
27 months
 
following the option holders date of retirement, six months following a
termination without just cause or death, and within
sixty days
 
following the date of termination for just
cause or resignation. Commencing with the 2022 stock option grant, vested options may be exercised
during the full term of the option following the option holders date of retirement, six months following a
termination without just cause or death, and within sixty days following the date of termination for just
cause or resignation. If stock options are not exercised within such time, they expire.
The Company uses the Black-Scholes valuation model to estimate the compensation expense related to
its stock-based compensation and recognizes the expense over the vesting period on a straight-line
basis.
 
The following table shows the weighted average fair values per stock option along with the assumptions
incorporated into the valuation models for options granted, for the year-ended December 31:
2022
2021
Weighted average fair value per option
$
5.35
$
3.63
Expected term
(1)
5
 
years
5
 
years
Risk-free interest rate
(2)
 
1.79
%
 
0.60
%
Expected dividend yield
(3)
 
4.55
%
 
5.00
%
Expected volatility
(4)
 
18.87
%
 
19.14
%
(1) The expected term of the option awards is calculated based on historical exercise behaviour and represents the period
 
of time
that the options are expected to be outstanding.
(2) Based on the Bank of Canada five-year government bond yields.
(3) Incorporates current dividend rates and historical dividend increase patterns.
(4) Estimated using the five-year historical volatility.
The following table summarizes stock option information for 2022:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
75
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, 2021
2,590,304
$
48.48
1,452,475
$
3.18
Granted
 
467,100
58.26
467,100
5.35
Exercised
(203,525)
43.87
N/A
N/A
Vested
N/A
N/A
(571,175)
2.83
Options outstanding December 31, 2022
2,853,879
$
50.41
1,348,400
$
4.08
Options exercisable December 31, 2022
(2)(3)
1,505,479
$
46.59
(1) As at December 31, 2022, there was $
4
 
million of unrecognized compensation related to stock options not yet vested which is
expected to be recognized over a weighted average period of approximately
3
 
years (2021 – $
3
 
million,
3
 
years).
(2) As at December 31, 2022, the weighted average remaining term of vested options was
5
 
years with an aggregate intrinsic value of
$
10
 
million (2021 –
6
 
years, $
21
 
million).
(3) As at December 31, 2022, the fair value of options that vested in the year was $
2
 
million (2021 – $
1
 
million).
Compensation cost recognized for stock options for the year ended December 31, 2022 was $
2
 
million
(2021 – $
2
 
million), which is included in OM&G on the Consolidated Statements of Income.
 
As at December 31, 2022, cash received from option exercises was $
9
 
million (2021 – $
14
 
million). The
total intrinsic value of options exercised for the year ended December 31, 2022 was $
4
 
million (2021 – $
6
million). The range of exercise prices for the options outstanding as at December 31, 2022 was $
32.35
 
to
$
60.03
 
(2021 – $
32.35
 
to $
60.03
).
Share Unit Plans
The Company has DSU, PSU and RSU plans. The plans and the liabilities are marked-to-market at the
end of each period based on an average common share price at the end of the period.
Deferred Share Unit Plans
 
Under the Directors’ DSU plan, Directors of the Company may elect to receive all or any portion of their
compensation in DSUs in lieu of cash compensation, subject to requirements to receive a minimum
portion of their annual retainer in DSUs. Directors’ fees are paid on a quarterly basis and, at the time of
each payment of fees, the applicable amount is converted to DSUs. A DSU has a value equal to one
Emera common share. When a dividend is paid on Emera’s common shares, the Director’s DSU account
is credited with additional DSUs. DSUs cannot be redeemed for cash until the Director retires, resigns or
otherwise leaves the Board. The cash redemption value of a DSU equals the market value of a common
share at the time of redemption, pursuant to the plan. Following retirement or resignation from the Board,
the value of the DSUs credited to the participant’s account is calculated by multiplying the number of
DSUs in the participant’s account by Emera’s closing common share price on the date DSUs are
redeemed.
Under the executive and senior management DSU plan, each participant may elect to defer all or a
percentage of their annual incentive award in the form of DSUs with the understanding, for participants
who are subject to executive share ownership guidelines, a minimum of 50 per cent of the value of their
actual annual incentive award (25 per cent in the first year of the program) will be payable in DSUs until
the applicable guidelines are met.
When short-term incentive awards are determined, the amount elected is converted to DSUs, which have
a value equal to the market price of an Emera common share. When a dividend is paid on Emera’s
common shares, each participant’s DSU account is allocated additional DSUs equal in value to the
dividends paid on an equivalent number of Emera common shares. Following termination of employment
or retirement, and by December 15 of the calendar year after termination or retirement, the value of the
DSUs credited to the participant’s account is calculated by multiplying the number of DSUs in the
participant’s account by the average of Emera’s stock closing price for the fifty trading days prior to a
given calculation date. Payments are made in cash.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
76
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, 2022
is presented in the following table:
Employee
DSU
Weighted
Average
Grant Date
Fair Value
Director
 
DSU
Weighted
Average
Grant Date
Fair Value
Outstanding as at December 31, 2021
610,601
$
39.22
614,365
$
43.80
Granted including DRIP
76,252
52.42
104,465
57.89
Exercised
(59,630)
31.57
(54,572)
46.04
Outstanding and exercisable as at December 31, 2022
627,223
$
41.55
664,258
$
45.83
Compensation cost recovery recognized for employee and director DSU’s for the year ended December
31, 2022 was $
6
 
million (2021 – $
9
 
million expense). Tax
 
expense related to this compensation cost
recovery for share units realized for the year ended December 31, 2022 was $
2
 
million (2021 – $
3
 
million
tax recovery). The aggregate intrinsic value of the outstanding shares for the year ended December 31,
2022 for employees was $
33
 
million (2021 – $
39
 
million). The aggregate intrinsic value of the outstanding
shares for the year ended December 31, 2022 for directors was $
34
 
million (2021 – $
39
 
million). Cash
payments made during the year ended December 31, 2021 associated with the DSU plan was $
8
 
million
(2021 – $
11
 
million).
Performance Share Unit Plan
 
Under the PSU plan, certain executive and senior employees are eligible for long-term incentives payable
through the PSU plan. PSUs are granted annually for
three
-year overlapping performance cycles,
resulting in a cash payment. PSUs are granted based on the average of Emera’s stock closing price for
the fifty trading days prior to the effective grant date. Dividend equivalents are awarded and paid in the
form of additional PSUs. The PSU value varies according to the Emera common share market price and
corporate performance.
PSUs vest at the end of the
three
-year cycle and the payouts will be calculated and approved by the
MRCC early in the following year. The value of the payout considers actual service over the performance
cycle and may be pro-rated in certain departure scenarios.
A summary of the activity related to employee PSUs for the year ended December 31, 2022 is presented
in the following table:
Employee PSU
Weighted Average
Grant Date Fair Value
Aggregate intrinsic value
Outstanding as at December 31, 2021
951,935
$
48.60
$
66
Granted including DRIP
242,462
59.30
Exercised
(357,960)
42.85
Forfeited
(145,991)
44.28
Outstanding as at December 31, 2022
690,446
$
56.24
$
40
Compensation cost recognized for the PSU plan for the year ended December 31, 2022 was $
18
 
million
(2021 – $
12
 
million). Tax
 
benefits related to this compensation cost for share units realized for the year
ended December 31, 2022 were $
5
 
million (2021 – $
3
 
million). Cash payments made during the year
ended December 31, 2021 associated with the PSU plan was $
24
 
million (2021 – $
29
 
million).
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
77
Restricted Share Unit Plan
 
Under the RSU plan, certain executive and senior employees are eligible for long-term incentives payable
through the RSU plan. RSUs are granted annually for
three
-year overlapping performance cycles,
resulting in a cash payment. RSUs are granted based on the average of Emera’s stock closing price for
the fifty trading days prior to the effective grant date. Dividend equivalents are awarded and paid in the
form of additional RSUs. The RSU value varies according to the Emera common share market price.
RSUs vest at the end of the
three
-year cycle and the payouts will be calculated and approved by the
MRCC early in the following year. The value of the payout considers actual service over the performance
cycle and may be pro-rated in certain departure scenarios.
A summary of the activity related to employee RSUs for the year ended December 31, 2022 is presented
in the following table:
 
Employee RSU
Weighted Average
Grant Date Fair Value
Aggregate intrinsic value
Outstanding as at December 31, 2021
343,952
$
54.64
$
24
Granted including DRIP
180,426
59.30
Exercised
(134)
54.63
Forfeited
(15,776)
56.08
Outstanding as at December 31, 2022
508,468
$
56.25
$
30
Compensation cost recognized for the RSU plan for the year ended December 31, 2022 was $
9
 
million
(2021 – $
8
 
million). Tax
 
benefits related to this compensation cost for share units realized for the year
ended December 31, 2022 were $
2
 
million (2021 – $
2
 
million). Cash payments made during the year
ended December 31, 2022 associated with the RSU plan was
nil
 
(2021–
nil
).
32.
 
VARIABLE INTEREST ENTITIES
Emera holds a variable interest in NSPML, a VIE for which it was determined that Emera is not the
primary beneficiary since it does not have the controlling financial interest of NSPML. When the critical
milestones were achieved, Nalcor Energy was deemed the primary beneficiary of the asset for financial
reporting purposes as it has authority over the majority of the direct activities that are expected to most
significantly impact the economic performance of the Maritime Link. Thus, Emera began recording the
Maritime Link as an equity investment.
BLPC has established a Self-Insurance Fund (“SIF”), primarily for the purpose of building a fund to cover
risk against damage and consequential loss to certain generating, transmission and distribution
systems. ECI holds a variable interest in the SIF for which it was determined that ECI was the primary
beneficiary and, accordingly, the SIF must be consolidated by ECI. In its determination that ECI controls
the SIF,
 
management considered that, in substance, the activities of the SIF are being conducted on
behalf of ECI’s subsidiary BLPC and BLPC, alone, obtains the benefits from the SIF’s operations.
Additionally, because ECI, through BLPC, has rights to all the benefits of the SIF,
 
it is also exposed to the
risks related to the activities of the SIF. Any withdrawal of SIF fund assets by the Company would be
subject to existing regulations. Emera’s consolidated VIE in the SIF is recorded as “Other long-term
assets”, “Restricted cash” and “Regulatory liabilities” on the Consolidated Balance Sheets. Amounts
included in restricted cash represent the cash portion of funds required to be set aside for the BLPC SIF.
The Company has identified certain long-term purchase power agreements that meet the definition of
variable interests as the Company has to purchase all or a majority of the electricity generation at a fixed
price. However, it was determined that the Company was not the primary beneficiary since it lacked the
power to direct the activities of the entity, including the ability to operate the generating facilities and make
management decisions.
The following table provides information about Emera’s portion of material unconsolidated VIEs:
 
 
 
78
As at
December 31, 2022
December 31, 2021
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)
$
 
501
$
 
6
$
 
533
$
 
11
33.
 
COMPARATIVE
 
INFORMATION
These financial statements contain certain reclassifications of prior period amounts to be consistent with
the current period presentation, with no effect on net income.
34.
 
SUBSEQUENT EVENTS
These financial statements and notes reflect the Company’s evaluation of events occurring subsequent to
the balance sheet date through February 23, 2023, the date the financial statements were issued.
 

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 23, 2023, with respect to the consolidated balance sheets of Emera Incorporated as at December 31, 2022 and 2021, and the consolidated statements of income, consolidated statements of comprehensive income, consolidated statements of changes in equity and consolidated statements of cash flows for the years then ended, included in this Annual Report on Form 40-F.

 

        /s/ Ernst & Young LLP
Halifax, Canada         Chartered Professional Accountants
February 24, 2023        

 

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 24, 2023
/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 24, 2023
/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, 2022 (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 24, 2023
  /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, 2022 (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 24, 2023
/s/ Gregory W. Blunden
Gregory W. Blunden
Chief Financial Officer