40-F

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM

40-F

☐

 REGISTRATION STATEMENT PURSUANT TO SECTION 12 OF THE SECURITIES EXCHANGE ACT OF 1934 

☒

 ANNUAL REPORT PURSUANT TO SECTION 13(a) OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended

December 31, 2023

Commission File Number

000-54516

EMERA INCORPORATED

(Exact name of Registrant as specified in its charter)

Nova Scotia, Canada

(Province or other jurisdiction of incorporation or organization)

4911

(Primary Standard Industrial Classification Code Number (if applicable))

Not applicable

(I.R.S. Employer Identification Number (if applicable))

5151 Terminal Road

Halifax

,

Nova Scotia

,

Canada

B3J 1A1

Telephone: (

902

)

428-6096

(Address and telephone number of Registrant’s principal executive offices)

Emera US Finance LP

c/o Corporation Service Company

251 Little Falls Drive

Wilmington

,

Delaware

19808

Telephone: (

302

)

636-5401

(Name, address (including zip code) and telephone number (including area code) 

of agent for service in the United States)

Securities registered or to be registered pursuant to Section 12(b) of the Act: Not applicable.

Securities registered or to be registered pursuant to Section 12(g) of the Act: Not applicable.

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act: Not applicable.

For annual reports, indicate by check mark the information filed with this Form:

☒

 Annual information form

☒

 Audited annual financial statements

Number of outstanding shares of each of the issuer’s classes of

capital or common stock as of December 31, 2023:

284,117,511

 Common Shares

4,866,814

 Series A First Preferred Shares

1,133,186

 Series B First Preferred Shares

10,000,000

 Series C First Preferred Shares

5,000,000

 Series E First Preferred Shares

8,000,000

 Series F First Preferred Shares

12,000,000

 Series H First Preferred Shares

8,000,000

 Series J First Preferred Shares

9,000,000

 Series L First Preferred Shares

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange

Act during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports) and (2) has

been subject to such filing requirements for the past 90 days.

Yes 

☐

No

☒

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every

Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during

the preceding 12 months (or for such shorter period that the Registrant was required to submit and post such files).

Yes

☒

 No 

☐

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the

registrant included in the filing reflect the correction of an error to previously issued financial statements. 

☐

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-

based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to

§ 240.10D-1(b). 

☐

Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 12b-2 of the Exchange Act.

Emerging growth company 

☐

If an emerging growth company that prepares is financial statements in accordance with U.S. GAAP, indicate by check mark if the

registrant has elected not to use the extended transition period for complying with any new or revised financial accounting

standards

†

 provided pursuant to Section 13(a) of the Exchange Act. 

☐

†

 The term “new or revised financial accounting standard” refers to any update issued by the Financial Accounting Standards Board

to its Accounting Standards Codification after April 5, 2012.

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the

effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b))

by the registered public accounting firm that prepared or issued its audit report.

☐

Certifications and Disclosure Regarding Controls and Procedures.

(a) Certifications regarding controls and procedures. See Exhibits 99.5 and 99.6.

(b) Evaluation of disclosure controls and procedures. As of December 31,

2023

, an evaluation of the

effectiveness of the Registrant’s “disclosure controls and procedures” (as such term is defined in Rules 13a-

15(e) and 15d-15(e) of the United States Securities Exchange Act of 1934, as amended (the “Exchange

Act”)), was carried out by the Registrant’s Chief Executive Officer (“CEO”) and Chief Financial Officer

(“CFO”). Based on that evaluation, the CEO and CFO have concluded that as of such date the Registrant’s

disclosure controls and procedures are effective to provide a reasonable level of assurance that information

required to be disclosed by the Registrant in reports that it files or submits under the Exchange Act is

recorded, processed, summarized and reported within the time periods specified in the United States

Securities and Exchange Commission’s (the “Commission”) rules and forms.

It should be noted that while the CEO and CFO believe that the Registrant’s disclosure controls and

procedures provide a reasonable level of assurance that they are effective, they do not expect the disclosure

controls and procedures or internal control over financial reporting to be capable of preventing all errors

and fraud. A control system, no matter how well conceived or operated, can provide only reasonable, not

absolute, assurance that the objectives of the control system are met.

(c) Management’s annual report on internal control over financial reporting. The Registrant's management is

responsible for establishing and maintaining adequate internal control over financial reporting. The

Registrant's internal control framework is based on the criteria published in the Internal Control –

Integrated Framework (2013), a report issued by the Committee of Sponsoring Organizations (COSO) of

the Treadway Commission. The Registrant's management, including the CEO and CFO, evaluated the

design and effectiveness of the Registrant's internal control over financial reporting as at December 31,

2023 and concluded that the Registrant's internal control over financial reporting is effective as at

December 31,

2023

.

(d) Attestation report of the registered public accounting firm. This annual report does not include an

attestation report of the Registrant’s registered public accounting firm regarding internal control over

financial reporting. 

(e) Changes in internal control over financial reporting. There were no changes in the Registrant’s internal

control over financial reporting during the fiscal year ended December 31,

2023

, that have materially

affected, or are reasonably likely to materially affect, the Registrant’s internal control over financial

reporting.

Audit Committee Financial Expert.

 The Registrant’s board of directors (the “Board”) has determined that five

audit committee financial experts serve on its Audit Committee. The audit committee financial experts are Paula Y.

Gold-Williams, Kent M. Harvey, B. Lynn Loewen, Ian E. Robertson, and Andrea S. Rosen. The Board has

determined that Paula Y. Gold-Williams, Kent M. Harvey, B. Lynn Loewen, Ian E. Robertson, and Andrea S. Rosen

are independent within the meaning of the listing standards of the New York Stock Exchange. Information

concerning the relevant experience of Paula Y. Gold-Williams, Kent M. Harvey, B. Lynn Loewen, Ian E. Robertson,

and Andrea S. Rosen is included in their biographical information contained in the Registrant’s Annual Information

Form for the fiscal year ended December 31,

2023

, filed as Exhibit 99.1 hereto (the “Annual Information Form”).

The Commission has indicated that the designation of a person as an audit committee financial expert does not make

such person an “expert” for any purpose, impose any duties, obligations or liability on such person that are greater

than those imposed on members of the audit committee and board of directors who do not carry this designation, or

affect the duties, obligations or liability of any other member of the audit committee or board of directors.

Code of Ethics.

 The Emera Code of Conduct was revised and became effective on October 1,

2023

 (the “Code”) and

applies to all directors, officers and employees of the Registrant, including the CEO and CFO. Since the adoption of

the Code, there have not been any waivers, including implied waivers, from any provision of the Code. A copy of

the Code can be found on Emera’s internet website at the following address: https://www.emera.com/about-us/who-

we-are/code-of-conduct. 

The Code was furnished to the Commission on November 24, 2023 as Exhibit 99.1 to a report on Form 6-K and is

incorporated by reference herein as Exhibit 99.9.

Principal Accountant Fees and Services.

 The information provided under the headings “Audit Committee—Audit

and Non-Audit Services Pre-Approval Process” and “Audit Committee—Auditors’ Fees” contained in the

Registrant’s Annual Information Form. The Registrant’s Audit Committee approved all of the Audit-Related and

Tax services provided by Ernst & Young LLP in

2023

 and none were approved pursuant to the de minimis exception

provided by Section (c)(7)(i)(C) of Rule 2-01 of Regulation S-X.

In connection with the Commission’s adoption of amendments to finalize the implementation of disclosure and

submission requirements on December 2, 2021, pursuant to Release No. 34-93701, the Registrant hereby affirms

that Ernst & Young LLP (PCAOB ID:

1263

) delivered an audit opinion relating to the Registrant’s Financial

Statements (as defined below) contained in the Annual Information Form, and such audit opinion was issued in

Halifax, Nova Scotia, Canada.

Liquidity and Capital Resources

The information provided under the headings (a) “Off-Balance Sheet Arrangements” and (b) “Contractual

Obligations” contained in the Registrant’s Management’s Discussion and Analysis dated

February 26, 2024

 for the

year ended December 31,

2023

, filed as Exhibit 99.2 hereto (the “MD&A”) and with respect to clause (a) the

information provided at note 27 (“D. Guarantees and Letters of Credit”) and note 32 (“Variable Interest Entities”),

and with respect to clause (b) note 27 (“A. Commitments”) and note 25 (“Long-Term Debt”), to the Audited

Consolidated Financial Statements as at and for the years ended December 31,

2023

 and December 31,

2022

, filed as

Exhibit 99.3 hereto (the “Financial Statements”), are incorporated by reference herein.

Identification of the Audit Committee.

 The information provided under the heading “Audit Committee” contained

in the Annual Information Form is incorporated by reference herein.

Mine Safety Disclosure.

 Neither the Registrant nor any of its subsidiaries is the “operator” of any “coal or other

mine”, as those terms are defined in section 3 of the Federal Mine Safety and Health Act of 1977 (30 U.S.C. 802),

that is subject to the provisions of such Act (30 U.S.C. 801 et seq.). Therefore, the provisions of Section 1503(a) of

the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 16 of General Instruction B to Form 40-

F requiring disclosure concerning mine safety violations and other regulatory matters do not apply to the Registrant

or any of its subsidiaries.

EXHIBIT INDEX

Exhibit

Number

Description

99.1

2023

 Annual Information Form dated

February 26, 2024

 for the fiscal year ended December 31,

2023

99.2

Management’s Discussion and Analysis dated February 26, 2024 for the year ended December

31, 2023

99.3

Audited Consolidated Financial Statements as at and for the years ended December 31, 2023 and

December 31, 2022

99.4

Consent of Independent Registered Public Accounting Firm

99.5

Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the U.S.

Securities Exchange Act of 1934, as amended

99.6

Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the U.S.

Securities Exchange Act of 1934, as amended

99.7

Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of

2002

99.8

Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of

2002

99.9

Emera Code of Conduct (as revised on October 1, 2023) (incorporated by reference to Emera

Incorporated’s Form 6-K, furnished to the Commission on November 24, 2023)

101

Interactive Data File (formatted as Inline XBRL)

104

Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

UNDERTAKING AND CONSENT TO SERVICE OF PROCESS

The Registrant undertakes to make available, in person or by telephone, representatives to respond to inquiries made

by the Commission staff, and to furnish promptly, when requested to do so by the Commission staff, information

relating to the securities in relation to which the obligation to file an annual report on Form 40-F arises or

transactions in said securities.

The Registrant has previously filed a Form F-X in connection with the class of securities in relation to which the

obligation to file this report arises.

Any change to the name or address of a Registrant’s agent for service shall be communicated promptly to the

Commission by amendment to Form F-X referencing the file number of the Registrant.

SIGNATURES

Pursuant to the requirements of the Exchange Act, the Registrant certifies that it meets all of the requirements for

filing on Form 40-F and has duly caused this annual report to be signed on its behalf by the undersigned, thereto

duly authorized.

DATED this 26

th

day of February, 2024.

EMERA

INCORPORATED

By: /s/ Scott C. Balfour

Name: Scott C. Balfour

Title: President & Chief

Executive Officer

EX-99.1

Exhibit 99.1

Emera Incorporated

Annual Information Form

For the year ended December 31, 2023

February 26, 2024

ANNUAL INFORMATION FORM

For the year ended December 31, 2023

Dated: February 26, 2024

TABLE OF CONTENTS

PRESENTATION OF INFORMATION	4
CAUTIONARY NOTE REGARDING FORWARD-LOOKING INFORMATION	4
CORPORATE STRUCTURE	5
Name and Incorporation	5
Amended Articles of Association	6
Intercorporate Relationships	6
INTRODUCTION	6
DESCRIPTION OF THE BUSINESS	8
Business Segments	8
Florida Electric Utility	8
Canadian Electric Utilities	11
Gas Utilities and Infrastructure	14
Other Electric Utilities	16
Other	18
GENERAL DEVELOPMENT OF THE BUSINESS	19
Florida Electric Utility	19
Canadian Electric Utilities	21
Gas Utilities and Infrastructure	25
Other Electric Utilities	26
USGAAP – Exemptive Relief	27
Financing Activity	27
RISK FACTORS	29
CAPITAL STRUCTURE	29
Common Shares	29
Emera First Preferred Shares	30
Emera Second Preferred Shares	30
Share Ownership Restrictions	30
CREDIT RATINGS	31
DIVIDENDS	33
MARKET FOR SECURITIES	34
Trading Price and Volume	34
At-The-Market Equity Program	34
DIRECTORS AND OFFICERS	35
Directors	35
Officers	37

Emera Incorporated – 2023 Annual Information Form 2

AUDIT COMMITTEE	38
Audit and Non-Audit Services Pre-Approval Process	39
Auditors’ Fees	40
CERTAIN PROCEEDINGS	40
CONFLICTS OF INTEREST	40
LEGAL PROCEEDINGS AND REGULATORY ACTIONS	41
NO INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS	41
MATERIAL CONTRACTS	41
TRANSFER AGENT AND REGISTRAR	41
EXPERTS	41
ADDITIONAL INFORMATION	41
APPENDIX “A” - DEFINITIONS OF CERTAIN TERMS	42
APPENDIX “B” – SUMMARY OF TERMS AND CONDITIONS OF AUTHORIZED SERIES OF FIRST PREFERRED SHARES	46
APPENDIX “C” - MONTHLY TRADING VOLUME AND HIGH AND LOW PRICE FOR EMERA’S SECURITIES IN 2023	49
APPENDIX “D” - EMERA INCORPORATED AUDIT COMMITTEE CHARTER	50

Emera Incorporated – 2023 Annual Information Form 3

PRESENTATION OF INFORMATION

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

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

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

CAUTIONARY NOTE REGARDING FORWARD-LOOKING INFORMATION

This AIF, including the documents incorporated herein by reference, contains “forward-looking information” and “forward-looking statements” within the meaning of applicable securities laws (collectively, “forward-looking information”). The words “anticipates”, “believes”, “budget”, “could”, “estimates”, “expects”, “forecast”, “intends”, “may”, “might”, “plans”, “projects”, “schedule”, “should”, “targets”, “will”, “would” and similar expressions are often intended to identify forward-looking information, although not all forward-looking information contains these identifying words. References to “Emera” in this section include references to the subsidiaries of Emera.

The forward-looking information in this AIF, including the documents incorporated herein by reference, includes statements which reflect the current view of Emera’s management with respect to Emera’s objectives, plans, financial and operating performance, carbon dioxide emissions reduction goals, business prospects and opportunities. The forward-looking information reflects management’s current beliefs and is based on information currently available to Emera’s management and should not be read as guarantees of future events, performance or results, and will not necessarily be accurate indications of whether, or the time(s) at which, such events, performance or results will be achieved. All such forward-looking information in this AIF is provided pursuant to safe harbour provisions contained in applicable securities laws.

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

Emera Incorporated – 2023 Annual Information Form 4

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

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

Readers are cautioned not to place undue reliance on forward-looking information as actual results could differ materially from the plans, expectations, estimates or intentions and statements expressed in the forward-looking information. All forward-looking information in this AIF and in the documents incorporated herein by reference is qualified in its entirety by the above cautionary statements and, except as required by law, Emera undertakes no obligation to revise or update any forward-looking information as a result of new information, future events or otherwise.

CORPORATE STRUCTURE

Name and Incorporation

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

Emera Incorporated – 2023 Annual Information Form 5

Amended Articles of Association

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

Intercorporate Relationships

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

Subsidiaries	Percentage Ownership  (%)	Jurisdiction
Tampa Electric Company1	100	Florida
Nova Scotia Power	100	Nova Scotia
Peoples Gas System1	100	Florida
New Mexico Gas Company	100	Delaware

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

INTRODUCTION

Based in Halifax, Nova Scotia, Emera owns and operates cost-of-service rate-regulated electric and gas utilities in Canada, the United States and the Caribbean. Cost-of-service utilities provide essential electric and gas services in designated territories under franchises and are overseen by regulatory authorities. Emera’s strategic focus continues to be safely delivering cleaner, affordable and reliable energy to its customers.

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

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

Emera Incorporated – 2023 Annual Information Form 6

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

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

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

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

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

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

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

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

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

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

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

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

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

Emera Incorporated – 2023 Annual Information Form 7

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

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

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

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

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

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

DESCRIPTION OF THE BUSINESS

Business Segments

Emera’s reportable segments are:

• Florida Electric Utility, which consists of TEC;

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

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

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

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

General

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

Operations by Segment

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

Florida Electric Utility

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

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

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

Emera Incorporated – 2023 Annual Information Form 8

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

Market and Sales

TEC Revenue and Sales Volumes by Customer Class
	Electric Revenues (%)		GWh Electric Sales Volumes  (%)
For the year ended December 31	2023	2022	2023	2022
Residential	64.9	54.7	49.0	48.4
Commercial	30.4	26.4	30.7	30.2
Industrial	7.7	7.0	9.9	10.1
Other	(3.0)1	11.9	10.4	11.3
Total	100.0	100.0	100.0	100.0

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

Energy Sources and Generation

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

System Operations

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

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

Contribution to Consolidated Net Income

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

Seasonal Nature

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

Capital Investments

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

Emera Incorporated – 2023 Annual Information Form 9

Environmental Considerations

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

Hazardous Air Pollutants

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

Carbon Reductions and GHG

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

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

Ozone

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

Water Supply and Quality

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

Emera Incorporated – 2023 Annual Information Form 10

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

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

Superfund and Former Manufactured Gas Plant Sites

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

Canadian Electric Utilities

Canadian Electric Utilities includes NSPI and ENL. NSPI is a vertically integrated regulated electric utility engaged in the generation, transmission and distribution of electricity and the primary electricity supplier to customers in Nova Scotia. ENL is a holding company with a 100 per cent equity investment in NSPML and a 31 per cent equity investment in LIL: two transmission investments related to the development of an 824 MW hydroelectric generating facility at Muskrat Falls hydroelectric project (“Muskrat Falls”) on the Lower Churchill River in Labrador.

NSPI

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

NSPI is a public utility as defined in the Public Utilities Act and is subject to regulation under the Public Utilities Act by the UARB. The Public Utilities Act gives the UARB supervisory powers over NSPI’s operations and expenditures. Electricity rates for NSPI’s customers are subject to UARB approval. NSPI is not subject to a general annual rate review process, but rather participates in hearings held from time to time at NSPI’s or the UARB’s request.

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

NSPI’s approved regulated ROE range is 8.75 per cent to 9.25 per cent, based on an actual five-quarter average regulated common equity component of up to 40 per cent.

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

Emera Incorporated – 2023 Annual Information Form 11

Market and Sales

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

Energy Sources and Generation

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

Nalcor is obligated to provide NSPI with approximately 900 GWh of energy annually over 35 years. In addition, for the first five years of the NS Block, Nalcor is obligated to provide approximately 240 GWh of additional energy from the Supplemental Energy Block transmitted through the Maritime Link. NSPI has the option of purchasing additional market-priced energy from Nalcor through the Energy Access Agreement. The Energy Access Agreement enables NSPI to access a market-priced bid from Nalcor for up to 1.8 Terawatt hours (“TWh”) of energy in any given year and, on average, 1.2 TWh of energy per year through August 31, 2041.

System Operations

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

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

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

Transmission and Distribution

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

Emera Incorporated – 2023 Annual Information Form 12

ENL

NSPML

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

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

LIL

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

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

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

Contribution to Consolidated Net Income and Adjusted Net Income

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

Seasonal Nature

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

Capital Investment

NSPI

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

Emera Incorporated – 2023 Annual Information Form 13

NSPML

NSPML does not anticipate any significant capital investment in 2024.

Environmental Considerations

NSPI is subject to environmental laws and regulations set by both the Government of Canada and the Province of Nova Scotia. NSPI continues to work with both levels of government to comply with these laws and regulations, to maximize efficiency of emission control measures and minimize customer cost. NSPI anticipates that costs prudently incurred to achieve legislated reductions will be recoverable under NSPI’s regulatory framework. NSPI faces risks associated with achieving climate-related and environmental legislative requirements, including the risk of non-compliance, which could adversely affect NSPI’s operations and financial performance. For further discussion on these risks and environmental legislation and regulations, refer to the “Enterprise Risk and Risk Management” section of the MD&A, which is hereby incorporated by reference, a copy of which is available electronically under Emera’s profile on SEDAR+ at www.sedarplus.ca.

Other Environmental Legislation and Regulations

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

Gas Utilities and Infrastructure

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

PGS and NMGC purchase gas from various suppliers depending on the needs of their customers. In Florida, gas is delivered to the PGS distribution system through interstate pipelines on which PGS has firm transportation capacity for delivery by PGS to its customers. NMGC’s natural gas is transported on major interstate pipelines on which NMGC has transportation capacity and NMGC’s intrastate transmission and distribution system for delivery to customers.

Market and sales

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

Emera Incorporated – 2023 Annual Information Form 14

PGS

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

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

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

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

NMGC

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

NMGC is subject to regulation by the NMPRC. Rates are set at a level that allows NMGC to collect total revenues equal to its cost of providing service, plus an appropriate return on invested capital.

NMGC’s approved ROE is 9.375 per cent on an allowed equity capital structure of 52 per cent.

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

EBPC

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

Since its commissioning in July 2009, the pipeline has been used solely to transport natural gas for RENAC under a 25-year firm service agreement, which expires in 2034. Brunswick Pipeline is regulated by the CER, which has classified it as a Group II pipeline. As a regulated Group II pipeline, the tolls of Brunswick Pipeline are regulated by the CER on a complaint basis, as opposed to a regulatory approval process. In the absence of a complaint, the CER does not normally undertake a detailed examination of Brunswick Pipeline’s tolls, which are subject to a firm service agreement with RENAC, as noted above. The firm service agreement provides for a predetermined toll increase in the fifth and fifteenth year of the contract.

Economic Dependence

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

Emera Incorporated – 2023 Annual Information Form 15

M&NP

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

Contribution to Consolidated Net Income

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

Seasonal Nature

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

Capital Investment

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

Environmental Considerations

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

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

Other Electric Utilities

Other Electric Utilities includes ECI, a holding company with regulated electric utilities. ECI’s regulated utilities include vertically integrated regulated electric utilities of BLPC on the island of Barbados, GBPC on Grand Bahama Island and a 19.5 per cent equity investment in Lucelec on the island of St. Lucia.

Market and Sales

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

Emera Incorporated – 2023 Annual Information Form 16

BLPC

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

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

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

GBPC

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

GBPC is regulated by the GBPA. Rates are set to recover prudently incurred costs of providing electricity service to customers plus an appropriate return on rate base. GBPC’s approved regulatory return on rate base is 8.52 per cent for 2024 (2023 – 8.32 per cent). For further details on GBPC’s regulatory environment and recovery mechanisms, refer to Note 6, Regulatory Assets and Liabilities, in the Audited Financial Statements, which is hereby incorporated by reference, a copy of which is available electronically under Emera’s profile on SEDAR+ at www.sedarplus.ca.

System Operation

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

Transmission and Distribution

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

Contribution to Consolidated Net Income and Adjusted Net Income

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

Emera Incorporated – 2023 Annual Information Form 17

Seasonal Nature

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

Capital Investment

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

Environmental Considerations

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

Other

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

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

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

Emera Energy

EES derives revenue and earnings from the wholesale marketing and trading of natural gas and electricity within the company’s risk tolerances, including those related to value-at-risk and credit exposure. EES purchases and sells physical natural gas and electricity, the related transportation and transmission capacity rights, and provides related energy asset management services. The primary market area for the natural gas and power marketing and trading business is northeastern North America, including the Marcellus and Utica shale supply areas. EES also participates in the Florida, United States Gulf Coast and Midwest/Central Canadian natural gas markets. Its counterparties include electric and gas utilities, natural gas producers, electricity generators and other marketing and trading entities. EES operates in a competitive environment, and the business relies on knowledge of the region’s energy markets, understanding of pipeline and transmission infrastructure, a network of counterparty relationships and a focus on customer service. EES manages its commodity risk by limiting open positions, utilizing financial products to hedge purchases and sales, and investing in transportation capacity rights to enable movement across its portfolio.

Earnings from EES are generally dependent on market conditions. In particular, volatility in natural gas and electricity markets, which can be influenced by weather, local supply constraints and other supply and

Emera Incorporated – 2023 Annual Information Form 18

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

Contribution to Consolidated Net Income and Adjusted Net Income

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

Capital Investment

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

GENERAL DEVELOPMENT OF THE BUSINESS

Three Year History and Changes Expected in 2024

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

Florida Electric Utility

Base Rates

On August 6, 2021, TEC filed with the FPSC a joint motion for approval of a settlement agreement by TEC and the intervenors in relation to its rate case filed with the FPSC in April 2021. On October 21, 2021, the FPSC approved a settlement agreement filed by TEC. The settlement agreement allows for an increase of $191 million USD annually, effective January 2022. This increase consisted of $123 million USD in base rate charges and $68 million USD to recover the costs of retiring assets, including Big Bend coal generation assets Units 1 through 3 and meter assets. The settlement agreement further includes two subsequent year adjustments of $90 million USD and $21 million USD, effective January 2023 and January 2024, respectively related to the recovery of future investments in the Big Bend Modernization project and solar generation. The allowed equity in the capital structure will continue to be 54 per cent from investor sources of capital. The settlement agreement includes an allowed regulated ROE range of 9.0 per cent to 11.0 per cent with a 9.95 per cent midpoint.

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

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

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

Emera Incorporated – 2023 Annual Information Form 19

Fuel Recovery

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

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

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

Solar Projects

During 2017 to 2021, TEC invested $850 million USD in 600 MW of utility-scale solar photovoltaic projects, which is recoverable through FPSC-approved SoBRAs. AFUDC was earned on these projects during construction. The FPSC has approved SoBRAs representing a total of 600 MW or $104 million USD annually in estimated revenue requirements for in-service projects.

On October 12, 2021, the FPSC approved the true-up filing for SoBRA tranche 3, included in base rates as of January 2020. A $4 million USD true-up was returned to customers during 2021. No true-up for SoBRA tranche 4 was required.

Big Bend Modernization Project

TEC invested $876 million USD, including $91 million USD of AFUDC, during 2018 through 2022 to modernize the Big Bend Power Station. The modernization project repowered Big Bend Unit 1 with natural gas combined-cycle technology and eliminated coal as this unit’s fuel. As part of the modernization project, TEC retired the Unit 1 components that will not be used in the modernized plant in 2020 and Big Bend Unit 2 in 2021. TEC retired Big Bend Unit 3 in 2023 as it is in the best interest of the customers from an economic, environmental risk and operational perspective. On December 31, 2021, the remaining costs of the retired Big Bend coal generation assets, Units 1 through 3, of $636 million USD and $267 million USD in accumulated depreciation were reclassified to a regulatory asset on the balance sheet.

TEC’s 2021 settlement agreement provides recovery for the Big Bend Modernization project in two phases. The first phase was a revenue increase to cover the costs of the assets in service during 2022, among other items. The remainder of the project costs were recovered as part of the 2023 subsequent year adjustment. The settlement agreement also includes a new charge to recover the remaining costs of the retired Big Bend coal generation assets, Units 1 through 3, which are spread over 15 years, effective January 1, 2022. This recovery mechanism is authorized by and survives the term of the settlement agreement approved by the FPSC in 2021.

Storm Reserve

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

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

Emera Incorporated – 2023 Annual Information Form 20

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

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

Storm Protection Cost Recovery Clause and Settlement Agreement

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

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

Canadian Electric Utilities

NSPI

General Rate Application

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

Fuel Recovery

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

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

Emera Incorporated – 2023 Annual Information Form 21

Extra Large Industrial Active Demand Tariff

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

Hurricane Fiona

On September 24, 2022, Nova Scotia was struck by Hurricane Fiona, which made landfall as a post-tropical storm equivalent to a Category 2 hurricane. The storm had sustained winds of over 100 km per hour and peak gusts of approximately 180 km per hour. This historic storm for Nova Scotia caused significant and widespread damage to NSPI’s transmission and distribution system and at the height of the storm approximately 415,000 customers lost power. The total cost of the restoration was approximately $120 million, of which $96 million was capitalized to “PP&E” and $24 million deferred to “Other long-term assets” for future amortization, subject to UARB approval.

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

Post-Tropical Storm Lee

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

Regulatory Matters – General

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

Environmental Legislation and Regulations

Greenhouse Gas Emissions

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

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

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

Emera Incorporated – 2023 Annual Information Form 22

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

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

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

Clean Electricity Solutions Task Force

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

Nova Scotia Renewable Electricity Regulations

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

Due to the delay of NSPI receiving energy form the NS Block, the Province provided NSPI with an alternative compliance plan that required NSPI to achieve 40 per cent of electric sales generated from renewable sources over the 2020 through 2022 period. With delivery of the NS Block commencing later than anticipated, as well as further interruptions in supply due to delays in the LIL, NSPI did not achieve the requirements of the alternative compliance plan.

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

Carbon Pricing Regulations

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

Emera Incorporated – 2023 Annual Information Form 23

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

Nova Scotia Cap-and-Trade Program Regulations

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

Other Legislation

Electricity Act Amendment

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

Performance Standards Penalty Amendment

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

ENL

Maritime Link Project

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

In February 2022, the UARB issued its decision and Board Order approving NSPML’s requested rate base of approximately $1.8 billion less $9 million of costs ($7 million after-tax) that would not have otherwise been recoverable if incurred by NSPI. NSPML also received approval to collect up to $168 million (2021 – $172 million) from NSPI for the recovery of costs associated with the Maritime Link in 2022. This was subject to a holdback of up to $2 million per month, beginning April 2022, release of which was contingent on receiving in that month at least 90 per cent of NS Block deliveries, including supplemental Energy deliveries.

Emera Incorporated – 2023 Annual Information Form 24

In December 2022, NSPML received UARB approval to collect up to $164 million from NSPI for the recovery of costs associated with the Maritime Link in 2023, subject to a monthly holdback of up to $2 million, which will increase to $4 million beginning December 2023, as discussed below.

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

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

Gas Utilities and Infrastructure

PGS

Base Rates

On November 19, 2020, the FPSC approved a settlement agreement filed by PGS. The settlement agreement allowed for an increase to base rates by $58 million USD annually effective January 1, 2021, which is a $34 million USD increase in revenue and $24 million USD increase of revenues previously recovered through the cast iron and bare steel replacement rider. It provided PGS the ability to reverse a total of $34 million USD of accumulated depreciation through 2023. PGS reversed $20 million USD of accumulated depreciation in 2023 and $14 million USD in 2022.

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

NMGC

Base Rates

On December 13, 2021, NMGC filed a rate case with the NMPRC for new rates to become effective January 2023. On May 20, 2022, NMGC filed an unopposed settlement agreement with the NMPRC for an increase of $19 million USD in annual base revenues. The rates reflect the recovery of increased operating costs and capital investments in pipelines and related infrastructure. The NMPRC approved the settlement agreement on November 30, 2022.

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

Emera Incorporated – 2023 Annual Information Form 25

NMGC Winter Event Gas Cost Recovery

In February 2021, the State of New Mexico experienced an extreme cold weather event that resulted in an incremental $108 million USD for gas costs above what it would normally have paid during this period. NMGC normally recovers gas supply and related costs through a purchased gas adjustment clause. On April 16, 2021, NMGC filed a Motion for Extraordinary Relief, as permitted by the NMPRC rules, to extend the terms of the repayment of the incremental gas costs and to recover a carrying charge. On June 15, 2021, the NMPRC approved the recovery of $108 million USD and related borrowing costs over a period of 30 months from July 1, 2021, to December 31, 2023.

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

Other Electric Utilities

BLPC

General Rate Review

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

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

Clean Energy Transition Program (“CETP”)

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

Emera Incorporated – 2023 Annual Information Form 26

GBPC

Base Rates

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

Fuel Recovery

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

Storm Restoration Costs – Hurricane Matthew

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

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

USGAAP – Exemptive Relief

On January 28, 2021, the International Accounting Standards Board (“IASB”) published an Exposure Draft: Regulatory Assets and Regulatory Liabilities, which proposes the accounting model under which a company subject to rate regulation that meets the scope criteria would recognize regulatory assets and liabilities. The proposed effective date is annual reporting periods beginning on or after a date 18-24 months from the date of publication of the standard. Emera was granted exemptive relief by Canadian securities regulators on September 13, 2022, and under the Companies Act (Nova Scotia) on October 12, 2022, each allowing Emera to continue to report its financial results in accordance with USGAAP (collectively the “Exemptive Relief”). The Exemptive Relief will terminate on the earliest of: (i) January 1, 2027; (ii) if the Company ceases to have rate-regulated activities, the first day of the Company’s financial year that commences after the Company ceases to have rate-regulated activities; and (iii) the first day of the Company’s financial year that commences on or following the later of: (a) the effective date prescribed by the IASB for the mandatory application of a standard within IFRS specific to entities with rate-regulated activities (“Mandatory Rate-regulated Standard”); and (b) two years after the IASB publishes the final version of a Mandatory Rate-regulated Standard. The Exemptive Relief replaces similar relief that had been granted to Emera in 2018 and would have expired by no later than January 1, 2024.

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

Financing Activity

At-The-Market Equity Program

On August 12, 2021, Emera renewed its ATM Program that allows the Company to issue up to $600 million of common shares from treasury to the public from time to time, at the Company’s discretion, at the

Emera Incorporated – 2023 Annual Information Form 27

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

During 2021, approximately 4.99 million common shares were issued under the ATM Program at an average price of $57.63 per share for gross proceeds of $287 million ($284 million net of after-tax issuance costs). As at December 31, 2021, an aggregate gross sales limit of $457 million remained available for issuance under the ATM Program.

During 2022, approximately 4.07 million common shares were issued under the ATM Program at an average price of $61.31 per share for gross proceeds of $250 million ($248 million net of after-tax issuance costs). As at December 31, 2022, an aggregate gross sales limit of $207 million remained available for issuance under the ATM Program, which expired on September 5, 2023.

On November 14, 2023, Emera renewed its ATM Program that allows the Company to issue up to $600 million of common shares from treasury to the public from time to time, at the Company’s discretion, at the prevailing market price. The ATM Program was renewed pursuant to a prospectus supplement dated November 14, 2023 to the Company’s short form base shelf prospectus dated October 3, 2023. The ATM program is expected to remain in effect until November 4, 2025.

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

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

Preferred Share Issuances

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

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

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

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

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

Senior Notes

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

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

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

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

RISK FACTORS

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

CAPITAL STRUCTURE

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

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

Common Shares

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

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

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

Emera Incorporated – 2023 Annual Information Form 29

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

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

Emera First Preferred Shares

The first preferred shares of each series rank on parity with the first preferred shares of every other series and are entitled to a preference over the second preferred shares, the common shares, and any other shares ranking junior to the first preferred shares with respect to the payment of dividends and the distribution of the remaining property and assets or return of capital of the Company in the liquidation, dissolution or wind-up, whether voluntary or involuntary.

In the event the Company fails to pay, in aggregate, eight quarterly dividends on any series of the first preferred shares, the holders of the first preferred shares will be entitled, for only as long as the dividends remain in arrears, to attend any meeting of shareholders of the Company at which directors are to be elected and to vote for the election of two directors out of the total number of directors elected at any such meeting.

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

Emera Second Preferred Shares

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

Share Ownership Restrictions

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

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

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

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CREDIT RATINGS

Emera has the following credit ratings by the Rating Agencies:

	Moody’s	S&P	Fitch
Corporate	Baa3	BBB	BBB
Outlook	Negative	Negative	Negative
Senior unsecured debt program	Baa3	BBB-	BBB
Hybrid Notes	Ba2	BB+	BB+
First Preferred Shares	N/A	P-3 (high)	BB+

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

Moody’s

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

S&P

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

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

Fitch

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

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

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

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

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DIVIDENDS

Any dividend payments will be at the Board’s discretion based upon earnings and capital requirements and any other factors as the Board may consider relevant. On September 20, 2023 Emera extended its annual dividend growth rate target of four to five per cent through 2026. The Company targets a long-term dividend payout ratio of 70 to 75 per cent, and while the payout ratio is likely to exceed that target through and beyond the forecast period, it is expected to return to that range over time.

Emera maintains the Dividend Reinvestment Plan, which provides an opportunity for shareholders to reinvest dividends and to participate in optional cash contributions for the purpose of purchasing common shares. This plan provides for a discount of up to 5 per cent from the average market price of Emera’s common shares for common shares purchased in connection with the reinvestment of cash dividends. The discount was 2 per cent in 2023.

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

Class of Shares	2023		2022		2021
Common Shares(1), (2), (3)		$2.7875		$2.6775		$2.5750
Series A First Preferred Shares(4)		$0.5456		$0.5456		$0.5456
Series B First Preferred Shares		$1.5583		$0.6869		$0.4873
Series C First Preferred Shares(5)		$1.2873		$1.1802		$1.1802
Series E First Preferred Shares		$1.1250		$1.1250		$1.1250
Series F First Preferred Shares(6)		$1.0505		$1.0505		$1.0505
Series H First Preferred Shares(7)		$1.3140		$1.2250		$1.2250
Series J First Preferred Shares(8)		$1.0625		$1.0625		$0.6470
Series L First Preferred Shares(9)		$1.1500		$1.1500		$0.1638

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

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

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

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

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

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

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

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

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

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

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MARKET FOR SECURITIES

Trading Price and Volume

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

At-The-Market Equity Program

On November 14, 2023, Emera renewed its ATM Program that allows the Company to issue up to $600 million of common shares from treasury to the public from time to time, at the Company’s discretion, at the prevailing market price. The ATM Program was renewed pursuant to a prospectus supplement dated November 14, 2023 to the Company’s short form base shelf prospectus dated October 3, 2023. The ATM program is expected to remain in effect until November 4, 2025, unless terminated prior to such date by the Company or otherwise in accordance with the terms of the equity distribution agreement. As at December 31, 2023, an aggregate gross sales limit of approximately $200 million remains available for issuance under the ATM program. For more information on the ATM Program, refer to “General Development of the Business – Financing Activity – At-The-Market Equity Program” above.

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DIRECTORS AND OFFICERS

Directors

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

Name, Residence, Principal Occupations During the Past Five Years	Director Since(2)	Committees(3)
M. Jacqueline Sheppard (Chair), Calgary, Alberta, Canada Chair of the Board since May 2014. Director of Suncor Energy Inc., a Canadian integrated energy company and of ARC Resources Ltd., a publicly traded Canadian energy company. Former Director of Alberta Investment Management Corporation (AIMCo), an institutional investment manager.(1) Former Executive Vice President, Corporate and Legal of Talisman Energy Inc. Founder and former Lead Director of Black Swan Energy Inc., an Alberta upstream energy company, which was sold in July 2021. Former Director of Cairn Energy PLC, a publicly traded UK-based international upstream company, as well as former director of the general partner of Pacific Northwest LNG LP and Chair of the Research and Development Corporation of the Province of Newfoundland and Labrador, a provincial Crown corporation, until June 2014.	2009	(4)
Scott C. Balfour, Halifax, Nova Scotia, Canada A Director and President and Chief Executive Officer of Emera since March 29, 2018. Mr. Balfour is a Director of many Emera subsidiaries, including being Chair of Tampa Electric Company and Nova Scotia Power Inc. He is a former director of Martinrea International Inc. He was Chief Operating Officer from 2016 to 2018 and was Executive Vice President and Chief Financial Officer of Emera from April 2012 to March 2016. From 1994 to 2011 he was Chief Financial Officer and then President of Aecon Group Inc., a Canadian publicly traded construction and infrastructure development company. He is also past Chair of the Ontario Energy Association.	2018	(5)
James V, Bertram Calgary, Alberta, Canada Chair of the Board, Keyera Corporation. Formerly President, and Chief Executive Officer of Keyera from its inception in 1998 until 2015, when he became Executive Chair. Previously Vice President – Marketing for the worldwide operations of Gulf Canada. Director of Methanex Corporation, the world’s largest producer and supplier of methanol to major international markets.	2018	Chair of HSEC and Member of MRCC
Henry E. Demone, Lunenburg, Nova Scotia, Canada Former Chair of High Liner Foods, the leading North American processor and marketer of value-added frozen seafood. Mr. Demone was President of High Liner Foods since 1989 and its President and Chief Executive Officer from 1992 to May 2015. He was interim Chief Executive Officer of High Liner Foods from August 2017 until April 2018. A Director of Saputo Inc.	2014	Chair of MRCC and Member of NCGC
Paula Y. Gold-Williams, San Antonio, Texas, U.S. Former President and CEO of CPS Energy, a fully integrated electric and natural gas municipal utility based in San Antonio, Texas. Currently serves as the Co-Chair of the Keystone Policy Center, having been a member of both the Policy Center and its Energy Board since 2016. Former .Board member and Treasurer of EPIcenter, an innovation think tank; incubator and accelerator; and strategic advisory organizationEnergy Pillar Co-Chair of Dentons’ Global Smart Cities & Communities Initiatives and Think Tank. Advisory Board Serves on the US Secretary of Energy’s Advisory Board. A Director of ReNew Energy Global Plc, a renewable energy company based in India.	2022	Member of AC and HSEC
Kent M. Harvey, New York, New York, U.S. Former Chief Financial Officer for PG&E Corporation, an energy-based holding company, and the parent of Pacific Gas and Electric Company, one of the largest combined natural gas and electric energy companies in the United States.	2017	Chair of AC and Member of HSEC

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B. Lynn Loewen, FCPA, FCA, Westmount, Quebec, Canada Former President of Minogue Medical Inc., a Canadian supplier of innovative medical technologies, supplies and equipment. Former President of Expertech Network Installation Inc., a Canadian network infrastructure service provider, from 2008 to 2011. Member of the Board of Directors of National Bank of Canada, a Canadian Chartered Bank, Chair of its Audit Committee and member of its Technology Comittee. Former member of the Board of Directors of Xplore Inc., a Canadian broadband service provider, and a member of its Audit Committee from 2021 to 2023. Former member of the Public Sector Pension Investment Board, serving on the Audit and Conflicts Committee and as Audit Committee Chair. Chancellor of Mount Allison University and a member of the Executive Committee and Chair of its Nominating and Governance Committee since 2018. Member of the Board of Regents from 1998 to 2008, serving as Chair from 2007-2008.	2013	Member of AC, HSEC and RSC
Ian E. Robertson, Oakville, Ontario, Canada A principal of the Northern Genesis Capital Group, an investment group focused on identifying and acquiring energy transition businesses which demonstrate strong sustainability and Environmental, Social and Governance (ESG) alignment. Former CEO of Algonquin Power & Utilities Corp. (Algonquin Power). Former member of the Board of Directors of Northern Genesis Acquisition Corp., Northern Genesis Acquisition Corp. II and Northern Genesis Acquisition Corp. III. Former Director of Embark Technology, Inc., an autonomous vehicle company,Largo Resources Ltd., Algonquin Power and Atlantica Sustainable Infrastructure plc.	2022	Member of AC and RSC
Andrea S. Rosen, Toronto, Ontario, Canada Former Vice-Chair of TD Bank Financial Group and President of TD Canada Trust. Director of Manulife Financial Corporation, a Canadian multinational insurance company and financial services provider; Ceridian HCM Holding Inc., a global human capital management software company and Element Fleet Management Corp., a global fleet management company, providing services and financing for commercial vehicle fleets. Former Director of Alberta Investment Management Corporation (“AIMCo.”). Former Director of Hiscox Ltd., a Bermuda-incorporated specialty insurer listed on the London Stock Exchange.	2007	Chair of NCGC and Member of AC
Karen H. Sheriff, Picton, Ontario, Canada Ms. Sheriff is past President and CEO of Q9 Networks Inc., and prior to that, President and CEO of Bell Aliant, Inc., from 2008 to 2014. She held senior leadership positions for more than nine years with BCE Inc. and currently serves on the BCE Inc. Board of Directors. She spent over 10 years at United Airlines in the areas of marketing, strategy, human resources, and finance. She is a former member of the Board of Directors of CPP Investments and WestJet Airlines Ltd.	2021	Member of MRCC, RSC and NCGC
Jochen E. Tilk, Toronto, Ontario, Canada Former Executive Chair of Nutrien Ltd., a Canadian global supplier of agricultural products and services based in Saskatoon, Saskatchewan. Former President and Chief Executive Officer of Potash Corporation of Saskatchewan. Previously President and Chief Executive Officer of Inmet Mining Corporation, a Canadian-based, international metals company. Mr. Tilk is a director of AngloGold Ashanti Limited, a publicly listed international gold mining company, headquartered in Johannesburg, South Africa. He is also Vice-Chair of the Princess Margaret Cancer Foundation, a not-for-profit organization. He is the former Chair of the board of directors of Canpotex Limited. Former Director of the Fertilizer Institute and the International Fertilizer Association.	2018	Chair of RSC and Member of MRCC and NCGC

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

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

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

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

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

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Officers

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

Name and Residence	Principal Occupations During the Past Five Years
Scott C. Balfour President and Chief Executive Officer Halifax, Nova Scotia, Canada	A Director and President and Chief Executive Officer of Emera since March 29, 2018.(1)
Gregory W. Blunden, FCPA Chief Financial Officer Halifax, Nova Scotia, Canada	Chief Financial Officer of Emera since March 2016.
Karen E. Hutt Executive Vice-President, Business Development and Strategy Halifax, Nova Scotia, Canada	Executive Vice-President, Business Development and Strategy of Emera since October 21, 2019. Previously, President and Chief Executive Officer of NSPI since August 2016.
Bruce A. Marchand Chief Risk and Sustainability Officer Halifax, Nova Scotia, Canada	Chief Risk and Sustainability Officer of Emera since June 30, 2022. Prior to this Chief Legal and Compliance Officer of Emera and NSPI since December 1, 2014 and Chief Legal Officer of Emera and NSPI since January 2012.
R. Michael Roberts Chief Human Resources Officer Halifax, Nova Scotia, Canada	Chief Human Resources Officer of Emera and NSPI since December 1, 2014.
Daniel P. Muldoon Executive Vice-President Project Development and Operations Support Halifax, Nova Scotia, Canada	Executive Vice-President Project Development and Operations Support of Emera. Chair of the Boards of ENL, EBPC, Emera Technologies LLC and NMGC and Block Energy, LLC. Former Director of Emera Maine from August 2013 until March 2020. Director of TEC and NSPML. Formerly Executive Vice-President, Major Renewables and Alternative Energy since May 2014.
Michael R. Barrett Executive Vice-President and General Counsel Halifax, Nova Scotia, Canada	Executive Vice-President and General Counsel of Emera since July 1, 2022. Prior to this, General Counsel of Emera since November 20, 2017. Prior to joining Emera, Senior Partner and head of the power and climate change practice groups at Bennett Jones LLP in Toronto.
Brian C. Curry Corporate Secretary Halifax, Nova Scotia, Canada	Corporate Secretary of Emera since November 16, 2023 (2) and prior to that Associate Corporate Secretary, Emera. Former Senior Director Regulatory and Corporate Secretary, NSPI from February 2021 to February 2023, Senior Regulaory Counsel and Corporate Secretary, NSPI from January 1, 2020 to February 2021 and Regulatory Counsel from January 2015 to January 2020.

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

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

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

Emera Incorporated – 2023 Annual Information Form 37

AUDIT COMMITTEE

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

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

Kent M. Harvey, Committee Chair

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

Paula Y. Gold-Williams

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

B. Lynn Loewen, FCPA, FCA

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

Emera Incorporated – 2023 Annual Information Form 38

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

Ian E. Robertson

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

Andrea S. Rosen

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

Audit and Non-Audit Services Pre-Approval Process

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

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

Emera Incorporated – 2023 Annual Information Form 39

Auditors’ Fees

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

Service Fee	2023 ($)		2022 ($)
Audit Fees	$	3,910,266	$	2,018,989
Audit-Related Fees (1)		174,410		19,600
Tax Fees (2)		39,450		337,999
All Other Fees		75,000		—
Total	$	4,199,126	$	2,376,588

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

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

CERTAIN PROCEEDINGS

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

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

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

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

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

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

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

CONFLICTS OF INTEREST

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

Emera Incorporated – 2023 Annual Information Form 40

LEGAL PROCEEDINGS AND REGULATORY ACTIONS

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

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

NO INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

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

MATERIAL CONTRACTS

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

TRANSFER AGENT AND REGISTRAR

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

EXPERTS

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

ADDITIONAL INFORMATION

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

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

Emera Incorporated – 2023 Annual Information Form 41

APPENDIX “A” - Definitions of Certain Terms

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

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

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

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

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

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

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

“Bahamas DRs” means the DRs listed on BISX;

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

“BBD” means Barbadian dollars;

“BISX” means The Bahamas International Securities Exchange;

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

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

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

“Board” means the Board of Directors of Emera;

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

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

“BSD” means Bahamian dollars;

“BSE” means the Barbados Stock Exchange;

“CAD” means Canadian dollars;

“CAIR” means the Clean Air Interstate Rule;

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

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

“Company” means Emera;

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

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

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

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

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

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

“ECRC” means the environmental cost recovery clause;

Emera Incorporated – 2023 Annual Information Form 42

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

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

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

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

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

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

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

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

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

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

“FCM” means forward capacity market;

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

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

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

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

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

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

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

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

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

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

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

“IFRS” means International Financial Reporting Standards;

“IMP” means integrity management programs;

“IPPs” means independent power producers;

“km” means kilometre(s);

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

Emera Incorporated – 2023 Annual Information Form 43

Muskrat Falls energy between Labrador and the island of Newfoundland;

“LNG” means liquefied natural gas;

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

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

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

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

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

“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;

“NERC” means North American Electric Reliability Corporation;

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

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

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

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

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

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

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

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

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

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

“OBPS” means output-based pricing system;

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

“PGAC” means purchased gas adjustment clause;

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

“PP&E” means property, plant and equipment;

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

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

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

Emera Incorporated – 2023 Annual Information Form 44

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

“RENAC” means Repsol Energy North America Canada Partnership;

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

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

“RER” means the Nova Scotia Renewable Electricity Regulations;

“ROE” means return on equity;

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

“SO₂” means sulphur dioxide;

“SoBRA” means solar base rate adjustment;

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

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

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

“TSX” means The Toronto Stock Exchange;

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

“USD” means U.S. dollars; and

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

Emera Incorporated – 2023 Annual Information Form 45

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

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

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

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

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

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

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

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

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

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

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

Emera Incorporated – 2023 Annual Information Form 46

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

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

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

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

Series of First Preferred Shares	Initial Redemption / Interest Reset Date	Subsequent Redemption / Conversion / Interest Reset Dates	Spreads
Series A	August 15, 2015	August 15, 2020 and every fifth year thereafter	1.84%
Series B	August 15, 2020	August 15, 2025 and every fifth year thereafter	1.84%
Series C	August 15, 2018	August 15, 2023 and every fifth year thereafter	2.65%
Series D	—	August 15, 2023 and every fifth year thereafter	2.65%
Series E	August 15, 2018	—	—
Series F	February 15, 2020	February 15, 2025 and every fifth year thereafter	2.63%
Series G	—	February 15, 2025 and every fifth year thereafter	2.63%
Series H	August 15, 2023	August 15, 2028 and every fifth year thereafter	2.54%
Series I	—	August 15, 2028 and every fifth year thereafter	2.54%
Series J	May 15, 2026	May 15, 2031 and every fifth year thereafter	3.28%
Series K	—	May 15, 2031 and every fifth year thereafter	3.28%
Series L	November 15, 2026	—	—

Series 2016-A Conversion, First Preferred Shares

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

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

Emera Incorporated – 2023 Annual Information Form 47

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

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

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

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

Emera Incorporated – 2023 Annual Information Form 48

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

	Common   Shares	Depositary Receipts		Series of First Preferred Shares
		Barbados   BBD (1)	Bahamas   BSD (2)	A	B	C	E	F	H	J	L
December High ($) Low ($) Volume	50.55 47.33 19,145,916	18.83 17.40 0	9.42 8.70 0	14.00 13.20 81,163	15.70 14.76 24,431	20.45 19.32 228,024	16.94 16.11 57,698	17.47 16.62 214,705	21.90 19.75 215,190	18.25 17.50 244,386	17.05 16.30 267,602
November High ($) Low ($) Volume	49.21 45.45 28,093,789	23.00 16.21 82	8.97 8.19 0	13.91 12.72 148,350	15.95 15.06 10,561	20.60 18.14 178,388	17.10 15.20 37,638	17.50 15.60 381,774	21.80 18.98 188,378	18.49 16.19 218,322	17.41 15.23 305,514
October High ($) Low ($) Volume	48.84 43.67 36,544,687	23.00 15.94 76	8.94 7.97 0	13.75 12.75 101,371	16.39 15.21 30,259	19.32 17.94 125,041	16.28 14.99 70,245	17.17 15.57 41,159	19.93 18.30 144,040	17.63 16.00 195,141	16.40 15.10 147,818
September High ($) Low ($) Volume	52.31 47.32 18,371,308	23.00 17.43 192	9.69 8.75 0	13.12 13.01 11,087	15.75 15.02 11,445	19.70 19.00 151,253	16.69 15.94 62,159	16.83 16.25 51,754	20.34 19.51 113,419	18.50 17.01 101,830	16.78 16.06 129,228
August High ($) Low ($) Volume	53.53 50.04 22,784,822	25.00 18.35 35	10.10 10.10 1,000	13.60 13.03 37,109	17.00 15.50 13,238	20.74 19.01 280,632	16.95 16.39 34,752	17.55 16.47 78,393	21.49 19.41 219,728	20.89 18.04 135,859	17.00 16.01 80,944
July High ($) Low ($) Volume	55.74 52.41 20,071,924	25.00 19.54 201	10.54 9.88 0	13.62 13.18 113,886	17.96 15.97 52,124	20.95 20.10 165,331	17.15 16.80 60,766	17.64 17.02 81,152	22.90 20.48 132,309	21.73 20.58 138,081	17.35 16.85 108,285
June High ($) Low ($) Volume	56.75 52.96 15,758,704	25.00 19.97 30	10.56 9.99 0	13.30 12.49 91,735	15.97 14.21 17,410	20.74 18.90 208,315	17.65 16.75 29,981	17.84 17.10 40,398	21.65 20.24 127,602	22.08 20.89 58,313	18.15 16.91 30,399
May High ($) Low ($) Volume	59.52 55.57 27,608,566	25.00 20.30 509	11.03 10.21 0	13.42 12.54 121,371	15.35 14.50 38,700	19.42 18.40 79,745	18.25 17.27 31,981	18.30 16.99 222,314	21.02 20.19 77,556	22.76 21.04 57,454	18.49 17.57 67,226
April High ($) Low ($) Volume	59.16 54.67 27,990,485	21.73 20.34 0	10.86 10.17 0	13.60 13.21 39,553	16.05 15.25 25,220	19.60 18.67 79,168	18.50 17.74 33,017	17.84 17.45 431,011	20.86 20.00 90,965	23.10 22.10 55,156	19.03 18.00 100,356
March High ($) Low ($) Volume	56.59 51.94 23,800,570	20.91 19.07 0	10.45 9.54 0	14.20 13.03 136,683	16.43 15.56 19,660	20.26 18.66 158,448	19.08 17.82 58,620	18.31 16.82 64,854	21.87 20.04 96,223	23.25 21.33 109,043	18.85 18.05 78,142
February High ($) Low ($) Volume	55.50 52.36 30,781,125	20.48 19.65 0	9.60 9.60 210	14.17 13.76 36,325	16.50 16.00 16,498	20.05 19.51 134,376	19.07 18.06 62,935	18.55 17.96 68,619	23.45 21.25 78,081	24.53 22.85 63,862	19.27 18.40 70,049
January High ($) Low ($) Volume	55.31 51.00 28,195,557	20.58 18.80 0	10.29 9.40 0	14.24 13.49 88,141	16.50 15.05 20,360	20.45 18.60 92,940	19.10 16.97 46,564	18.81 17.47 43,481	22.80 20.95 83,125	23.86 21.82 69,677	19.28 17.20 108,678

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

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

Emera Incorporated – 2023 Annual Information Form 49

February 2023

APPENDIX “D” - EMERA INCORPORATED AUDIT COMMITTEE CHARTER

PART I

MANDATE AND RESPONSIBILITIES

Committee Purpose

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

- the quality and integrity of Emera’s financial statements;

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

- the internal audit and assurance process;

- the qualifications, independence and performance of the external auditors;

- major financial risk exposures;

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

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

1. Financial Reporting

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

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

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

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

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

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

2. External Auditors

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

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

Emera Incorporated – 2023 Annual Information Form 50

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

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

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

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

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

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

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

3. Non-Audit Services

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

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

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

4. Oversight and Monitoring of Audits

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

Emera Incorporated – 2023 Annual Information Form 51

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

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

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

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

5. Oversight and Review of Accounting Principles and Practices

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

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

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

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

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

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

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

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

Emera Incorporated – 2023 Annual Information Form 52

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

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

6. Hiring Policies

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

7. Pension Plans

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

8. Oversight of Finance Matters

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

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

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

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

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

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

Emera Incorporated – 2023 Annual Information Form 53

9. Internal Controls

The Committee shall oversee:

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

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

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

The Committee will carry out the following specific duties:

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

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

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

10. Internal Auditor

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

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

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

Emera Incorporated – 2023 Annual Information Form 54

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

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

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

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

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

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

11. Complaints

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

12. Other Responsibilities

The Committee shall:

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

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

(c) Annually provide feedback on the performance of the Chief Financial Officer;

Emera Incorporated – 2023 Annual Information Form 55

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

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

13. Limitation on Authority

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

PART II

COMPOSITION

14. Composition

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

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

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

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

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

Emera Incorporated – 2023 Annual Information Form 56

PART III

COMMITTEE PROCEDURE

15. Meetings

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

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

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

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

16. Separate Sessions

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

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

(c) The Committee shall meet periodically without Management present.

17. Quorum

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

18. Chair

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

19. Secretary and Minutes

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

Emera Incorporated – 2023 Annual Information Form 57

20. Board Relationships and Reporting

The Committee shall:

(a) Review annually the Committee’s Charter;

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

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

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

21. Powers

The Committee shall:

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

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

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

22. Experts and Advisors

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

Emera Incorporated – 2023 Annual Information Form 58

EX-99.2

Exhibit 99.2

1

Management’s Discussion & Analysis

As at February 26, 2024

Management’s Discussion & Analysis (“MD&A”) provides a review of the results of operations of Emera

Incorporated and its consolidated subsidiaries and investments (collectively referred to as “Emera” or the

“Company”) during the fourth quarter of, and for the full year of, 2023 relative to the same periods in 2022

and selected financial information for 2021; and its financial position as at December 31, 2023 relative to

December 31, 2022. The Company’s activities are carried out through five reportable segments: Florida

Electric Utility, Canadian Electric Utilities, Gas Utilities and Infrastructure, Other Electric Utilities, and

Other. 

This MD&A should be read in conjunction with the Emera annual audited consolidated financial

statements and supporting notes as at and for the year ended December 31, 2023. Emera follows United

States Generally Accepted Accounting Principles (“USGAAP” or “GAAP”). Additional information related

to Emera, including the Company’s Annual Information Form can be found on Sedar+ at

www.sedarplus.ca.

The accounting policies used by Emera’s rate-regulated entities may differ from those used by Emera’s

non-rate-regulated businesses with respect to the timing of recognition of certain assets, liabilities,

revenues and expenses. At December 31, 2023, Emera’s rate-regulated subsidiaries and investments

include: 

Emera Rate-Regulated Subsidiary or Equity

Investment

Accounting Policies Approved/Examined By

Subsidiary

Tampa Electric Company (“TEC”)

(1)

Florida Public Service Commission (“FPSC”) and the

Federal Energy Regulatory Commission (“FERC”)

Nova Scotia Power Inc. ("NSPI")

Nova Scotia Utility and Review Board (“UARB”) 

Peoples Gas System, Inc. (“PGS”)

(1)

FPSC

New Mexico Gas Company, Inc. (“NMGC”)

New Mexico Public Regulation Commission (“NMPRC”)

SeaCoast Gas Transmission, LLC ("SeaCoast")

FPSC

Emera Brunswick Pipeline Company Limited (“Brunswick

Pipeline”) 

Canadian Energy Regulator ("CER")

Barbados Light & Power Company Limited (“BLPC”) 

Fair Trading Commission, Barbados ("FTC")

Grand Bahama Power Company Limited (“GBPC”) 

The Grand Bahama Port Authority (“GBPA”)

Equity Investments

NSP Maritime Link Inc. (“NSPML”)

UARB

Labrador Island Link Limited Partnership (“LIL”)

Newfoundland and Labrador Board of Commissioners of

Public Utilities

Maritimes & Northeast Pipeline Limited Partnership and

Maritimes & Northeast Pipeline, LLC (“M&NP”)

CER and FERC

St. Lucia Electricity Services Limited (“Lucelec”)

National Utility Regulatory Commission

(1) Effective January 1, 2023, Peoples Gas System ceased to be a division of TEC and the gas utility was reorganized, resulting in a

separate legal entity called Peoples Gas System, Inc., a wholly owned direct subsidiary of TECO Gas Operations, Inc.

All amounts are in Canadian dollars (“CAD”), except for the Florida Electric Utility, Gas Utilities and

Infrastructure, and Other Electric Utilities sections of the MD&A, which are reported in United States

dollars (“USD”) unless otherwise stated.

Exhibit 99.2

2

TABLE OF CONTENTS

Forward-looking Information……………………......

2

Introduction and Strategic Overview………….……

3

Non-GAAP Financial Measures and Ratios….…...

5

Consolidated Financial Review……….………….…

7

  Significant Items Affecting Earnings………........

7

  Consolidated Financial Highlights……………… 

7

  Consolidated Income Statement Highlights……

9

Business Overview and Outlook…………….……..

11

  Florida Electric Utility ………………...............…

12

  Canadian Electric Utilities …..………….……….

13

  Gas Utilities and Infrastructure..…….…….…….

17

  Other Electric Utilities ……………………………

18

  Other……………………………………………….

19

Consolidated Balance Sheet Highlights…………..

20

Other Developments…………………………………

21

Financial Highlights……………………………..…..

21

  Florida Electric Utility …………..........................

21

  Canadian Electric Utilities ……..…………..……

22

  Gas Utilities and Infrastructure……………...…..

25

  Other Electric Utilities …………………………....

27

  Other…………………………………………….….

28

Liquidity and Capital Resources………..…………..

31

  Consolidated Cash Flow Highlights…..…………

32

  Working Capital……………………………………

33

 Contractual Obligations…………………………..

33

 Forecasted Consolidated Capital Investments…

34

 Debt Management………………………………..

34

 Credit Ratings……………………………………..

36

 Guaranteed Debt………………………………….

37

 Outstanding Stock Data………………………….

38

Pension Funding……………………………………..

38

Off-Balance Sheet Arrangements………………….

39

Dividend Payout Ratio……………………………….

40

Transactions with Related Parties….……………...

40

Enterprise Risk and Risk Management……………

41

Risk Management including Financial 

Instruments…………………………………………

54

Disclosure and Internal Controls……….…………..

55

Critical Accounting Estimates….……………………

56

Changes in Accounting Policies and Practices…...

61

  Future Accounting Pronouncements……………

61

Summary of Quarterly Results……........................

62

FORWARD  -LOOKING INFORMATION

This MD&A contains “forward-looking information” (“FLI”) and statements which reflect the current view

with respect to the Company’s expectations regarding future growth, results of operations, performance,

carbon dioxide emissions reduction goals, business prospects and opportunities, and may not be

appropriate for other purposes within the meaning of applicable Canadian securities laws. All such

information and statements are made pursuant to safe harbour provisions contained in applicable

securities legislation. The words “anticipates”, “believes”, “budget”, “could”, “estimates”, “expects”,

“forecast”, “intends”, “may”, “might”, “plans”, “projects”, “schedule”, “should”, “targets”, “will”, “would” and

similar expressions are often intended to identify FLI, although not all FLI contains these identifying

words. The FLI reflects management’s current beliefs and is based on information currently available to

Emera’s management and should not be read as guarantees of future events, performance or results,

and will not necessarily be accurate indications of whether, or the time at which, such events,

performance or results will be achieved. 

Exhibit 99.2

3

The FLI is based on reasonable assumptions and is subject to risks, uncertainties and other factors that

could cause actual results to differ materially from historical results or results anticipated by the FLI.

Factors that could cause results or events to differ from current expectations include, without limitation:

regulatory and political risk; operating and maintenance risks; changes in economic conditions;

commodity price and availability risk; liquidity and capital market risk; changes in credit ratings; future

dividend growth; timing and costs associated with certain capital investments; expected impacts on

Emera of challenges in the global economy; estimated energy consumption rates; maintenance of

adequate insurance coverage; changes in customer energy usage patterns; developments in technology

that could reduce demand for electricity; global climate change; weather risk, including higher frequency

and severity of weather events; risk of wildfires; unanticipated maintenance and other expenditures;

system operating and maintenance risk; derivative financial instruments and hedging; interest rate risk;

inflation risk; counterparty risk; disruption of fuel supply; country risks; supply chain risk; environmental

risks; foreign exchange (“FX”); regulatory and government decisions, including changes to environmental

legislation, financial reporting and tax legislation; risks associated with pension plan performance and

funding requirements; loss of service area; risk of failure of information technology (“IT”) infrastructure and

cybersecurity risks; uncertainties associated with infectious diseases, pandemics and similar public health

threats; market energy sales prices; labour relations; and availability of labour and management

resources. 

Readers are cautioned not to place undue reliance on FLI, as actual results could differ materially from

the plans, expectations, estimates or intentions and statements expressed in the FLI. All FLI in this MD&A

is qualified in its entirety by the above cautionary statements and, except as required by law, Emera

undertakes no obligation to revise or update any FLI as a result of new information, future events or

otherwise.

INTRODUCTION AND STRATEGIC OVERVIEW

Based in Halifax, Nova Scotia, Emera owns and operates cost-of-service rate-regulated electric and gas

utilities in Canada, the United States (“US”) and the Caribbean. Cost-of-service utilities provide essential

electric and gas services in designated territories under franchises and are overseen by regulatory

authorities. Emera’s strategic focus continues to be safely delivering cleaner, affordable and reliable

energy to its customers.

The majority of Emera’s investments in rate-regulated businesses are located in Florida with other

investments in Nova Scotia, New Mexico and the Caribbean. Emera’s portfolio of regulated utilities

provides reliable earnings, cash flow and dividends. Earnings opportunities in regulated utilities are

generally driven by the magnitude of net investment in the utility (known as “rate base”), and the amount

of equity in the capital structure and the return on that equity (“ROE”) as approved through regulation.

Earnings are also affected by sales volumes and operating expenses.

Emera’s capital investment plan is approximately $9 billion over the 2024 through 2026 period with

approximately $2 billion of additional potential capital investments over the same period. The capital

investment plan and additional potential capital result in an anticipated compound annual rate base

growth in the range of approximately 7 per cent to 8 per cent through 2026. The capital investment plan

includes significant investments across the portfolio in renewable and cleaner generation, reliability and

system integrity investments, infrastructure modernization, infrastructure expansion to meet the needs of

new and existing customers, and technologies to better support the business and customer experiences.

It is anticipated that approximately 75 per cent of Emera’s $9 billion capital investment plan over the 2024

through 2026 period will be made in Florida. 

Emera’s capital investment plan is being funded primarily through internally generated cash flows, debt

raised at the operating company level consistent with regulated capital structures, equity, and select asset

sales. Generally, equity requirements in support of the Company’s capital investment plan are expected

to be funded through the issuance of preferred equity and the issuance of common equity through

Emera’s dividend reinvestment plan (“DRIP”) and at-the-market program (“ATM program”). Maintaining

investment-grade credit ratings is a priority of the Company.

Exhibit 99.2

4

Emera has provided annual dividend growth guidance of four to five per cent through 2026. The

Company targets a long-term dividend payout ratio of adjusted net income of 70 to 75 per cent and, while

the payout ratio is likely to exceed that target through and beyond the forecast period, it is expected to

return to that range over time. For further information on the non-GAAP measure “Dividend Payout Ratio

of Adjusted Net Income”, refer to the “Non-GAAP Financial Measures and Ratios” section.

Seasonal patterns and other weather events affect demand and operating costs. Similarly, mark-to-

market (“MTM”) adjustments and foreign currency exchange can have a material impact on financial

results for a specific period. Emera’s consolidated net income and cash flows are impacted by

movements in the USD relative to the CAD. Emera may hedge both transactional and translational

exposure. These impacts, as well as the timing of capital investments and other factors, mean results in

any one quarter are not necessarily indicative of results in any other quarter, or for the year as a whole.

Energy markets worldwide are experiencing significant change and Emera is well-positioned to continue

to respond to shifting customer demands and meet the challenges of digitization, decarbonization and

decentralized generation, within complex regulatory environments.

Customers depend on energy and are looking for more choice, better control, and greater reliability. The

costs of decentralized generation and storage have become more competitive and advancing

technologies are transforming how utilities operate and interact with customers. Concurrently, climate

change and the increased frequency of extreme weather events are shaping government energy policy.

This is also creating a need to replace aging infrastructure and make investments to protect and harden

energy systems to deliver energy reliability and system resiliency. These factors combined with inflation,

higher interest rates and higher cost of capital place increased pressure on energy costs, and thus

customer rates, at a time when affordability is a challenge.

Emera’s strategy is centered on delivering value for customers, and in doing so creating value for

shareholders. This includes:

•

 investing in cleaner and renewable sources of energy, in the related transmission assets, and in

energy storage needed to support intermittent renewables;

•

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

•

 improving system reliability and resiliency, including replacing aging infrastructure and expanding

systems to service new customers; and

•

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

customer experiences. 

Building on its decarbonization progress, Emera is continuing its efforts by establishing clear carbon

reduction goals and a vision to achieve net-zero carbon dioxide emissions by 2050.

This vision is inspired by Emera’s strong track record, the Company’s experienced team, and a visible

path to Emera’s interim carbon goals. With existing technologies and resources, and subject to supportive

government and regulatory decisions, Emera is working to achieve the following goals compared to

corresponding 2005 levels: 

•

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

•

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

•

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

Achieving the above climate goals on these timelines is subject to the Company's regulatory obligations

and other external factors beyond Emera's control.

Emera seeks to deliver on its Climate Commitment while maintaining its focus on investing in reliability

and staying focused on the cost impacts for customers. Emera is also committed to identifying emerging

technologies and continuing to work constructively with policymakers, regulators, partners, investors and

customers to achieve these goals and realize its net-zero vision.

Emera is committed to world-class safety, operational excellence, good governance, excellent customer

service, reliability, being an employer of choice, and building constructive relationships.

Exhibit 99.2

5

NON-GAAP FINANCIAL MEASURES AND RATIOS

Emera uses financial measures and ratios that do not have standardized meaning under USGAAP and

may not be comparable to similar measures presented by other entities. The non-GAAP measures and

ratios are calculated by adjusting certain GAAP measures for specific items. Management believes

excluding these items better distinguishes ongoing operations of the business and allows investors to

better understand and evaluate the business. These measures and ratios are discussed and reconciled

below.

Adjusted Net Income Attributable to Common Shareholders, Adjusted Earnings (Loss) Per

Common Share (“EPS”) – Basic and Dividend Payout Ratio of Adjusted Net Income

Emera calculates an adjusted net income attributable to common shareholders (“adjusted net income”)

measure by excluding the effect of MTM adjustments, the GBPC impairment charge in 2022, and the

impact of the 2022 NSPML unrecoverable costs.

Management believes excluding from net income the effect of MTM valuations and changes thereto, until

settlement, better aligns the intent and financial effect of these contracts with the underlying cash flows,

and therefore excludes MTM adjustments for evaluation of performance and incentive compensation. The

MTM adjustments are related to the following:

●

 held-for-trading (“HFT”) commodity derivative instruments, including adjustments related to the

price differential between the point where natural gas is sourced and where it is delivered, and

the related amortization of transportation capacity recognized as a result of certain Emera Energy

marketing and trading transactions;

●

 the business activities of Bear Swamp Power Company LLC (“Bear Swamp”) included in Emera’s

equity income;

●

 equity securities held in BLPC and Emera Energy; and

●

 FX hedges entered into to hedge USD denominated operating unit earnings exposure.

For further detail on these MTM adjustments, refer to the “Consolidated Financial Review”, “Financial

Highlights – Other Electric Utilities”, and “Financial Highlights – Other” sections.

In Q4 2022, the Company recognized a $73 million non-cash goodwill impairment charge related to

GBPC due to a decline in the fair value (“FV”) of the reporting unit driven by the effects of macro-

economic factors on the discount rate calculation. Management believes excluding from net income the

effect of this charge better distinguishes ongoing operations of the business and allows investors to better

understand and evaluate the Company. For further details on the GBPC impairment charge, refer to

“Significant Items Impacting Earnings”, and “Financial Highlights – Other Electric Utilities” sections.

In February 2022, the UARB issued a decision to disallow recovery of $9 million in costs ($7 million after-

tax) included in NSPML’s final capital cost application. The after-tax unrecoverable costs were recognized

in “Income from equity investments” in Emera’s Consolidated Statements of Income. Management

believes excluding these unrecoverable costs from the calculation of adjusted net income better reflects

the underlying operations in the period. For further details on the 2022 NSPML unrecoverable costs, refer

to the “Financial Highlights – Canadian Electric Utilities” section.

Adjusted EPS – basic and dividend payout ratio of adjusted net income are non-GAAP ratios which are

calculated using adjusted net income, as described above. For further details on dividend payout ratio of

adjusted net income, see the “Dividend Payout Ratio” section.

Emera calculates adjusted net income for the Canadian Electric Utilities, Other Electric Utilities, and Other

segments. Reconciliation to the nearest GAAP measure is included in each segment. Refer to “Financial

Highlights – Canadian Electric Utilities”, “Financial Highlights – Other Electric Utilities” and “Financial

Highlights – Other” sections.

Exhibit 99.2

6

The following reconciles net income attributable to common shareholders to adjusted net income:

Three months ended

Year ended

For the

December 31

December 31

millions of dollars (except per share amounts)

2023

2022

2023

2022

2021

Net income attributable to common shareholders

$

 289

$

 483

$

 978

$

 945

$

 510

MTM gain (loss), after-tax

(1)

 114

 307

 169

 175

 (213)

GBPC impairment charge 

  - 

 (73)

 - 

 (73)

 - 

NSPML unrecoverable costs

(2)

  - 

  - 

  - 

 (7)

 - 

Adjusted net income

$

 175

$

 249

$

 809

$

 850

$

 723

EPS – basic

$

 1.04

$

 1.80

$

 3.57

$

 3.56

$

 1.98

Adjusted EPS – basic

$

 0.63

$

 0.93

$

 2.96

$

 3.20

$

 2.81

(1) Net of income tax expense of $44 million for the three months ended December 31, 2023 (2022 – $124 million expense) and $68

million expense for the year ended December 31, 2023 (2022 – $73 million expense) (2021 – $86 million recovery).

(2) Emera accounts for NSPML as an equity investment and therefore the after-tax unrecoverable costs were recorded in “Income

from equity investments” on Emera’s Consolidated Statements of Income.

EBITDA and Adjusted EBITDA

Earnings before interest, income taxes, depreciation and amortization (“EBITDA”) and adjusted EBITDA

are non-GAAP financial measures used by Emera. These financial measures are used by numerous

investors and lenders to better understand cash flows and credit quality. EBITDA is useful to assess

Emera’s operating performance and indicates the Company’s ability to service or incur debt, invest in

capital, and finance working capital requirements.

Similar to adjusted net income calculations described above, adjusted EBITDA represents EBITDA

absent the income effect of MTM adjustments, the 2022 GBPC impairment charge and the 2022 NSPML

unrecoverable costs.

The following is a reconciliation of net income to EBITDA and Adjusted EBITDA:

Three months ended

Year ended

For the

December 31

December 31

millions of dollars

2023

2022

2023

2022

2021

Net income

(1)

$

 307

$

 499

$

 1,045

$

 1,009

$

 561

Interest expense, net

 241

 206

 925

 709

 611

Income tax expense (recovery)

 51

 154

 128

 185

 (6)

Depreciation and amortization

 264

 254

 1,049

 952

 902

EBITDA

$

 863

$

 1,113

$

 3,147

$

 2,855

$

 2,068

MTM gain (loss), before-tax

 158

 431

 237

 248

 (299)

GBPC impairment charge

 - 

 (73)

 - 

 (73)

 - 

NSPML unrecoverable costs

(2)

 - 

 - 

 - 

 (7)

 - 

Adjusted EBITDA

$

 705

$

 755

$

 2,910

$

 2,687

$

 2,367

(1) Net income is before Non-controlling interest in subsidiaries and Preferred stock dividends.

(2) Emera accounts for NSPML as an equity investment and therefore the after-tax unrecoverable costs were recorded in “Income

from equity investments” on Emera’s Consolidated Statements of Income.

Exhibit 99.2

7

CONSOLIDATED FINANCIAL REVIEW

Significant Items Affecting Earnings

2023

Earnings Impact of MTM Gain, After-Tax

MTM gain, after-tax decreased $193 million to $114 million in Q4 2023, compared to $307 million in Q4

2022 primarily due to unfavourable changes in existing positions, partially offset by higher amortization of

gas transportation assets in 2022 at Emera Energy Services (“EES”). For the year ended December 31,

2023, MTM gain, after-tax decreased $6 million to $169 million compared to $175 million for the same

period in 2022 primarily due to higher amortization of gas transportation assets at EES, partially offset by

favourable changes in existing positions at EES and gains on Corporate FX hedges. 

2022

GBPC Impairment Charge

In Q4 2022, Emera recognized a goodwill impairment charge of $73 million ($0.27 per common share) for

GBPC due to a decline in the FV of the reporting unit driven by the effects of macro-economic factors on

discount rate calculations. This non-cash charge was recorded in “GBPC Impairment charge” on the

Consolidated Statements of Income and reduced the GBPC goodwill balance to nil. For further details,

refer to note 22 in the consolidated financial statements.

TECO Guatemala Holdings (“TGH”) International Arbitration and Award

In Q4 2022, a payment of $63 million ($45 million after tax and legal costs, or $0.17 per common share),

was made by the Republic of Guatemala to TECO Energy in satisfaction of the second and final award

issued by the International Centre of the Settlement of Investment Disputes tribunal regarding a dispute

over an investment of TGH, a wholly owned subsidiary of TECO Energy. The payment was recognized in

‘Other income, net” on the Consolidated Statements of Income. For further details, refer to note 8 in the

consolidated financial statements.

Consolidated Financial Highlights

For the

Three months ended

Year ended

millions of dollars 

December 31

December 31

Adjusted net income

2023

2022

2023

2022

2021

Florida Electric Utility

$

 115

$

 124

$

 627

$

 596

$

 462

Canadian Electric Utilities

 68

 46

 247

 222

 241

Gas Utilities and Infrastructure

 59

 72

 214

 221

 198

Other Electric Utilities

 4

 8

 35

 29

 20

Other

 (71)

 (1)

 (314)

 (218)

 (198)

Adjusted net income

$

 175

$

 249

$

 809

$

 850

$

 723

MTM gain (loss), after-tax

 114

 307

 169

 175

 (213)

GBPC impairment charge

 - 

 (73)

 - 

 (73)

 - 

NSPML unrecoverable costs

 - 

 - 

 - 

 (7)

 - 

Net income attributable to common shareholders

$

 289

$

 483

$

 978

$

 945

$

 510

Exhibit 99.2

8

The following table highlights the significant changes in adjusted net income from 2022 to 2023:

For the

Three months ended

Year ended

millions of dollars

December 31

December 31

Adjusted net income – 2022

$

 249

$

 850

Operating Unit Performance

Increased earnings at NSPI due to new base rates and increased sales

volumes, partially offset by higher operating, maintenance and general

expenses ("OM&G"), interest expense and depreciation

 17

 10

Increased income from equity investments at NSPML quarter-over-

quarter primarily due to the Maritime Link holdback (the "holdback")

recognized in Q4 2022. Year-over-year also due to the partial reversal in

Q3 2023 of the holdback recognized in 2022

 4

 10

Decreased earnings quarter-over-quarter at TEC due to increased

interest expense, depreciation, state and municipal taxes, unfavourable

weather, and higher OM&G, partially offset by new base rates and

customer growth driving higher sales volumes. Increased earnings year-

over-year due to new base rates, the impact of a weaker CAD and

customer growth, partially offset by higher interest expense,

depreciation, state and municipal taxes, and OM&G, and unfavourable

weather

 (9)

 31

Decreased earnings quarter-over-quarter at NMGC primarily due to

lower asset optimization revenues and higher OM&G, partially offset by

new base rates. Increased earnings year-over-year due to new base

rates, partially offset by higher OM&G and interest expense

 (11)

 12

Decreased earnings at EES due to more favourable market conditions in

2022

 (21)

 (22)

Corporate

Decreased OM&G, pre-tax, due to timing of long-term compensation

and related hedges

 13

 10

Increased interest expense, pre-tax, due to higher interest rates and

higher debt levels

 (9)

 (51)

Decreased income tax recovery quarter-over-quarter primarily due to the

impact of effective state tax rates

 (10)

 2

TGH award, after tax and legal costs, in Q4 2022. Refer to the

"Significant Items Affecting Earnings" section

 (45)

 (45)

Other Variances

 (3)

 2

Adjusted net income – 2023

$

 175

$

 809

For further details of reportable segments contributions, refer to the "Financial Highlights" section.

For the

Year ended December 31

millions of dollars

2023

2022

2021

Operating cash flow before changes in working capital

$

 2,336

$

 1,147

$

 1,337

Change in working capital

 (95)

 (234)

 (152)

Operating cash flow

$

 2,241

$

 913

$

 1,185

Investing cash flow

$

 (2,917)

$

 (2,569)

$

 (2,332)

Financing cash flow

$

 939

$

 1,555

$

 1,311

For further discussion of cash flow, refer to the "Consolidated Cash Flow Highlights" section.

As at 

December 31

millions of dollars

2023

2022

2021

Total assets

$

 39,480

$

 39,742

$

 34,244

Total long-term debt (including current portion)

$

 18,365

$

 16,318

$

 14,658

Exhibit 99.2

9

Consolidated Income Statement Highlights

For the 

Three months ended

Year ended

Year ended

millions of dollars

December 31

December 31

December 31

(except per share amounts)

2023

2022

Variance

2023

2022

Variance

2021

Operating revenues

$

 1,972

$

 2,358

$

 (386)

$

 7,563

$

 7,588

$

 (25)

$

 5,765

Operating expenses

 1,467

 1,638

 171

 5,769

 5,959

 190

 4,835

Income from operations

$

 505

$

 720

$

 (215)

$

 1,794

$

 1,629

$

 165

$

 930

Other income, net

$

 51

$

 102

$

 (51)

$

 158

$

 145

$

 13

$

 93

Interest expense, net

$

 241

$

 206

$

 (35)

$

 925

$

 709

$

 (216)

$

 611

Net income attributable to

common shareholders

$

 289

$

 483

$

 (194)

$

 978

$

 945

$

 33

$

 510

Adjusted net income

$

 175

$

 249

$

 (74)

$

 809

$

 850

$

 (41)

$

 723

Weighted average shares of

common stock outstanding 

(in millions)

(1)

 277.7

 269.0

 8.7

 273.6

 265.5

 8.1

 257.2

EPS – basic

$

 1.04

$

 1.80

$

(0.76)

$

 3.57

$

 3.56

$

0.01

$

 1.98

EPS – diluted

$

 1.04

$

 1.80

$

(0.76)

$

 3.57

$

 3.55

$

0.02

$

 1.98

Adjusted EPS – basic

$

 0.63

$

 0.93

$

(0.30)

$

 2.96

$

 3.20

$

(0.24)

$

 2.81

Adjusted EBITDA

$

 705

$

 755

$

 (50)

$

 2,910

$

 2,687

$

 223

$

 2,367

Dividends per common share

declared

$

 0.7175

$

 0.6900

$

 0.0275

$

 2.7875

$

 2.6775

$

 0.1100

$

 2.5750

Dividends per first preferred shares declared:

 Series A

$

 0.5456

$

 0.5456

$

 - 

$

 0.5456

 Series B

$

 1.5583

$

 0.6869

$

 0.8714

$

 0.4873

 Series C

$

 1.2873

$

 1.1802

$

 0.1071

$

 1.1802

 Series E

$

 1.1250

$

 1.1250

$

 - 

$

 1.1250

 Series F

$

 1.0505

$

 1.0505

$

-

$

 1.0505

 Series H

$

 1.3140

$

 1.2250

$

 0.0890

$

 1.2250

 Series J

$

 1.0625

$

 1.0625

$

 - 

$

 0.6470

 Series L

$

 1.1500

$

 1.1500

$

 - 

$

 0.1638

(1) Effective February 10, 2022, deferred share units are no longer able to be settled in shares and are therefore excluded from

weighted average shares of common stock outstanding.

Operating Revenues

For Q4 2023, operating revenues decreased $386 million compared to Q4 2022 and, excluding

decreased MTM gains of $286 million, decreased $100 million. The decrease was due to lower fuel

revenues at NMGC, TEC, and NSPI; decreased marketing and trading margin at EES; lower asset

optimization revenue at NMGC; and unfavourable weather at TEC. These decreases were partially offset

by new base rates at TEC, NSPI and NMGC; storm cost recovery surcharge revenue at TEC; customer

growth at TEC and NSPI; and favourable weather at NSPI.

For the year ended December 31, 2023, operating revenues decreased $25 million compared to 2022

and, excluding decreased MTM gains of $62 million, increased $37 million. The increase was due to new

base rates at TEC, NSPI and NMGC; the impact of a weaker CAD; storm cost recovery surcharge

revenue at TEC; and customer growth at TEC and NSPI. These increases were partially offset by lower

fuel revenues at NMGC, TEC, NSPI, PGS and BLPC; lower off-system sales at PGS; a change in fuel

cost recovery methodology for an industrial customer at NSPI; and decreased marketing and trading

margin at EES.

Exhibit 99.2

10

Operating Expenses

For Q4 2023, operating expenses decreased $171 million compared to Q4 2022 and excluding the 2022

GBPC impairment charge of $73 million, decreased $98 million. For the year ended December 31, 2023,

operating expenses decreased $190 million compared to 2022 and excluding the 2022 GBPC impairment

charge of $73 million, decreased $117 million. The decreases in both periods were due to lower fuel

expenses at TEC, NMGC, and PGS; partially offset by higher OM&G at TEC due to storm restoration

costs recognized related to the storm cost recovery surcharge revenue, and at NSPI due to higher power

generation and transmission and distribution field services cost. Year-over-year the decrease was also

due to a change in fuel cost recovery for an industrial customer at NSPI, partially offset by the impact of a

weaker CAD and the recognition of the Nova Scotia Renewable Electricity Regulations (“RER”) penalty at

NSPI. 

Other Income, net

For Q4 2023, other income, net decreased $51 million compared to Q4 2022, primarily due to the TGH

award in Q4 2022. For the year ended December 31, 2023, other income, net increased $13 million

compared to 2022, primarily due to increased FX gains in 2023; higher interest income primarily at TEC;

and higher pension non-current service cost recovery, partially offset by the TGH award in 2022.

Interest Expense, net

Interest expense, net for Q4 2023 increased $35 million, and for the year ended December 31, 2023

increased $216 million compared to the same periods in 2022. The increases in both periods were due to

higher interest rates; higher borrowings to support capital investments and ongoing operations; and the

impact of a weaker CAD.

Net Income and Adjusted Net Income

Net income attributable to common shareholders for Q4 2023, compared to Q4 2022, was unfavourably

impacted by the $193 million decrease in MTM gains, after-tax, and favourably impacted by the $73

million GBPC impairment charge from 2022. Excluding these changes, adjusted net income decreased

$74 million. This was primarily due to the TGH award in Q4 2022; decreased earnings at EES, NMGC

and TEC; lower Corporate income tax recovery; and increased Corporate interest expense. These were

partially offset by increased earnings at NSPI and NSPML; and decreased Corporate OM&G due to the

timing of long-term compensation and related hedges.

Net income attributable to common shareholders for the year ended 2023, as compared to the same

period in 2022, was unfavourably impacted by the $6 million decrease in MTM gains, after-tax, and

favourably impacted by the $73 million GBPC impairment charge and the $7 million in NSPML

unrecoverable costs from 2022. Excluding these changes, adjusted net income decreased $41 million.

The decrease was primarily due to increased Corporate interest expense due to higher interest rates and

increased total debt; the TGH award in Q4 2022; and decreased earnings at EES. These were partially

offset by increased earnings at TEC, NMGC, NSPI and NSPML.

EPS and Adjusted EPS – Basic

EPS and Adjusted EPS – basic were lower for Q4

2023 due to the increase in weighted average shares

of common stock outstanding and decreased earnings as discussed above.

EPS – basic was higher for the year ended December 31, 2023, due to the impact of higher earnings as

discussed above. Adjusted EPS – basic was lower for the year ended December 31, 2023 due to the

increase in weighted average shares of common stock outstanding and decreased adjusted earnings, as

discussed above.

Exhibit 99.2

11

Effect of Foreign Currency Translation

Emera operates in Canada, the United States and various Caribbean countries and, as such, generates

revenues and incurs expenses denominated in local currencies which are translated into CAD for

financial reporting. Changes in translation rates, particularly in the value of the USD against the CAD, can

positively or adversely affect results.

Results of foreign operations are translated at the weighted average rate of exchange, and assets and

liabilities of foreign operations are translated at period end rates.

The relevant CAD/USD exchange rates

for 2023 and 2022 are as follows:

Three months ended 

Year ended

December 31

December 31

2023

2022

2023

2022

Weighted average CAD/USD 

$

1.36

$

1.37

$

1.35

$

1.34

Period end CAD/USD exchange rate

$

1.32

$

1.35

$

1.32

$

1.35

The table below includes Emera’s significant segments whose contributions to adjusted net income are

recorded in USD currency:

Three months ended

Year ended

For the 

December 31

December 31

millions of USD

2023

2022

2023

2022

Florida Electric Utility

$

85

$

91

$

466

$

458

Gas Utilities and Infrastructure

  (1)

41

45

142

143

Other Electric Utilities

3

7

26

23

Other segment

(2)

(18)

30

(95)

(50)

Total

(3)

$

111

$

173

$

539

$

574

(1) Includes USD net income from PGS, NMGC, SeaCoast and M&NP.

(2) Includes Emera Energy's USD adjusted net income from EES, Bear Swamp and interest expense on Emera Inc.'s USD

denominated debt.

(3) Excludes $73 million USD in MTM gain, after-tax, for the three months ended December 31, 2023 (2022 – $222 million USD

MTM gain, after-tax) and MTM gain, after-tax of $116 million USD for the year ended December 31, 2023 (2022 – $130 million USD

MTM gain, after-tax) and the GBPC impairment charge of nil for the three months and year ended December 31, 2023 (2022 – $54

million USD).

The translation impact of the change in FX rates on foreign denominated earnings increased net income

by $13 million in Q4 2023 and $46 million for the year ended December 31, 2023, compared to the same

periods in 2022. The translation impact of the change in FX rates on foreign denominated earnings

decreased adjusted net income by $3 million in Q4 2023 and increased adjusted net income by $20

million for the year ended December 31, 2023 compared to the same periods in 2022. Impacts of the

changes in the translation of the CAD include the impacts of Corporate FX hedges used to mitigate

translation risk of USD earnings in the Other segment.

BUSINESS OVERVIEW AND OUTLOOK

Emera’s 2023 results were impacted by macroeconomic conditions, specifically higher interest rates as

well as other impacts of inflation. These macroeconomic conditions are likely to continue for the near

term. For information on general economic risk, including interest rate and inflation risk, refer to the

“Enterprise Risk and Risk Management – General Economic Risk” section.

Exhibit 99.2

12

Florida Electric Utility

Florida Electric Utility consists of TEC, a vertically integrated regulated electric utility engaged in the

generation, transmission and distribution of electricity, serving customers in West Central Florida. TEC

has $12 billion USD of assets and approximately 840,000 customers at December 31, 2023. TEC owns

6,433 megawatts (“MW”) of generating capacity, of which 74 per cent is natural gas fired, 19 per cent is

solar and 7 per cent is coal. TEC owns 2,192 kilometres of transmission facilities and 20,299 kilometres of

distribution facilities. TEC meets the planning criteria for reserve capacity established by the FPSC, which

is a 20 per cent reserve margin over firm peak demand.

TEC’s approved regulated ROE range is 9.25 per cent to 11.25 per cent, based on an allowed equity

capital structure of 54 per cent. An ROE of 10.20 per cent is used for the calculation of the return on

investments for clauses.

TEC anticipates earning towards the lower end of the ROE range in 2024 but expects earnings to be

higher than 2023. Normalizing 2023 for weather, TEC sales volumes in 2024 are projected to be higher

than 2023 due to customer growth. TEC expects customer growth rates in 2024 to be comparable to

2023, reflective of the expected economic growth in Florida. 

On February 1, 2024, TEC notified the FPSC of its intent to seek a base rate increase effective January

2025, reflecting a revenue requirement increase of approximately $290 to $320 million USD and

additional adjustments of approximately $100 million USD and $70 million USD for 2026 and 2027,

respectively. TEC’s proposed rates include recovery of solar generation projects, energy storage

capacity, a more resilient and modernized energy control center, and numerous other resiliency and

reliability projects. The filing range amounts are estimates until TEC files its detailed case in April 2024.

The FPSC is scheduled to hear the case in Q3 2024 with a decision expected by the end of 2024.

On August 16, 2023, TEC filed a petition to implement the 2024 Generation Base Rate Adjustment

provisions pursuant to the 2021 rate case settlement agreement. Inclusive of TEC’s ROE adjustment, the

increase of $22 million USD was approved by the FPSC on November 17, 2023.

On January 23, 2023, TEC petitioned the FPSC for recovery of the storm reserve regulatory asset and

the replenishment of the balance in the storm reserve to the approved storm reserve level of $56 million

USD, for a total of $131 million USD.

The storm cost recovery surcharge was approved by the FPSC on

March 7, 2023, and TEC began applying the surcharge in April 2023. Subsequently, on November 9,

2023, the FPSC approved TEC’s petition, filed on August 16, 2023, to update the total storm cost

collection to $134 million USD. It also changed the collection of the expected remaining balance of $29

million USD as of December 31, 2023, from over the first three months of 2024 to over the 12 months of

2024. The storm recovery is subject to review of the underlying costs for prudency and accuracy by the

FPSC and issuance of an order by the FPSC is expected by Q3 2024.

In Q3 2023, TEC was impacted by Hurricane Idalia. The related storm restoration costs were

approximately $35 million USD, which were charged to the storm reserve regulatory asset, resulting in

minimal impact to earnings. TEC will determine the timing of the request for recovery of Hurricane Idalia

costs at a future time.

On January 23, 2023, TEC requested an adjustment to its fuel charges to recover the 2022 fuel under-

recovery of $518 million USD over a period of 21 months. The request also included an adjustment to

2023 projected fuel costs to reflect the reduction in natural gas prices since September 2022 for a

projected reduction of $170 million USD for the balance of 2023. The changes were approved by the

FPSC on March 7, 2023, and were effective beginning on April 1, 2023. 

In 2024, capital investment in the Florida Electric Utility segment is expected to be $1.3 billion USD (2023

– $1.3 billion USD), including allowance for funds used during construction (“AFUDC”). Capital projects

include solar investments, grid modernization, storm hardening investments and building resilience. 

Exhibit 99.2

13

Canadian Electric Utilities

Canadian Electric Utilities includes NSPI and ENL. NSPI is a vertically integrated regulated electric utility

engaged in the generation, transmission and distribution of electricity and the primary electricity supplier

to customers in Nova Scotia. ENL is a holding company with equity investments in NSPML and LIL: two

transmission investments related to the development of an 824 MW hydroelectric generating facility at

Muskrat Falls on the Lower Churchill River in Labrador. 

NSPI

With $7.2 billion of assets and approximately 549,000 customers, NSPI owns 2,422 MW of generating

capacity, of which 44 per cent is coal and/or oil-fired; 28 per cent is natural gas and/or oil; 19 per cent is

hydro, wind, or solar; 7 per cent is petroleum coke (“petcoke”) and 2 per cent is biomass-fueled

generation. In addition, NSPI has contracts to purchase renewable energy from independent power

producers (“IPPs”) and community feed-in tariff (“COMFIT") participants, which own 532 MW of capacity.

NSPI also has rights to 153 MW of Maritime Link capacity, representing Nalcor Energy’s (“Nalcor”) Nova

Scotia Block (“NS Block”) delivery obligations, as discussed below. NSPI owns approximately 5,000

kilometres of transmission facilities and 28,000 kilometres of distribution facilities.

Nalcor is obligated to provide NSPI with approximately 900 Gigawatt hours (“GWh”) of energy annually

over 35 years. In addition, for the first five years of the NS Block, Nalcor is obligated to provide

approximately 240 GWh of additional energy from the Supplemental Energy Block transmitted through

the Maritime Link. NSPI has the option of purchasing additional market-priced energy from Nalcor through

the Energy Access Agreement. The Energy Access Agreement enables NSPI to access a market-priced

bid from Nalcor for up to 1.8 Terawatt hours (“TWh”) of energy in any given year and, on average, 1.2

TWh of energy per year through August 31, 2041. 

NSPI’s approved regulated ROE range is 8.75 per cent to 9.25 per cent, based on an actual five-quarter

average regulated common equity component of up to 40 per cent of approved rate base. 

NSPI expects earnings and sales volumes to be higher in 2024 than 2023 but anticipates earning below

its allowed ROE range in 2024. 

On January 29, 2024, NSPI applied to the UARB for approval of a structure that would begin to recover

the outstanding Fuel Adjustment Mechanism (“FAM”) balance. As part of the application, NSPI requested

approval for the sale of $117 million of the FAM regulatory asset to Invest Nova Scotia, a provincial

Crown corporation, with the proceeds paid to NSPI upon approval. NSPI has requested approval to

collect from customers the amortization and financing costs of $117 million on behalf of Invest Nova

Scotia over a 10-year period, and remit those amounts to Invest Nova Scotia as collected, reducing short-

term customer rate increases relative to the currently established FAM process. If approved, this portion

of the FAM regulatory asset would be removed from the Consolidated Balance Sheets and NSPI would

collect the balance on behalf of Invest Nova Scotia in NSPI rates beginning in 2024. A decision is

expected in the first half of 2024. It is anticipated that NSPI will apply to the UARB later in 2024 to collect

additional under-recovered fuel amounts in 2025 or future periods, subject to the approval of the UARB.

On October 31, 2023, NSPI submitted an application to the UARB to defer $24 million in incremental

operating costs incurred during Hurricane Fiona storm restoration efforts in September 2022. NSPI is

seeking amortization of the costs over a period to be approved by the UARB during a future rate setting

process. At December 31, 2023, the $24 million is deferred to “Other long-term assets”, pending UARB

approval. A decision is expected from the UARB in 2024.

Exhibit 99.2

14

On September 16, 2023, Nova Scotia was struck by post-tropical storm Lee and as a result,

approximately 280,000 customers lost power. The total cost of storm restoration was $19 million, with $9

million charged to “OM&G”, $5 million capitalized to property, plant and equipment (“PP&E) and $5 million

deferred to the UARB approved storm rider. The storm rider, for each of 2023, 2024, and 2025, allows

NSPI to apply to the UARB for deferral and recovery of expenses if major storm restoration expenses

exceed approximately $10 million in any given year. The application for deferral of the storm rider is made

in the year following the year of the incurred costs, with recovery beginning in the year after the

application. 

On February 2, 2023, the UARB approved the General Rate Application settlement agreement between

NSPI, key customer representatives and participating interest groups. This resulted in average customer

rate increases of 6.9 per cent effective on February 2, 2023, and a further average increase of 6.5 per

cent on January 1, 2024, with any under or over-recovery of fuel costs addressed through the UARB’s

established FAM process. It also established a storm rider, described above, and a demand-side

management rider. On March 27, 2023, the UARB issued a final order approving the electricity rates

effective on February 2, 2023.

In 2024, capital investment, including AFUDC, is expected to be $435 million (2023 – $451 million). NSPI

is primarily investing in capital projects required to support power system reliability and reliable service for

customers. 

Environmental Legislation and Regulations

NSPI is subject to environmental laws and regulations set by both the Government of Canada and the

Province of Nova Scotia (the “Province”). NSPI continues to work with both levels of government to

comply with these laws and regulations to maximize efficiency of emission control measures and

minimize customer cost. NSPI anticipates that costs prudently incurred to achieve legislated compliance

will be recoverable under NSPI’s regulatory framework. NSPI faces risks associated with achieving

climate-related and environmental legislative requirements, including the risk of non-compliance, which

could adversely affect NSPI’s operations and financial performance. For further discussion on these risks

and environmental legislation and regulations, refer to the “Enterprise Risk and Risk Management”

section. Recent developments related to provincial and federal environmental laws and regulations are

outlined below.

Clean Electricity Solutions Task Force:

The Clean Electricity Solutions Task Force (the “Task Force”) was created by the Province in April 2023

to advise the provincial government on Nova Scotia’s transition away from coal to more renewable

sources of energy. On February 23, 2024, the Task Force released its report and recommendations,

based on engagement with stakeholders, including NSPI. The Task Force report focuses on findings

related to system operations, regulatory oversight, reliability, transmission and affordability. The Task

Force announced a number of recommendations, including a strengthening of the authority and

independence of the regulator and the establishment of an independent system operator, in order to

support the continuing transition to clean energy and the achievement of federal and provincial clean

energy goals and legislation. The Province announced they intend to accept these recommendations and

will table enabling legislation in its upcoming session which starts February 27, 2024.

RER:

On April 6, 2023, the Province levied a $10 million penalty on NSPI for non-compliance with the RER

compliance period ending in 2022. The penalty was recorded in “OM&G” on the Consolidated Statements

of Income. On May 26, 2023, NSPI initiated an appeal of the penalty through a proceeding with the

UARB, as permitted under the RER. On October 12, 2023, the UARB decided that it will hear the appeal

by giving due deference to the Province’s decision but permitting the filing of new evidence to support the

parties’ positions. The hearing for the matter is scheduled for June 2024 and a decision is expected

before the end of 2024.

Exhibit 99.2

15

Carbon Pricing Regulations:

In November 2022, the Province enacted amendments to the Environment Act which provided the

framework for Nova Scotia to implement an output-based pricing system (“OBPS”) to comply with the

Government of Canada’s 2023 through 2030 carbon pollution pricing regulations effective January 1,

2023. The Government of Canada approved the Province’s proposed system, however the OBPS will be

subject to an interim review by the Government of Canada of the standards effective for 2026. The final

Output-Based Pricing System Reporting and Compliance Regulations were prescribed by Order in

Council dated January 30, 2024. The OBPS implements greenhouse gas (“GHG”) emissions

performance standards for large industrial GHG emitters that vary by fuel type. GHG emissions in excess

of the prescribed intensity standards will be subject to a carbon price that starts at $65 per tonne in 2023

and will increase by $15 per tonne annually, reaching $170 per tonne by 2030. NSPI’s regulatory

framework provides for the recovery of costs prudently incurred to comply with carbon pricing programs

pursuant to NSPI’s FAM.

Nova Scotia Cap-and-Trade Program Regulations:

NSPI was a participant in the Nova Scotia Cap-and-Trade Program and was subject to the 2019 through

2022 compliance period. On March 16, 2023, the Province provided NSPI with emissions allowances

sufficient to achieve compliance for the 2019 through 2022 compliance period. As such, compliance costs

accrued of $166 million were reversed in Q1 2023. The credits NSPI purchased from provincial auctions

in the amount of $6 million were not refunded and no further costs were incurred to achieve compliance

with the Nova Scotia Cap-and-Trade Program.

Other Legislation

Electricity Act Amendment:

On November 9, 2023, the Province enacted amendments in the Electricity Act which permit the

Governor in Council to approve energy storage projects proposed by a public utility and owned wholly or

in majority by the public utility if the project is in the best interest of ratepayers. Further, the amendments

to the Electricity Act expand the ability of the Province to require NSPI to enter into power purchase

agreements with renewable generation facilities by further empowering the Province to require NSPI to

enter into an agreement for the sale of the electricity to specified customers. This allows specified

customers to buy renewable electricity from specified producers, with NSPI managing the transmission

and sale of the energy. On December 21, 2023, the Governor in Council enacted regulations which

directed NSPI to install three 50 MW four-hour duration grid-scale batteries as part of the regulated

assets of NSPI.

Performance Standards Penalty Amendment:

On April 12, 2023, the Province enacted amendments to the Public Utilities Act which increased the

cumulative total of administrative penalties that could be levied by the UARB against NSPI for non-

compliance with current and future performance standards in a calendar year from $1 million to $25

million. Any administrative penalties levied against NSPI must be credited to customers and NSPI cannot

recover administrative penalties imposed through rates.

Exhibit 99.2

16

ENL

Total equity earnings from NSPML and LIL are expected to be higher in 2024, compared to 2023 resulting

from an increased investment in LIL planned for 2024. Both the NSPML and LIL investments are

recorded as “Investments subject to significant influence” on Emera’s Consolidated Balance Sheets.

NSPML

Equity earnings from the Maritime Link are dependent on the approved ROE and operational

performance of NSPML. NSPML’s approved regulated ROE range is 8.75 per cent to 9.25 per cent,

based on an actual five-quarter average regulated common equity component of up to 30 per cent.

The Maritime Link assets entered service on January 15, 2018, enabling the transmission of energy

between Newfoundland and Nova Scotia, improved reliability and ancillary benefits, supporting the

efficiency and reliability of energy in both provinces. Nalcor’s NS Block delivery obligations commenced

on August 15, 2021, and the NS Block will be delivered over the next 35 years pursuant to the project

agreements. 

On December 21, 2023, NSPML received approval to collect up to $164 million from NSPI for the

recovery of costs associated with the Maritime Link in 2024; subject to a holdback of $4 million per month,

as discussed below. 

On October 4, 2023 and January 31, 2024, the UARB issued decisions providing clarification on

remaining aspects of the Maritime Link holdback mechanism primarily relating to release of past and

future holdback amounts and requirements to end the holdback mechanism. In these decisions, the

UARB agreed with the Company’s submission that $12 million ($8 million related to 2022 and $4 million

relating to 2023) of the previously recorded holdback remain credited to NSPI’s FAM, with the remainder

released to NSPML and recorded in Emera’s “Income from equity investments. NSPML did not record

any additional holdback in Q4 2023. The UARB also confirmed that the holdback mechanism will cease

once 90 per cent of NS Block deliveries are achieved for 12 consecutive months (subject to potential

relief for planned outages or exceptional circumstances) and the net outstanding balance of previously

underdelivered NS Block energy is less than 10 per cent of the contracted annual amount. In addition, the

UARB increased the monthly holdback amount from $2 million to $4 million beginning December 1, 2023.

NSPML expects to file an application to terminate the holdback mechanism in 2024. 

NSPML does not anticipate any significant capital investment in 2024.

LIL

ENL is a limited partner with Nalcor in LIL. Construction of the LIL is complete and the Newfoundland

Electrical System Operator confirmed the asset to be operating suitably to support reliable system

operation and full functionality at 700MW, which was validated by the Government of Canada’s

Independent Engineer issuing its Commissioning Certificate on April 13, 2023.

Upon issuance of the Commissioning Certificate, AFUDC equity earnings ceased and cash equity

earnings and return of equity to Emera commenced. The first distribution was received from the LIL

partnership in Q4 2023.

Equity earnings from the LIL investment are based upon the book value of the equity investment and the

approved ROE. Emera’s current equity investment is $747 million, comprised of $410 million in equity

contribution and $337 million of accumulated equity earnings. Emera’s total equity contribution in the LIL,

excluding accumulated equity earnings, is estimated to be approximately $650 million once the final

costing has been confirmed by Nalcor to determine the amount of the remaining investment.

Exhibit 99.2

17

Gas Utilities and Infrastructure

Gas Utilities and Infrastructure includes PGS, NMGC, SeaCoast, Brunswick Pipeline and Emera’s equity

investment in M&NP. PGS is a regulated gas distribution utility engaged in the purchase, distribution and

sale of natural gas serving customers in Florida. NMGC is an intrastate regulated gas distribution utility

engaged in the purchase, transmission, distribution and sale of natural gas serving customers in New

Mexico. SeaCoast is a regulated intrastate natural gas transmission company offering services in Florida.

Brunswick Pipeline is a regulated 145-kilometre pipeline delivering re-gasified liquefied natural gas from

Saint John, New Brunswick, to markets in the northeastern United States.

Peoples Gas System

With $2.8 billion USD of assets and approximately 490,000 customers, the PGS system includes 24,300

kilometres of natural gas mains and 13,500 kilometres of service lines. Natural gas throughput (the

amount of gas delivered to its customers, including transportation-only service) was 2 billion therms in

2023. 

Beginning in 2024, the approved ROE range for PGS is 9.15 per cent to 11.15 per cent (2023 – 8.9 per

cent to 11.0 per cent), based on an allowed equity capital structure of 54.7 per cent (2023 – 54.7 per

cent). An ROE of 10.15 per cent (2023 – 9.9 per cent) is used for the calculation of return on investments

for clauses.

New Mexico Gas Company, Inc.

With $1.8 billion USD of assets and approximately 540,000 customers, NMGC’s system includes

approximately 2,408 kilometres of transmission pipelines and 17,657 kilometres of distribution pipelines.

Annual natural gas throughput was approximately 1 billion therms in 2023.

The approved ROE for NMGC is 9.375 per cent, on an allowed equity capital structure of 52 per cent. 

Gas Utilities and Infrastructure Outlook

Gas Utilities and Infrastructure USD earnings are anticipated to be higher in 2024 than 2023, primarily

due to a base rate increase effective January 2024 at PGS and an expected base rate increase effective

Q4 2024 at NMGC, partially offset by lower asset optimization revenues expected at NMGC. 

PGS expects rate base to be higher than in 2023 and anticipates earning within its allowed ROE range in

2024. USD earnings for 2024 are expected to be to be significantly higher than in 2023 primarily due to

higher revenue from new base rates in support of significant ongoing system investment and continued

customer growth in 2024, which is expected to be consistent with Florida’s population growth rates.

On April 4, 2023, PGS filed a rate case with the FPSC and a hearing for the matter was held in

September 2023. On November 9, 2023, the FPSC approved a $118 million USD increase to base

revenues which includes $11 million USD transferred from the cast iron and bare steel replacement rider,

for a net incremental increase to base revenues of $107 million USD. This reflects a 10.15 per cent

midpoint ROE with an allowed equity capital structure of 54.7 per cent. A final order was issued on

December 27, 2023, with the new rates effective January 2024. 

The 2020 PGS rate case settlement provided the ability to reverse a total of $34 million USD of

accumulated depreciation through 2023. PGS reversed $20 million USD of accumulated depreciation in

2023 and $14 million USD in 2022.

Exhibit 99.2

18

NMGC expects 2024 rate base growth to be consistent with 2023, with slightly lower USD earnings as a

result of lower asset optimization revenues, partially offset by higher revenue from expected new base

rates, effective Q4 2024. NMGC anticipates earning near its authorized ROE in 2024. Customer growth

rates are expected to be consistent with historical trends. 

On September 14, 2023, NMGC filed a rate case with the NMPRC for new base rates to become effective

Q4 2024. NMGC requested a $49 million USD increase in annual base revenues primarily as a result of

increased operating costs and capital investments in pipeline projects and related infrastructure. The rate

case includes a requested ROE of 10.5 per cent. A final order from the NMPRC is expected in Q3 2024.

In 2024, capital investment in the Gas Utilities and Infrastructure segment is expected to be

approximately $465 million USD (2023 – $495 million USD), including AFUDC. PGS and NMGC will make

investments to maintain the reliability of their systems and support customer growth. 

Other Electric Utilities

Other Electric Utilities includes Emera (Caribbean) Incorporated (“ECI”), a holding company with

regulated electric utilities. ECI’s regulated utilities include vertically integrated regulated electric utilities of

BLPC on the island of Barbados, GBPC on Grand Bahama Island, and an equity investment in Lucelec

on the island of St. Lucia.

BLPC

With $517 million USD of assets and approximately 134,000 customers, BLPC owns 243 MW of

generating capacity, of which 96 per cent is oil-fired and four per cent is solar. BLPC owns approximately

188 kilometres of transmission facilities and 3,839 kilometres of distribution facilities. BLPC’s approved

regulated return on rate base for 2023 was 10 per cent.

GBPC

With $334 million USD of assets and approximately 19,000 customers, GBPC owns 98 MW of oil-fired

generation, approximately 90 kilometres of transmission facilities and 994 kilometres of distribution

facilities. GBPC’s approved regulatory return on rate base for 2024 is 8.52 per cent (2023 – 8.32 per

cent). 

Other Electric Utilities Outlook

Other Electric Utilities’ USD earnings in 2024 are expected to increase over the prior year.

BLPC currently operates pursuant to a single integrated license to generate, transmit and distribute

electricity on the island of Barbados until 2028. In 2019, the Government of Barbados passed legislation

requiring multiple licenses for the supply of electricity. In 2021, BLPC reached commercial agreement with

the Government of Barbados for each of the license types, subject to the passage of implementing

legislation. The timing of the final enactment is unknown at this time, but BLPC will work towards the

implementation of the licenses once enacted.

Exhibit 99.2

19

In 2021, BLPC submitted a general rate review application to the FTC. In September 2022, the FTC

granted BLPC interim rate relief, allowing an increase in base rates of approximately $1 million USD per

month. On February 15, 2023, the FTC issued a decision on the application which included the following

significant items: an allowed regulatory ROE of 11.75 per cent, an equity capital structure of 55 per cent,

a directive to update the major components of rate base to September 16, 2022, and a directive to

establish regulatory liabilities related to the self-insurance fund of $50 million USD, prior year benefits

recognized on remeasurement of deferred income taxes of $5 million USD, and accumulated depreciation

of $16 million USD. On March 7, 2023, BLPC filed a Motion for Review and Variation (the “Motion”) and

applied for a stay of the FTC’s decision, which was subsequently granted. On November 20, 2023, the

FTC issued their decision dismissing the Motion. Interim rates continue to be in effect through to a date to

be determined in a final decision and order.

On December 1, 2023, BLPC appealed certain aspects of the FTC’s February 15 and November 20,

2023, decisions to the Supreme Court of Barbados in the High Court of Justice (the “Court”) and

requested that they be stayed. On December 11, 2023, the Court granted the stay. BLPC’s position is

that the FTC made errors of law and jurisdiction in their decisions and believes the success of the appeal

is probable, and as a result, the adjustments to BLPC’s final rates and rate base, including any

adjustments to regulatory assets and liabilities, have not been recorded at this time. Management does

not expect the final decision and order to have a material impact on adjusted net income.

In 2024, capital investment in the Other Electric Utilities segment is expected to be approximately $80

million USD (2023 – $47 million USD), primarily in more efficient and cleaner sources of generation,

including renewables and battery storage. 

Other

The Other segment includes those business operations that in a normal year are below the required

threshold for reporting as separate segments; and corporate expense and revenue items that are not

directly allocated to the operations of Emera’s subsidiaries and investments.

Business operations in the Other segment include Emera Energy and Block Energy LLC (“Block Energy”).

Emera Energy consists of EES, a wholly owned physical energy marketing and trading business and an

equity investment in a 50 per cent joint venture ownership of Bear Swamp, a 660 MW pumped storage

hydroelectric facility in northwestern Massachusetts. Block Energy is a wholly owned technology company

focused on finding ways to deliver renewable and resilient energy to customers.

Corporate items included in the Other segment are certain corporate-wide functions including executive

management, strategic planning, treasury services, legal, financial reporting, tax planning, corporate

business development, corporate governance, investor relations, risk management, insurance, acquisition

and disposition related costs, gains or losses on select assets sales, and corporate human resource

activities. It includes interest revenue on intercompany financings and interest expense on corporate debt

in both Canada and the United States. It also includes costs associated with corporate activities that are

not directly allocated to the operations of Emera’s subsidiaries and investments.

Earnings from EES are generally dependent on market conditions. In particular, volatility in natural gas

and electricity markets, which can be influenced by weather, local supply constraints and other supply

and demand factors, can provide higher levels of margin opportunity. The business is seasonal, with Q1

and Q4 usually providing the greatest opportunity for earnings. EES is generally expected to deliver

annual adjusted net income within its guidance range of $15 to $30 million USD.

The adjusted net loss from the Other segment is expected to be higher in 2024 due to increased interest

expense and lower contribution to net income from Emera Energy primarily as a result of one-time

investment tax credits at Bear Swamp in 2023. 

The Other segment does not anticipate any significant capital investment in 2024.

Exhibit 99.2

20

CONSOLIDATED BALANCE SHEET HIGHLIGHTS

Significant changes in the Consolidated Balance Sheets between December 31, 2022 and December 31,

2023 include:

millions of dollars

Increase

(Decrease)

Explanation 

Assets

Cash and cash equivalents

$

 257

Increased due to cash from operations, proceeds from long-term

debt issuances at PGS and NSPI, and issuance of Emera

common stock. These were partially offset by investment in PP&E

at the regulated utilities, net repayments of debt at TEC, and

dividends paid on Emera common stock

Derivative instruments (current and

long-term)

 (156)

Decreased due to settlements of derivative instruments and

decreased pricing on power derivative instruments at NSPI,

partially offset by reversal of 2022 contracts at EES

Regulatory assets (current and long-

term)

 (515)

Decreased due to higher fuel clause and storm cost recoveries at

TEC, and reversal of accrued Cap-and-Trade emission

compliance charges at NSPI. These were partially offset by

increased FAM deferrals at NSPI due to an under-recovery of fuel

costs and a change in fuel cost recovery methodology for an

industrial customer, and increased deferred income tax regulatory

assets at NSPI

Receivables and other assets

(current and long-term)

 (1,079)

Decreased due to lower gas transportation assets, decreased

cash collateral and lower trade receivables as a result of lower

commodity prices at EES, and settlement of the gas hedge

receivable at NMGC

PP&E, net of accumulated

depreciation and amortization

 1,380

Increased due to capital additions in excess of depreciation and

amortization, partially offset by the effect of FX translation of

Emera's non-Canadian affiliates

Goodwill

 (141)

Decreased due to the effect of the FX translation of non-Canadian

affiliates

Liabilities and Equity

Short-term debt and long-term debt

(including current portion)

$

 754

Issuance of long-term debt at PGS and NSPI and proceeds from

committed credit facilities at Emera, partially offset by net

repayments under committed credit facilities at NSPI and TEC,

repayment of debt at NMGC, and the effect of the FX translation

of non-Canadian affiliates

Accounts payable

 (571)

Decreased due to lower commodity prices at EES, NMGC and

TEC, decreased cash collateral position on derivative instruments

and lower fuel related payables at NSPI

Deferred income tax liabilities, net of

deferred income tax assets 

 185

Increased due to tax deductions in excess of accounting

depreciation related to PP&E, partially offset by changes in

derivative instruments and increased tax credits related to solar

projects at TEC and Bear Swamp facility upgrades

Derivative instruments (current and

long-term)

 (574)

Decreased due to changes in existing positions and reversal of

2022 contracts, partially offset by new contracts in 2023 at EES

Regulatory liabilities (current and

long-term)

 (501)

Decreased due to lower deferrals related to derivative instruments

at NSPI and settlement of NMGC gas hedges

Other liabilities (current and long-

term)

 (157)

Decreased due to reversal of accrued Cap-and-Trade emissions

compliance charges at NSPI

Common stock

 700

Increased due to shares issued

Accumulated other comprehensive

income

 (273)

Decreased due to the effect of the FX translation of non-Canadian

affiliates

Retained earnings

 219

Increased due to net income in excess of dividends paid

Exhibit 99.2

21

OTHER DEVELOPMENTS

Increase in Common Dividend

On September 20, 2023, the Emera Board of Directors (the “Board”) approved an increase in the annual

common share dividend rate to $2.87 from $2.76 per common share. The first payment was effective

November 15, 2023. Emera also extended its dividend growth rate target of four to five per cent through

2026.

FINANCIAL HIGHLIGHTS

Florida Electric Utility

Three months ended

Year ended

For the

December 31

December 31

millions of USD (except as indicated)

2023

2022

2023

2022

Operating revenues – regulated electric

$

 613

$

 597

$

 2,637

$

 2,523

Regulated fuel for generation and purchased power

$

 162

$

 201

$

 682

$

 832

Contribution to consolidated net income 

$

 85

$

 91

$

 466

$

 458

Contribution to consolidated net income – CAD

$

 115

$

 124

$

 627

$

 596

Average fuel costs in dollars per MWh

$

 34

$

 41

$

 31

$

 39

The impact of the change in the FX rate increased CAD earnings for the three months and year ended

December 31, 2023, by $1 million and $22 million, respectively.

Net Income

Highlights of the net income changes are summarized in the following table:

For the

Three months ended

Year ended

millions of USD

December 31

December 31

Contribution to consolidated net income – 2022

$

91

$

 458

Increased operating revenues due to storm cost recovery surcharge

revenue (offset in OM&G), new base rates and customer growth driving

higher sales volumes, partially offset by changes in fuel recovery

clause revenue and unfavourable weather

 16

 114

Decreased fuel for generation and purchased power due to lower

natural gas prices

 39

 150

Increased OM&G primarily due to storm cost recovery recognition

related to the storm surcharge (offset in revenue) and timing of

deferred clause recoveries

 (25)

 (136)

Increased depreciation and amortization due to additions to facilities

and generation projects placed in service

 (8)

 (33)

Increased interest expense due to higher interest rates and higher

borrowings to support capital investments and ongoing operations

 (7)

 (59)

Increased state, and municipal taxes due to higher retail sales and

higher taxable property placed in service

 (8)

 (33)

(Increased) decreased income tax expense primarily due to production

tax credits related to solar facilities

 (6)

 7

Other

 (7)

 (2)

Contribution to consolidated net income – 2023

$

 85

$

 466

Exhibit 99.2

22

Operating Revenues – Regulated Electric

Annual electric revenues and sales volumes are summarized in the following table by customer class:

Electric Revenues

Electric Sales Volumes

 (millions of USD)

(Gigawatt hours ("GWh"))

2023

2022

2023

2022

Residential

$

 1,711

$

 1,381

 10,307

 10,109

Commercial

 803

 666

 6,462

 6,300

Industrial

 203

 176

 2,082

 2,111

Other

(1)

  (80)

 300

 2,194

 2,352

Total

$

 2,637

$

 2,523

 21,045

 20,872

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

Regulated Fuel for Generation and Purchased Power

Annual production volumes are summarized in the following table:

Production Volumes (GWh)

2023

2022

Natural gas 

  17,843

 17,083

Solar

 1,748

 1,492

Purchased power 

  1,443

 1,685

Coal 

 744

 1,325

Total 

 21,778

 21,585

TEC’s fuel costs are affected by commodity prices and generation mix that is largely dependent on

economic dispatch of the generating fleet, bringing the lowest cost options on first (renewable energy

from solar or battery storage), such that the incremental cost of production increases as sales volumes

increase. Generation mix may also be affected by plant outages, plant performance, availability of lower

priced short-term purchased power, availability of renewable solar generation, and compliance with

environmental standards and regulations.

Regulatory Environment

TEC is regulated by the FPSC and is also subject to regulation by the FERC. The FPSC sets rates at a

level that allows utilities such as TEC to collect total revenues or revenue requirements equal to their cost

of providing service, plus an appropriate return on invested capital. Base rates are determined in FPSC

rate setting hearings which can occur at the initiative of TEC, the FPSC or other interested parties. For

further details on TEC’s regulatory environment, base rates and recovery mechanisms, refer to note 6 in

the consolidated financial statements.

Canadian Electric Utilities

Three months ended

Year ended

For the

December 31

December 31

millions of dollars (except as indicated)

2023

2022

2023

2022

Operating revenues – regulated electric

$

 439

$

 421

$

 1,671

$

 1,675

Regulated fuel for generation and purchased power

(1)

$

 234

$

 173

$

 777

$

 950

Contribution to consolidated adjusted net income

$

 68

$

 46

$

 247

$

 222

NSPML unrecoverable costs

$

 - 

$

 - 

$

 - 

$

 (7)

Contribution to consolidated net income

$

 68

$

 46

$

 247

$

 215

Average fuel costs in dollars per MWh

(2)

$

 81

$

 61

$

 70

$

 85

(1) Regulated fuel for generation and purchased power includes NSPI's FAM deferral on the Consolidated Statements of Income,

however, it is excluded in the segment overview. 

(2) Average fuel costs for the year ended December 31, 2023 include reversal of the $166 million of the Nova Scotia Cap-and-Trade

Program provision (2022 – $134 million expense).

Exhibit 99.2

23

Canadian Electric Utilities' contribution to consolidated adjusted net income is summarized in the following

table:

Three months ended 

Year ended

For the

December 31

December 31

millions of dollars

2023

2022

2023

2022

NSPI

$

 40

$

 23

$

 141

$

 131

Equity investment in LIL

 16

 15

 60

 55

Equity investment in NSPML

(1)

 12

 8

 46

 36

Contribution to consolidated adjusted net income 

$

 68

$

 46

$

 247

$

 222

(1) Excludes $7 million in NSPML unrecoverable costs, after-tax, for the year ended December 31, 2022.

Net Income

Highlights of the net income changes are summarized in the following table:

For the

Three months ended

Year ended

millions of dollars

December 31

December 31

Contribution to consolidated net income – 2022

$

 46

$

 215

Increased operating revenues quarter-over-quarter due to new rates,

increased residential, commercial and other class sales volumes, and

favourable weather, partially offset by decreased industrial sales

volume. Year-over-year decrease primarily due to changes in fuel cost

recovery methodology for an industrial customer

(1)

, partially offset by

quarter-over-quarter impacts noted above

 18

 (4)

Increased fuel for generation and purchased power quarter-over-quarter

due to increased commodity prices and partial reversal of Nova Scotia

Cap-and-Trade Program costs accrued in 2022, partially offset by a

change in generation mix. Year-over-year decreased due to reversal of

the Nova Scotia Cap-and-Trade Program provision in 2023, compared

to an expense in 2022, partially offset by increased commodity prices

and the Nova Scotia OBPS carbon tax accrual

 (61)

 173

Increased FAM deferral quarter-over-quarter due to under-recovery of

fuel costs. Year-over-year decreased due to reversal of the Nova Scotia

Cap-and-Trade provision in 2023, partially offset by increased under-

recovery of fuel costs and changes in the fuel recovery methodology for

an industrial customer

(1)

  74

 (69)

Increased OM&G due to higher costs for power generation and

transmission and distribution field services. Year-over-year also

increased due to the recognition of the RER penalty and higher

vegetation management costs

 (8)

 (46)

Increased depreciation and amortization due to increased PP&E in

service

 (3)

 (17)

Increased interest expense due to increased interest rates and higher

debt levels

 (5)

 (34)

Increased income from equity investments at NSPML quarter-over-

quarter primarily due to the holdback recognized in Q4 2022. Year-over-

year also increased due to partial reversal in Q3 2023 of the holdback

recognized in 2022, and higher equity earnings from LIL

 5

 15

NSPML unrecoverable costs in 2022

 - 

 7

Other

 2

 7

Contribution to consolidated net income – 2023

$

 68

$

 247

(1) For more information on the changes in fuel cost recovery methodology for an industrial customer, refer to note 6 in the 2023

consolidated financial statements

Exhibit 99.2

24

NSPI

Operating Revenues – Regulated Electric

Annual electric revenues and sales volumes are summarized in the following tables by customer class:

Electric Revenues

Electric Sales Volumes

(millions of dollars)

(GWh)

2023

2022

2023

2022

Residential

$

 910

$

 834

 4,986

 4,822

Commercial

 463

 427

 3,053

 3,006

Industrial

 219

 353

 2,164

 2,480

Other

 41

 28

 239

 148

Total

$

 1,633

$

 1,642

 10,442

 10,456

Regulated Fuel for Generation and Purchased Power

Annual production volumes are summarized in the following table:

Production Volumes (GWh)

2023

2022

Coal 

 3,086

 3,771

Natural gas

 1,946

 1,650

Purchased power

 881

 910

Petcoke

 553

 897

Oil

 145

 251

Total non-renewables

 6,611

 7,479

Purchased power - IPP, COMFIT and imports

 3,251

 2,423

Wind, hydro and solar

 1,149

 1,105

Biomass 

 128

 127

Total renewables

 4,528

 3,655

Total production volumes

 11,139

 11,134

NSPI’s fuel costs are affected by commodity prices and generation mix, which is largely dependent on

economic dispatch of the generating fleet. NSPI brings the lowest cost options on stream first after

renewable energy from IPPs including COMFIT participants, for which NSPI has power purchase

agreements in place, and the NS Block of energy, including the Supplemental Energy Block, which

carries no additional fuel cost outside of the UARB approved annual assessments paid to NSPML for the

use of the Maritime Link. 

Generation mix may also be affected by plant outages, carbon pricing programs, including the Nova

Scotia OBPS, availability of renewable generation, availability of energy from the NS Block, plant

performance, and compliance with environmental regulations. 

The Nova Scotia Cap-and-Trade Program provision related to the accrued cost of acquiring emissions

credits for the 2019 through 2022 compliance period. As of December 31, 2022, NSPI had recognized a

cumulative $166 million accrual in fuel costs related to anticipated purchase of emissions credits and $6

million related to credits purchased from provincial auction. Accrued compliance costs of $166 million

were reversed in Q1 2023 and NSPI does not anticipate further costs related to the Nova Scotia Cap-and-

Trade Program. For further information on the reversal of this non-cash accrual and the FAM regulatory

balance, refer to the “Business Overview and Outlook – Canadian Electric Utilities – NSPI” section and

note 6 in the consolidated financial statements.

Exhibit 99.2

25

Regulatory Environment - NSPI

NSPI is a public utility as defined in the Public Utilities Act and is subject to regulation under the Public

Utilities Act by the UARB. The Public Utilities Act gives the UARB supervisory powers over NSPI’s

operations and expenditures. Electricity rates for NSPI’s customers are subject to UARB approval. NSPI

is not subject to a general annual rate review process, but rather participates in hearings held from time to

time at NSPI’s or the UARB’s request. For further details on NSPI’s regulatory environment and recovery

mechanisms, refer to note 6 in the consolidated financial statements.

Gas Utilities and Infrastructure

Three months ended

Year ended

For the

December 31

December 31

millions of USD (except as indicated)

2023

2022

2023

2022

Operating revenues – regulated gas

(1)

$

 290

$

 372

$

 1,114

$

 1,296

Operating revenues – non-regulated

 3

 2

 15

 12

Total operating revenue

$

 293

$

 374

$

 1,129

$

 1,308

Regulated cost of natural gas

$

 99

$

 181

$

 391

$

 614

Contribution to consolidated net income 

$

 43

$

 53

$

 158

$

 170

Contribution to consolidated net income – CAD

$

 59

$

 72

$

 214

$

 221

 (1) Operating revenues – regulated gas includes $11 million of finance income from Brunswick Pipeline (2022 – $13 million) for the

three months ended December 31, 2023 and $46 million (2022 – $47 million) for the year ended December 31 2023; however, it is

excluded from the gas revenues and cost of natural gas analysis below.

Gas Utilities and Infrastructure's contribution to consolidated net income is summarized in the following

table:

Three months ended 

Year ended

For the

December 31

December 31

millions of USD

2023

2022

2023

2022

PGS

$

 21

$

 17

$

 79

$

 82

NMGC

 14

 22

 43

 35

Other

 8

 14

 36

 53

Contribution to consolidated net income 

$

 43

$

 53

$

 158

$

 170

Impact of the change in the FX rate on CAD earnings was minimal for the three months ended and

increased CAD earnings for the year ended December 31, 2023, by $8 million.

Exhibit 99.2

26

Net Income

Highlights of the net income changes are summarized in the following table:

For the

Three months ended

Year ended

millions of USD

December 31

December 31

Contribution to consolidated net income – 2022

$

 53

$

 170

Decreased operating revenues due to lower fuel revenues at PGS and

NMGC, and lower off-system sales at PGS, partially offset by new base

rates at NMGC and customer growth at PGS

 (71)

 (181)

Decreased asset optimization revenue quarter-over-quarter at NMGC

 (10)

 2

Decreased cost of natural gas sold due to lower natural gas prices at

PGS and NMGC

 82

 223

Increased OM&G primarily due to higher labour and benefit costs

 (10)

 (20)

Decreased depreciation and amortization expense quarter-over-quarter

due to a higher reversal of accumulated depreciation in 2023 as a

result of the 2021 rate case settlement at PGS. Year-over-year

increase due to asset growth at PGS and NMGC, partially offset by a

higher reversal of accumulated depreciation in 2023 at PGS

 6

 (3)

Increased interest expense due to higher interest rates and increased

borrowings to support ongoing operations and capital investments

 (10)

 (33)

Other

 3

 - 

Contribution to consolidated net income – 2023

$

 43

$

 158

Operating Revenues – Regulated Gas

Annual gas revenues and sales volumes are summarized in the following tables by customer class: 

Gas Revenues

Gas Volumes

(millions of USD)

(Therms)

2023

2022

2023

2022

Residential

$

 537

$

 614

 414

 421

Commercial

 315

 354

 839

 836

Industrial

(1)

 69

 64

 1,615

 1,429

Other

(2)

 147

 217

 266

 227

Total

(3)

$

 1,068

$

 1,249

 3,134

 2,913

(1) Industrial gas revenue includes sales to power generation customers.

(2) Other gas revenue includes off-system sales to other utilities and various other items.

(3) Total gas revenue excludes $46 million of finance income from Brunswick Pipeline (2022 – $47 million).

Regulated Cost of Natural Gas

PGS and NMGC purchase gas from various suppliers depending on the needs of their customers. In

Florida, gas is delivered to the PGS distribution system through interstate pipelines on which PGS has

firm transportation capacity for delivery by PGS to its customers. NMGC’s natural gas is transported on

major interstate pipelines and NMGC’s intrastate transmission and distribution system for delivery to

customers. 

In Florida, natural gas service is unbundled for non-residential customers and residential customers who

use more than 1,999 therms annually and elect the option. In New Mexico, NMGC is required, if

requested, to provide transportation-only services for all customer classes. The commodity portion of

bundled sales is included in operating revenues, at the cost of the gas on a pass-through basis, therefore

no net earnings effect when a customer shifts to transportation-only sales.

Exhibit 99.2

27

Annual gas sales by type are summarized in the following table:

Gas Volumes by Type (millions of Therms)

2023

2022

Transportation

 2,461

 2,206

System supply

 673

 707

Total

 3,134

 2,913

Regulatory Environments

PGS is regulated by the FPSC. The FPSC sets rates at a level that allows utilities such as PGS to collect

total revenues or revenue requirements equal to their cost of providing service, plus an appropriate return

on invested capital.

NMGC is subject to regulation by the NMPRC. The NMPRC sets rates at a level that allows NMGC to

collect total revenues equal to its cost of providing service, plus an appropriate return on invested capital. 

For further information on PGS and NMGC’s regulatory environment and recovery mechanisms, refer to

note 6 in the consolidated financial statements.

Other Electric Utilities

.

Three months ended

Year ended

For the

December 31

December 31

millions of USD (except as indicated)

2023

2022

2023

2022

Operating revenues – regulated electric

$

 104

$

 98

$

 390

$

 398

Regulated fuel for generation and purchased power

$

 57

$

 54

$

 204

$

 223

Contribution to consolidated adjusted net income

$

 3

$

 7

$

 26

$

 23

Contribution to consolidated adjusted net income – CAD

$

 4

$

 8

$

 35

$

 29

GBPC Impairment charge

$

 - 

$

 54

$

 - 

$

 54

Equity securities MTM gain (loss)

$

 2

$

 1

$

 2

$

 (4)

Contribution to consolidated net income (loss)

$

 5

$

 (46)

$

 28

$

 (35)

Contribution to consolidated net income (loss) – CAD

$

 6

$

 (62)

$

 37

$

 (48)

Electric sales volumes (GWh)

 323

 301

 1,260

 1,239

Electric production volumes (GWh)

 345

 325

 1,362

 1,340

Average fuel cost in dollars per MWh

$

 165

$

 161

$

 150

$

 166

On March 31, 2022, Emera completed the sale of its 51.9 per cent interest in Dominica Electricity

Services Ltd. (“Domlec”) for proceeds which approximated carrying value. The sale did not have a

material impact on earnings.

The impact of the change in the FX rate on CAD earnings for the three months and year ended

December 31, 2023 was minimal.

Other Electric Utilities' contribution to consolidated adjusted net income is summarized in the following

table:

Three months ended 

Year ended

For the

December 31

December 31

millions of USD

2023

2022

2023

2022

BLPC

$

 4

$

 5

$

 18

$

 11

GBPC

 - 

 1

 11

 10

Other

 (1)

 1

 (3)

 2

Contribution to consolidated adjusted net income 

$

 3

$

 7

$

 26

$

 23

Exhibit 99.2

28

Net Income

Highlights of the net income changes are summarized in the following table:

For the

Three months ended

Year ended

millions of USD

December 31

December 31

Contribution to consolidated net income – 2022

$

 (46)

$

 (35)

Increased operating revenues quarter-over-quarter due to higher fuel

revenue at BLPC and GBPC as a result of higher fuel prices and higher

sales volumes at BLPC. Year-over-year decreased due to lower fuel

revenue at BLPC reflecting lower fuel prices, and the sale of Domlec in

Q1 2022, partially offset by interim rates at BLPC and increased sales

volumes at BLPC and GBPC

 6

 (8)

Increased fuel for generation and purchased power quarter-over-

quarter due to higher fuel costs at BLPC and GBPC. Decreased year-

over-year due to lower fuel prices and change in generation mix at

BLPC

 (3)

 19

GBPC impairment charge in 2022

 54

 54

Other

 (6)

 (2)

Contribution to consolidated net income – 2023

$

 5

$

 28

Regulatory Environments

BLPC is regulated by the FTC. Rates are set to recover prudently incurred costs of providing electricity

service to customers plus an appropriate return on capital invested. 

GBPC is regulated by the GBPA. Rates are set to recover prudently incurred costs of providing electricity

service to customers plus an appropriate return on rate base. 

For further details on BLPC and GBPC’s regulatory environments and recovery mechanisms, refer to note

6 in the consolidated financial statements.

Other

Three months ended

Year ended

For the

December 31

December 31

millions of dollars

2023

2022

2023

2022

Marketing and trading margin

(1) (2)

$

 35

$

 72

$

 96

$

 143

Other non-regulated operating revenue

 5

 3

 27

 16

Total operating revenues – non-regulated

$

 40

$

 75

$

 123

$

 159

Contribution to consolidated adjusted net income (loss)

$

 (71)

$

 (1)

$

 (314)

$

 (218)

MTM gain, after-tax

(3)

 112

 304

 167

 179

Contribution to consolidated net income (loss)

$

 41

$

 303

$

 (147)

$

 (39)

(1) Marketing and trading margin represents EES's purchases and sales of natural gas and electricity, pipeline and storage capacity

costs and energy asset management services’ revenues.

(2) Marketing and trading margin excludes a MTM gain, pre-tax of $131 million in Q4 2023 (2022 – $430 million gain) and a gain of

$216 million for the year ended December 31, 2023 (2022 – $281 million gain). 

(3) Net of income tax expense of $44 million for the three months ended December 31, 2023 (2022 – $124 million expense) and $68

million expense for the year ended December 31, 2023 (2022 – $73 million expense).

Exhibit 99.2

29

Other's contribution to consolidated adjusted net income is summarized in the following table:

Three months ended 

Year ended

For the

December 31

December 31

millions of dollars

2023

2022

2023

2022

Emera Energy:

 EES

$

 19

$

 40

$

 46

$

 68

 Other

 6

 1

 18

 2

Corporate – see breakdown of adjusted contribution below

 (91)

 (37)

 (356)

 (267)

Block Energy LLC

(1)

  (4)

 (5)

 (18)

 (18)

Other

 (1)

 - 

 (4)

 (3)

Contribution to consolidated adjusted net income (loss)

$

 (71)

$

 (1)

$

 (314)

$

 (218)

(1) Previously Emera Technologies LLC

Net Income

Highlights of the net income changes are summarized in the following table:

For the

Three months ended 

Year ended

millions of dollars

December 31

December 31

Contribution to consolidated net income (loss) – 2022

$

 303

$

 (39)

Decreased marketing and trading margin quarter-over-quarter primarily

due to weather driven market conditions in Q4 2022 that increased

pricing and volatility. Year -over-year decrease reflects less favourable

market conditions, specifically lower natural gas prices and volatility

and higher cost commitments for gas transportation in 2023 compared

to 2022

 (37)

 (47)

Decreased OM&G, pre-tax, primarily due to the timing of long-term

compensation and related hedges

 12

 10

Increased interest expense, pre-tax, due to increased interest rates

and increased total debt

 (8)

 (51)

Increased income tax recovery primarily due to increased losses before

provision for income taxes and the recognition of investment tax credits

related to Bear Swamp facility upgrades, partially offset by the impact

of effective state tax rates

 7

 26

TGH award in 2022, after tax and legal costs

 (45)

 (45)

Decreased MTM gain, after-tax, quarter-over-quarter due to

unfavourable changes in existing positions, partially offset by higher

amortization of gas transportation assets in 2022 at EES. Decreased

MTM gain after-tax, year-over-year primarily due to higher amortization

of gas transportation assets partially offset by favourable changes in

existing positions at EES and gains on Corporate FX hedges

 (194)

 (12)

Other 

 3

 11

Contribution to consolidated net income (loss) – 2023

$

 41

$

 (147)

Exhibit 99.2

30

Emera Energy 

EES derives revenue and earnings from wholesale marketing and trading of natural gas and electricity

within the Company’s risk tolerances, including those related to value-at-risk (“VaR”) and credit exposure.

EES purchases and sells physical natural gas and electricity, the related transportation and transmission

capacity rights, and provides energy asset management services. The primary market area for the natural

gas and power marketing and trading business is northeastern North America, including the Marcellus

and Utica shale supply areas. EES also participates in the Florida, United States Gulf Coast and

Midwest/Central Canadian natural gas markets. Its counterparties include electric and gas utilities, natural

gas producers, electricity generators and other marketing and trading entities. EES operates in a

competitive environment, and the business relies on knowledge of the region’s energy markets,

understanding of pipeline and transmission infrastructure, a network of counterparty relationships and a

focus on customer service. EES manages its commodity risk by limiting open positions, utilizing financial

products to hedge purchases and sales, and investing in transportation capacity rights to enable

movement across its portfolio.

EES’ contribution to consolidated adjusted net income was $19 million in Q4 2023, compared to $40

million in Q4 2022; and $46 million ($33 million USD) for the year ended December 31, 2023, compared

to $68 million ($50 million USD) for the same period in 2022. The 2023 and 2022 EES contribution to

consolidated adjusted net income was above the expected EES annual adjusted net income guidance

range of $15 to $30 million USD. Market conditions in 2022 were very favourable, due to high natural gas

pricing and volatility, which reflected weather patterns and geopolitical conditions.

MTM Adjustments

Emera Energy’s “Marketing and trading margin”, “Non-regulated fuel for generation and purchased

power”, “Income from equity investments” and “Income tax expense (recovery)” are affected by MTM

adjustments. Management believes excluding the effect of MTM valuations, and changes thereto, from

income until settlement better matches the financial effect of these contracts with the underlying cash

flows. Variance explanations of the MTM changes for this quarter and for the year are explained in the

table below. 

Emera Energy has a number of asset management agreements (“AMA”) with counterparties, including

local gas distribution utilities, power utilities and natural gas producers in North America. The AMAs

involve Emera Energy buying or selling gas for a specific term, and the corresponding release of the

counterparties’ gas transportation/storage capacity to Emera Energy. MTM adjustments on these AMAs

arise on the price differential between the point where gas is sourced and where it is delivered. At

inception, the MTM adjustment is offset fully by the value of the corresponding gas transportation asset,

which is amortized over the term of the AMA contract. 

Subsequent changes in gas price differentials, to the extent they are not offset by the accounting

amortization of the gas transportation asset, will result in MTM gains or losses recorded in income. MTM

adjustments may be substantial during the term of the contract, especially in the winter months of a

contract when delivered volumes and market pricing are usually at peak levels. As a contract is realized,

and volumes reduce, MTM volatility is expected to decrease. Ultimately, the gas transportation asset and

the MTM adjustment reduce to zero at the end of the contract term. As the business grows, and AMA

volumes increase, MTM volatility resulting in gains and losses may also increase.

Emera Corporate has FX forwards to manage the cash flow risk of forecasted USD cash inflows.

Fluctuations in the FX rate result in MTM gains or losses are recorded in “Other income, net” on the

Consolidated Statements of Income.

Exhibit 99.2

31

Corporate

Corporate's adjusted loss is summarized in the following table: 

Three months ended 

Year ended

For the

December 31

December 31

millions of dollars

2023

2022

2023

2022

Operating expenses

  (1)

$

 7

$

 20

$

 73

$

 83

Interest expense

 88

 79

 329

 278

Income tax recovery 

  (25)

 (35)

 (111)

 (109)

Preferred dividends

 18

 16

 66

 63

TGH award, after tax and legal costs

 - 

 (45)

 - 

 (45)

Other

  (2)(3)

 3

 2

 (1)

 (3)

Corporate adjusted net loss

  (4)

$

 (91)

$

 (37)

$

 (356)

$

 (267)

(1) Operating expenses include OM&G and depreciation. 

(2) Other includes realized FX gains and losses on FX hedges entered into to hedge USD denominated operating unit earnings

exposure. 

(3) Includes a realized net loss, pre-tax of $4 million ($3 million after-tax) for the three months ended December 31, 2023 (2022 – $5

million net loss, pre-tax and $4 million loss, after-tax) and a $11 million net loss, pre-tax ($8 million after-tax) for the year ended

December 31, 2023 (2022 – $6 million net loss, pre-tax and $5 million loss after-tax) on FX hedges, as discussed above.

(4) Excludes a MTM gain, after-tax of $15 million for the three months ended December 31, 2023 (2022 – $9 million gain, after-tax)

and a MTM gain, after-tax of $20 million for the year ended December 31, 2023 (2022 – $12 million loss, after-tax).

LIQUIDITY AND CAPITAL RESOURCES

The Company generates internally sourced cash from its various regulated and non-regulated energy

investments. Utility customer bases are diversified by both sales volumes and revenues among customer

classes. Emera’s non-regulated businesses provide diverse revenue streams and counterparties to the

business. Circumstances that could affect the Company’s ability to generate cash include changes to

global macro-economic conditions, downturns in markets served by Emera, impact of fuel commodity

price changes on collateral requirements and timely recoveries of fuel costs from customers, the loss of

one or more large customers, regulatory decisions affecting customer rates and the recovery of regulatory

assets, and changes in environmental legislation. Emera’s subsidiaries are generally in a financial

position to contribute cash dividends to Emera provided they do not breach their debt covenants, where

applicable, after giving effect to the dividend payment, and maintain their credit metrics.

Emera’s future liquidity and capital needs will be predominately for working capital requirements, ongoing

rate base investment, business acquisitions, greenfield development, dividends and debt servicing.

Emera has an approximate $9 billion capital investment plan over the 2024 through 2026 period with

approximately $2 billion of additional potential capital investments over the same period. Capital

investments at Emera’s regulated utilities are subject to regulatory approval.

Emera plans to use cash from operations, debt raised at the utilities, equity, and select asset sales to

support normal operations, repayment of existing debt, and capital requirements. Debt raised at certain of

the Company’s utilities is subject to applicable regulatory approvals. Generally, equity requirements in

support of the Company’s capital investment plan are expected to be funded through issuance of

preferred equity and issuance of common equity through Emera’s DRIP and ATM programs. 

Emera has credit facilities with varying maturities that cumulatively provide $5.3 billion of credit, with

approximately $2.3 billion undrawn and available at December 31, 2023. The Company was holding a

cash balance of $588 million at December 31, 2023. For further discussion, refer to the “Debt

Management” section below. For additional information regarding the credit facilities, refer to notes 23

and 25 in the consolidated financial statements.

Exhibit 99.2

32

Consolidated Cash Flow Highlights

Significant changes in the Consolidated Statements of Cash Flows between the years ended December

31, 2023 and 2022 include:

millions of dollars

2023

2022

$ Change

Cash, cash equivalents and restricted cash, beginning of period

$

 332

$

 417

$

 (85)

Provided by (used in):

 Operating cash flow before changes in working capital

 2,336

 1,147

 1,189

 Change in working capital

 (95)

 (234)

 139

Operating activities

$

 2,241

$

 913

$

 1,328

Investing activities

 (2,917)

 (2,569)

 (348)

Financing activities

 939

 1,555

 (616)

Effect of exchange rate changes on cash, cash equivalents and restricted cash

 (7)

 16

 (23)

Cash, cash equivalents, and restricted cash, end of period

$

 588

$

 332

$

 256

Cash Flow from Operating Activities

Net cash provided by operating activities increased

$1,328 million to $2,241 million for the year ended

December 31, 2023, compared to $913 million in 2022.

Cash from operations before changes in working capital increased

$1,189 million for the year ended

December 31, 2023. This increase was due to higher fuel clause recoveries and favourable changes in

the storm reserve balance at TEC, decreased fuel for generation and purchased power expense at NSPI

driven by the decreased Nova Scotia Cap-and-Trade Program provision and a distribution received from

the LIL partnership. This was partially offset by a decrease in regulatory liabilities due to 2022 gas hedge

settlements at NMGC, and receipt of the TGH award in 2022.

Changes in working capital increased operating cash flows by $139 million for the year ended December

31, 2023. This increase was due to favourable changes in accounts receivable at NMGC due to receipt of

its 2022 gas hedge settlement, favourable changes in cash collateral positions at Emera Energy,

favourable changes in natural gas inventory at EES in 2023, and the required prepayment of income

taxes and related interest in 2022 at NSPI. These increases were offset by the timing of accounts payable

payments at NSPI, TEC and NMGC, unfavourable changes in cash collateral positions at NSPI, and

decreased accrual for the Nova Scotia Cap-and-Trade emissions compliance charges at NSPI.

Cash Flow used in Investing Activities

Net cash used in investing activities increased $348 million to $2,917 million for the year ended

December 31, 2023, compared to $2,569 million in 2022. The increase was due to higher capital

investment in 2023.

Capital expenditures for the year ended December 31, 2023, including AFUDC, were $2,976 million

compared to $2,646 million in 2022. Details of 2023 capital spending by segment are shown below: 

●

 $1,771 million – Florida Electric Utility (2022 – $1,481 million);

●

 $461 million – Canadian Electric Utilities (2022 – $518 million);

●

 $673 million – Gas Utilities and Infrastructure (2022 – $578 million); 

●

 $63 million – Other Electric Utilities (2022 – $63 million); and

●

 $8 million – Other (2022 – $6 million).

Exhibit 99.2

33

Cash Flow from Financing Activities

Net cash provided by financing activities decreased $616 million to $939 million for the year ended

December 31, 2023, compared to $1,555 million in 2022. This decrease was due to lower proceeds from

long-term debt at TEC, higher repayment of short-term debt at TEC, lower proceeds from short-term debt

at TECO Finance and Emera, and higher repayments of committed credit facilities at NSPI. This was

partially offset by proceeds from long-term debt at PGS and NSPI, retirement of long-term debt at TEC in

2022, and higher issuance of common stock.

Working Capital

As at December 31, 2023, Emera’s cash and cash equivalents were $567 million (2022 – $310 million)

and Emera’s investment in non-cash working capital was $831 million (2022 – $1,173 million). Of the

cash and cash equivalents held at December 31, 2023, $482 million was held by Emera’s foreign

subsidiaries (2022 – $250 million). A portion of these funds are invested in countries that have certain

exchange controls, approvals, and processes for repatriation. Such funds are available to fund local

operating and capital requirements unless repatriated. 

Contractual Obligations

As at December 31, 2023, contractual commitments for each of the next five years and in aggregate

thereafter consisted of the following:

millions of dollars

2024

2025

2026

2027

2028

Thereafter

Total

Long-term debt principal

$

 1,670

$

 264

$

 3,047

$

 666

$

 525

$

 12,318

$

 18,490

Interest payment obligations

(1)

  836

 807

 719

 626

 587

 7,438

 11,013

Transportation

(2)

  696

 495

 405

 388

 338

 2,597

 4,919

Purchased power

(3)

  274

 249

 263

 312

 312

 3,435

 4,845

Fuel, gas supply and storage

 556

 215

 62

 - 

 5

 - 

 838

Capital projects

 778

111

70

 1

 - 

 - 

 960

Asset retirement obligations

 10

 2

 1

 1

 2

 407

 423

Pension and post-retirement

obligations

(4)

  28

 29

 38

 47

 32

 155

 329

Equity investment commitments

(5)

  240

 - 

 - 

 - 

 - 

 - 

 240

Other

 154

 147

 56

 46

 35

 221

 659

$

 5,242

$

 2,319

$

 4,661

$

 2,087

$

 1,836

$

 26,571

$

 42,716

(1) Future interest payments are calculated based on the assumption that all debt is outstanding until maturity. For debt instruments

with variable rates, interest is calculated for all future periods using the rates in effect at December 31, 2023, including any expected

required payment under associated swap agreements.

(2) Purchasing commitments for transportation of fuel and transportation capacity on various pipelines. Includes a commitment of

$134 million related to a gas transportation contract between PGS and SeaCoast through 2040.

(3) Annual requirement to purchase electricity production from IPPs or other utilities over varying contract lengths.

(4) The estimated contractual obligation is calculated as the current legislatively required contributions to the registered funded

pension plans (excluding the possibility of wind-up), plus the estimated costs of further benefit accruals contracted under NSPI's

Collective Bargaining Agreement and estimated benefit payments related to other unfunded benefit plans.

(5) Emera has a commitment to make equity contributions to the LIL related to an investment true up in 2024 and sustaining capital

contributions over the life of the partnership. The commercial agreements between Emera and Nalcor require true ups to finalize the

respective investment obligations of the parties in relation the Maritime Link and LIL which is expected to be approximately $240

million in 2024. In addition, Emera has future commitments to provide sustaining capital to the LIL for routine capital and major

maintenance.

NSPI has a contractual obligation to pay NSPML for use of the Maritime Link over approximately 38 years

from its January 15, 2018 in-service date. In February 2022, the UARB issued its decision and Board

Order approving NSPML’s requested rate base of approximately $1.8 billion. In December 2023, the

UARB approved collection of up to $164 million from NSPI for recovery of Maritime Link costs in 2024.

The timing and amounts payable to NSPML for the remainder of the 38-year commitment period are

subject to UARB approval.

Exhibit 99.2

34

Construction of the LIL is complete and the Newfoundland Electrical System Operator confirmed the

asset to be operating suitably to support reliable system operation and full functionality at 700MW, which

was validated by the Government of Canada’s Independent Engineer issuing its Commissioning

Certificate on April 13, 2023.

Emera has committed to obtain certain transmission rights for Nalcor, if requested, to enable it to transmit

energy which is not otherwise used in Newfoundland and Labrador or Nova Scotia. Nalcor has the right to

transmit this energy from Nova Scotia to New England energy markets effective August 15, 2021 and

continuing for 50 years. As transmission rights are contracted, the obligations are included within “Other”

in the above table.

Forecasted Consolidated Capital Investments

The 2024 forecasted consolidated capital investments are as follows:

millions of dollars

Florida

Electric

Utility

Canadian

Electric

Utilities

Gas Utilities

and

Infrastructure

Other

Electric

Utilities

Other

Total

Generation

$

 266

$

 143

$

 - 

$

 30

$

 - 

$

 439

New renewable generation

 280

 - 

 - 

 - 

 - 

 280

Electric transmission

 119

 88

 - 

 - 

 - 

 207

Electric distribution

 496

 142

 - 

 58

 - 

 696

Gas transmission and distribution

 - 

 - 

 566

 - 

 - 

 566

Facilities, equipment, vehicles, and other

 567

 63

 51

 17

 4

 702

$

 1,728

$

 436

$

 617

$

 105

$

 4

$

 2,890

Debt Management

In addition to funds generated from operations, Emera and its subsidiaries have, in aggregate, access to

committed syndicated revolving and non-revolving bank lines of credit in either CAD or USD per the table

below. 

Undrawn

Credit

and

millions of Canadian dollars (unless otherwise indicated)

Maturity

Facilities

Utilized

Available

Emera – Unsecured committed revolving credit facility

June 2027

$

 900

$

 265

$

 635

TEC (in USD) – Unsecured committed revolving credit facility

December 2026

 800

 707

 93

NSPI – Unsecured committed revolving credit facility

December 2027

 800

 332

 468

Emera – Unsecured non-revolving facility 

December 2024

 400

 400

 - 

Emera – Unsecured non-revolving facility 

February 2024

 400

 200

 200

Emera – Unsecured non-revolving facility

August 2024

 400

 400

 - 

TECO Finance (in USD) – Unsecured committed revolving credit

facility

December 2026

 400

 185

 215

NSPI – Unsecured non-revolving facility

July 2024

 400

 400

 - 

PGS (in USD) – Unsecured revolving facility

December 2028

 250

 55

 195

TEC (in USD) - Unsecured revolving facility

February 2024

 200

 - 

 200

TEC (in USD) - Unsecured revolving facility

April 2024

 200

 - 

 200

NMGC (in USD) – Unsecured revolving credit facility

December 2026

 125

 21

 104

NMGC (in USD) – Unsecured non-revolving facility

March 2024

 23

 23

 - 

Other (in USD) – Unsecured committed revolving credit facilities

Various

 21

 6

 15

Exhibit 99.2

35

Emera and its subsidiaries have certain financial and other covenants associated with their debt and

credit facilities. Covenants are tested regularly, and the Company is in compliance with covenant

requirements as at December 31, 2023. Emera’s significant covenant is listed below:

As at

Financial Covenant

Requirement

December 31, 2023

Emera

Syndicated credit facilities

Debt to capital ratio

Less than or equal to 0.70 to 1

0.57 : 1

Recent significant financing activity for Emera and its subsidiaries are discussed below by segment:

Florida Electric Utilities

On January 30, 2024, TEC issued $500 million USD of senior unsecured bonds that bear interest at 4.90

per cent with a maturity date of March 1, 2029. Proceeds from the issuance were primarily used for the

repayment of short-term borrowings outstanding under the 5-year credit facility. Therefore, $497 million

USD of short-term borrowings that was repaid was classified as long-term debt at December 31, 2023.

On November 24, 2023, TEC repaid its $400 million USD unsecured non-revolving facility, which expired

on December 13, 2023.

On April 3, 2023, TEC entered into a 364-day, $200 million USD senior unsecured revolving credit facility

which matures on April 1, 2024. The credit agreement contains customary representations and

warranties, events of default and financial and other covenants, and bears interest at a variable interest

rate, based on either the term secured overnight financing rate (“SOFR”), Wells Fargo’s prime rate, the

federal funds rate or the one-month SOFR, plus a margin. Proceeds from this facility will be used for

general corporate purposes.

On March 1, 2023, TEC entered into a 364-day, $200 million USD senior unsecured revolving credit

facility which matures on February 28, 2024. The credit facility contains customary representations and

warranties, events of default and financial and other covenants, and bears interest at a variable interest

rate, based on either the term SOFR, the Bank of Nova Scotia’s prime rate, the federal funds rate or the

one-month SOFR, plus a margin. Proceeds from this facility will be used for general corporate purposes. 

Canadian Electric Utilities

On March 24, 2023, NSPI issued $500 million in unsecured notes. The issuance included $300 million

unsecured notes that bear interest at 4.95 per cent with a maturity date of November 15, 2032, and $200

million unsecured notes that bear interest at 5.36 per cent with a maturity date of March 24, 2053.

Proceeds from these issuances were added to the general funds of the Company and applied primarily to

refinance existing indebtedness, to finance capital investment and for general corporate purposes. 

Gas Utilities and Infrastructure

On December 19, 2023, PGS completed an issuance of $925 million USD in senior notes. The issuance

included $350 million USD senior notes that bear interest at 5.42 per cent with a maturity date of

December 19, 2028, $350 million USD senior notes that bear interest at 5.63 per cent with a maturity date

of December 19, 2033 and $225 million USD senior notes that bear interest at 5.94 per cent with a

maturity date of December 19, 2053. Proceeds from these issuances were used to settle intercompany

loan agreements with TEC for the assets and liabilities transferred to PGS as part of the reorganization of

the gas division of Tampa Electric, effective on January 1, 2023.

Exhibit 99.2

36

On December 1, 2023, PGS entered into a $250 million USD senior unsecured revolving credit facility

with a group of banks, maturing on December 1, 2028. PGS has the ability to request the lenders to

increase their commitments under the credit facility by up to $100 million USD in the aggregate subject to

agreement from participating lenders. The credit agreement contains customary representations and

warranties, events of default and financial and other covenants, and bears interest at Bankers’

Acceptances or prime rate advances, plus a margin. Proceeds from these facilities will be used for

general corporate purposes.

On October 19, 2023, NMGC issued $100 million USD in senior unsecured notes that bear interest at

6.36 per cent with a maturity date of October 19, 2033. Proceeds from the issuance were used to repay

short-term borrowings.

Other Electric Utilities 

On May 24, 2023, GBPC issued a $28 million USD non-revolving term loan that bears interest at 4.00 per

cent with a maturity date of May 24, 2028. Proceeds from this issuance were used to repay GBPC’s $28

million USD bond, which matured in May 2023.

Other 

On December 16, 2023, Emera amended its $400 million unsecured non-revolving facility to extend the

maturity date from December 16, 2023 to December 16, 2024. There were no other changes in

commercial terms from the prior agreement.

On August 18, 2023, Emera entered into a $400 million non-revolving term facility which matures on

February 19, 2024. The credit agreement contains customary representations and warranties, events of

default and financial and other covenants, and bears interest at Bankers’ Acceptances or prime rate

advances, plus a margin. Proceeds from this facility will be used for general corporate purposes. On

February 16, 2024, Emera extended the term of this agreement to a maturity date of February 19, 2025.

On June 30, 2023, Emera amended its $400 million unsecured non-revolving facility to extend the

maturity date from August 2, 2023 to August 2, 2024. There were no other changes in commercial terms

from the prior agreement. 

On May 2, 2023, Emera issued $500 million in senior unsecured notes that bear interest at 4.84 per cent

with a maturity date of May 2, 2030. The proceeds were used to repay Emera’s $500 million unsecured

fixed rate notes, which matured in June 2023. 

Credit Ratings

Emera and its subsidiaries have been assigned the following senior unsecured debt ratings:

Fitch

S&P

Moody's

DBRS

Emera Inc.

BBB (Negative)

BBB- (Negative)

Baa3 (Negative)

N/A

TEC

A (Negative)

BBB+ (Negative)

A3 (Negative)

N/A

PGS (1)

A (Negative)

N/A

N/A

N/A

NMGC

BBB+ (Negative)

N/A

N/A

N/A

NSPI

N/A

BBB- (Negative)

N/A

BBB (high)(stable)

(1) On November 10, 2023 Fitch Ratings ("Fitch") assigned first-time long-term issuer default rating of 'A-' to PGS and an instrument

rating of 'A' for its private placements of senior unsecured bonds.

Exhibit 99.2

37

Guaranteed Debt

As of December 31, 2023, the Company had $2.75 billion USD (2022 – $2.75 billion USD) senior

unsecured notes ("US Notes”) outstanding. 

The US Notes are fully and unconditionally guaranteed, on a joint and several basis, by Emera and

Emera US Holdings Inc. (in such capacity, the “Guarantor Subsidiaries”). Emera owns, directly or

indirectly, all of the limited and general partnership interests in Emera US Finance LP. Other subsidiaries

of the Company do not guarantee the US Notes (such subsidiaries are referred to as the "Non-Guarantor

Subsidiaries"); however, Emera has unrestricted access to the assets of consolidated entities. 

In compliance with Rule 13-01 of Regulation S-X, the Company is including summarized financial

information for Emera, Emera US Holdings Inc., and Emera US Finance LP (together, the "Obligor

Group"), on a combined basis after transactions and balances between the combined entities have been

eliminated. Investments in and equity earnings of the Non-Guarantor Subsidiaries have been excluded

from the summarized financial information. 

The Obligor Group was not determined using geographic, service line or other similar criteria and, as a

result, the summarized financial information includes portions of Emera’s domestic and international

operations. Accordingly, this basis of presentation is not intended to present Emera’s financial condition

or results of operations for any purpose other than to comply with the specific requirements for guarantor

reporting.

Summarized Statement of Income (Loss) 

The Company recognized income related to guaranteed debt under the following categories:

For the

Year ended December 31

millions of dollars

2023

2022

Loss from operations

$

 (62)

$

 (73)

Net gains (losses)

(1)

$

 349

$

 (131)

(1) Includes $750 million (2022 – $262 million) in interest and dividend income, net, from non-guarantor subsidiaries.

Summarized Balance Sheet

The Company has the following categories on the balance sheet related to guaranteed debt:

As at

December 31

millions of dollars

2023

2022

Current assets

  (1)

$

 223

$

 172

Goodwill

 5,871

 6,012

Other assets

(2)

 6,243

 6,402

Total assets

  (3)

$

 12,337

$

 12,586

Current liabilities

(4)

$

 1,451

$

 1,903

Long-term liabilities

(5)

 6,815

 6,431

Total liabilities

$

 8,266

$

 8,334

(1) Includes $179 million (2022 – $144 million) in amounts due from non-guarantor subsidiaries.

(2) Includes $5,941 million (2022 – $6,058 million) in amounts due from non-guarantor subsidiaries.

(3) Excludes investments in non-guarantor subsidiaries. Consolidated Emera total assets are $39,480 million (2022 – $39,742 million).

(4) Includes $411 million (2022 – $392 million) due to non-guarantor subsidiaries.

(5) Includes $619 million (2022 – $769 million) due to non-guarantor subsidiaries.

Exhibit 99.2

38

Outstanding Stock Data

Common Stock

millions of

millions of

Issued and outstanding:

shares

dollars

Balance, December 31, 2022

269.95

$

7,762

Issuance of common stock under ATM program

(1)

8.29

397

Issued under the DRIP, net of discounts

5.26

272

Senior management stock options exercised and Employee Share Purchase Plan

0.62

31

Balance, December 31, 2023

284.12

$

8,462

(1) For the year ended December 31,2023, 8,287,037 common shares were issued under Emera's ATM program at an average

price of $48.27 per share for gross proceeds of $400 million ($397 million net of after-tax issuance costs). As at December

31,2023, an aggregate gross sales limit of $200 million remained available for issuance under the ATM program.

As at February 20, 2024, the amount of issued and outstanding common shares was 285.8 million.

If all outstanding stock options were converted as at February 20, 2024, an additional 3.1 million common

shares would be issued and outstanding.

ATM Equity Program

On October 3, 2023, Emera filed a short form base shelf prospectus, primarily in support of the renewal of

its ATM Program in Q4 2023 that will allow the Company to issue up to $600 million of common shares

from treasury to the public from time to time, at the Company’s discretion, at the prevailing market price.

This ATM Program is expected to remain in effect until November 4, 2025.

Preferred Stock

As at February 20, 2024, Emera had the following preferred shares issued and outstanding: Series A –

4.9 million; Series B – 1.1 million; Series C – 10.0 million; Series E – 5.0 million; Series F – 8.0 million;

Series H – 12.0 million; Series J – 8.0 million, and Series L – 9.0 million. Emera’s preferred shares do not

have voting rights unless the Company fails to pay, in aggregate, eight quarterly dividends.

On July 6, 2023, Emera announced it would not redeem the 10 million outstanding Cumulative Rate

Reset Preferred Shares, Series C (“Series C Shares”) or the 12 million outstanding Cumulative Minimum

Rate Reset First Preferred Shares, Series H (“Series H Shares”) on August 15, 2023. 

On August 4, 2023, Emera announced after having taken into account all conversion notices received

from holders, no Series C Shares were converted into Cumulative Floating Rate First Preferred Shares,

Series D Shares and no Series H shares were converted into Cumulative Floating Rate First Preferred

Shares, Series I shares. The holders of the Series C Shares are entitled to receive a dividend of 6.434

per cent per annum on the Series C Shares during the five-year period commencing on August 15, 2023,

and ending on (and inclusive of) August 14, 2028 ($0.40213 per Series C Share per quarter). The holders

of the Series H Shares are entitled to receive a dividend of 6.324 per cent per annum on the Series H

Shares during the five-year period commencing on August 15, 2023, and ending on (and inclusive of)

August 14, 2028 ($0.39525 per Series H Share per quarter).

PENSION FUNDING

For funding purposes, Emera determines required contributions to its largest defined benefit (“DB”)

pension plans based on smoothed asset values. This reduces volatility in the cash funding requirement

as the impact of investment gains and losses are recognized over a three-year period. Expected cash

flow for DB pension plans is $34 million in 2024 (2023 – $42 million). All pension plan contributions are

tax deductible and will be funded with cash from operations.

Exhibit 99.2

39

Emera’s DB pension plans employ a long-term strategic approach with respect to asset allocation, real

return and risk. The underlying objective is to earn an appropriate return, given the Company’s goal of

preserving capital with an acceptable level of risk for the pension fund investments. 

To  achieve the overall long-term asset allocation, pension assets are managed by external investment

managers per each pension plan’s investment policy and governance framework. The asset allocation

includes investments in the assets of domestic and global equities, domestic and global bonds and short-

term investments. The Company reviews investment manager performance on a regular basis and

adjusts the plans’ asset mixes as needed in accordance with the pension plans’ investment policy.

Emera’s projected contributions to defined contribution pension plans are $46 million for 2024 (2023 –

$45 million). 

Defined Benefit Pension Plan Summary

in millions of dollars

Plans by region

TECO Energy

NSPI

Caribbean 

Total

Assets as at December 31, 2023

$

 907

$

 1,381

$

 10

$

 2,298

Accounting obligation at December 31, 2023

$

 896

$

 1,361

$

 16

$

 2,273

Accounting expense (income) during fiscal 2023

$

 4

$

 (16)

$

 1

$

 (11)

Off-Balance Sheet Arrangements

Defeasance

Upon privatization in 1992, NSPI became responsible for managing a portfolio of defeasance securities

that provide principal and interest streams to match the related defeased debt, which at December 31,

2023 totalled $200 million (2022 – $200 million). The securities are held in trust for an affiliate of the

Province of Nova Scotia. Approximately 66 per cent of the defeasance portfolio consists of investments in

the related debt, eliminating all risk associated with this portion of the portfolio.

Guarantees and Letters of Credit

Emera has guarantees and letters of credit on behalf of third parties outstanding. The following significant

guarantees and letters of credit are not included within the Consolidated Balance Sheets as at December

31, 2023:

TECO Energy has issued a guarantee in connection with SeaCoast’s performance of obligations under a

gas transportation precedent agreement. The guarantee is for a maximum potential amount of $45 million

USD if SeaCoast fails to pay or perform under the contract. The guarantee expires five years after the

gas transportation precedent agreement termination date, which was terminated on January 1, 2022. In

the event TECO Energy’s and Emera’s long-term senior unsecured credit ratings are downgraded below

investment grade by Moody’s or S&P, TECO Energy would be required to provide its counterparty a letter

of credit or cash deposit of $27 million USD.

TECO Energy issued a guarantee in connection with SeaCoast’s performance obligations under a firm

service agreement, which expires December 31, 2055, subject to two extension terms at the option of the

counterparty with a final expiration date of December 31, 2071. The guarantee is for a maximum potential

amount of $13 million USD if SeaCoast fails to pay or perform under the firm service agreement. In the

event that TECO Energy’s long-term senior unsecured credit ratings are downgraded below investment

grade by Moody’s or S&P, TECO Energy would need to provide either a substitute guarantee from an

affiliate with an investment grade credit rating or a letter of credit or cash deposit of $13 million USD.

Emera Inc. has issued a guarantee of $66 million USD relating to outstanding notes of ECI. This

guarantee will automatically terminate on the date upon which the obligations have been repaid in full.

Exhibit 99.2

40

NSPI has issued guarantees on behalf of its subsidiary, NS Power Energy Marketing Incorporated, in the

amount of $104 million USD (2022 – $119 million USD) with terms of varying lengths.

The Company has standby letters of credit and surety bonds in the amount of $103 million USD

(December 31, 2022 – $145 million USD) to third parties that have extended credit to Emera and its

subsidiaries. These letters of credit and surety bonds typically have a one-year term and are renewed

annually as required.

Emera Inc., on behalf of NSPI, has a standby letter of credit to secure obligations under a supplementary

retirement plan. The expiry date of this letter of credit was extended to June 2024. The amount committed

as at December 31, 2023 was $56 million (December 31, 2022 – $63 million).

DIVIDEND PAYOUT RATIO

Emera has provided annual dividend growth guidance of four to five per cent through 2026. The

Company targets a long-term dividend payout ratio of adjusted net income of 70 to 75 per cent and, while

the payout ratio is likely to exceed that target through and beyond the forecast period, it is expected to

return to that range over time. Emera’s common share dividends paid in 2023 were $2.7875 ($0.6900 in

Q1, Q2, and Q3 and $0.7175 in Q4) per common share and $2.6775 ($0.6625 in Q1, Q2, and Q3 and

$0.6900 in Q4) per common share for 2022, representing a dividend payout ratio of 78 per cent in 2023

(2022 – 75 per cent) and a dividend payout ratio of adjusted net income of 94 per cent in 2023 (2022 – 83

per cent). 

On September 20, 2023, the Board approved an increase in the annual common share dividend rate to

$2.87 from $2.76 per common share. The first quarterly dividend payment at the increased rate was paid

on November 15, 2023.

TRANSACTIONS WITH RELATED PARTIES

In the ordinary course of business, Emera provides energy and other services and enters into

transactions with its subsidiaries, associates and other related companies on terms similar to those

offered to non-related parties. Intercompany balances and intercompany transactions have been

eliminated on consolidation, except for the net profit on certain transactions between non-regulated and

regulated entities in accordance with accounting standards for rate-regulated entities. All material

amounts are under normal interest and credit terms. 

Significant transactions between Emera and its associated companies are as follows:

●

 Transactions between NSPI and NSPML related to the Maritime Link assessment are reported in the

Consolidated Statements of Income. NSPI’s expense is reported in Regulated fuel for generation and

purchased power, totalling $163 million for the year ended December 31, 2023 (2022 – $157 million).

NSPML is accounted for as an equity investment, and therefore corresponding earnings related to

this revenue are reflected in Income from equity investments. For further details, refer to the

“Business Overview and Outlook - Canadian Electric Utilities – ENL” and “Contractual Obligations”

sections.

●

Natural gas transportation capacity purchases from M&NP are reported in the Consolidated

Statements of Income. Purchases from M&NP reported net in Operating revenues, Non-regulated,

totalled $14 million for the year ended December 31, 2023 (2022

– $9 million).

There were no significant receivables or payables between Emera and its associated companies reported

on Emera’s Consolidated Balance Sheets as at December 31, 2023 and at December 31, 2022.

Exhibit 99.2

41

ENTERPRISE RISK AND RISK MANAGEMENT

Emera has an enterprise-wide risk management process, overseen by its Enterprise Risk Management

Committee (“ERMC”) and monitored by the Board, to ensure an effective, consistent and coherent

approach to risk management. Certain risk management activities for Emera are overseen by the ERMC

to ensure such risks are appropriately identified, assessed, monitored and subject to appropriate controls. 

The Board has a Risk and Sustainability Committee (“RSC”) with a mandate to assist the Board in

carrying out its risk and sustainability oversight responsibilities. The RSC’s mandate includes oversight of

the Company’s Enterprise Risk Management framework, including the identification, assessment,

monitoring and management of enterprise risks. It also includes oversight of the Company’s approach to

sustainability and its performance relative to its sustainability objectives.

The Company’s financial risk management activities are focused on those areas that most significantly

impact profitability, quality and consistency of income, and cash flow. Emera’s risk management focus

extends to key operational risks including safety and environment, which represent core values of Emera.

In this section, Emera describes the principal risks that management believes could materially affect its

business, revenues, operating income, net income, net assets, liquidity or capital resources. The nature

of risk is such that no list is comprehensive, and other risks may arise or risks not currently considered

material may become material in the future.

Regulatory and Political Risk

The Company’s rate-regulated subsidiaries and certain investments subject to significant influence are

subject to risk of the recovery of costs and investments. Regulatory and political risk can include changes

in regulatory frameworks, shifts in government policy, legislative changes, and regulatory decisions.

As cost-of-service utilities with an obligation to serve customers, Emera’s utilities operate under formal

regulatory frameworks, and must obtain regulatory approval to change or add rates and/or riders. Emera

also holds investments in entities in which it has significant influence, and which are subject to regulatory

and political risk including NSPML, LIL, and M&NP. As a regulated Group II pipeline, the tolls of

Brunswick Pipeline are regulated by the CER on a complaint basis, as opposed to the regulatory approval

process described above. In the absence of a complaint, the CER does not normally undertake a detailed

examination of Brunswick Pipeline’s tolls, which are subject to a firm service agreement, expiring in 2034,

with Repsol Energy North America Canada Partnership. 

Regulators administer the regulatory frameworks covering material aspects of the utilities’ businesses,

including applying market-based tests to determine the appropriate customer rates and/or riders, the

underlying allowed ROEs, deemed capital structures, capital investment, the terms and conditions for the

provision of service, performance standards, and affiliate transactions. Regulators also review the

prudency of costs and other decisions that impact customer rates and reliability of service and work to

ensure the financial health of the utility for the benefit of customers. Costs and investments can be

recovered upon approval by the respective regulator as an adjustment to rates and/or riders, which

normally require a public hearing process or may be mandated by other governmental bodies. During

public hearing processes, consultants and customer representatives scrutinize the costs, actions and

plans of these rate-regulated companies, and their respective regulators determine whether to allow

recovery and to adjust rates based upon the evidence and any contrary evidence from other parties. In

some circumstances, other government bodies may influence the setting of rates. Regulatory decisions,

legislative changes, and prolonged delays in the recovery of costs or regulatory assets could result in

decreased rate affordability for customers and could materially affect Emera and its utilities. 

Exhibit 99.2

42

Emera’s utilities generally manage this risk through transparent regulatory disclosure, ongoing

stakeholder and government consultation, and multi-party engagement on aspects such as utility

operations, regulatory audits, rate filings and capital plans. The subsidiaries work to establish

collaborative relationships with regulatory stakeholders, including customer representatives, both through

its approach to filings and additional efforts with technical conferences and, where appropriate, negotiated

settlements. 

Changes in government and shifts in government policy and legislation can impact the commercial and

regulatory frameworks under which Emera and its subsidiaries operate. This includes initiatives regarding

deregulation or restructuring of the energy industry. Deregulation or restructuring of the energy industry

may result in increased competition and unrecovered costs that could adversely affect the Company’s

operations, net income and cash flows. State and local policies in some United States jurisdictions have

sought to prevent or limit the ability of utilities to provide customers the choice to use natural gas while in

other jurisdictions policies have been adopted to prevent limitations on the use of natural gas. Changes in

applicable state or local laws and regulations, including electrification legislation, could adversely impact

PGS and NMGC.

Emera cannot predict future legislative, policy, or regulatory changes, whether caused by economic,

political or other factors, or its ability to respond in an effective and timely manner or the resulting

compliance costs. Government interference in the regulatory process can undermine regulatory stability,

predictability, and independence, and could have a material adverse effect on the Company.

Global Climate Change Risk

The Company is subject to risks that may arise from the impacts of climate change. There is increasing

public concern about climate change and growing support for reducing carbon dioxide emissions.

Municipal, state, provincial and federal governments have been setting policies and enacting laws and

regulations to deal with climate change impacts in a variety of ways, including decarbonization initiatives

and promotion of cleaner energy and renewable energy generation of electricity. Refer to “Changes in

Environmental Legislation” risk below. Insurance companies have begun to limit their exposure to coal-

fired electricity generation and are evaluating the medium and long-term impacts of climate change which

may result in fewer insurers, more restrictive coverage and increased premiums. Refer to the “Insurance”

section below and “Uninsured Risk”.

Climate change may lead to increased frequency and intensity of events and related impacts such as

hurricanes, ice and other storms, heavy rainfall, cyclones, extreme winds, wildfires, flooding and

droughts. The potential impacts of climate change, such as rising sea levels and larger storm surges from

more intense hurricanes, can combine to produce even greater damage to coastal generation and other

facilities. Climate change is also characterized by rising global temperatures. Increased air temperatures

may bring increased frequency and severity of wildfires within the Company’s service territories. Refer to

“Weather Risk” and “System Operating and Maintenance Risks”.

The Company’s long-term capital investment plan includes significant investment across the portfolio in

renewable and cleaner generation, infrastructure modernization, storm hardening, energy storage and

customer-focused technologies. All these initiatives contribute toward mitigating the potential impacts of

climate change. The Company continues to engage with government, regulators, industry partners and

stakeholders to share information and participate in the development of climate change related policies

and initiatives. 

Exhibit 99.2

43

Physical Impacts:

The Company is subject to physical risks that arise, or may arise, from global climate change, including

damage to operating assets from more frequent and intense weather events and from wildfires due to

warming air temperatures and increasing drought conditions. Substantially all of the Company’s fossil

fueled generation assets are located at or near coastal sites and, as such, are exposed to the separate

and combined effects of rising sea levels and increasing storm intensity, including storm surges and

flooding. Refer to “Weather Risk” for further information.

These risks are mitigated to an extent through features such as flood walls at certain plants and through

the location of plants on higher ground. Planned investments in under-grounding parts of the electricity

infrastructure contribute to risk mitigation, as does insurance coverage (for assets other than electricity

transmission and distribution assets). In addition, implementation of regulatory mechanisms for recovery

of costs, such as storm reserves and regulatory deferral accounts, help smooth out the recovery of storm

restoration costs over time. 

Reputation:

Failure to address issues related to climate change could affect Emera’s reputation with stakeholders, its

ability to operate and grow, and the Company’s access to, and cost of, capital. Refer to “Liquidity and

Capital Market Risk”. The Company seeks to mitigate this in part by moving away from higher-carbon

generation in favour of lower-carbon generation and non-emitting renewable generation.

Supply Chain:

Changing carbon-related costs, policy and regulatory changes and shifts in supply and demand factors

could lead to more expensive or more scarce products and services that are required by the Company in

its operations. This could lead to supply shortages, delivery delays and the need to source alternate

products and services. The Company seeks to mitigate these risks through close monitoring of such

developments and adaptive changes to supply chain procurement strategies. Refer to “Supply Chain

Risk” and “Uninsured Risk”.

Insurance:

Given concerns regarding carbon-emitting generation, assets and businesses may, over time, become

difficult (or uneconomic) to insure in commercial insurance markets. In the short term, this may be

mitigated through increased investment in engineered protection or alternative risk financing (such as

funded self-insurance or regulatory structures, including storm reserves). Longer-term mitigation may be

achieved through infrastructure siting decisions and further engineered protections. This risk may also be

mitigated through the continued transition away from high-carbon generation sources to sources with low

or zero carbon dioxide emissions.

Policy:

Government and regulatory initiatives, including greenhouse gas emissions standards, air emissions

standards and generation mix standards, are being proposed and adopted in many jurisdictions in

response to concerns regarding the effects of climate change. In some jurisdictions, government policy

has included timelines for mandated shutdowns of coal generating facilities, percentage of electricity

generation from renewables, carbon pricing, emissions limits and cap and trade mechanisms. Over the

medium and longer terms, this could potentially lead to a significant portion of hydrocarbon infrastructure

assets being subject to additional regulation and limitations in respect of GHG emissions and operations. 

The Company is subject to climate-related and environmental legislative and regulatory requirements.

Such legislative and regulatory initiatives could adversely affect Emera’s operations and financial

performance. Refer to “Regulatory and Political Risk” and “Changes in Environmental Legislation” risk.

The Company seeks to mitigate these risks through active engagement with governments and regulators

to pursue transition strategies that meet the needs of customers, stakeholders and the Company. This

has included NSPI’s participation in negotiated equivalency agreements in Nova Scotia to provide for an

affordable transition to lower-carbon generation. Equivalency agreements allow NSPI to achieve

compliance with federal GHG emissions regulations by meeting provincial legislative and regulatory

requirements as they are deemed to be equivalent. There is no guarantee that such equivalency

agreements will be renewed or remain in force in the future.

Exhibit 99.2

44

Regulatory:

Depending on the regulatory response to government legislation and regulations, the Company may be

exposed to the risk of reduced recovery through rates in respect of the affected assets. Valuation

impairments could result from such regulatory outcomes. Mitigation efforts in respect of these risks

include active engagement with policy makers and regulators to find mechanisms to avoid such impacts

while being responsive to customers’ and stakeholders’ objectives.

Legal:

The Company could face litigation or regulatory action related to environmental harms from carbon

dioxide emissions or climate change public disclosure issues. The Company addresses these risks

through compliance with all relevant laws, emissions reduction strategies, and public disclosure of climate

change risks.

Water Resources:

For thermal plants requiring cooling water, reduced availability of water resulting from climate change

could adversely impact operations or the costs of operations. The Company seeks ways to reduce and

recycle water as it does in its Polk power plant in Florida, where recovered and treated wastewater is

used in operations to reduce reliance on fresh water supplies in an area where water is not as abundant

as in other markets.

The Company operates hydroelectric generation in certain of its markets. Such generation depends on

availability of water and the hydrological profile of water sources. Changes in precipitation patterns, water

temperatures and air temperatures could adversely affect the availability of water and consequently the

amount of electricity that may be produced from such facilities. The Company is reinvesting in the

efficiency of certain hydroelectric generation facilities to increase generation capacity and continues to

monitor changing hydrology patterns. Such issues may also affect the availability of purchased power

from third-party owned hydroelectricity sources.

Weather Risk

The Company is subject to risks that arise or may arise from weather including seasonal variations

impacting energy sales, more frequent and intense weather events, changing air temperatures, wildfires

and extreme weather conditions associated with climate change. Refer to “Global Climate Change Risk”.

Fluctuations in the amount of electricity or natural gas used by customers can vary significantly in

response to seasonal changes in weather and could impact the operations, results of operations, financial

condition, and cash flows of the Company’s utilities. For example, TEC could see lower demand in

summer months if temperatures are cooler than expected. Further, extreme weather conditions such as

hurricanes and other severe weather conditions which may be associated with climate change could

cause these seasonal fluctuations to be more pronounced. In the absence of a regulatory recovery

mechanism for unanticipated costs, such events could influence the Company’s results of operations,

financial conditions or cash flows.

Extreme weather events create a risk of physical damage to the Company’s assets. High winds can

impact structures and cause widespread damage to transmission and distribution infrastructure, solar

generation, and wind powered generation. Higher frequency and severity of weather events increase the

likelihood of longer power outages and more fuel supply disruptions. Increased frequency and intensity of

flooding and storm surge could adversely affect the operations of utilities and in particular generation

assets. The impact of extreme weather events would be amplified if the same events affect multiple

utilities.

Exhibit 99.2

45

Each of Emera’s regulated electric utilities have programs for storm hardening of transmission and

distribution facilities to minimize damage, but there can be no assurance that these measures will fully

mitigate the risk. This risk to transmission and distribution facilities is typically not insured, and as such

the restoration cost is generally recovered through regulatory processes, either in advance through

reserves or designated self-insurance funds, or after the fact through the establishment of regulatory

assets. Recovery is not assured and is subject to prudency review. The risk to generation assets is, in

part, mitigated through the design, siting, construction and maintenance of such facilities, regular risk

assessments, engineered mitigation, emergency storm response plans, and insurance. 

High winds and lack of precipitation increase the risk of wildfires resulting from the Company’s

infrastructure or for which the Company may otherwise have responsibility. The risk of wildfires is

addressed primarily through asset management programs for natural gas transmission and distribution

operations, and asset management, storm hardening, and vegetation management programs for electric

utilities, but there can be no assurance that these measures will fully mitigate the risk. If it is found to be

responsible for such a fire, the Company could suffer material costs, losses and damages, all or some of

which may not be recoverable through insurance, legal, regulatory cost recovery or other processes. If

not recovered through these means, they could materially affect Emera’s business, access to capital,

financial condition and results of operations including its reputation with customers, regulators,

governments and financial markets. Resulting costs could include fire suppression costs, regeneration,

timber value, increased insurance costs and costs arising from damages and losses incurred by third

parties. 

Changes in Environmental Legislation 

Emera is subject to regulation by federal, provincial, state, regional and local authorities regarding

environmental matters, primarily related to its utility operations. This includes laws setting GHG emissions

standards and air emissions standards. Emera is also subject to laws regarding waste management,

wastewater discharges and aquatic and terrestrial habitats.

Changes to GHG emissions standards and air emissions standards could adversely affect Emera’s

operations and financial performance. 

Both the Government of Nova Scotia and the Government of Canada have enacted or introduced

legislation that includes goals of net-zero GHG emissions by 2050. The Province of Nova Scotia has

established targets with respect to the percentage of renewable energy in NSPI’s generation mix,

reductions in GHG emissions, as well as the goal to phase out coal-fired electricity generation by 2030.

Failure to meet such goals by 2030 could result in material fines, penalties, other sanctions and adverse

reputational impacts. NSPI continues to work with both the provincial and federal governments on

measures to seek to address their carbon reduction goals. Within Emera’s natural gas utilities, there are

ongoing efforts to reduce methane and carbon dioxide emissions through replacement of aging

infrastructure, more efficient operations, operational and supply chain optimization, renewable natural gas

projects, and support of public policy initiatives that address the effects of climate change.

In 2023, the United States Environmental Protection Agency proposed new carbon emission standards

for fossil fuel-fired power plants and the Government of Canada released draft Clean Electricity

Regulations which propose limitations on the use of natural gas generation. Until final rules are issued, it

is not certain what the impact will be on the Company and its operations. 

These and other legislative or regulatory changes could influence decisions regarding capital investment,

early retirement of generation facilities and may result in stranded costs if the Company is not able to fully

recover the costs and investment in the affected generation assets. Recovery is not assured and is

subject to prudency review. Legislative or regulatory changes may curtail sales of natural gas to new

customers, which could reduce future customer growth in Emera’s natural gas businesses. Stricter

environmental laws and enforcement of such laws in the future could increase Emera’s exposure to

additional liabilities and costs. These changes could also affect earnings and strategy by changing the

nature and timing of capital investments.

Exhibit 99.2

46

Per- and polyfluoroalkyl substances (“PFAS”) are man-made chemicals that are widely used in consumer

products and can persist and bio-accumulate in the environment. The Company does not manufacture

PFAS but because these emerging contaminants of concern are so ubiquitous in products and the

environment, it may impact Emera’s operations. Changes in environmental laws and regulations related

to PFAS could result in new costs or obligations for investigation and cleanup and change the Company’s

strategy for land acquisition for projects such as solar generation.

In addition to imposing continuing compliance obligations, there are permit requirements, laws and

regulations authorizing the imposition of penalties for non-compliance, including fines, injunctive relief,

and other sanctions. The cost of complying with current and future environmental requirements is, and

may be, material to Emera. Failure to comply with environmental requirements or to recover

environmental costs in a timely manner through rates, could have a material adverse effect on Emera. In

addition, Emera’s business could be materially affected by changes in government policy, utility

regulation, and environmental and other legislation that could occur in response to environmental and

climate change concerns. 

Emera manages its environmental risk by operating in a manner that is respectful and protective of the

environment and in compliance with applicable legal requirements and Company policy. Emera has

implemented this policy through the development and application of environmental management systems

in its operating subsidiaries. Comprehensive audit programs are in place to regularly assess compliance. 

Cybersecurity Risk

Emera is exposed to potential risks related to cyberattacks and unauthorized access. The Company relies

on IT systems, cloud infrastructure, third-party service providers and the diligence of its team members to

effectively manage and safely operate its assets. This includes controls for interconnected systems of

generation, distribution and transmission as well as financial, billing and other enterprise systems. As the

Company operates critical assets, it may be at greater risk of cyberattacks, which could include those

from nation-state cyber threat actors. Major emerging and ongoing global conflicts may also elevate this

risk. 

Cyberattacks can reach the Company’s assets and information via their interfaces with third parties or the

public internet and gain access to critical infrastructures. Cyberattacks can also occur via personnel with

access to critical assets or trusted networks. Methods used to attack critical assets could include generic

or energy-sector-specific malware delivered via network transfer, removable media, attachments, or links

in e-mails. The methods used by attackers are continuously evolving and can be difficult to predict and

detect.

Despite security measures in place, that are described below, the Company’s systems, assets and

information could experience security breaches that could cause system failures, disrupt operations, or

adversely affect safety. Such breaches could compromise customer, employee-related or other

information systems and could result in loss of service to customers, unavailability of critical assets, safety

issues, or the release, destruction, or misuse of critical, sensitive or confidential information. These

breaches could also delay delivery or result in contamination or degradation of hydrocarbon products the

Company transports, stores or distributes. 

Cyberattacks or unauthorized accesses may cause lost revenues, costs, losses and damages all, or

some of which, may not be recoverable (through insurance, legal, regulatory cost recovery or other

processes). This could materially adversely affect Emera’s business and financial results including its

reputation with customers, regulators, governments and financial markets. Resulting costs could include,

amongst others, response, recovery and remediation costs, increased protection or insurance costs and

costs arising from damages and losses incurred by third parties. If any such security breaches occur,

there is no assurance they can be adequately addressed in a timely manner.

Exhibit 99.2

47

The Company seeks to manage these risks by aligning to a common set of cybersecurity standards and

policies derived, in part, on the National Institute of Standards and Technology’s Cyber Security

Framework, periodic security testing, program maturity objectives, cybersecurity incident readiness

program, and employee communication and training. With respect to certain of its assets, the Company is

required to comply with rules and standards relating to cybersecurity and IT including, but not limited to,

those mandated by bodies such as the North American Electric Reliability Corporation, Northeast Power

Coordinating Council, and the United States Department of Homeland Security. The status of key

elements of the Company’s cybersecurity program is reported to the RSC. The Board oversees risk and

mitigation plans in relation to cybersecurity risks and receives a quarterly update in a risk dashboard at

each regularly scheduled Board meeting. 

Public Health Risk

An outbreak of infectious disease, a pandemic or a similar public health threat, or a fear of any of the

foregoing, could adversely impact the Company, including causing operating, supply chain and project

development delays and disruptions, labour shortages and shutdowns (including as a result of

government regulation and prevention measures), which could have a negative impact on the Company’s

operations.

Any adverse changes in general economic and market conditions arising as a result of a public health

threat could negatively impact demand for electricity and natural gas, revenue, operating costs, timing

and extent of capital expenditures, results of financing efforts, or credit risk and counterparty risk; which

could result in a material adverse effect on the Company’s business. The Company maintains pandemic

and business contingency plans in each of its operations to manage and help mitigate the impact of any

such public health threat. 

Energy Consumption Risk

Emera’s rate-regulated utilities are affected by demand for energy based on changing customer patterns

due to fluctuations in a number of factors including general economic conditions, weather events,

customers’ focus on energy efficiency, changes in rates, and advancements in new technologies such as

rooftop solar, electric vehicles and battery storage. Government policies promoting distributed generation,

and new technology developments that enable those policies, have the potential to impact how electricity

enters the system and how it is bought and sold. In addition, increases in distributed generation may

impact demand resulting in lower load and revenues. These changes could negatively impact Emera’s

operations, rate base, net earnings, and cash flows. The Company’s rate-regulated utilities are focused

on understanding customer demand, energy efficiency, and government policy to ensure that the impact

of these activities benefit customers, that they do not negatively impact the reliability of the energy service

and that they are addressed through regulations.

Foreign Exchange Risk 

The Company is exposed to foreign currency exchange rate changes. Emera operates internationally,

with an increasing amount of the Company’s net income earned outside of Canada. As such, Emera is

exposed to movements in exchange rates between the CAD and, particularly, the USD, which could

positively or adversely affect results.

Consistent with the Company’s risk management policies, Emera manages currency risks through

matching United States denominated debt to finance its United States operations and may use foreign

currency derivative instruments to hedge specific transactions and earnings exposure. The Company may

enter FX forward and swap contracts to limit exposure on certain foreign currency transactions such as

fuel purchases, revenue streams and capital expenditures, and on net income earned outside of Canada.

The regulatory framework for the Company’s rate-regulated subsidiaries permits the recovery of prudently

incurred costs, including FX.

Exhibit 99.2

48

The Company does not utilize derivative financial instruments for foreign currency trading or speculative

purposes or to hedge the value of its investments in foreign subsidiaries. Exchange gains and losses on

net investments in foreign subsidiaries do not impact net income as they are reported in Accumulated

Other Comprehensive Income (Loss) ("AOCI”) (“AOCL”).

Liquidity and Capital Market Risk

Liquidity risk relates to Emera’s ability to ensure sufficient funds are available to meet its financial

obligations. Emera manages this risk by forecasting cash requirements on a continuous basis to

determine whether sufficient funds are available. Liquidity and capital needs could be financed through

internally generated cash flows, asset sales, short-term credit facilities, and ongoing access to capital

markets. The Company reasonably expects liquidity sources to meet capital needs.

Emera’s access to capital and cost of borrowing is subject to several risk factors, including financial

market conditions, market disruptions and ratings assigned by various market analysts, including credit

rating agencies. Disruptions in capital markets could prevent Emera from issuing new securities or cause

the Company to issue securities with less than preferred terms and conditions. Emera’s growth plan

requires significant capital investments in PP&E and the risk associated with changes in interest rates

could have an adverse effect on the cost of financing. The Company’s future access to capital and cost of

borrowing may be impacted by various market disruptions. The inability to access cost-effective capital

could have a material impact on Emera’s ability to fund its growth plan. 

Emera is subject to financial risk associated with changes in its credit ratings. There are a number of

factors that rating agencies evaluate to determine credit ratings, including the Company’s business, its

regulatory framework and legislative environment, political interference in the regulatory process, the

ability to recover costs and earn returns, diversification, leverage, liquidity and increased exposure to

climate change-related impacts, including increased frequency and severity of hurricanes and other

severe weather events. A decrease in a credit rating could result in higher interest rates in future

financings, increased borrowing costs under certain existing credit facilities, limit access to the

commercial paper market, or limit the availability of adequate credit support for subsidiary operations. For

more information on interest rate risk, refer to “General Economic Risk – Interest Rate Risk”. For certain

derivative instruments, if the credit ratings of the Company were reduced below investment grade, the full

value of the net liability of these positions could be required to be posted as collateral. Emera manages

these risks by actively monitoring and managing key financial metrics with the objective of sustaining

investment grade credit ratings.

The Company has exposure to its own common share price through the issuance of various forms of

stock-based compensation, which affect earnings through revaluation of the outstanding units every

period. The Company uses equity derivatives to reduce the earnings volatility derived from stock-based

compensation.

General Economic Risk

The Company has exposure to the macro-economic conditions in North America and in other geographic

regions in which Emera operates. Like most utilities, economic factors such as consumer income,

employment and housing affect demand for electricity and natural gas and, in turn, the Company’s

financial results. Adverse changes in general economic conditions and inflation may impact the ability of

customers to afford rate increases arising from increases to fuel, operating, capital, environmental

compliance, and other costs, and therefore could materially affect Emera and its utilities. This may also

result in higher credit and counterparty risk, adverse shifts in government policy and legislation, and/or

increased risk to full and timely recovery of costs and regulatory assets.

Exhibit 99.2

49

Interest Rate Risk:

Emera utilizes a combination of fixed and floating rate debt financing for operations and capital

expenditures, resulting in an exposure to interest rate risk. Emera seeks to manage interest rate risk

through a portfolio approach that includes the use of fixed and floating rate debt with staggered

maturities. The Company will, from time to time, issue long-term debt or enter interest rate hedging

contracts to limit its exposure to fluctuations in floating interest rate debt.

For Emera’s regulated subsidiaries, the cost of debt is a component of rates and prudently incurred debt

costs are recovered from customers. Regulatory ROE will generally follow the direction of interest rates,

such that regulatory ROEs are likely to fall in times of reducing interest rates and rise in times of

increasing interest rates, albeit not directly and generally with a lag period reflecting the regulatory

process. Rising interest rates may also negatively affect the economic viability of project development

and acquisition initiatives.

Interest rates could also be impacted by changes in credit ratings. For more information, refer to “Liquidity

and Capital Market Risk”. 

As with most other utilities and other similar yield-returning investments, Emera’s share price may be

affected by changes in interest rates and could underperform the market in an environment of rising

interest rates.

Inflation Risk:

The Company may be exposed to changes in inflation that may result in increased operating and

maintenance costs, capital investment, and fuel costs compared to the revenues provided by customer

rates. Emera’s utilities have budgeting and forecasting processes to identify inflationary risk factors and

measure operating performance, as well as collective bargaining agreements that mitigate the short-term

impact of inflation on labour costs of unionized employees.

Project Development and Land Use Rights Risk

The Company’s capital plan includes significant investment in generation, infrastructure modernization,

and customer-focused technologies. Any projects planned or currently in construction, particularly

significant capital projects, may be subject to risks including, but not limited to, impact on costs from

schedule delays, increased demand for renewable energy inputs, risk of cost overruns, ensuring

compliance with operating and environmental requirements and other events within or beyond the

Company’s control. The Company’s projects may also require approvals and permits at the federal,

provincial, state, regional and local levels. There is no assurance that Emera will be able to obtain the

necessary project approvals or applicable permits or receive regulatory approval to recover the costs in

rates.

Some of the Company’s assets are located on land owned by third parties, including Indigenous Peoples,

and may be subject to land claims. Present or future assets may be located on lands that have been used

for traditional purposes and therefore subject to specific consultations, consents, or conditions for

development or operation. If the Company’s rights to locate and operate its assets on any such lands are

subject to expiry or become invalid, it may incur material costs to renew rights or obtain such rights. If

reasonable terms for land-use rights cannot be negotiated, the Company may incur significant costs to

remove and relocate its assets and restore the land. Additional costs incurred could cause projects to be

uneconomical to proceed with.

Emera manages these project development and land use rights risks by deploying robust project and risk

management approaches, led by teams with extensive experience in large projects. The Company

consults with Indigenous Peoples in obtaining approvals, constructing, maintaining and operating such

facilities, consistent with laws and public policy frameworks. Emera maintains relationships through on-

going communications with stakeholders, including Indigenous Peoples, landowners and governments.

Exhibit 99.2

50

Counterparty Risk

Emera is exposed to risk related to its reliance on certain key partners, suppliers, and customers, any of

which may endure financial challenges resulting from commodity price and market volatility, economic

instability or adversity, adverse political or regulatory changes and other causes which may cause or

contribute to such parties’ insolvency, bankruptcy, restructuring or default on their contractual obligations

to Emera. Emera is also exposed to potential losses related to amounts receivable from customers,

energy marketing collateral deposits and derivative assets due to a counterparty’s non-performance

under an agreement.

Emera manages this counterparty risk through due diligence and third-party risk assessment processes

prior to signing contracts, contractual rights and remedies, regulatory frameworks, and by monitoring

significant developments with its customers, partners and suppliers. The Company also manages credit

risk with policies and procedures for counterparty analysis, exposure measurement, and exposure

monitoring and mitigation. Credit assessments may be conducted on new customers and counterparties,

and deposits or collateral may be requested on certain accounts. There is no assurance that

management strategies will be effective, and significant counterparty defaults could have a material effect

on the Company.

Country Risk

The majority of Emera’s earnings are from outside of Canada, mostly concentrated in the United States.

Emera’s investments are currently in regions where political and economic risks are considered by the

Company to be acceptable. For more information, refer to the “Regulatory and Political Risk” and

“General Economic Risk” sections above. Emera’s operations in some countries may be subject to

changes in economic growth, restrictions on the repatriation of income or capital exchange controls,

inflation, the effect of global health, safety and environmental matters, including climate change, or

economic conditions and market conditions, and change in financial policy and availability of credit. The

Company mitigates this risk through a rigorous approval process for investment, and by forecasting cash

requirements on a continuous basis to determine whether sufficient funds are available in all affiliates. 

Supply Chain Risk

Emera’s ability to meet customer energy requirements, respond to storm-related disruptions and execute

on our capital program in a cost-effective and timely manner are dependent on maintaining an efficient

supply chain. Domestic and global supply chain issues may delay the delivery or result in shortages of

certain materials, equipment and other resources that are critical to the Company’s operations. These

disruptions may be further exacerbated by inflationary pressures, labour shortages, government

incentives increasing demand for clean energy projects, and the impact of international conflicts, tariffs, or

other trade restrictions. Failure to eliminate or manage supply chain constraints may impact the

availability and cost of items and labour that are necessary to support operations and capital investment.

Emera continues to monitor the situation and seeks to mitigate the impacts of supply chain risk by

securing alternative suppliers, third party risk management, modifying design standards, and adjusting

the timing of work.

Commodity Price Risk

The Company’s utility fuel supply and purchase of other commodities is subject to commodity price risk.

In addition, Emera Energy is subject to commodity price risk through its portfolio of commodity contracts

and arrangements.

Exhibit 99.2

51

The Company manages this risk through established processes and practices to identify, monitor, report

and mitigate these risks. These include the Company’s commercial arrangements, such as the

combination of supply and purchase agreements, asset management agreements, pipeline transportation

agreements, and financial hedging instruments. In addition, its credit policies, counterparty credit

assessments, market and credit position reporting, and other risk management and reporting practices,

are also used to manage and mitigate this risk.

Regulated Utilities:

The Company’s utility fuel supply is exposed to broader global conditions, which may include impacts on

delivery reliability and price, despite contracted terms. Supply and demand dynamics in fuel markets can

be affected by a wide range of factors which are difficult to predict and may change rapidly, including but

not limited to, currency fluctuations, changes in global economic conditions, natural disasters,

transportation or production disruptions, and geo-political risks, such as political instability, conflicts,

changes to international trade agreements, trade sanctions or embargos. The Company seeks to manage

this risk using financial hedging instruments and physical contracts and through contractual protection

with counterparties, where applicable. 

The majority of Emera’s regulated electric and gas utilities have adopted and implemented fuel

adjustment mechanisms and purchased gas adjustment mechanisms respectively, which further helps

manage commodity price risk, as the regulatory framework for the Company’s rate-regulated subsidiaries

permits the recovery of prudently incurred fuel and gas costs. There is no assurance that such

mechanisms and regulatory frameworks will continue to exist in the future. Prolonged and substantial

increases in fuel prices could result in decreased rate affordability, increased risk of recovery of costs or

regulatory assets, and/or negative impacts on customer consumption patterns and sales.

Emera Energy Marketing and Trading:

Emera Energy has employed further measures to manage commodity risk. The majority of Emera

Energy’s portfolio of electricity and gas marketing and trading contracts and, in particular, its natural gas

asset management arrangements, are contracted on a back-to-back basis, avoiding any material long or

short commodity positions. However, the portfolio is subject to commodity price risk, particularly with

respect to basis point differentials between relevant markets in the event of an operational issue or

counterparty default. Changes in commodity prices can also result in increased collateral requirements

associated with physical contracts and financial hedges, resulting in higher liquidity requirements and

increased costs to the business.

To measure commodity price risk exposure, Emera Energy employs a number of controls and processes,

including an estimated VaR analysis of its exposures. The VaR amount represents an estimate of the

potential change in FV that could occur from changes in Emera Energy’s portfolio or changes in market

factors within a given confidence level, if an instrument or portfolio is held for a specified time period. The

VaR calculation is used to quantify exposure to market risk associated with physical commodities,

primarily natural gas and power positions.

Future Employee Benefit Plan Performance and Funding Risk

Emera subsidiaries have both defined benefit and defined contribution employee pension plans that cover

their employees and retirees. All defined benefit plans are closed to new entrants, except for the TECO

Energy Group Retirement Plan and the Grand Bahama Power Company Limited Union Employees’

Pension Plan. The cost of providing these benefit plans varies depending on plan provisions, interest

rates, inflation, investment performance and actuarial assumptions concerning the future. Actuarial

assumptions include earnings on plan assets, discount rates (interest rates used to determine funding

levels, contributions to the plans and the pension and post-retirement liabilities) and expectations around

future salary growth, inflation and mortality. Three of the largest drivers of cost are investment

performance, interest rates and inflation, which are affected by global financial and capital markets.

Depending on future interest rates and future inflation and actual versus expected investment

performance, Emera could be required to make larger contributions in the future to fund these plans,

which could adversely affect Emera’s cash flows, financial condition and operations.

Exhibit 99.2

52

Each of Emera’s employee defined benefit pension plans are managed according to an approved

investment policy and governance framework. Emera employs a long-term approach with respect to asset

allocation and each investment policy outlines the level of risk which the Company is prepared to accept

with respect to the investment of the pension funds in achieving both the Company’s fiduciary and

financial objectives. Studies are routinely undertaken approximately every five years with the objective

that the plans’ asset allocations are appropriate for meeting Emera’s long-term pension objectives.

Labour Risk

Emera’s ability to deliver service to its customers and to execute its growth plan depends on attracting,

developing and retaining a skilled workforce. Utilities are faced with demographic challenges related to

trades, technical staff and engineers with an increasing number of employees expected to retire over the

next several years. Failure to attract, develop and retain an appropriately qualified workforce could

adversely affect the Company’s operations and financial results. Emera seeks to manage this risk through

maintaining competitive compensation programs, a dedicated talent acquisition team, human resources

programs and practices, including ethics and diversity training, employee engagement surveys,

succession planning for key positions and apprenticeship programs.

Approximately 30 per cent of Emera’s labour force is represented by unions and subject to collective

labour agreements. The inability to maintain or negotiate future agreements on acceptable terms could

result in higher labour costs and work disruptions, which could adversely affect service to customers and

have an adverse effect on the Company’s earnings, cash flow and financial position. Emera seeks to

manage this risk through ongoing discussions and working to maintain positive relationships with local

unions. The Company maintains contingency plans in each of its operations to manage and reduce the

effect of any potential labour disruption.

IT Risk

Emera relies on various IT systems to manage operations. This subjects Emera to inherent costs and

risks associated with maintaining, upgrading, replacing and changing these systems. This includes

impairment of its IT, potential disruption of internal control systems, substantial capital expenditures,

demands on management time and other risks of delays, difficulties in upgrading existing systems,

transitioning to new systems or integrating new systems into its current systems. Emera’s digital

transformation strategy, including investment in infrastructure modernization and customer focused

technologies, is driving increased investment in IT solutions, resulting in increased project risks

associated with the implementation of these solutions. 

Emera manages these risks through IT asset lifecycle planning and management, governance, internal

auditing and testing of systems, and executive oversight. Employees with extensive subject matter

expertise assist in risk identification and mitigation, project management, implementation, change

management and training. System resiliency, formal disaster recovery and backup processes, combined

with critical incident response practices, table-top exercises, and simulations, help mitigate operational

disruptions. 

Income Tax Risk

The computation of the Company’s provision for income taxes is impacted by changes in tax legislation in

Canada, the United States and the Caribbean. Any such changes could affect the Company’s future

earnings, cash flows, and financial position. The value of Emera’s existing deferred income tax assets

and liabilities are determined by existing tax laws and could be negatively impacted by changes in laws.

Emera monitors the status of existing tax laws to ensure that changes impacting the Company are

appropriately reflected in the Company’s tax compliance filings and financial results.

Exhibit 99.2

53

System Operating and Maintenance Risks

The safe and reliable operation of electric generation and electric and natural gas transmission and

distribution systems is critical to Emera’s operations. There are a variety of hazards and operational risks

inherent in operating electric utilities and natural gas transmission and distribution pipelines. Electric

generation, transmission and distribution operations can be impacted by risks such as mechanical

failures, supply chain issues impacting timely access to critical equipment, activities of third parties,

terrorism, cyberattacks, damage to facilities, solar panels and infrastructure caused by hurricanes,

storms, falling trees, lightning strikes, floods, fires and other natural disasters. Natural gas pipeline

operations can also be impacted by risks such as leaks, explosions, mechanical failures, activities of third

parties, terrorism, cyberattacks, and damage to the pipeline facilities and equipment caused by

hurricanes, storms, floods, fires and other natural disasters. Refer to “Global Climate Change Risk” and

“Weather Risk”. Electric utility and natural gas transmission and distribution pipeline operation interruption

could negatively affect revenue, earnings, and cash flows as well as customer and public confidence, and

public safety.

Emera manages these risks by investing in a highly skilled workforce, operating prudently, preventative

maintenance, safety and operations management systems, third-party risk program, and making effective

capital investments. Insurance, warranties, or recovery through regulatory mechanisms may not cover

any or all these losses, which could adversely affect the Company’s results of operations and cash flows. 

Fuel Supply Disruptions:

Emera’s electric and natural gas utilities are also exposed to the risk of fuel supply chain disruptions, both

within and outside their service territories, which may be caused by severe weather or natural disasters.

This may also be caused by damage to, operational issues with, terrorist or cyberattacks on, third party

fuel production, storage, pipeline, and distribution facilities. The risk of fuel supply disruptions is managed

through contractual protections, maintaining a diversity of fuel suppliers and transportation contracts, and

contracting for access to third-party storage facilities. Significant unanticipated fuel supply disruptions

could result in increased exposure to commodity price risk for Emera’s regulated electric and gas utilities

and Emera Energy, and these could have adverse effects on service to utility customers and on the

Company’s reputation, earnings, cash flow and financial position. 

Uninsured Risk

Emera and its subsidiaries maintain insurance to cover accidental loss suffered to its facilities and to

provide indemnity in the event of liability to third parties. This is consistent with Emera’s risk management

policies. Certain facilities, in particular coal and other thermal generation, may, over time, become more

difficult (or uneconomic) to insure as a result of the impact of global climate change. Refer to “Global

Climate Change Risk – Markets”. There are certain elements of Emera’s operations which are not

insured. These include a significant portion of its electric utilities’ transmission and distribution assets and

its gas utilities’ distribution assets, as is customary in the industry. The cost of this coverage is not

economically viable. In addition, Emera accepts deductibles and self-insured retentions under its various

insurance policies. Insurance is subject to coverage limits as well as time sensitive claims discovery and

reporting provisions and there can be no assurance that the types of liabilities or losses that may be

incurred by the Company and its subsidiaries will be covered by insurance.

The occurrence of significant uninsured claims, claims in excess of the insurance coverage limits

maintained by Emera and its subsidiaries, or claims that fall within a significant self-insured retention

could have a material adverse effect on Emera’s results of operations, cash flows and financial position, if

regulatory recovery is not available.

The Company manages its insured risk by aligning insurance limits with risk exposures, and for uninsured

assets and operations, that appropriate risk assessments and mitigation measures are in place. The

regulatory framework for the Company’s rate-regulated subsidiaries permits the recovery of prudently

incurred costs, including uninsured losses. 

Exhibit 99.2

54

RISK MANAGEMENT INCLUDING FINANCIAL

INSTRUMENTS 

Emera’s risk management policies and procedures provide a framework through which management

monitors various risk exposures. Risk management policies and practices are overseen by the Board.

The Company has established a number of processes and practices to identify, monitor, report on and

mitigate material risks to the Company. This includes establishment of the ERMC, whose responsibilities

include preparing an updated risk dashboard and heat map presented at regular meetings of the Board’s

Risk and Sustainability Committee. Furthermore, a corporate team independent from operations is

responsible for tracking and reporting on market and credit risks.

The Company manages exposure to normal operating and market risks relating to commodity prices, FX,

interest rates and share prices through contractual protections with counterparties where practicable, and

by using financial instruments consisting mainly of FX forwards and swaps, interest rate options and

swaps, equity derivatives, and coal, oil and gas futures, options, forwards and swaps. In addition, the

Company has contracts for the physical purchase and sale of natural gas. These physical and financial

contracts are classified as HFT. Collectively, these contracts and financial instruments are considered

derivatives.

The Company recognizes the FV of all its derivatives on its balance sheet, except for non-financial

derivatives that meet the normal purchases and normal sales (“NPNS”) exception. Physical contracts that

meet the NPNS exception are not recognized on the balance sheet; these contracts are recognized in

income when they settle. A physical contract generally qualifies for the NPNS exception if the transaction

is reasonable in relation to the Company’s business needs, the counterparty owns or controls resources

within the proximity to allow for physical delivery, the Company intends to receive physical delivery of the

commodity, and the Company deems the counterparty creditworthy. The Company continually assesses

contracts designated under the NPNS exception and will discontinue the treatment of these contracts

under this exemption if the criteria are no longer met. 

Derivatives qualify for hedge accounting if they meet stringent documentation requirements and can be

proven to effectively hedge identified risk both at the inception and over the term of the instrument.

Specifically, for cash flow hedges, change in the FV of derivatives is deferred to AOCI and recognized in

income in the same period the related hedged item is realized. Where documentation or effectiveness

requirements are not met, the derivatives are recognized at FV with any changes in FV value recognized

in net income in the reporting period, unless deferred as a result of regulatory accounting.

Derivatives entered into by NSPI, NMGC and GBPC that are documented as economic hedges or for

which the NPNS exception has not been taken, are subject to regulatory accounting treatment. The

change in FV of the derivatives is deferred to a regulatory asset or liability. The gain or loss is recognized

in the hedged item when the hedged item is settled. Management believes any gains or losses resulting

from settlement of these derivatives related to fuel for generation and purchased power will be refunded

to or collected from customers in future rates. TEC has no derivatives related to hedging as a result of a

FPSC approved five-year moratorium on hedging of natural gas purchases that ended on December 31,

2022 and was extended through December 31, 2024 as a result of TEC’s 2021 rate case settlement

agreement.

Derivatives that do not meet any of the above criteria are designated as HFT, with changes in FV

normally recorded in net income of the period. The Company has not elected to designate any derivatives

to be included in the HFT category where another accounting treatment would apply.

Exhibit 99.2

55

Derivative Assets and Liabilities Recognized on the Balance Sheet

As at

December 31

December 31

millions of dollars

2023

2022

Regulatory Deferral:

Derivative instrument assets

(1)

$

 16

$

 238

Derivative instrument liabilities

(2)

 (76)

 (25)

Regulatory assets

(1)

 88

 30

Regulatory liabilities

  (2)

 (17)

 (230)

Net asset

$

 11

$

 13

HFT Derivatives: 

Derivative instrument assets

  (1)

$

 202

$

 153

Derivatives instruments liabilities

(2)

 (421)

 (1,025)

Net liability

$

 (219)

$

 (872)

Other Derivatives:

Derivative instrument assets

(1)

$

 22

$

 5

Derivatives instruments liabilities

  (2)

 (7)

 (28)

Net asset (liability)

$

 15

$

 (23)

(1) Current and other assets.

(2) Current and long-term liabilities. 

Realized and Unrealized Gains (Losses) Recognized in Net Income

For the

Year ended December 31

millions of dollars

2023

2022

Regulatory Deferral:

Regulated fuel for generation and purchased power

(1)

$

 62

$

 210

HFT Derivatives:

Non-regulated operating revenues

$

 1,037

$

 64

Other Derivatives:

OM&G

$

 (9)

$

 (22)

Other income, net

 17

 (24)

Net gains (losses)

$

 8

$

 (46)

Total net gains

$

 1,107

$

 228

(1) Realized gains (losses) on derivative instruments settled and consumed in the period, hedging relationships that have been

terminated or the hedged transaction is no longer probable. Realized gains (losses) recorded in inventory will be recognized in

“Regulated fuel for generation and purchased power” when the hedged item is consumed.

For the year ended December 31, 2023, unrealized gains of $2 million (2022 – $2 million), have been

reclassified out of AOCI into interest expense. 

As at

December 31, 2023

December 31, 2022

Interest rate

Interest rate

millions of dollars

hedge

hedge

Total unrealized gain in AOCI – net of tax

$

14

$

 16

DISCLOSURE AND INTERNAL CONTROLS

Management is responsible for establishing and maintaining adequate disclosure controls and

procedures (“DC&P”) and internal control over financial reporting (“ICFR”), as defined in National

Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings (“NI 52-109”). The

Company’s internal control framework is based on criteria published in the Internal Control Integrated

Framework (2013), a report issued by the Committee of Sponsoring Organizations (“COSO”) of the

Treadway Commission. Management, including the Chief Executive Officer and Chief Financial Officer,

evaluated the design and effectiveness of the Company’s DC&P and ICFR as at December 31, 2023 to

provide reasonable assurance regarding the reliability of financial reporting in accordance with USGAAP.

Exhibit 99.2

56

Management recognizes the inherent limitations in internal control systems, no matter how well designed.

Control systems determined to be appropriately designed can only provide reasonable assurance with

respect to the reliability of financial reporting and may not prevent or detect all misstatements.

There were no changes in the Company’s ICFR, during the year ended December 31, 2023, that have

materially affected, or are reasonably likely to materially affect, the Company’s internal control over

financial reporting.

CRITICAL ACCOUNTING ESTIMATES

The preparation of consolidated financial statements in accordance with USGAAP requires management

to make estimates and assumptions. These may affect reported amounts of assets and liabilities at the

date of the financial statements and reported amounts of revenues and expenses during the reporting

periods. Significant areas requiring use of management estimates relate to rate-regulated assets and

liabilities, accumulated reserve for cost of removal, pension and post-retirement benefits, unbilled

revenue, useful lives for depreciable assets, goodwill and long-lived assets impairment assessments,

income taxes, asset retirement obligations (“ARO”), and valuation of financial instruments. Management

evaluates the Company’s estimates on an ongoing basis based upon historical experience, current and

expected conditions and assumptions believed to be reasonable at the time the assumption is made, with

any adjustments recognized in income in the year they arise.

Rate Regulation

The rate-regulated accounting policies of Emera’s rate-regulated subsidiaries and regulated equity

investments are subject to examination and approval by their respective regulators and may differ from

the accounting policies of non-rate-regulated companies. Differences occur when regulators render their

decisions on rate applications or other matters, and generally involve a difference in the timing of revenue

and expense recognition. The accounting for these items is based on expectations of the future actions of

the regulators. Assumptions and judgments used by regulatory authorities continue to have an impact on

recovery of costs, rates earned on invested capital, and the timing and amount of assets to be recovered.

Application of regulatory accounting guidance is a critical accounting policy as a change in these

assumptions may result in a material impact on reported assets, liabilities and the results of operations.

As at December 31, 2023, the Company had recorded $3,105 million (2022 – $3,620 million) of regulatory

assets and $1,772 million (2022 – $2,273 million) of regulatory liabilities.

Accumulated Reserve – Cost of Removal

TEC, PGS, NMGC and NSPI recognize non-ARO costs of removal (“COR”) as regulatory liabilities. The

non-ARO COR represent estimated funds received from customers through depreciation rates to cover

future COR of PP&E upon retirement that are not legally required. The companies accrue for COR over

the life of the related assets based on depreciation studies approved by their respective regulators. Costs

are estimated based on historical experience and future expectations, including expected timing and

estimated future cash outlays. As at December 31, 2023, the balance of the Accumulated reserve – COR

within regulatory liabilities was $849 million (2022 – $895 million).

Pension and Other Post-Retirement Employee Benefits

The Company provides post-retirement benefits to employees, including defined benefit pension plans.

The cost of providing these benefits is dependent upon many factors that result from actual plan

experience and assumptions of future expectations.

Exhibit 99.2

57

The accounting related to employee post-retirement benefits is a critical accounting estimate. Changes in

the estimated benefit obligation, affected by employee demographics - including age, compensation

levels, employment periods, contribution levels and earnings - could have a material impact on reported

assets, liabilities, accumulated other comprehensive income and results of operations. Changes in key

actuarial assumptions, including anticipated rates of return on plan assets and discount rates used in

determining the accrued benefit obligation and benefit costs, could change annual funding requirements.

This could have a significant impact on the Company’s annual earnings and cash requirements.

Pension plan assets are comprised primarily of equity and fixed income investments. Fluctuations in

actual equity market returns and changes in interest rates may result in changes to pension costs in

future periods.

The Company’s accounting policy is to amortize the net actuarial gain or loss that exceeds 10 per cent of

the greater of the projected benefit obligation / accumulated post-retirement benefit obligation (“PBO”)

and the market-related value of assets, over active plan members’ average remaining service period. For

the largest plans this is currently 8.0 years (8.4 years for 2023 benefit cost) for Canadian plans and a

weighted average of 11.5 years for United States plans. The Company’s use of smoothed asset values

reduces volatility related to amortization of actuarial investment experience. As a result, the main cause of

volatility in reported pension cost is the discount rate used to determine the PBO. 

The discount rate used to determine benefit costs is based on the yield of high quality long-term corporate

bonds in each operating entity’s country and is determined with reference to bonds which have the same

duration as the PBO as at January 1 of the fiscal year. The following table shows the discount rate for

benefit cost purposes and the expected return on plan assets for each plan:

2023

2022

Discount rate for

benefit cost

purposes

Expected

return on 

plan assets

Discount rate for

benefit cost 

purposes

Expected 

return on 

plan assets

TECO Energy Group Retirement Plan

5.55%

7.05%

2.78%

6.50%

TECO Energy Group Supplemental

Executive Retirement Plan

(1)

5.45%/5.31%

N/A

2.35/5.33%

N/A

TECO Energy Group Benefit

Restoration Plan (1)

5.48/5.30/5.49%

N/A

2.27/4.19/5.48%

N/A

TECO Energy Post-retirement Health

and Welfare Plan

5.53%/6.14%

N/A

2.84%

N/A

New Mexico Gas Company Retiree

Medical Plan

5.55%

2.50%

2.85%

1.50%

NSPI 

5.17%, 5.19%

6.25%

3.25%, 3.48%

5.75%

GBPC Salaried

5.75%

 6.00%

5.75%

6.00%

GBPC Union

5.75%

 5.35%

5.75%

5.35%

(1) The discount rate for benefit cost purposes is updated throughout the year as special events occur, such as settlements and

curtailments

Based on management’s estimate, the reported benefit cost for defined benefit and defined contribution

plans was $43 million in 2023 (2022 – $64 million). The reported benefit cost is impacted by numerous

assumptions, including the discount rate and asset return assumptions. A 0.25 per cent change in the

discount rate and asset return assumptions would have had +/- impact on the 2023 benefit cost of $0.5

million and $2.5 million, respectively (2022 – $0.5 million and $1 million). 

Exhibit 99.2

58

Unbilled Revenue

Electric and gas revenues are billed on a systematic basis over a one or two-month period for NSPI and a

one-month period for other Emera utilities. At the end of each month, the Company must make an

estimate of energy delivered to customers since the date their meter was last read and determine related

revenues earned but not yet billed. The unbilled revenue is estimated based on several factors, including

current month’s generation, estimated customer usage by class, weather, line losses, inter-period

changes to customer classes and applicable customer rates. Based on the extent of estimates included in

determination of unbilled revenue, actual results may differ from the estimate. At December 31, 2023,

unbilled revenues totalled $363 million (2022 – $424 million) on total regulated operating revenues of

$7,235 million (2022 – $7,154 million).

PP&E

PP&E represents 62 per cent of total assets on the Company’s balance sheet and includes generation,

transmission and distribution, and other assets of the Company.

Depreciation is determined by the straight-line method, based on the estimated remaining service lives of

depreciable assets in each category. The service lives of regulated PP&E are determined based on

depreciation studies and require appropriate regulatory approval. Due to the magnitude of the Company’s

PP&E, changes in estimated depreciation rates can have a material impact on depreciation expense and

accumulated depreciation.

Depreciation expense was $1,019 million for the year ended December 31, 2023 (2022 – $927 million).

Goodwill Impairment Assessments

Goodwill is calculated as the excess of the purchase price of an acquired entity over the estimated FV of

identifiable assets acquired, and liabilities assumed at the acquisition date. 

Goodwill is subject to assessment for impairment at the reporting unit level annually, or if an event or

change in circumstances indicates that the FV of a reporting unit may be below its carrying value.

Application of the goodwill impairment test requires management judgment on significant assumptions

and estimates. When assessing goodwill for impairment, the Company has the option of first performing a

qualitative assessment to determine whether a quantitative assessment is necessary. In performing a

qualitative assessment, management considers, among other factors, macroeconomic conditions,

industry and market considerations and overall financial performance.

If the Company performs a qualitative assessment and determines it is more likely than not that its FV is

less than its carrying amount, or if the Company chooses to bypass the qualitative assessment, a

quantitative test is performed. The quantitative test compares the FV of the reporting unit to its carrying

amount, including goodwill. If the carrying amount of the reporting unit exceeds its FV, an impairment loss

is recorded. Significant assumptions used in estimating the FV of a reporting unit include discount and

growth rates, rate case assumptions including future cost of capital, valuation of the reporting units' net

operating loss (“NOL”), and projected operating and capital cash flows. Adverse changes in these

assumptions could result in a future material impairment of the goodwill assigned to Emera’s reporting

units.

Exhibit 99.2

59

As of December 31, 2023, $5,868 million (2022 – $6,009 million) of Emera’s goodwill represents the

excess of the acquisition purchase price for TECO Energy (TEC, PGS and NMGC reporting units) over

the FV assigned to identifiable assets acquired and liabilities assumed. In Q4 2023, qualitative

assessments were performed for NMGC and PGS, given the significant excess of FV over carrying

amounts calculated during the last quantitative tests in Q4 2022 and Q4 2019, respectively. Management

concluded it was more likely than not that the FV of these reporting units exceeded their respective

carrying amounts, including goodwill. As such, no quantitative testing was required. Given the length of

time passed since the last quantitative impairment test for the TEC reporting unit, Emera elected to

bypass a qualitative assessment and performed a quantitative impairment assessment in Q4 2023 using

a combination of the income and market approach. This assessment estimated that the FV of the TEC

reporting unit exceeded its carrying amount, including goodwill, and as a result no impairment charges

were recognized.

As of December 31, 2023, the Company had goodwill with a total carrying amount of $5,871 million

(December 31, 2022 – $6,012 million). The change in the carrying value of goodwill from 2022 to 2023

was a result of the effect of the FX translation of Emera’s foreign affiliates.

In Q4 2022, as a result of a quantitative assessment, the Company recorded a goodwill impairment

charge of $73 million, reducing the GBPC goodwill balance to nil as at December 31, 2022. For further

detail, refer to note 22 in the consolidated financial statements.

Long-Lived Assets Impairment Assessments

The Company assesses whether there has been an impairment of long-lived assets and intangibles when

a triggering event occurs, such as a significant market disruption or the sale of a business. The

assessment involves comparing undiscounted expected future cash flows, to the carrying value of the

asset. When the undiscounted cash flow analysis indicates a long-lived asset is not recoverable, the

amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-

lived asset over its estimated FV.

The Company believes accounting estimates related to asset impairments are critical estimates, as they

are highly susceptible to change and the impact of an impairment on reported assets and earnings could

be material. Management is required to make assumptions based on expectations regarding results of

operations for significant/indefinite future periods and current and expected market conditions in such

periods. Markets can experience significant uncertainties. Estimates based on the Company’s

assumptions relating to future results of operations or other recoverable amounts are based on a

combination of historical experience, fundamental economic analysis, observable market activity and

independent market studies. The Company’s expectations regarding uses and holding periods of assets

are based on internal long-term budgets and projections, which consider external factors and market

forces, as of the end of each reporting period. Assumptions made by management are consistent with

generally accepted industry approaches and assumptions used for valuation and pricing activities.

As at December 31, 2023, there were no indications of impairment of Emera’s long-lived assets. No

impairment charges were recognized in either 2023 or 2022.

Exhibit 99.2

60

Income Taxes

Income taxes are determined based on expected tax treatment of transactions recorded in the

consolidated financial statements. In determining income taxes, tax legislation is interpreted in a variety of

jurisdictions, the likelihood that deferred income tax assets will be recovered from future taxable income is

assessed, and assumptions are made about expected timing of reversal of deferred income tax assets

and liabilities. Uncertainty associated with application of tax statutes and regulations and outcomes of tax

audits and appeals, requires that judgments and estimates be made in the accrual process and in

calculation of effective tax rates. Only income tax benefits that meet the “more likely than not” threshold

may be recognized or continue to be recognized. Unrecognized tax benefits are evaluated quarterly and

changes are recorded based on new information, including issuance of relevant guidance by the courts or

tax authorities and developments occurring in examinations of the Company’s tax returns.

The Company believes accounting estimates related to income taxes are critical estimates. Realization of

deferred income tax assets depends on the generation of sufficient taxable income, both operating and

capital, in future periods. A change in estimated valuation allowance could have a material impact on

reported assets and results of operations. Administrative actions of tax authorities, changes in tax law or

regulation, and uncertainty associated with the application of tax statutes and regulations, could change

the Company’s estimate of income taxes, including the potential for elimination or reduction of the

Company’s ability to realize tax benefits and to utilize deferred income tax assets.

Asset Retirement Obligations

Measurement of the FV of AROs requires the Company to make reasonable estimates concerning the

method and timing of settlement associated with legally obligated costs. There are uncertainties in

estimating future asset-retirement costs due to potential events, such as changing legislation or

regulations, and advances in remediation technologies. Emera has AROs associated with remediation of

generation, transmission, distribution and pipeline assets. 

An ARO represents the FV of estimated cash flows necessary to discharge the future obligation using the

Company’s credit-adjusted risk-free rate. The amounts are reduced by actual expenditures incurred.

Estimated future cash flows are based on completed depreciation studies, remediation reports, prior

experience, estimated useful lives, and governmental regulatory requirements. The present value of the

liability is recorded and the carrying amount of the related long-lived asset is correspondingly increased.

The amount capitalized at inception is depreciated in the same manner as the related long-lived asset.

Over time, the liability is accreted to its estimated future value. Accretion expense is included as part of

“Depreciation and amortization expense”. Any accretion expense not yet approved by the regulator is

recorded in “PP&E” and included in the next depreciation study. Accordingly, changes to the ARO or cost

recognition attributable to changes in the factors discussed above, should not impact the results of

operations of the Company.

Some of the Company’s transmission and distribution assets may have conditional AROs that are not

recognized in the consolidated financial statements as the FV of these obligations could not be

reasonably estimated given insufficient information to do so. A conditional ARO refers to a legal obligation

to perform an asset retirement activity in which the timing and/or method of settlement are conditional on

a future event that may or may not be within the control of the entity. Management monitors these

obligations and a liability is recognized at FV when an amount can be determined.

As at December 31, 2023, AROs recorded on the balance sheet were $192 million (2022 – $174 million).

The Company estimates the undiscounted amount of cash flow required to settle the obligations is

approximately $426 million (2022 – $429 million), which will be incurred between 2023 and 2061. The

majority of these costs will be incurred between 2028 and 2050.

Exhibit 99.2

61

Financial Instruments

The Company is required to determine the FV of all derivatives except those that qualify for the normal

purchase, normal sale exception. FV is the price that would be received for the sale of an asset or paid to

transfer a liability in an orderly arms-length transaction between market participants at the measurement

date. FV measurements are required to reflect assumptions that market participants would use in pricing

an asset or liability based on the best available information, including the risks inherent in a particular

valuation technique, such as a pricing model, and the risks inherent in the inputs to the model.

Level Determinations and Classifications

The Company uses Level 1, 2, and 3 classifications in the FV hierarchy. The FV measurement of a

financial instrument is included in only one of the three levels and is based on the lowest level input

significant to the derivation of the FV. FV is determined, directly or indirectly, using inputs that are

observable for the asset or liability. Only in limited circumstances does the Company enter into

commodity transactions involving non-standard features where market observable data is not available or

have contract terms that extend beyond five years.

CHANGES IN ACCOUNTING POLICIES AND

PRACTICES

Future Accounting Pronouncements

The Company considers the applicability and impact of all ASUs issued by the Financial Accounting

Standards Board (“FASB”). The following updates have been issued by the FASB, but as allowed, have

not yet been adopted by Emera. Any ASUs not included below were assessed and determined to be

either not applicable to the Company or to have an insignificant impact on the consolidated financial

statements.

Improvements to Income Tax Disclosures

In December 2023, the FASB issued ASU 2023-09, Income Taxes (Topic 740): Improvements to Income

Tax Disclosures. The standard enhances the transparency, decision usefulness and effectiveness of

income tax disclosures by requiring consistent categories and greater disaggregation of information in the

reconciliation of income taxes computed using the enacted statutory income tax rate to the actual income

tax provision and effective income tax rate, as well as the disaggregation of income taxes paid (refunded)

by jurisdiction. The standard also requires disclosure of income (loss) before provision for income taxes

and income tax expense (recovery) in accordance with U.S. Securities and Exchange Commission

Regulation S-X 210.4-08(h), Rules of General Application – General Notes to Financial Statements:

Income Tax Expense, and the removal of disclosures no longer considered cost beneficial or relevant.

The guidance will be effective for annual reporting periods beginning after December 15, 2024, and

interim periods within annual reporting periods beginning after December 15, 2025. Early adoption is

permitted. The standard will be applied on a prospective basis, with retrospective application permitted.

The Company is currently evaluating the impact of adoption of the standard on its consolidated financial

statements.

Exhibit 99.2

62

Improvements to Reportable Segment Disclosures

In November 2023, the FASB issued ASU 2023-07, Segment Reporting (Topic 280), Improvements to

Reportable Segment Disclosures. The change in the standard improves reportable segment disclosure

requirements, primarily through enhanced disclosures about significant segment expenses. The changes

improve financial reporting by requiring disclosure of incremental segment information on an annual and

interim basis for all public entities to enable investors to develop more decision-useful financial analyses.

The guidance will be effective for annual reporting periods beginning after December 15, 2023, and for

interim periods beginning after December 15, 2024. Early adoption is permitted. The standard will be

applied retrospectively. The Company is currently evaluating the impact of adoption of the standard on its

consolidated financial statements. 

SUMMARY OF QUARTERLY RESULTS

For the quarter ended

millions of dollars 

Q4

Q3

Q2

Q1

Q4

Q3

Q2

Q1

(except per share amounts)

2023

2023

2023

2023

2022

2022

2022

2022

Operating revenues

$

 1,972

$

 1,740

$

 1,418

$

 2,433

$

 2,358

$

 1,835

$

 1,380

$

 2,015

Net income (loss) attributable to

common shareholders

$

 289

$

 101

$

 28

$

 560

$

 483

$

 167

$

 (67)

$

 362

Adjusted net income

$

 175

$

 204

$

 162

$

 268

$

 249

$

 203

$

 156

$

 242

EPS – basic

$

1.04

$

 0.37

$

 0.10

$

 2.07

$

 1.80

$

 0.63

$

 (0.25)

$

 1.38

EPS – diluted

$

1.04

$

 0.37

$

 0.10

$

 2.07

$

 1.80

$

 0.63

$

 (0.25)

$

 1.38

Adjusted EPS – basic

$

0.63

$

 0.75

$

 0.60

$

 0.99

$

 0.93

$

 0.76

$

 0.59

$

 0.92

Quarterly operating revenues and adjusted net income are affected by seasonality. The first quarter

provides strong earnings contributions due to a significant portion of the Company’s operations being in

northeastern North America, where winter is the peak electricity usage season. The third quarter provides

strong earnings contributions due to summer being the heaviest electric consumption season in Florida.

Seasonal and other weather patterns, as well as the number and severity of storms, can affect demand

for energy and the cost of service. Quarterly results could also be affected by items outlined in the

“Significant Items Affecting Earnings” section.

EX-99.3

Exhibit 99.3

1

EMERA INCORPORATED

Consolidated

Financial Statements

December 31, 2023 and 2022

Exhibit 99.3

2

MANAGEMENT REPORT

Management's Responsibility for Financial Reporting

The accompanying consolidated financial statements of Emera Incorporated and the information in this

annual report are the responsibility of management and have been approved by the Board of Directors

(“Board”).

The consolidated financial statements have been prepared by management in accordance with United

States Generally Accepted Accounting Principles. When alternative accounting methods exist,

management has chosen those it considers most appropriate in the circumstances. In preparation of

these consolidated financial statements, estimates are sometimes necessary when transactions affecting

the current accounting period cannot be finalized with certainty until future periods. Management

represents that such estimates, which have been properly reflected in the accompanying consolidated

financial statements, are based on careful judgments and are within reasonable limits of materiality.

Management has determined such amounts on a reasonable basis in order to ensure that the

consolidated financial statements are presented fairly in all material respects. Management has prepared

the financial information presented elsewhere in the annual report and has ensured that it is consistent

with that in the consolidated financial statements.

Emera Incorporated maintains effective systems of internal accounting and administrative controls,

consistent with reasonable cost. Such systems are designed to provide reasonable assurance that the

financial information is reliable and accurate, and that Emera Incorporated's assets are appropriately

accounted for and adequately safeguarded. 

The Board is responsible for ensuring that management fulfils its responsibilities for financial reporting

and is ultimately responsible for reviewing and approving the consolidated financial statements. The

Board carries out this responsibility principally through its Audit Committee.

The Audit Committee is appointed by the Board, and its members are directors who are not officers or

employees of Emera Incorporated. The Audit Committee meets periodically with management, as well as

with the internal auditors and with the external auditors, to discuss internal controls over the financial

reporting process, auditing matters and financial reporting issues, to satisfy itself that each party is

properly discharging its responsibilities, and to review the annual report, the consolidated financial

statements and the external auditors' report. The Audit Committee reports its findings to the Board for

consideration when approving the consolidated financial statements for issuance to the shareholders. 

The Audit Committee also considers, for review by the Board and approval by the shareholders, the

appointment of the external auditors. 

The consolidated financial statements have been audited by Ernst & Young LLP, the external auditors, in

accordance with Canadian Generally Accepted Auditing Standards and with the standards of the Public

Company Accounting Oversight Board. Ernst & Young LLP has full and free access to the Audit

Committee.

February 26, 2024

“Scott Balfour”

“Gregory Blunden”

President and Chief Executive Officer President and Chief Executive Officer Chief Financial Officer 

Exhibit 99.3

3

Report of Independent Registered Public Accounting Firm

To the Shareholders and the Board of Directors of Emera Incorporated

Opinion on the Consolidated Financial Statements 

We have audited the accompanying Consolidated Balance Sheets of Emera Incorporated (the

“Company“) as of December 31, 2023 and 2022, the related Consolidated Statements of Income,

Consolidated Statements of Comprehensive Income, Consolidated Statements of Changes in Equity and

Consolidated Statements of Cash Flows for the years then ended, and the related notes (collectively

referred to as the “consolidated financial statements“). In our opinion, the consolidated financial

statements present fairly, in all material respects, the consolidated financial position of the Company as of

December 31, 2023 and 2022, and the consolidated results of its operations and its consolidated cash

flows for each of the two years in the period ended December 31, 2023, in conformity with United States

generally accepted accounting principles.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company‘s management. Our

responsibility is to express an opinion on the Company‘s consolidated financial statements based on our

audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board

(United States) (“PCAOB”) and are required to be independent with respect to the Company in

accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities

and Exchange Commission and the PCAOB. 

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that

we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial

statements are free of material misstatement, whether due to error or fraud. The Company is not required

to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part

of our audits we are required to obtain an understanding of internal control over financial reporting but not

for the purpose of expressing an opinion on the effectiveness of the Company's internal control over

financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the

consolidated financial statements, whether due to error or fraud, and performing procedures that respond

to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and

disclosures in the consolidated financial statements. Our audits also included evaluating the accounting

principles used and significant estimates made by management, as well as evaluating the overall

presentation of the consolidated financial statements. We believe that our audits provide a reasonable

basis for our opinion. 

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current period audit of the

financial statements that were communicated or required to be communicated to the audit committee and

that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our

especially challenging, subjective or complex judgments. The communication of critical audit matters

does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we

are not, by communicating the critical audit matters below, providing separate opinions on the critical

audit matters or on the accounts or disclosures to which they relate.

Exhibit 99.3

4

Accounting for the effects of rate regulation

Description of the

Matter

As disclosed in note 6 of the consolidated financial statements, the

Company has $3.1 billion in regulatory assets and $1.8 billion in regulatory

liabilities. The Company’s rate-regulated subsidiaries are subject to

regulation by various federal, state and provincial regulatory authorities in

the geographic regions in which they operate. The regulatory rates are

designed to recover the prudently incurred costs of providing the regulated

products or services and provide a reasonable return on the equity invested

or assets, as applicable. In addition to regulatory assets and liabilities, rate

regulation impacts multiple financial statement line items, including, but not

limited to, property, plant and equipment (“PP&E”), operating revenues and

expenses, income taxes, and depreciation expense.

Auditing the impact of rate regulation on the Company’s financial

statements is complex and highly judgmental due to the significant

judgments made by the Company to support its accounting and disclosure

for regulatory matters when final regulatory decisions or orders have not yet

been obtained or when regulatory formulas are complex. There is also

subjectivity involved in assessing the potential impact of future regulatory

decisions on the financial statements. Although the Company expects to

recover costs from customers through rates, there is a risk that the regulator

will not approve full recovery of the costs incurred. The Company’s

judgments include making an assessment of the probability of recovery of

and return on costs incurred, of the potential disallowance of part of the cost

incurred, or of the probable refund of gains or amounts previously collected

from customers through future rates.

How We Addressed

the Matter in Our

Audit

We performed audit procedures that included, amongst others, assessing

the Company’s evaluation of the probability of future recovery for regulatory

assets, PP&E, and refund of regulatory liabilities by obtaining and reviewing

relevant regulatory orders, filings, testimony, hearings and correspondence,

and other publicly available information. For regulatory matters for which

regulatory decisions or orders have not yet been obtained, we inspected the

rate-regulated subsidiaries’ filings for any evidence that might contradict the

Company’s assertions, and reviewed other regulatory orders, filings and

correspondence for other entities within the same or similar jurisdictions to

assess the likelihood of recovery or refund in future rates based on the

regulator’s treatment of similar costs under similar circumstances. We

obtained and evaluated an analysis from the Company and corroborated

that analysis with letters from legal counsel, when appropriate, regarding

cost recoveries, gains or amounts previously collected from customers or

future changes in rates. We also assessed the methodology, accuracy and

completeness of the Company’s calculations of regulatory asset and liability

balances based on provisions and formulas outlined in rate orders and

other correspondence with the regulators. We evaluated the Company's

disclosures related to the impacts of rate regulation.

Fair Value (“FV”) measurement of derivative financial

instruments

Description of the

Matter

Held-for-trading (“HFT”) derivative assets of $348 million and liabilities of

$567 million, disclosed in note 15 to the consolidated financial statements,

are measured at FV. The Company recognized $1,037 million in realized

and unrealized gains during the year with respect to HFT derivatives.

Exhibit 99.3

5

Auditing the Company’s valuation of HFT derivatives is complex and highly

judgmental due to the complexity of the contract terms and valuation

models, and the significant estimation required in determining the FV of the

contracts. In determining the FV of HFT derivatives, significant assumptions

about future economic and market assumptions with uncertain outcomes

are used, including third-party sourced forward commodity pricing curves

based on illiquid markets, internally developed correlation factors and basis

differentials. These assumptions have a significant impact on the FV of the

HFT derivatives. 

How We Addressed

the Matter in Our

Audit

We performed audit procedures that included, amongst others, reviewing

executed contracts and agreements for the identification of inputs and

assumptions impacting the valuation of derivatives. With the support of our

valuation specialists, we assessed the methodology and mathematical

accuracy of the Company’s valuation models and compared the commodity

pricing curves used by the Company to current market and economic data.

For the forward commodity pricing curves, we compared the Company’s

pricing curves to independently sourced pricing curves. We also assessed

the methodology and mathematical accuracy of the Company’s calculations

to develop correlation factors and basis differentials. In addition, we

assessed whether the FV hierarchy disclosures in note 16 to the

consolidated financial statements were consistent with the source of the

significant inputs and assumptions used in determining the FV of

derivatives. 

/s/

Ernst & Young LLP

Chartered Professional Accountants

We have served as the Company‘s auditor since 1998.

Halifax, Canada

February 26, 2024

Exhibit 99.3

6

Emera Incorporated

Consolidated Statements of Income 

For the

Year ended December 31

millions of dollars (except per share amounts)

2023

2022

Operating revenues

 Regulated electric

$

5,746

$

5,473

 Regulated gas

1,489

1,681

 Non-regulated

328

434

 Total operating revenues (note 5)

7,563

7,588

Operating expenses

 Regulated fuel for generation and purchased power

1,881

2,171

 Regulated cost of natural gas

527

800

 Operating, maintenance and general expenses ("OM&G")

1,879

1,596

 Provincial, state, and municipal taxes 

433

367

 Depreciation and amortization

1,049

952

 GBPC Impairment charge (note 22)

-

73

 Total operating expenses

5,769

5,959

Income from operations

1,794

1,629

Income from equity investments (note 7)

146

129

Other income, net (note 8)

158

145

Interest expense, net (note 9)

925

709

Income before provision for income taxes

1,173

1,194

Income tax expense (note 10)

128

185

Net income 

1,045

1,009

Non-controlling interest in subsidiaries

1

1

Preferred stock dividends

66

63

Net income attributable to common shareholders

$

978

$

945

Weighted average shares of common stock outstanding (in millions) (note 12)

 Basic

274

266

 Diluted

274

266

Earnings per common share (note 12)

 Basic

$

3.57

$

3.56

 Diluted

$

3.57

$

3.55

Dividends per common share declared

$

2.7875

$

2.6775

The accompanying notes are an integral part of these consolidated financial statements.

Exhibit 99.3

7

Emera Incorporated

Consolidated Statements of Comprehensive Income 

For the

Year ended December 31

millions of dollars

2023

2022

Net income 

$

1,045

$

1,009

Other comprehensive (loss) income, net of tax

Foreign currency translation adjustment

(1)

(270)

629

Unrealized gains (losses) on net investment hedges

(2) (3)

38

(97)

Cash flow hedges – reclassification adjustment for gains included in income

(4)

(2)

(2)

Unrealized losses on available-for-sale investment

-

(1)

Net change in unrecognized pension and post-retirement benefit obligation

(5)

(39)

24

Other comprehensive (loss) income

(6)

(273)

553

Comprehensive income

772

1,562

Comprehensive income attributable to non-controlling interest

1

1

Comprehensive Income of Emera Incorporated

$

771

$

1,561

The accompanying notes are an integral part of these consolidated financial statements.

1) Net of tax recovery of $7 million for the year ended December 31, 2023 (2022 – $

7

 million expense).

2) The Company has designated $

1.2

 billion United States dollar (USD) denominated Hybrid Notes as a hedge of the foreign

currency exposure of its net investment in USD denominated operations. 

3) Net of tax expense of nil for the year ended December 31, 2023 (2022 – $6 million recovery).

4) Net of tax expense of nil for the year ended December 31, 2023 (2022 – $1 million recovery).

5) Net of tax expense of $

1

 million for the year ended December 31, 2023 (2022 – $

1

 million expense).

6) Net of tax recovery of $6 million for the year ended December 31, 2023 (2022 – $

1

 million expense).

Exhibit 99.3

8

Emera Incorporated

Consolidated Balance Sheets

As at

December 31

December 31

millions of dollars

2023

2022

Assets

Current assets

 Cash and cash equivalents

$

567

$

310

 Restricted cash (note 32)

21

22

 Inventory (note 14)

790

769

 Derivative instruments (notes 15 and 16)

174

296

 Regulatory assets (note 6)

339

602

 Receivables and other current assets (note 18)

1,817

2,897

3,708

4,896

Property, plant and equipment ("PP&E"),

net of accumulated depreciation

and amortization of $

9,994

 and $

9,574

, respectively (note 20)

24,376

22,996

Other assets

 Deferred income taxes (note 10)

208

237

 Derivative instruments (notes 15 and 16)

66

100

 Regulatory assets (note 6)

2,766

3,018

 Net investment in direct finance and sales type leases (note 19)

621

604

 Investments subject to significant influence (note 7)

1,402

1,418

 Goodwill (note 22)

5,871

6,012

 Other long-term assets (note 32)

462

461

11,396

11,850

Total assets

$

39,480

$

39,742

Liabilities and Equity

Current liabilities

 Short-term debt (note 23)

$

1,433

$

2,726

 Current portion of long-term debt (note 25)

676

574

 Accounts payable 

1,454

2,025

 Derivative instruments (notes 15 and 16)

386

888

 Regulatory liabilities (note 6)

168

495

 Other current liabilities (note 24)

427

579

4,544

7,287

Long-term liabilities

 Long-term debt (note 25)

17,689

15,744

 Deferred income taxes (note 10)

2,352

2,196

 Derivative instruments (notes 15 and 16)

118

190

 Regulatory liabilities (note 6)

1,604

1,778

 Pension and post-retirement liabilities (note 21)

265

281

 Other long-term liabilities (note 7 and 26)

820

825

22,848

21,014

Equity

 Common stock (note 11)

8,462

7,762

 Cumulative preferred stock (note 28)

1,422

1,422

 Contributed surplus

82

81

 Accumulated other comprehensive income ("AOCI') (note 13)

305

578

 Retained earnings 

1,803

1,584

 Total Emera Incorporated equity

12,074

11,427

 Non-controlling interest in subsidiaries (note 29)

14

14

 Total equity

12,088

11,441

Total liabilities and equity

$

39,480

$

39,742

Commitments and contingencies (note 27)

Approved on behalf of the Board of Directors

The accompanying notes are an integral part of 

 “M. Jacqueline Sheppard” 

 “Scott Balfour”

these consolidated financial statements.

 Chair of the Board 

 President and Chief Executive Officer

Exhibit 99.3

9

Emera Incorporated

Consolidated Statements of Cash Flows 

For the

Year ended December 31

millions of dollars

2023

2022

Operating activities

Net income 

$

1,045

$

1,009

Adjustments to reconcile net income to net cash provided by operating activities:

 Depreciation and amortization

1,060

959

 Income from equity investments, net of dividends

(22)

(61)

 Allowance for funds used during construction ("AFUDC") – equity

(38)

(52)

 Deferred income taxes, net

97

152

 Net change in pension and post-retirement liabilities

(68)

(48)

 NSPI Fuel adjustment mechanism ("FAM")

(88)

(162)

 Net change in Fair Value ("FV") of derivative instruments

(666)

206

 Net change in regulatory assets and liabilities 

554

(471)

 Net change in capitalized transportation capacity

434

(445)

 GBPC impairment charge

-

73

 Other operating activities, net

28

(13)

Changes in non-cash working capital (note 30)

(95)

(234)

Net cash provided by operating activities

2,241

913

Investing activities

 Additions to PP&E

(2,937)

(2,596)

 Other investing activities

20

27

Net cash used in investing activities

(2,917)

(2,569)

Financing activities

 Change in short-term debt, net

(66)

1,028

 Proceeds from short-term debt with maturities greater than 90 days

548

544

 Repayment of short-term debt with maturities greater than 90 days

(1,086)

(680)

 Proceeds from long-term debt, net of issuance costs

1,932

784

 Retirement of long-term debt

(151)

(367)

 Net (repayments) proceeds under committed credit facilities

(96)

511

 Issuance of common stock, net of issuance costs

424

277

 Dividends on common stock

(488)

(472)

 Dividends on preferred stock

(66)

(63)

 Other financing activities 

(12)

(7)

Net cash provided by financing activities

939

1,555

Effect of exchange rate changes on cash, cash equivalents, and restricted cash

(7)

16

Net increase (decrease) in cash, cash equivalents, and restricted cash

256

(85)

Cash, cash equivalents, and restricted cash, beginning of year

332

417

Cash, cash equivalents, and restricted cash, end of year

$

588

$

332

Cash, cash equivalents, and restricted cash consists of:

Cash

$

559

$

302

Short-term investments

8

8

Restricted cash

21

22

Cash, cash equivalents, and restricted cash

$

588

$

332

Supplementary Information to Consolidated Statements of Cash Flows (note 30)

The accompanying notes are an integral part of these consolidated financial statements.

Exhibit 99.3

10

Emera Incorporated

Consolidated Statements of Changes in Equity

Non-

Common

Preferred

Contributed

Retained

Controlling

Total

 Stock

Stock

Surplus

AOCI

Earnings

Interest

Equity

millions of dollars

Balance, December 31, 2022

$

7,762

$

1,422

$

81

$

578

$

1,584

$

14

$

11,441

Net income of Emera Inc.

-

-

-

-

1,044

1

1,045

Other comprehensive loss, net of tax

recovery of $

6

 million

-

-

-

(273)

-

-

(273)

Dividends declared on preferred stock

(note 28)

-

-

-

-

(66)

-

(66)

Dividends declared on common stock

($

2.7875

/share)

-

-

-

-

(759)

-

(759)

Issued under the at-the-market

program ("ATM"), net of after-tax

issuance costs

397

-

-

-

-

-

397

Issued under the Dividend

Reinvestment Program ("DRIP"), net of

discount

272

-

-

-

-

-

272

Senior management stock options

exercised and Employee Common

Share Purchase Plan ("ECSPP")

31

-

1

-

-

-

32

Other

-

-

-

-

-

(1)

(1)

Balance, December 31, 2023

$

8,462

$

1,422

$

82

$

305

$

1,803

$

14

$

12,088

Balance, December 31, 2021

$

7,242

$

1,422

$

79

$

25

$

1,348

$

34

$

10,150

Net income of Emera Inc.

-

-

-

-

1,008

1

1,009

Other comprehensive income, net of tax

expense of $

1

 million

-

-

-

553

-

-

553

Dividends declared on preferred stock

(note 28)

-

-

-

-

(63)

-

(63)

Dividends declared on common stock

($

2.6775

/share)

-

-

-

-

(709)

-

(709)

Issued under the ATM, net of after-tax

issuance costs

248

-

-

-

-

-

248

Issued under the DRIP, net of discount

238

-

-

-

-

-

238

Senior management stock options

exercised and ECSPP

34

-

2

-

-

-

36

Disposal of non-controlling interest of

Dominica Electricity Services Ltd

("Domlec")

-

-

-

-

-

(20)

(20)

Other

-

-

-

-

-

(1)

(1)

Balance, December 31, 2022

$

7,762

$

1,422

$

81

$

578

$

1,584

$

14

$

11,441

The accompanying notes are an integral part of these consolidated financial statements.

Exhibit 99.3

11

Emera Incorporated

Notes to the Consolidated Financial Statements

As at December 31, 2023 and 2022

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Operations

Emera Incorporated (“Emera” or the “Company”) is an energy and services company which invests in

electricity generation, transmission and distribution, and gas transmission and distribution. 

At December 31, 2023, Emera’s reportable segments include the following: 

●

 Florida Electric Utility, which consists of Tampa Electric (“TEC”), a vertically integrated regulated

electric utility, serving approximately

840,000

 customers in West Central Florida;

●

 Canadian Electric Utilities, which includes:

●

 Nova Scotia Power Inc. (“NSPI”), a vertically integrated regulated electric utility and the

primary electricity supplier in Nova Scotia, serving approximately

549,000

 customers; and

●

 Emera Newfoundland & Labrador Holdings Inc. (“ENL”), consisting of two transmission

investments related to an

824

 megawatt (“MW”) hydroelectric generating facility at Muskrat

Falls on the Lower Churchill River in Labrador, developed by Nalcor Energy. ENL’s two

investments are:

●

 a

100

 per cent equity interest in NSP Maritime Link Inc. (“NSPML”), which developed

the Maritime Link Project, a $

1.8

 billion transmission project, including AFUDC; and

●

 a

31

 per cent equity interest in the partnership capital of Labrador-Island Link Limited

Partnership (“LIL”), a $

3.7

 billion electricity transmission project in Newfoundland and

Labrador. 

●

 Gas Utilities and Infrastructure, which includes:

●

 Peoples Gas System Inc. (“PGS”), a regulated gas distribution utility, serving approximately

490,000

 customers across Florida. Effective January 1, 2023, Peoples Gas System ceased

to be a division of Tampa Electric Company and the gas utility was reorganized, resulting in a

separate legal entity called Peoples Gas System Inc., a wholly owned direct subsidiary of

TECO Gas Operations, Inc.;

●

 New Mexico Gas Company, Inc. (“NMGC”), a regulated gas distribution utility, serving

approximately

540,000

 customers in New Mexico; 

●

 Emera Brunswick Pipeline Company Limited (“Brunswick Pipeline”), a

145

-kilometre pipeline

delivering re-gasified liquefied natural gas from Saint John, New Brunswick to the United

States border under a

25

-year firm service agreement with Repsol Energy North America

Canada Partnership (“Repsol Energy”), which expires in 2034; 

●

 SeaCoast Gas Transmission, LLC (“SeaCoast”), a regulated intrastate natural gas

transmission company offering services in Florida; and

●

 a

12.9

 per cent equity interest in Maritimes & Northeast Pipeline (“M&NP”), a

1,400

-kilometre

pipeline that transports natural gas throughout markets in Atlantic Canada and the

northeastern United States. 

●

 Other Electric Utilities, which includes Emera (Caribbean) Incorporated (“ECI”), a holding company

with regulated electric utilities that include:

●

 The Barbados Light & Power Company Limited (“BLPC”), a vertically integrated regulated

electric utility on the island of Barbados, serving approximately

134,000

 customers; 

●

 Grand Bahama Power Company Limited (“GBPC”), a vertically integrated regulated electric

utility on Grand Bahama Island, serving approximately

19,000

 customers; and

●

 a

19.5

 per cent equity interest in St. Lucia Electricity Services Limited (“Lucelec”), a vertically

integrated regulated electric utility on the island of St. Lucia.

Exhibit 99.3

12

●

 Emera’s other reportable segment includes investments in energy-related non-regulated companies

which include:

●

 Emera Energy, which consists of:

●

 Emera Energy Services (“EES”), a physical energy business that purchases and sells

natural gas and electricity and provides related energy asset management services; 

●

 Brooklyn Power Corporation (“Brooklyn Energy”), a

30

 MW biomass co-generation

electricity facility in Brooklyn, Nova Scotia; and

●

 a

50.0

 per cent joint venture interest in Bear Swamp Power Company LLC (“Bear

Swamp”), a

660

 MW pumped storage hydroelectric facility in northwestern

Massachusetts. 

●

 Emera US Finance LP (“Emera Finance”) and TECO Finance, Inc. (“TECO Finance”),

financing subsidiaries of Emera;

●

 Block Energy LLC (previously Emera Technologies LLC), a wholly owned technology

company focused on finding ways to deliver renewable and resilient energy to customers;

●

 Emera US Holdings Inc., a wholly owned holding company for certain of Emera’s assets

located in the United States; and

●

 Other investments.

Basis of Presentation

These consolidated financial statements are prepared and presented in accordance with United States

Generally Accepted Accounting Principles (“USGAAP”) and in the opinion of management, include all

adjustments that are of a recurring nature and necessary to fairly state the financial position of Emera. 

All dollar amounts are presented in Canadian dollars (“CAD”), unless otherwise indicated.

Principles of Consolidation

These consolidated financial statements include the accounts of Emera Incorporated, its majority-owned

subsidiaries, and a variable interest entity (“VIE”) in which Emera is the primary beneficiary. Emera uses

the equity method of accounting to record investments in which the Company has the ability to exercise

significant influence, and for VIEs in which Emera is not the primary beneficiary.

The Company performs ongoing analysis to assess whether it holds any VIEs or whether any

reconsideration events have arisen with respect to existing VIEs. To identify potential VIEs, management

reviews contractual and ownership arrangements such as leases, long-term purchase power agreements,

tolling contracts, guarantees, jointly owned facilities and equity investments. VIEs of which the Company

is deemed the primary beneficiary must be consolidated. The primary beneficiary of a VIE has both the

power to direct the activities of the VIE that most significantly impacts its economic performance and the

obligation to absorb losses or the right to receive benefits of the VIE that could potentially be significant to

the VIE. In circumstances where Emera has an investment in a VIE but is not deemed the primary

beneficiary, the VIE is accounted for using the equity method. For further details on VIEs, refer to note 32.

Intercompany balances and transactions have been eliminated on consolidation, except for the net profit

on certain transactions between certain non-regulated and regulated entities in accordance with

accounting standards for rate-regulated entities. The net profit on these transactions, which would be

eliminated in the absence of the accounting standards for rate-regulated entities, is recorded in non-

regulated operating revenues. An offset is recorded to PP&E, regulatory assets, regulated fuel for

generation and purchased power, or OM&G, depending on the nature of the transaction.

Exhibit 99.3

13

Use of Management Estimates

The preparation of consolidated financial statements in accordance with USGAAP requires management

to make estimates and assumptions. These may affect reported amounts of assets and liabilities at the

date of the financial statements and reported amounts of revenues and expenses during the reporting

periods. Significant areas requiring use of management estimates relate to rate-regulated assets and

liabilities, accumulated reserve for cost of removal, pension and post-retirement benefits, unbilled

revenue, useful lives for depreciable assets, goodwill and long-lived assets impairment assessments,

income taxes, asset retirement obligations (“ARO”), and valuation of financial instruments. Management

evaluates the Company’s estimates on an ongoing basis based upon historical experience, current and

expected conditions and assumptions believed to be reasonable at the time the assumption is made, with

any adjustments recognized in income in the year they arise.

Regulatory Matters

Regulatory accounting applies where rates are established by, or subject to approval by, an independent

third-party regulator. Rates are designed to recover prudently incurred costs of providing regulated

products or services and provide an opportunity for a reasonable rate of return on invested capital, as

applicable. For further detail, refer to note 6.

Foreign Currency Translation 

Monetary assets and liabilities denominated in foreign currencies are converted to CAD at the rates of

exchange prevailing at the balance sheet date. The resulting differences between the translation at the

original transaction date and the balance sheet date are included in income.

Assets and liabilities of foreign operations whose functional currency is not the Canadian dollar are

translated using exchange rates in effect at the balance sheet date and the results of operations at the

average exchange rate in effect for the period. The resulting exchange gains and losses on the assets

and liabilities are deferred on the balance sheet in AOCI.

The Company designates certain USD denominated debt held in CAD functional currency companies as

hedges of net investments in USD denominated foreign operations. The change in the carrying amount of

these investments, measured at exchange rates in effect at the balance sheet date is recorded in Other

Comprehensive Income (“OCI”).

Revenue Recognition

Regulated Electric and Gas Revenue:

Electric and gas revenues, including energy charges, demand charges, basic facilities charges and

clauses and riders, are recognized when obligations under the terms of a contract are satisfied, which is

when electricity and gas are delivered to customers over time as the customer simultaneously receives

and consumes the benefits. Electric and gas revenues are recognized on an accrual basis and include

billed and unbilled revenues. Revenues related to the sale of electricity and gas are recognized at rates

approved by the respective regulators and recorded based on metered usage, which occurs on a

periodic, systematic basis, generally monthly or bi-monthly. At the end of each reporting period, electricity

and gas delivered to customers, but not billed, is estimated and corresponding unbilled revenue is

recognized. The Company’s estimate of unbilled revenue at the end of the reporting period is calculated

by estimating the megawatt hours (“MWh”) or therms delivered to customers at the established rates

expected to prevail in the upcoming billing cycle. This estimate includes assumptions as to the pattern of

energy demand, weather, line losses and inter-period changes to customer classes.

Exhibit 99.3

14

Non-regulated Revenue:

Marketing and trading margins are comprised of Emera Energy’s corresponding purchases and sales of

natural gas and electricity, pipeline capacity costs and energy asset management revenues. Revenues

are recorded when obligations under terms of the contract are satisfied and are presented on a net basis

reflecting the nature of contractual relationships with customers and suppliers.

Energy sales are recognized when obligations under the terms of the contracts are satisfied, which is

when electricity is delivered to customers over time. 

Other non-regulated revenues are recorded when obligations under the terms of the contract are

satisfied.

Other:

Sales, value add, and other taxes, except for gross receipts taxes discussed below, collected by the

Company concurrent with revenue-producing activities are excluded from revenue.

Franchise Fees and Gross Receipts

TEC and PGS recover from customers certain costs incurred, on a dollar-for-dollar basis, through prices

approved by the Florida Public Service Commission (“FPSC”). The amounts included in customers’ bills

for franchise fees and gross receipt taxes are included as “Regulated electric” and “Regulated gas”

revenues in the Consolidated Statements of Income. Franchise fees and gross receipt taxes payable by

TEC and PGS are included as an expense on the Consolidated Statements of Income in “Provincial, state

and municipal taxes”.

NMGC is an agent in the collection and payment of franchise fees and gross receipt taxes and is not

required by a tariff to present the amounts on a gross basis. Therefore, NMGC’s franchise fees and gross

receipt taxes are presented net with no line item impact on the Consolidated Statements of Income.

PP&E 

PP&E is recorded at original cost, including AFUDC or capitalized interest, net of contributions received in

aid of construction.

The cost of additions, including betterments and replacements of units, are included in “PP&E” on the

Consolidated Balance Sheets. When units of regulated PP&E are replaced, renewed or retired, their cost,

plus removal or disposal costs, less salvage proceeds, is charged to accumulated depreciation, with no

gain or loss reflected in income. Where a disposition of non-regulated PP&E occurs, gains and losses are

included in income as the dispositions occur.

The cost of PP&E represents the original cost of materials, contracted services, direct labour, AFUDC for

regulated property or interest for non-regulated property, ARO, and overhead attributable to the capital

project. Overhead includes corporate costs such as finance, information technology and labour costs,

along with other costs related to support functions, employee benefits, insurance, procurement, and fleet

operating and maintenance. Expenditures for project development are capitalized if they are expected to

have a future economic benefit.

Normal maintenance projects and major maintenance projects that do not increase overall life of the

related assets are expensed as incurred. When a major maintenance project increases the life or value of

the underlying asset, the cost is capitalized. 

Depreciation is determined by the straight-line method, based on the estimated remaining service lives of

the depreciable assets in each functional class of depreciable property. For some of Emera’s rate-

regulated subsidiaries, depreciation is calculated using the group remaining life method, which is applied

to the average investment, adjusted for anticipated costs of removal less salvage, in functional classes of

depreciable property. The service lives of regulated assets require regulatory approval.

Exhibit 99.3

15

Intangible assets, which are included in “PP&E” on the Consolidated Balance Sheets, consist primarily of

computer software and land rights. Amortization is determined by the straight-line method, based on the

estimated remaining service lives of the asset in each category. For some of Emera’s rate-regulated

subsidiaries, amortization is calculated using the amortizable life method which is applied to the net book

value to date over the remaining life of those assets. The service lives of regulated intangible assets

require regulatory approval.

Goodwill

Goodwill is calculated as the excess of the purchase price of an acquired entity over the estimated FV of

identifiable assets acquired and liabilities assumed at the acquisition date. Goodwill is carried at initial

cost less any write-down for impairment and is adjusted for the impact of foreign exchange (“FX”).

Goodwill is subject to assessment for impairment at the reporting unit level annually, or if an event or

change in circumstances indicates that the FV of a reporting unit may be below its carrying value. When

assessing goodwill for impairment, the Company has the option of first performing a qualitative

assessment to determine whether a quantitative assessment is necessary. In performing a qualitative

assessment management considers, among other factors, macroeconomic conditions, industry and

market considerations and overall financial performance.

If the Company performs a qualitative assessment and determines it is more likely than not that its FV is

less than its carrying amount, or if the Company chooses to bypass the qualitative assessment, a

quantitative test is performed. The quantitative test compares the FV of the reporting unit to its carrying

amount, including goodwill. If the carrying amount of the reporting unit exceeds its FV, an impairment loss

is recorded. Management estimates the FV of the reporting unit by using the income approach, or a

combination of the income and market approach. The income approach uses a discounted cash flow

analysis which relies on management’s best estimate of the reporting unit’s projected cash flows. The

analysis includes an estimate of terminal values based on these expected cash flows using a

methodology which derives a valuation using an assumed perpetual annuity based on the reporting unit’s

residual cash flows. The discount rate used is a market participant rate based on a peer group of publicly

traded comparable companies and represents the weighted average cost of capital of comparable

companies. For the market approach, management estimates FV based on comparable companies and

transactions within the utility industry. Significant assumptions used in estimating the FV of a reporting

unit using an income approach include discount and growth rates, rate case assumptions including future

cost of capital, valuation of the reporting unit’s net operating loss (“NOL”) and projected operating and

capital cash flows. Adverse changes in these assumptions could result in a future material impairment of

the goodwill assigned to Emera’s reporting units. 

As of December 31, 2023, $

5,868

 million of Emera’s goodwill represents the excess of the acquisition

purchase price for TECO Energy (TEC, PGS and NMGC reporting units) over the FV assigned to

identifiable assets acquired and liabilities assumed. In Q4 2023, qualitative assessments were performed

for NMGC and PGS given the significant excess of FV over carrying amounts calculated during the last

quantitative tests in Q4 2022 and Q4 2019, respectively. Management concluded it was more likely than

not that the FV of these reporting units exceeded their respective carrying amounts, including goodwill. As

such, no quantitative testing was required. Given the length of time passed since the last quantitative

impairment test for the TEC reporting unit, Emera elected to bypass a qualitative assessment and

performed a quantitative impairment assessment in Q4 2023 using a combination of the income and

market approach. This assessment estimated that the FV of the TEC reporting unit exceeded its carrying

amount, including goodwill, and as a result, no impairment charges were recognized.

In Q4 2022, as a result of a quantitative assessment, the Company recorded a goodwill impairment

charge of $

73

 million, reducing the GBPC goodwill balance to

nil

 as at December 31, 2022. For further

details, refer to note 22.

Exhibit 99.3

16

Income Taxes and Investment Tax Credits

Emera recognizes deferred income tax assets and liabilities for the future tax consequences of events

that have been included in financial statements or income tax returns. Deferred income tax assets and

liabilities are determined based on the difference between the carrying value of assets and liabilities on

the Consolidated Balance Sheets, and their respective tax bases using enacted tax rates in effect for the

year in which the differences are expected to reverse. The effect of a change in income tax rates on

deferred income tax assets and liabilities is recognized in earnings in the period when the change is

enacted, unless required to be offset to a regulatory asset or liability by law or by order of the regulator.

Emera recognizes the effect of income tax positions only when it is more likely than not that they will be

realized. Management reviews all readily available current and historical information, including forward-

looking information, and the likelihood that deferred income tax assets will be recovered from future

taxable income is assessed and assumptions are made about the expected timing of reversal of deferred

income tax assets and liabilities. If management subsequently determines it is likely that some or all of a

deferred income tax asset will not be realized, a valuation allowance is recorded to reflect the amount of

deferred income tax asset expected to be realized. 

Generally, investment tax credits are recorded as a reduction to income tax expense in the current or

future periods to the extent that realization of such benefit is more likely than not. Investment tax credits

earned on regulated assets by TEC, PGS and NMGC are deferred and amortized as required by

regulatory practices.

TEC, PGS, NMGC and BLPC collect income taxes from customers based on current and deferred income

taxes. NSPI, ENL and Brunswick Pipeline collect income taxes from customers based on income tax that

is currently payable, except for the deferred income taxes on certain regulatory balances specifically

prescribed by regulators. For the balance of regulated deferred income taxes, NSPI, ENL and Brunswick

Pipeline recognize regulatory assets or liabilities where the deferred income taxes are expected to be

recovered from or returned to customers in future years. These regulated assets or liabilities are grossed

up using the respective income tax rate to reflect the income tax associated with future revenues that are

required to fund these deferred income tax liabilities, and the income tax benefits associated with reduced

revenues resulting from the realization of deferred income tax assets. GBPC is not subject to income

taxes.

Emera classifies interest and penalties associated with unrecognized tax benefits as interest and

operating expense, respectively. For further detail, refer to note 10.

Derivatives and Hedging Activities

The Company manages its exposure to normal operating and market risks relating to commodity prices,

FX, interest rates and share prices through contractual protections with counterparties where practicable,

and by using financial instruments consisting mainly of FX forwards and swaps, interest rate options and

swaps, equity derivatives, and coal, oil and gas futures, options, forwards and swaps. In addition, the

Company has contracts for the physical purchase and sale of natural gas. These physical and financial

contracts are classified as HFT. Collectively, these contracts and financial instruments are considered

derivatives.

The Company recognizes the FV of all its derivatives on its balance sheet, except for non-financial

derivatives that meet the normal purchases and normal sales (“NPNS”) exception. Physical contracts that

meet the NPNS exception are not recognized on the balance sheet; these contracts are recognized in

income when they settle. A physical contract generally qualifies for the NPNS exception if the transaction

is reasonable in relation to the Company’s business needs, the counterparty owns or controls resources

within the proximity to allow for physical delivery, the Company intends to receive physical delivery of the

commodity, and the Company deems the counterparty creditworthy. The Company continually assesses

contracts designated under the NPNS exception and will discontinue the treatment of these contracts

under this exemption if the criteria are no longer met. 

Exhibit 99.3

17

Derivatives qualify for hedge accounting if they meet stringent documentation requirements and can be

proven to effectively hedge identified risk both at the inception and over the term of the instrument.

Specifically, for cash flow hedges, change in the FV of derivatives is deferred to AOCI and recognized in

income in the same period the related hedged item is realized. Where documentation or effectiveness

requirements are not met, the derivatives are recognized at FV with any changes in FV recognized in net

income in the reporting period, unless deferred as a result of regulatory accounting.

Derivatives entered into by NSPI, NMGC and GBPC that are documented as economic hedges or for

which the NPNS exception has not been taken, are subject to regulatory accounting treatment. The

change in FV of the derivatives is deferred to a regulatory asset or liability. The gain or loss is recognized

in the hedged item when the hedged item is settled. Management believes any gains or losses resulting

from settlement of these derivatives related to fuel for generation and purchased power will be refunded

to or collected from customers in future rates. TEC has no derivatives related to hedging as a result of a

FPSC approved five-year moratorium on hedging of natural gas purchases that ended on December 31,

2022 and was extended through December 31, 2024 as a result of TEC’s 2021 rate case settlement

agreement.

Derivatives that do not meet any of the above criteria are designated as HFT, with changes in FV

normally recorded in net income of the period. The Company has not elected to designate any derivatives

to be included in the HFT category where another accounting treatment would apply.

Emera classifies gains and losses on derivatives as a component of non-regulated operating revenues,

fuel for generation and purchased power, other expenses, inventory, and OM&G, depending on the

nature of the item being economically hedged. Transportation capacity arising as a result of marketing

and trading derivative transactions is recognized as an asset in “Receivables and other current assets”

and amortized over the period of the transportation contract term. Cash flows from derivative activities are

presented in the same category as the item being hedged within operating or investing activities on the

Consolidated Statements of Cash Flows. Non-hedged derivatives are included in operating cash flows on

the Consolidated Statements of Cash Flows.

Derivatives, as reflected on the Consolidated Balance Sheets, are not offset by the FV amounts of cash

collateral with the same counterparty. Rights to reclaim cash collateral are recognized in “Receivables

and other current assets” and obligations to return cash collateral are recognized in “Accounts payable”.

Leases

The Company determines whether a contract contains a lease at inception by evaluating whether the

contract conveys the right to control the use of an identified asset for a period of time in exchange for

consideration. 

Emera has leases with independent power producers (“IPP”) and other utilities for annual requirements to

purchase wind and hydro energy over varying contract lengths which are classified as finance leases.

These finance leases are not recorded on the Company’s Consolidated Balance Sheets as payments

associated with the leases are variable in nature and there are no minimum fixed lease payments. Lease

expense associated with these leases is recorded as “Regulated fuel for generation and purchased

power” on the Consolidated Statements of Income.

Operating lease liabilities and right-of-use assets are recognized on the Consolidated Balance Sheets

based on the present value of the future minimum lease payments over the lease term at commencement

date. As most of Emera’s leases do not provide an implicit rate, the incremental borrowing rate at

commencement of the lease is used in determining the present value of future lease payments. Lease

expense is recognized on a straight-line basis over the lease term and is recorded as “Operating,

maintenance and general” on the Consolidated Statements of Income.

Exhibit 99.3

18

Where the Company is the lessor, a lease is a sales-type lease if certain criteria are met and the

arrangement transfers control of the underlying asset to the lessee. For arrangements where the criteria

are met due to the presence of a third-party residual value guarantee, the lease is a direct financing

lease. 

For direct finance leases, a net investment in the lease is recorded that consists of the sum of the

minimum lease payments and residual value, net of estimated executory costs and unearned income.

The difference between the gross investment and the cost of the leased item is recorded as unearned

income at the inception of the lease. Unearned income is recognized in income over the life of the lease

using a constant rate of interest equal to the internal rate of return on the lease. 

For sales-type leases, the accounting is similar to the accounting for direct finance leases however, the

difference between the FV and the carrying value of the leased item is recorded at lease commencement

rather than deferred over the term of the lease. 

Emera has certain contractual agreements that include lease and non-lease components, which

management has elected to account for as a single lease component.

Cash, Cash Equivalents and Restricted Cash

Cash equivalents consist of highly liquid short-term investments with original maturities of three months or

less at acquisition.

Receivables and Allowance for Credit Losses

Utility customer receivables are recorded at the invoiced amount and do not bear interest. Standard

payment terms for electricity and gas sales are approximately 30 days. A late payment fee may be

assessed on account balances after the due date. The Company recognizes allowances for credit losses

to reduce accounts receivable for amounts expected to be uncollectable. Management estimates credit

losses related to accounts receivable by considering historical loss experience, customer deposits,

current events, the characteristics of existing accounts and reasonable and supportable forecasts that

affect the collectability of the reported amount. Provisions for credit losses on receivables are expensed

to maintain the allowance at a level considered adequate to cover expected losses. Receivables are

written off against the allowance when they are deemed uncollectible.

Inventory

Fuel and materials inventories are valued at the lower of weighted-average cost or net realizable value,

unless evidence indicates the weighted-average cost will be recovered in future customer rates.

Asset Impairment

Long-Lived Assets:

Emera assesses whether there has been an impairment of long-lived assets and intangibles when a

triggering event occurs, such as a significant market disruption or sale of a business. 

The assessment involves comparing undiscounted expected future cash flows to the carrying value of the

asset. When the undiscounted cash flow analysis indicates a long-lived asset is not recoverable, the

amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-

lived asset over its estimated FV. The Company’s assumptions relating to future results of operations or

other recoverable amounts, are based on a combination of historical experience, fundamental economic

analysis, observable market activity and independent market studies. The Company’s expectations

regarding uses and holding periods of assets are based on internal long-term budgets and projections,

which consider external factors and market forces, as of the end of each reporting period. The

assumptions made are consistent with generally accepted industry approaches and assumptions used for

valuation and pricing activities.

Exhibit 99.3

19

As at December 31, 2023, there are no indications of impairment of Emera’s long-lived assets.

No

impairment charges related to long-lived assets were recognized in 2023 or 2022. 

Equity Method Investments:

The carrying value of investments accounted for under the equity method are assessed for impairment by

comparing the FV of these investments to their carrying values, if a FV assessment was completed, or by

reviewing for the presence of impairment indicators. If an impairment exists, and it is determined to be

other-than-temporary, a charge is recognized in earnings equal to the amount the carrying value exceeds

the investment’s FV.

No

 impairment of equity method investments was required in either 2023 or 2022.

Financial Assets:

Equity investments, other than those accounted for under the equity method, are measured at FV, with

changes in FV recognized in the Consolidated Statements of Income. Equity investments that do not

have readily determinable FV are recorded at cost minus impairment, if any, plus or minus changes

resulting from observable price changes in orderly transactions for the identical or similar investments.

No

impairment of financial assets was required in either 2023 or 2022.

Asset Retirement Obligations

An ARO is recognized if a legal obligation exists in connection with the future disposal or removal costs

resulting from the permanent retirement, abandonment or sale of a long-lived asset. A legal obligation

may exist under an existing or enacted law or statute, written or oral contract, or by legal construction

under the doctrine of promissory estoppel.

An ARO represents the FV of estimated cash flows necessary to discharge the future obligation, using

the Company’s credit adjusted risk-free rate. The amounts are reduced by actual expenditures incurred.

Estimated future cash flows are based on completed depreciation studies, remediation reports, prior

experience, estimated useful lives, and governmental regulatory requirements. The present value of the

liability is recorded and the carrying amount of the related long-lived asset is correspondingly increased.

The amount capitalized at inception is depreciated in the same manner as the related long-lived asset.

Over time, the liability is accreted to its estimated future value. AROs are included in “Other long-term

liabilities” and accretion expense is included as part of “Depreciation and amortization”. Any regulated

accretion expense not yet approved by the regulator is recorded in “Property, plant and equipment” and

included in the next depreciation study.

Some of the Company’s transmission and distribution assets may have conditional AROs that are not

recognized in the consolidated financial statements, as the FV of these obligations could not be

reasonably estimated, given insufficient information to do so. A conditional ARO refers to a legal

obligation to perform an asset retirement activity in which the timing and/or method of settlement are

conditional on a future event that may or may not be within the control of the entity. Management

monitors these obligations and a liability is recognized at FV in the period in which an amount can be

determined.

Cost of Removal (“COR”)

TEC, PGS, NMGC and NSPI recognize non-ARO COR as regulatory liabilities. The non-ARO COR

represent funds received from customers through depreciation rates to cover estimated future non-legally

required COR of PP&E upon retirement. The companies accrue for COR over the life of the related

assets based on depreciation studies approved by their respective regulators. The costs are estimated

based on historical experience and future expectations, including expected timing and estimated future

cash outlays.

Exhibit 99.3

20

Stock-Based Compensation

The Company has several stock-based compensation plans: a common share option plan for senior

management; an employee common share purchase plan; a deferred share unit (“DSU”) plan; a

performance share unit (“PSU”) plan; and a restricted share unit (“RSU”) plan. The Company accounts for

its plans in accordance with the FV-based method of accounting for stock-based compensation. Stock-

based compensation cost is measured at the grant date, based on the calculated FV of the award, and is

recognized as an expense over the employee’s or director’s requisite service period using the graded

vesting method. Stock-based compensation plans recognized as liabilities are initially measured at FV

and re-measured at FV at each reporting date, with the change in liability recognized in income.

Employee Benefits

The costs of the Company’s pension and other post-retirement benefit programs for employees are

expensed over the periods during which employees render service. The Company recognizes the funded

status of its defined-benefit and other post-retirement plans on the balance sheet and recognizes

changes in funded status in the year the change occurs. The Company recognizes unamortized gains

and losses and past service costs in “AOCI” or “Regulatory assets” on the Consolidated Balance Sheets.

The components of net periodic benefit cost other than the service cost component are included in “Other

income, net” on the Consolidated Statements of Income. For further detail, refer to note 21.

2. FUTURE ACCOUNTING PRONOUNCEMENTS

The Company considers the applicability and impact of all ASUs issued by the Financial Accounting

Standards Board (“FASB”). The following updates have been issued by the FASB, but as allowed, have

not yet been adopted by Emera. Any ASUs not included below were assessed and determined to be

either not applicable to the Company or to have an insignificant impact on the consolidated financial

statements.

Improvements to Income Tax Disclosures

In December 2023, the FASB issued ASU 2023-09, Income Taxes (Topic 740): Improvements to Income

Tax Disclosures. The standard enhances the transparency, decision usefulness and effectiveness of

income tax disclosures by requiring consistent categories and greater disaggregation of information in the

reconciliation of income taxes computed using the enacted statutory income tax rate to the actual income

tax provision and effective income tax rate, as well as the disaggregation of income taxes paid (refunded)

by jurisdiction. The standard also requires disclosure of income (loss) before provision for income taxes

and income tax expense (recovery) in accordance with U.S. Securities and Exchange Commission

Regulation S-X 210.4-08(h), Rules of General Application – General Notes to Financial Statements:

Income Tax Expense, and the removal of disclosures no longer considered cost beneficial or relevant.

The guidance will be effective for annual reporting periods beginning after December 15, 2024, and

interim periods within annual reporting periods beginning after December 15, 2025. Early adoption is

permitted. The standard will be applied on a prospective basis, with retrospective application permitted.

The Company is currently evaluating the impact of adoption of the standard on its consolidated financial

statements.

Exhibit 99.3

21

Improvements to Reportable Segment Disclosures

In November 2023, the FASB issued ASU 2023-07, Segment Reporting (Topic 280), Improvements to

Reportable Segment Disclosures. The change in the standard improves reportable segment disclosure

requirements, primarily through enhanced disclosures about significant segment expenses. The changes

improve financial reporting by requiring disclosure of incremental segment information on an annual and

interim basis for all public entities to enable investors to develop more decision-useful financial analyses.

The guidance will be effective for annual reporting periods beginning after December 15, 2023, and for

interim periods beginning after December 15, 2024. Early adoption is permitted. The standard will be

applied retrospectively. The Company is currently evaluating the impact of adoption of the standard on its

consolidated financial statements.

3.

DISPOSITIONS

On March 31, 2022, Emera completed the sale of its

51.9

 per cent interest in Domlec for proceeds which

approximated its carrying value. Domlec was included in the Company’s Other Electric reportable

segment up to its date of sale. The sale did not have a material impact on earnings.

Exhibit 99.3

22

4. SEGMENT INFORMATION

Emera manages its reportable segments separately due in part to their different operating, regulatory and

geographical environments. Segments are reported based on each subsidiary’s contribution of revenues,

net income attributable to common shareholders and total assets, as reported to the Company’s chief

operating decision maker.

Florida 

Canadian

Gas Utilities

Other

Inter-

Electric

Electric

and

Electric

Segment

millions of dollars

Utility

Utilities

Infrastructure

Utilities

Other

Eliminations

Total

For the year ended December 31, 2023 

Operating revenues from

external customers (1)

$

3,548

$

1,671

$

1,510

$

526

$

308

$

 - 

$

7,563

Inter-segment revenues

(1)

8

-

14

-

31

(53)

 - 

 Total operating revenues

3,556

1,671

1,524

526

339

(53)

7,563

Regulated fuel for generation

and purchased power

920

699

-

275

-

(13)

1,881

Regulated cost of natural gas

-

-

527

-

-

-

527

OM&G

830

384

405

130

151

(21)

1,879

Provincial, state and municipal

taxes

289

45

91

3

5

-

433

Depreciation and amortization

571

276

126

68

8

-

1,049

Income from equity

investments

-

109

21

4

12

-

146

Other income, net

69

32

11

7

20

19

158

Interest expense, net

(2)

271

170

129

23

332

-

925

Income tax expense

(recovery)

117

(9)

64

-

(44)

-

128

Non-controlling interest in

subsidiaries

-

-

-

1

-

-

1

Preferred stock dividends

-

-

-

-

66

-

66

Net income (loss) attributable

to common shareholders

$

627

$

247

$

214

$

37

$

(147)

$

-

$

978

Capital expenditures

$

1,736

$

450

$

664

$

63

$

8

$

-

$

2,921

As at December 31, 2023

Total assets

$

21,119

$

8,634

$

7,735

$

1,311

$

1,938

$

(1,257)

$

39,480

Investments subject to

significant influence

$

-

$

1,236

$

118

$

48

$

-

$

-

$

1,402

Goodwill

$

4,628

$

-

$

1,240

$

-

$

3

$

-

$

5,871

(1) All significant inter-company balances and transactions have been eliminated on consolidation except for certain transactions

between non-regulated and regulated entities. Management believes elimination of these transactions would understate PP&E,

OM&G, or regulated fuel for generation and purchased power. Inter-company transactions that have not been eliminated are

measured at the amount of consideration established and agreed to by the related parties. Eliminated transactions are included in

determining reportable segments.

(2) Segment net income is reported on a basis that includes internally allocated financing costs of $

95

 million for the year ended

December 31, 2023, between the Florida Electric Utility, Gas Utilities and Infrastructure and Other segments.

Exhibit 99.3

23

Florida 

Canadian

Gas Utilities

Other

Inter-

Electric

Electric

and

Electric

Segment

millions of dollars

Utility

Utilities

Infrastructure

Utilities

Other

Eliminations

Total

For the year ended December 31, 2022 

Operating revenues from

external customers

(1)

$

3,280

$

1,675

$

1,697

$

518

$

418

$

 - 

$

7,588

Inter-segment revenues

(1)

7

-

7

-

22

(36)

 - 

 Total operating revenues

3,287

1,675

1,704

518

440

(36)

7,588

Regulated fuel for generation

and purchased power

1,086

803

-

290

-

(8)

2,171

Regulated cost of natural gas

-

-

800

-

-

-

800

OM&G

625

338

365

123

156

(11)

1,596

Provincial, state and municipal

taxes

235

43

83

3

3

-

367

Depreciation and amortization

507

259

118

61

7

-

952

Income from equity

investments

-

87

21

4

17

-

129

Other income (expenses), net

68

24

13

-

23

17

145

Interest expense, net

(2)

185

136

81

19

288

-

709

GBPC impairment charge

-

-

-

73

-

-

73

Income tax expense (recovery)

121

(8)

70

-

2

-

185

Non-controlling interest in

subsidiaries

-

-

-

1

-

-

1

Preferred stock dividends

-

-

-

-

63

-

63

Net income (loss) attributable

to common shareholders

$

596

$

215

$

221

$

(48)

$

(39)

$

-

$

945

Capital expenditures

$

1,425

$

507

$

574

$

63

$

6

$

-

$

2,575

As at December 31, 2022

Total assets

$

21,053

$

8,223

$

7,737

$

1,337

$

2,835

$

(1,443)

$

39,742

Investments subject to

significant influence

$

-

$

1,241

$

128

$

49

$

-

$

-

$

1,418

Goodwill

$

4,739

$

-

$

1,270

$

-

$

3

$

-

$

6,012

(1) All significant inter-company balances and transactions have been eliminated on consolidation except for certain transactions

between non-regulated and regulated entities. Management believes elimination of these transactions would understate PP&E,

OM&G, or regulated fuel for generation and purchased power. Inter-company transactions that have not been eliminated are

measured at the amount of consideration established and agreed to by the related parties. Eliminated transactions are included in

determining reportable segments.

(2) Segment net income is reported on a basis that includes internally allocated financing costs of $

13

 million for the year ended

December 31, 2022, between the Gas Utilities and Infrastructure and Other segments.

Geographical Information

Revenues (based on country of origin of the product or service sold)

For the

Year ended December 31

millions of dollars

2023

2022

United States

5,310

$

5,346

Canada

1,727

1,725

Barbados

389

384

The Bahamas

137

122

Dominica

-

11

$

7,563

$

7,588

Property Plant and Equipment:

As at 

December 31

December 31

millions of dollars

2023

2022

United States

$

18,588

$

17,382

Canada

4,878

4,689

Barbados

576

583

The Bahamas

334

342

$

24,376

$

22,996

Exhibit 99.3

24

5. REVENUE

The following disaggregates the Company’s revenue by major source:

Electric

Gas

Other

Florida

Canadian

Other 

Gas Utilities

Inter-

Electric

Electric

Electric

and 

Segment

millions of dollars

Utility

Utilities

Utilities

Infrastructure

Other

Eliminations

Total

For the year ended December 31, 2023 

Regulated Revenue

Residential

$

2,307

$

910

$

183

$

724

$

-

$

-

$

4,124

Commercial

1,083

463

285

425

-

-

2,256

Industrial

274

219

33

93

-

(13)

606

Other electric

395

41

7

-

-

-

443

Regulatory deferrals

(522)

-

12

-

-

-

(510)

Other (1) 

19

38

6

199

-

(8)

254

Finance income (2)(3)

-

-

-

62

-

62

 Regulated revenue

$

3,556

$

1,671

$

526

$

1,503

$

-

$

(21)

$

7,235

Non-Regulated Revenue

Marketing and trading margin (4)

-

-

-

-

96

-

96

Other non-regulated operating

revenue

-

-

-

21

27

(23)

25

Mark-to-market (3)

-

-

-

-

216

(9)

207

 Non-regulated revenue

$

-

$

-

$

-

$

21

$

339

$

(32)

$

328

Total operating revenues

$

3,556

$

1,671

$

526

$

1,524

$

339

$

(53)

$

7,563

For the year ended December 31, 2022 

Regulated Revenue

Residential

$

1,799

$

834

$

184

$

800

$

-

$

-

$

3,617

Commercial

869

427

282

461

-

-

2,039

Industrial

230

353

32

83

-

(7)

691

Other electric

398

28

6

-

-

-

432

Regulatory deferrals

(27)

-

6

-

-

-

(21)

Other (1) 

18

33

8

283

-

(7)

335

Finance income (2)(3)

-

-

-

61

-

-

61

 Regulated revenue

$

3,287

$

1,675

$

518

$

1,688

$

-

$

(14)

7,154

Non-Regulated 

Marketing and trading margin (4)

-

-

-

-

143

-

143

Other non-regulated operating

revenue

-

-

-

16

16

(10)

22

Mark-to-market (3)

-

-

-

-

281

(12)

269

 Non-regulated revenue

$

-

$

-

$

-

$

16

$

440

$

(22)

434

Total operating revenues

$

3,287

$

1,675

$

518

$

1,704

$

440

$

(36)

$

7,588

(1) Other includes rental revenues, which do not represent revenue from contracts with customers.

(2) Revenue related to Brunswick Pipeline's service agreement with Repsol Energy Canada.

(3) Revenue which does not represent revenues from contracts with customers.

(4) Includes gains (losses) on settlement of energy related derivatives, which do not represent revenue from contracts with

customers.

Remaining Performance Obligations:

Remaining performance obligations primarily represent gas transportation contracts, lighting contracts,

and long-term steam supply arrangements with fixed contract terms. As of December 31, 2023, the

aggregate amount of the transaction price allocated to remaining performance obligations was $

488

million (2022 – $

450

 million). This amount includes $

134

 million of future performance obligations related

to a gas transportation contract between SeaCoast and PGS through

2040

. This amount excludes

contracts with an original expected length of one year or less and variable amounts for which Emera

recognizes revenue at the amount to which it has the right to invoice for services performed. Emera

expects to recognize revenue for the remaining performance obligations through

2043

.

Exhibit 99.3

25

6. REGULATORY ASSETS AND LIABILITIES

Regulatory assets represent prudently incurred costs that have been deferred because it is probable they

will be recovered through future rates or tolls collected from customers. Management believes existing

regulatory assets are probable for recovery either because the Company received specific approval from

the applicable regulator, or due to regulatory precedent established for similar circumstances. If

management no longer considers it probable that an asset will be recovered, deferred costs are charged

to income. 

Regulatory liabilities represent obligations to make refunds to customers or to reduce future revenues for

previous collections. If management no longer considers it probable that a liability will be settled, the

related amount is recognized in income.

For regulatory assets and liabilities that are amortized, the amortization is as approved by the respective

regulator.

As at

December 31

December 31

millions of dollars 

2023

2022

Regulatory assets

Deferred income tax regulatory assets

$

1,233

$

1,166

TEC capital cost recovery for early retired assets 

671

674

NSPI FAM

395

307

Pension and post-retirement medical plan

364

369

Cost recovery clauses

151

707

Deferrals related to derivative instruments

88

30

Storm cost recovery clauses 

52

138

Environmental remediations

26

27

Stranded cost recovery

25

27

NMGC winter event gas cost recovery

-

69

Other

100

106

$

3,105

$

3,620

Current

$

339

$

602

Long-term

2,766

3,018

Total regulatory assets 

$

3,105

$

3,620

Regulatory liabilities

Accumulated reserve – COR

849

895

Deferred income tax regulatory liabilities

830

877

Cost recovery clauses 

32

70

BLPC Self-insurance fund ("SIF") (note 32)

29

30

Deferrals related to derivative instruments

17

230

NMGC gas hedge settlements (note 18)

-

162

Other

15

9

$

1,772

$

2,273

Current

$

168

$

495

Long-term

1,604

1,778

Total regulatory liabilities

$

1,772

$

2,273

Deferred Income Tax Regulatory Assets and Liabilities

To the extent deferred income taxes are expected to be recovered from or returned to customers in future

years, a regulatory asset or liability is recognized as appropriate. 

Exhibit 99.3

26

TEC Capital Cost Recovery for Early Retired Assets

This regulatory asset is related to the remaining net book value of Big Bend Power Station Units 1

through 3 and smart meter assets that were retired. The balance earns a rate of return as permitted by

the FPSC and is recovered as a separate line item on customer bills for a period of

15 years

. This

recovery mechanism is authorized by and survives the term of the settlement agreement approved by the

FPSC in 2021. For further information, refer to “Big Bend Modernization Project” in the TEC section

below.

NSPI FAM

NSPI has a FAM, approved by the UARB, allowing NSPI to recover fluctuating fuel and certain fuel-

related costs from customers through regularly scheduled fuel rate adjustments. Differences between

prudently incurred fuel costs and amounts recovered from customers through electricity rates in a year

are deferred to a FAM regulatory asset or liability and recovered from or returned to customers in

subsequent periods. 

Pension and Post-Retirement Medical Plan 

This asset is primarily related to the deferred costs of pension and post-retirement benefits at TEC, PGS

and NMGC. It is included in rate base and earns a rate of return as permitted by the FPSC and NMPRC,

as applicable. It is amortized over the remaining service life of plan participants.

Cost Recovery Clauses 

These assets and liabilities are related to TEC, PGS and NMGC clauses and riders. They are recovered

or refunded through cost-recovery mechanisms approved by the FPSC or New Mexico Public Regulation

Commission (“NMPRC”), as applicable, on a dollar-for-dollar basis in a subsequent period.

Deferrals Related to Derivative Instruments

This asset is primarily related to NSPI deferring changes in FV of derivatives that are documented as

economic hedges or that do not qualify for NPNS exemption, as a regulatory asset or liability as approved

by the UARB. The realized gain or loss is recognized when the hedged item settles in regulated fuel for

generation and purchased power, other income, inventory, or OM&G, depending on the nature of the item

being economically hedged.

Storm Cost Recovery Clauses

TEC and PGS Storm Reserve:

The storm reserve is for hurricanes and other named storms that cause significant damage to TEC and

PGS systems. As allowed by the FPSC, if charges to the storm reserve exceed the storm liability, the

excess is to be carried as a regulatory asset. TEC and PGS can petition the FPSC to seek recovery of

restoration costs over a 12-month period or longer, as determined by the FPSC, as well as replenish the

reserve. In 2022, TEC and PGS were impacted by Hurricane Ian. For further information, refer to “TEC

Storm Reserve” in the Florida Electric Utility section below.

NSPI Storm Rider:

NSPI has a UARB approved storm rider for each of 2023, 2024 and 2025, which gives NSPI the option to

apply to the UARB for recovery of costs if major storm restoration expenses exceed approximately $

10

million in a given year. 

GBPC Storm Restoration:

This asset represents storm restoration costs incurred by GBPC. GBPC maintains insurance for its

generation facilities and, as with most utilities, its transmission and distribution networks are not covered

by commercial insurance. 

Exhibit 99.3

27

In January 2020, the Grand Bahama Port Authority (“GBPA”) approved recovery of $

15

 million USD of

2019 costs related to Hurricane Dorian, over a five-year period from 2021 through 2025.

Restoration costs associated with Hurricane Matthew in 2016 are being recovered through an approved

fuel charge. For further information, refer to “Storm Restoration Costs – Hurricane Matthew” in the GBPC

section below.

Environmental Remediations

This asset is primarily related to PGS costs associated with environmental remediation at Manufactured

Gas Plant sites. The balance is included in rate base, partially offsetting the related liability, and earns a

rate of return as permitted by the FPSC. The timing of recovery is based on a settlement agreement

approved by the FPSC.

Stranded Cost Recovery

Due to decommissioning of a GBPC steam turbine in 2012, the GBPA approved recovery of a $

21

 million

USD stranded cost through electricity rates; it is included in rate base and expected to be included in

rates in future years. 

NMGC Winter Event Gas Cost Recovery

In February 2021, the State of New Mexico experienced an extreme cold weather event that resulted in

an incremental $

108

 million USD for gas costs above what it would normally have paid during this period.

NMGC normally recovers gas supply and related costs through a purchased gas adjustment clause

(“PGAC”). On June 15, 2021, the NMPRC approved recovery of $

108

 million USD and related borrowing

costs in customer rates over a period of

30 months

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

Accumulated Reserve – COR

This regulatory liability represents the non-ARO COR reserve in TEC, PGS, NMGC and NSPI. AROs

represent the FV of estimated cash flows associated with the Company’s legal obligation to retire its

PP&E. Non-ARO COR represent estimated funds received from customers through depreciation rates to

cover future COR of PP&E value upon retirement that are not legally required. This reduces rate base for

ratemaking purposes. This liability is reduced as COR are incurred and increased as depreciation is

recorded for existing assets and as new assets are put into service.

NMGC Gas Hedge Settlements

This regulatory liability represents regulatory deferral of gas options exercised above strike price but

settled subsequent to the period end. The value from cash settlement of these options flows to customers

via the PGAC.

Other Regulatory Assets and Liabilities

Comprised of regulatory assets and liabilities that are not individually significant.

Exhibit 99.3

28

Regulatory Environments and Updates

Florida Electric Utility

TEC is regulated by the FPSC and is also subject to regulation by the Federal Energy Regulatory

Commission. The FPSC sets rates at a level that allows utilities such as TEC to collect total revenues or

revenue requirements equal to their cost of providing service, plus an appropriate return on invested

capital. Base rates are determined in FPSC rate setting hearings which can occur at the initiative of TEC,

the FPSC or other interested parties.

TEC’s approved regulated return on equity (“ROE”) range for 2023 and 2022 was

9.25

 per cent to

11.25

per cent based on an allowed equity capital structure of

54

 per cent. An ROE of

10.20

 per cent (2022 –

10.20

 per cent) is used for the calculation of the return on investments for clauses.

Base Rates:

On February 1, 2024, TEC notified the FPSC of its intent to seek a base rate increase effective January

2025, reflecting a revenue requirement increase of approximately $

290

 to $

320

 million USD and

additional adjustments of approximately $

100

 million USD and $

70

 million USD for 2026 and 2027,

respectively. TEC’s proposed rates include recovery of solar generation projects, energy storage

capacity, a more resilient and modernized energy control center, and numerous other resiliency and

reliability projects. The filing range amounts are estimates until TEC files its detailed case in April 2024.

The FPSC is scheduled to hear the case in Q3 2024.

On August 16, 2023, TEC filed a petition to implement the 2024 Generation Base Rate Adjustment

provisions pursuant to the 2021 rate case settlement agreement. Inclusive of TEC’s ROE adjustment, the

increase of $

22

 million USD was approved by the FPSC on November 17, 2023.

Fuel Recovery and Other Cost Recovery Clauses:

TEC has a fuel recovery clause approved by the FPSC, allowing the opportunity to recover fluctuating

fuel expenses from customers through annual fuel rate adjustments. The FPSC annually approves cost-

recovery rates for purchased power, capacity, environmental and conservation costs, including a return

on capital invested. Differences between prudently incurred fuel costs and the cost-recovery rates and

amounts recovered from customers through electricity rates in a year are deferred to a regulatory asset or

liability and recovered from or returned to customers in subsequent periods. 

On January 23, 2023, TEC requested an adjustment to its fuel charges to recover the 2022 fuel under-

recovery of $

518

 million USD over a period of

21 months

. The request also included an adjustment to

2023 projected fuel costs to reflect the reduction in natural gas prices since September 2022 for a

projected reduction of $

170

 million USD for the balance of 2023. The changes were approved by the

FPSC on March 7, 2023, and were effective beginning on April 1, 2023.

The mid-course fuel adjustment requested by TEC on January 19, 2022, was approved on March 1,

2022. The rate increase, effective with the first billing cycle in April 2022, covered higher fuel and capacity

costs of $

169

 million USD, and was spread over customer bills from April 1, 2022 through December

2022.

Big Bend Modernization Project:

TEC invested $

876

 million USD, including $

91

 million USD of AFUDC, between 2018 and 2022 to

modernize the Big Bend Power Station. The modernization project repowered Big Bend Unit 1 with

natural gas combined-cycle technology and eliminated coal as this unit’s fuel. As part of the

modernization project, TEC in 2020 retired the Unit 1 components that would not be used in the

modernized plant and did the same for Big Bend Unit 2 in 2021. TEC retired Big Bend Unit 3 in 2023 as it

was in the best interests of the customers from an economic, environmental risk and operational

perspective. On December 31, 2021, the remaining costs of the retired Big Bend coal generation assets,

Units 1 through 3, of $

636

 million USD and $

267

 million USD in accumulated depreciation were

reclassified to a regulatory asset on the balance sheet.

Exhibit 99.3

29

TEC’s 2021 settlement agreement provides for cost recovery of the Big Bend Modernization project in two

phases. The first phase was a revenue increase to cover the costs of the assets in service during 2022,

among other items. The remainder of the project costs were recovered as part of the 2023 subsequent

year adjustment. The settlement agreement also includes a new charge to recover the remaining costs of

the retired Big Bend coal generation assets, Units 1 through 3, which are spread over

15 years

, effective

January 1, 2022. This recovery mechanism was authorized by and survives the term of the settlement

agreement approved by the FPSC in 2021.

Storm Reserve:

In September 2022, TEC was impacted by Hurricane Ian, with $

119

 million USD of restoration costs

charged against TEC’s FPSC approved storm reserve. Total restoration costs charged to the storm

reserve exceeded the reserve balance and have been deferred as a regulatory asset for future recovery. 

On January 23, 2023, TEC petitioned the FPSC for recovery of the storm reserve regulatory asset and

the replenishment of the balance in the storm reserve to the approved storm reserve level of $

56

 million

USD, for a total of $

131

 million USD. The storm cost recovery surcharge was approved by the FPSC on

March 7, 2023, and TEC began applying the surcharge in April 2023. Subsequently, on November 9,

2023, the FPSC approved TEC’s petition, filed on August 16, 2023, to update the total storm cost

collection to $

134

 million USD. It also changed the collection of the expected remaining balance of $

29

million USD as of December 31, 2023, from over the first three months of 2024 to over the 12 months of

2024. The storm recovery is subject to review of the underlying costs for prudency and accuracy by the

FPSC.

In Q3 2023, TEC was impacted by Hurricane Idalia. The related storm restoration costs were

approximately $

35

 million USD, which were charged to the storm reserve regulatory asset, resulting in

minimal impact to earnings.

Storm Protection Cost Recovery Clause and Settlement Agreement:

The Storm Protection Plan (“SPP”) Cost Recovery Clause provides a process for Florida investor-owned

utilities, including TEC, to recover transmission and distribution storm hardening costs for incremental

activities not already included in base rates. Differences between prudently incurred clause-recoverable

costs and amounts recovered from customers through electricity rates in a year are deferred and

recovered from or returned to customers in a subsequent year. A settlement agreement was approved on

August 10, 2020, and TEC’s cost recovery began in January 2021. The current approved plan addressed

the years 2023, 2024 and 2025 and was approved by the FPSC on October 4, 2022.

Canadian Electric Utilities

NSPI

NSPI is a public utility as defined in the Public Utilities Act of Nova Scotia (“Public Utilities Act”) and is

subject to regulation under the Public Utilities Act by the UARB. The Public Utilities Act gives the UARB

supervisory powers over NSPI’s operations and expenditures. Electricity rates for NSPI’s customers are

also subject to UARB approval. NSPI is not subject to a general annual rate review process, but rather

participates in hearings held from time to time at NSPI’s or the UARB’s request.

NSPI is regulated under a cost-of-service model, with rates set to recover prudently incurred costs of

providing electricity service to customers and provide a reasonable return to investors. NSPI’s approved

regulated ROE range for 2023 and 2022 was

8.75

 per cent to

9.25

 per cent based on an actual five

quarter average regulated common equity component of up to

40

 per cent of approved rate base.

Exhibit 99.3

30

General Rate Application (“GRA”):

On February 2, 2023, the UARB approved the GRA settlement agreement between NSPI, key customer

representatives and participating interest groups. This resulted in average customer rate increases of

6.9

per cent effective on February 2, 2023, and further average increases of

6.5

 per cent on January 1, 2024,

with any under or over-recovery of fuel costs addressed through the UARB’s established FAM process. It

also established a storm rider and a demand-side management rider. On March 27, 2023, the UARB

issued a final order approving the electricity rates effective on February 2, 2023.

Fuel Recovery:

For the period of 2020 through 2022, NSPI operated under a three-year fuel stability plan with no fuel rate

adjustments related to the under-recovery of fuel and fuel-related costs in the period. 

On January 29, 2024, NSPI applied to the UARB for approval of a structure that would begin to recover

the outstanding FAM balance. As part of the application, NSPI requested approval for the sale of $

117

million of the FAM regulatory asset to Invest Nova Scotia, a provincial Crown corporation, with the

proceeds paid to NSPI upon approval. NSPI has requested approval to collect from customers the

amortization and financing costs of $

117

 million on behalf of Invest Nova Scotia over a

10

-year period,

and remit those amounts to Invest Nova Scotia as collected, reducing short-term customer rate increases

relative to the currently established FAM process. If approved, this portion of the FAM regulatory asset

would be removed from the Consolidated Balance Sheets and NSPI would collect the balance on behalf

of Invest Nova Scotia in NSPI rates beginning in 2024. 

Storm Rider:

The storm rider was effective as of the GRA decision date. The application for deferral and recovery of

the storm rider is made in the year following the year of the incurred cost, with recovery beginning in the

year after the application. Total major storm restoration expense for 2023 was $

31

 million, of which $

21

million was deferred to the storm rider.

Hurricane Fiona:

On October 31, 2023, NSPI submitted an application to the UARB to defer $

24

 million in incremental

operating costs incurred during Hurricane Fiona storm restoration efforts in September 2022. NSPI is

seeking amortization of the costs over a period to be approved by the UARB during a future rate setting

process. At December 31, 2023, the $

24

 million is deferred to “Other long-term assets”, pending UARB

approval. 

Maritime Link:

The Maritime Link is a $

1.8

 billion (including AFUDC) transmission project including

two

170

-kilometre

sub-sea cables, connecting the island of Newfoundland and Nova Scotia. The Maritime Link entered

service on January 15, 2018 and NSPI started interim assessment payments to NSPML at that time. 

Any difference between the amounts recovered from customers through rates and those approved by the

UARB through the NSPML interim assessment application will be addressed through the FAM. 

Nova Scotia Cap-and-Trade (“Cap-and-Trade”) Program:

As of December 31, 2022, the FAM included a cumulative $

166

 million in fuel costs related to the accrued

purchase of emissions credits and $

6

 million related to credits purchased from provincial auctions. On

March 16, 2023, the Province of Nova Scotia provided NSPI with emissions allowances sufficient to

achieve compliance for the 2019 through 2022 period. As such, compliance costs accrued of $

166

 million

were reversed in Q1 2023. The credits NSPI purchased from provincial auctions in the amount of $

6

million were not refunded and no further costs were incurred to achieve compliance with the Cap-and-

Trade Program.

Exhibit 99.3

31

Extra Large Industrial Active Demand Tariff:

On July 5, 2023, NSPI received approval from the UARB to change the methodology in which fuel cost

recovery from an industrial customer is calculated. Due to significant volatility in commodity prices in

2022, the previous methodology did not result in a reasonable determination of the fuel cost to serve this

customer. The change in methodology, effective January 1, 2022, results in a shifting of fuel costs from

this industrial customer to the FAM. This adjustment was recorded in Q2 2023 resulting in a $

51

 million

increase to the FAM regulatory asset and an offsetting decrease to unbilled revenue within Receivables

and other current assets. This adjustment had minimal impact on earnings.

NSPML

Equity earnings from the Maritime Link are dependent on the approved ROE and operational

performance of NSPML. NSPML’s approved regulated ROE range is

8.75

 per cent to

9.25

 per cent,

based on an actual five-quarter average regulated common equity component of up to

30

 per cent. 

Nalcor’s Nova Scotia Block (“NS Block”) delivery obligations commenced on August 15, 2021 and

delivery will continue over the next

35 years

 pursuant to the agreements. 

In February 2022, the UARB issued its decision and Board Order approving NSPML’s requested rate

base of approximately $

1.8

 billion less $

9

 million of costs ($

7

 million after-tax) that would not have

otherwise been recoverable if incurred by NSPI.

On October 4, 2023 and January 31, 2024, the UARB issued decisions providing clarification on

remaining aspects of the Maritime Link holdback mechanism primarily relating to release of past and

future holdback amounts and requirements to end the holdback mechanism. In these decisions, the

UARB agreed with the Company’s submission that $

12

 million ($

8

 million related to 2022 and $

4

 million

relating to 2023) of the previously recorded holdback remain credited to NSPI’s FAM, with the remainder

released to NSPML and recorded in Emera’s “Income from equity investments. NSPML did not record

any additional holdback in Q4 2023. The UARB also confirmed that the holdback mechanism will cease

once

90

 per cent of NS Block deliveries are achieved for 12 consecutive months (subject to potential

relief for planned outages or exceptional circumstances) and the net outstanding balance of previously

underdelivered NS Block energy is less than

10

 per cent of the contracted annual amount. In addition, the

UARB increased the monthly holdback amount from $

2

 million to $

4

 million beginning December 1, 2023. 

On December 21, 2023, NSPML received approval to collect up to $

164

 million (2023 – $

164

 million)

from NSPI for the recovery of costs associated with the Maritime Link in 2024; subject to a holdback of up

to $

4

 million a month, as discussed above.

Gas Utilities and Infrastructure

PGS

PGS is regulated by the FPSC. The FPSC sets rates at a level that allows utilities such as PGS to collect

total revenues or revenue requirements equal to their cost of providing service, plus an appropriate return

on invested capital.

PGS’s approved ROE range for 2023 and 2022 was

8.9

 per cent to

11.0

 per cent with a

9.9

 per cent

midpoint, based on an allowed equity capital structure of

54.7

 per cent. 

Base Rates:

On April 4, 2023, PGS filed a rate case with the FPSC and a hearing for the matter was held in

September 2023. On November 9, 2023, the FPSC approved a $

118

 million USD increase to base

revenues which includes $

11

 million USD transferred from the cast iron and bare steel replacement rider,

for a net incremental increase to base revenues of $

107

 million USD. This reflects a

10.15

 per cent

midpoint ROE with an allowed equity capital structure of

54.7

 per cent.  A final order was issued on

December 27, 2023, with the new rates effective January 2024.

Exhibit 99.3

32

The 2020 PGS rate case settlement provided the ability to reverse a total of $

34

 million USD of

accumulated depreciation through 2023. PGS reversed $

20

 million USD of accumulated depreciation in

2023 and $

14

 million USD in 2022.

Fuel Recovery:

PGS recovers the costs it pays for gas supply and interstate transportation for system supply through its

PGAC. This clause is designed to recover actual costs incurred by PGS for purchased gas, gas storage

services, interstate pipeline capacity, and other related items associated with the purchase, distribution,

and sale of natural gas to its customers. These charges may be adjusted monthly based on a cap

approved annually by the FPSC.

Recovery of Energy Conservation and Pipeline Replacement Programs:

The FPSC annually approves a conservation charge that is intended to permit PGS to recover prudently

incurred expenditures in developing and implementing cost effective energy conservation programs which

are required by Florida law and approved and monitored by the FPSC. PGS also has a Cast Iron/Bare

Steel Pipe Replacement clause to recover the cost of accelerating the replacement of cast iron and bare

steel distribution lines in the PGS system. In February 2017, the FPSC approved expansion of the Cast

Iron/Bare Steel clause to allow recovery of accelerated replacement of certain obsolete plastic pipe. The

majority of cast iron and bare steel pipe has been removed from its system, with replacement of obsolete

plastic pipe continuing until 2028 under the rider. 

NMGC

NMGC is subject to regulation by the NMPRC. The NMPRC sets rates at a level that allows NMGC to

collect total revenues equal to its cost of providing service, plus an appropriate return on invested capital. 

NMGC’s approved ROE for 2023 and 2022 was

9.375

 per cent on an allowed equity capital structure of

52

 per cent.

Base Rates:

On September 14, 2023, NMGC filed a rate case with the NMPRC for new base rates to become effective

Q4 2024. NMGC requested $

49

 million USD in annual base revenues primarily as a result of increased

operating costs and capital investments in pipeline projects and related infrastructure. The rate case

includes a requested ROE of

10.5

 per cent.

Fuel Recovery:

NMGC recovers gas supply costs through a PGAC. This clause recovers actual costs for purchased gas,

gas storage services, interstate pipeline capacity, and other related items associated with the purchase,

transmission, distribution, and sale of natural gas to its customers. On a monthly basis, NMGC can adjust

charges based on the next month’s expected cost of gas and any prior month under-recovery or over-

recovery. The NMPRC requires that NMGC annually file a reconciliation of the PGAC period costs and

recoveries. NMGC must file a PGAC Continuation Filing with the NMPRC every four years to establish

that the continued use of the PGAC is reasonable and necessary. NMGC received approval of its PGAC

Continuation in December 2020, for the four-year period ending December 2024.

Integrity Management Programs (“IMP”) Regulatory Asset:

A portion of NMGC’s annual spending on infrastructure is for IMP, or the replacement and update of

legacy systems. These programs are driven both by NMGC integrity management plans and federal and

state mandates. In December 2020, NMGC received approval through its rate case to defer costs through

an IMP regulatory asset for certain of its IMP capital investments occurring between January 1, 2022 and

December 31, 2023 and petitioned recovery of the regulatory asset in its rate case filed on December 13,

2021. On November 30, 2022, the NMPRC issued a Final Order that included approval of recovery of the

IMP regulatory asset.

Exhibit 99.3

33

Brunswick Pipeline 

Brunswick Pipeline is a

145

-kilometre pipeline delivering natural gas from the Saint John LNG import

terminal near Saint John, New Brunswick to markets in the northeastern United States. Brunswick

Pipeline entered into a

25

-year firm service agreement commencing in July 2009 with Repsol Energy

North America Canada Partnership. The agreement provides for a predetermined toll increase in the fifth

and fifteenth year of the contract. The pipeline is considered a Group II pipeline regulated by the Canada

Energy Regulator (“CER”). The CER Gas Transportation Tariff is filed by Brunswick Pipeline in

compliance with the requirements of the CER Act and sets forth the terms and conditions of the

transportation rendered by Brunswick Pipeline.

Other Electric Utilities

BLPC

BLPC is regulated by the Fair Trading Commission (“FTC”), under the Utilities Regulation (Procedural)

Rules 2003. BLPC is regulated under a cost-of-service model, with rates set to recover prudently incurred

costs of providing electricity service to customers plus an appropriate return on capital invested. BLPC’s

approved regulated return on rate base was

10

 per cent for 2023 and 2022.

Licenses:

BLPC currently operates pursuant to a single integrated license to generate, transmit and distribute

electricity on the island of Barbados until 2028. In 2019, the Government of Barbados passed legislation

requiring multiple licenses for the supply of electricity. In 2021, BLPC reached commercial agreement with

the Government of Barbados for each of the license types, subject to the passage of implementing

legislation. The timing of the final enactment is unknown at this time, but BLPC will work towards the

implementation of the licenses once enacted.

Base Rates:

In 2021, BLPC submitted a general rate review application to the FTC. In September 2022, the FTC

granted BLPC interim rate relief, allowing an increase in base rates of approximately $

1

 million USD per

month. On February 15, 2023, the FTC issued a decision on the application which included the following

significant items: an allowed regulatory ROE of

11.75

 per cent, an equity capital structure of

55

 per cent,

a directive to update the major components of rate base to September 16, 2022, and a directive to

establish regulatory liabilities related to the self-insurance fund of $

50

 million USD, prior year benefits

recognized on remeasurement of deferred income taxes of $

5

 million USD, and accumulated depreciation

of $

16

 million USD. On March 7, 2023, BLPC filed a Motion for Review and Variation (the “Motion”) and

applied for a stay of the FTC’s decision, which was subsequently granted. On November 20, 2023, the

FTC issued their decision dismissing the Motion. Interim rates continue to be in effect through to a date to

be determined in a final decision and order. 

On December 1, 2023, BLPC appealed certain aspects of the FTC’s February 15 and November 20,

2023, decisions to the Supreme Court of Barbados in the High Court of Justice (the “Court”) and

requested that they be stayed. On December 11, 2023, the Court granted the stay. BLPC’s position is

that the FTC made errors of law and jurisdiction in their decisions and believes the success of the appeal

is probable, and as a result, the adjustments to BLPC’s final rates and rate base, including any

adjustments to regulatory assets and liabilities, have not been recorded at this time.

Fuel Recovery:

BLPC’s fuel costs flow through a fuel pass-through mechanism which provides opportunity to recover all

prudently incurred fuel costs from customers in a timely manner. The calculation of the fuel charge is

adjusted on a monthly basis and reported to the FTC for approval.

Exhibit 99.3

34

Clean Energy Transition Program (“CETP”):

On May 31, 2023, the FTC approved BLPC’s application to establish an alternative cost recovery

mechanism to recover prudently incurred costs associated with its CETP (the “Decision”). The

mechanism is intended to facilitate the timely recovery between rate cases of costs associated with

approved renewable energy assets. BLPC will be required to submit an individual application for the

recovery of costs of each asset through the cost recovery mechanism, meeting the minimum criteria as

set out in the Decision. On October 5, 2023, BLPC applied to the FTC to recover the costs of a battery

storage system through the CETP.

Fuel Hedging:

On October 21, 2021, the FTC approved BLPC’s application to implement a fuel hedging program which

will be incorporated into the calculation of the fuel clause adjustment. On November 10, 2021, BLPC

requested the FTC review the required

50

/50 cost sharing arrangement between BLPC and customers in

relation to the hedging administrative costs, or any gains and losses associated with the hedging

program.

GBPC

GBPC is regulated by the GBPA. The GBPA has granted GBPC a licensed, regulated and exclusive

franchise to produce, transmit and distribute electricity on the island until 2054. Rates are set to recover

prudently incurred costs of providing electricity service to customers plus an appropriate return on rate

base. GBPC’s approved regulated return on rate base was

8.32

 per cent for 2023 (2022 –

8.23

 per cent).

Base Rates:

There is a fuel pass-through mechanism and tariff review policy with new rates submitted every three

years. On January 14, 2022, the GBPA issued its decision on GBPC’s application for rate review that was

filed with the GBPA on September 23, 2021. The decision, which became effective April 1, 2022, allows

for an increase in revenues of $

3.5

 million USD. The rates include a regulatory ROE of

12.84

 per cent.

Fuel Recovery:

GBPC’s fuel costs flow through a fuel pass-through mechanism which provides the opportunity to recover

all prudently incurred fuel costs from customers in a timely manner.

Effective November 1, 2022, GBPC’s fuel pass through charge was increased due to an increase in

global oil prices impacting the unhedged fuel cost. In 2023, the fuel pass through charge was adjusted

monthly, in-line with actual fuel costs.

Storm Restoration Costs – Hurricane Matthew:

As part of the recovery of costs incurred as a result of Hurricane Matthew, in 2016, the GBPA approved a

fixed per kWh fuel charge and allowed the difference between this and the actual cost of fuel to be

applied to the Hurricane Matthew regulatory asset. As part of its decision on GBPC’s application for rate

review, issued January 14, 2022, and effective April 1, 2022, the GBPA approved the continued

amortization of the remaining regulatory asset over the three year period ending December 31, 2024.

Exhibit 99.3

35

7. INVESTMENTS SUBJECT TO SIGNIFICANT INFLUENCE AND EQUITY INCOME

Equity Income

Percentage

Carrying Value

For the year ended

of

As at December 31

December 31

Ownership

millions of dollars

2023

2022

2023

2022

2023

LIL

(1)

$

747

$

740

$

63

$

58

31.0

NSPML

489

501

46

29

100.0

M&NP

 (2)

118

128

21

21

12.9

Lucelec

(2)

48

49

4

4

19.5

Bear Swamp

 (3)

-

-

12

17

50.0

$

1,402

$

1,418

$

146

$

129

(1) Emera indirectly owns

100

 per cent of the Class B units, which comprises

24.5

 per cent of the total units issued. Percentage

ownership in LIL is subject to change, based on the balance of capital investments required from Emera and Nalcor Energy to

complete construction of the LIL. Emera’s ultimate percentage investment in LIL will be determined upon final costing of 

all transmission projects related to the Muskrat Falls development, including the LIL, Labrador Transmission Assets and Maritime

Link Projects, such that Emera’s total investment in the Maritime Link and LIL will equal

49

 per cent of the cost of all of these

transmission developments.

(2) Emera has significant influence over the operating and financial decisions of these companies through Board representation and

therefore, records its investment in these entities using the equity method. 

(3) The investment balance in Bear Swamp is in a credit position primarily as a result of a $

179

 million distribution received in 2015.

Bear Swamp's credit investment balance of $

81

 million (2022 – $

95

 million) is recorded in Other long-term liabilities on the

Consolidated Balance Sheets.

Equity investments include a $

10

 million difference between the cost and the underlying FV of the

investees' assets as at the date of acquisition. The excess is attributable to goodwill.

Emera accounts for its variable interest investment in NSPML as an equity investment (note 32).

NSPML's consolidated summarized balance sheets are illustrated as follows:

As at

December 31

millions of dollars

2023

2022

Balance Sheets

Current assets

$

21

$

17

PP&E

1,473

1,517

Regulatory assets

272

265

Non-current assets

29

29

Total assets

$

1,795

$

1,828

Current liabilities

$

48

$

48

Long-term debt

(1)

1,109

1,149

Non-current liabilities

149

130

Equity

489

501

Total liabilities and equity

$

1,795

$

1,828

(1) The project debt has been guaranteed by the Government of Canada.

8. OTHER INCOME, NET

For the

Year ended December 31

millions of dollars

2023

2022

Interest income

$

43

$

25

AFUDC

38

52

Pension non-current service cost recovery

35

24

FX gains (losses)

20

(26)

TECO Guatemala Holdings award

(1)

-

63

Other 

22

7

$

158

$

145

(1) On December 15, 2022, a payment of $

63

 million was made by the Republic of Guatemala to TECO Energy in satisfaction of the

second and final award issued by the International Centre of the Settlement of Investment Disputes tribunal regarding a dispute over

an investment in TGH, a wholly-owned subsidiary of TECO Energy.

Exhibit 99.3

36

9. INTEREST EXPENSE, NET

Interest expense, net consisted of the following:

For the

Year ended December 31

millions of Canadian dollars

2023

2022

Interest on debt 

$

954

$

727

Allowance for borrowed funds used during construction

(16)

(21)

Other

(13)

3

$

925

$

709

10. INCOME TAXES

The income tax provision, for the years ended December 31, differs from that computed using the

enacted combined Canadian federal and provincial statutory income tax rate for the following reasons:

millions of dollars

2023

2022

Income before provision for income taxes

$

1,173

$

1,194

Statutory income tax rate

29.0%

29.0%

Income taxes, at statutory income tax rate

340

346

Deferred income taxes on regulated income recorded as regulatory assets and

regulatory liabilities

(72)

(70)

Tax credits

(53)

(18)

Foreign tax rate variance

(36)

(44)

Amortization of deferred income tax regulatory liabilities

(33)

(33)

Tax effect of equity earnings

(15)

(10)

GBPC impairment charge 

-

21

Other

(3)

(7)

Income tax expense

$

128

$

185

Effective income tax rate

11%

15%

On August 16, 2022, the United States Inflation Reduction Act (“IRA”) was signed into legislation. The

IRA includes numerous tax incentives for clean energy, such as the extension and modification of existing

investment and production tax credits for projects placed in service through 2024 and introduces new

technology-neutral clean energy related tax credits beginning in 2025. As of December 31, 2023, the

Company has recorded a $

30

 million (2022 - $

9

 million) regulatory liability on the Consolidated Balance

Sheets in recognition of its obligation to pass the incremental tax benefits realized to customers.

The following table reflects the composition of taxes on income from continuing operations presented in

the Consolidated Statements of Income for the years ended December 31:

millions of dollars

2023

2022

Current income taxes

 Canada

$

26

$

25

 United States

5

8

Deferred income taxes

 Canada

93

122

 United States

128

252

Investment tax credits

 United States

(29)

(7)

Operating loss carryforwards

 Canada

(93)

(94)

 United States

(2)

(121)

Income tax expense

$

128

$

185

Exhibit 99.3

37

The following table reflects the composition of income before provision for income taxes presented in the

Consolidated Statements of Income for the years ended December 31:

millions of dollars

2023

2022

Canada

$

171

$

173

United States

964

1,063

Other

38

(42)

Income before provision for income taxes

$

1,173

$

1,194

The deferred income tax assets and liabilities presented in the Consolidated Balance Sheets as at

December 31 consisted of the following:

millions of dollars

2023

2022

Deferred income tax assets:

Tax loss carryforwards

$

1,195

$

1,207

Tax credit carryforwards

454

415

Derivative instruments

205

45

Regulatory liabilities 

175

264

Other

372

341

Total deferred income tax assets before valuation allowance

2,401

2,272

Valuation allowance

(363)

(312)

Total deferred income tax assets after valuation allowance

$

2,038

$

1,960

Deferred income tax (liabilities):

PP&E

$

(3,223)

$

(2,981)

Derivative instruments

(235)

(125)

Investments subject to significant influence

(216)

(181)

Regulatory assets

(196)

(310)

Other

(312)

(322)

Total deferred income tax liabilities 

$

(4,182)

$

(3,919)

Consolidated Balance Sheets presentation:

Long-term deferred income tax assets

$

208

$

237

Long-term deferred income tax liabilities

(2,352)

(2,196)

Net deferred income tax liabilities

$

(2,144)

$

(1,959)

Considering all evidence regarding the utilization of the Company’s deferred income tax assets, it has

been determined that Emera is more likely than not to realize all recorded deferred income tax assets,

except for certain loss carryforwards and unrealized capital losses on long-term debt and investments. A

valuation allowance of $

363

 million has been recorded as at December 31, 2023 (2022 – $

312

 million)

related to the loss carryforwards, long-term debt and investments.

The Company intends to indefinitely reinvest earnings from certain foreign operations. Accordingly, as at

December 31, 2023, $

4.7

 billion (2022 – $

3.8

 billion) in cumulative temporary differences for which

deferred taxes might otherwise be required, have not been recognized. It is impractical to estimate the

amount of income and withholding tax that might be payable if a reversal of temporary differences

occurred.

Exhibit 99.3

38

Emera’s NOL, capital loss and tax credit carryforwards and their expiration periods as at December 31,

2023 consisted of the following:

Subject to

Tax

Valuation

Net Tax

Expiration

millions of dollars

Carryforwards

Allowance

Carryforwards

Period

Canada

 NOL

$

2,914

$

(1,164)

$

1,750

2026 - 2043

 Capital loss

73

(73)

-

Indefinite

United States

 Federal NOL

$

1,360

$

(1)

$

1,359

2036 - Indefinite

 State NOL

1,003

(1)

1,002

2026 - Indefinite

 Tax credit

454

(3)

451

2025 - 2043

Other

 NOL

$

81

$

(28)

$

53

2024 - 2030

The following table provides details of the change in unrecognized tax benefits for the years ended

December 31 as follows:

millions of dollars

2023

2022

Balance, January 1

$

33

$

28

Increases due to tax positions related to current year

5

5

Increases due to tax positions related to a prior year

1

2

Decreases due to tax positions related to a prior year

(2)

(2)

Balance, December 31

$

37

$

33

Unrecognized tax benefits relate to the timing of certain tax deductions at NSPI and research and

development tax credits primarily at TEC. The total amount of unrecognized tax benefits as at December

31, 2023 was $

37

 million (2022 – $

33

 million), which would affect the effective tax rate if recognized. The

total amount of accrued interest with respect to unrecognized tax benefits was $

9

 million (2022 – $

7

million) with $

2

 million interest expense recognized in the Consolidated Statements of Income (2022 – $

1

million).

No

 penalties have been accrued. The balance of unrecognized tax benefits could change in the

next 12 months as a result of resolving Canada Revenue Agency (“CRA”) and Internal Revenue Service

audits. A reasonable estimate of any change cannot be made at this time.

During 2022, the CRA issued notices of reassessment to NSPI for the 2013 through 2016 taxation years.

NSPI and the CRA are currently in a dispute with respect to the timing of certain tax deductions for

its 2006 through 2010 and 2013 through 2016 taxation years. The ultimate permissibility of the tax

deductions is not in dispute; rather, it is the timing of those deductions. The cumulative net amount in

dispute to date is $

126

 million (2022 – $

126

 million), including interest. NSPI has prepaid $

55

 million of

the amount in dispute, as required by CRA.

On November 29, 2019, NSPI filed a Notice of Appeal with the Tax Court of Canada with respect to its

dispute of the 2006 through 2010 taxation years. Should NSPI be successful in defending its position, all

payments including applicable interest will be refunded. If NSPI is unsuccessful in defending any portion

of its position, the resulting taxes and applicable interest will be deducted from amounts previously paid,

with the difference, if any, either owed to, or refunded from, the CRA. The related tax deductions will be

available in subsequent years.

Should NSPI be similarly reassessed by the CRA for years not currently in dispute, further payments will

be required; however, the ultimate permissibility of these deductions would be similarly not in dispute.

NSPI and its advisors believe that NSPI has reported its tax position appropriately. NSPI continues to

assess its options to resolving the dispute; however, the outcome of the Notice of Appeal process is not

determinable at this time.

Exhibit 99.3

39

Emera files a Canadian federal income tax return, which includes its Nova Scotia provincial income tax.

Emera’s subsidiaries file Canadian, US, Barbados, and St. Lucia income tax returns. As at December 31,

2023, the Company’s tax years still open to examination by taxing authorities include 2005 and

subsequent years.

11. COMMON STOCK

Authorized

: Unlimited number of non-par value common shares.

2023

2022

Issued and outstanding:

millions

of shares

 millions of

dollars

millions of

shares

 millions of

dollars

Balance, January 1

269.95

$

7,762

261.07

$

7,242

Issuance of common stock under ATM program

(1)(2)

8.29

397

4.07

248

Issued under the DRIP, net of discounts

5.26

272

4.21

238

Senior management stock options exercised and Employee Share

Purchase Plan

0.62

31

0.60

34

Balance, December 31

284.12

$

8,462

269.95

$

7,762

(1) For the year ended December 31, 2022, a total of

4,072,469

 common shares were issued under Emera's ATM program at an

average price of $

61.31

 per share for gross proceeds of $

250

 million ($

248

 million net of after-tax issuance costs).

(2) For the year ended December 31, 2023, a total of

8,287,037

 common shares were issued under Emera's ATM program at an

average price of $

48.27

 per share for gross proceeds of $

400

 million ($

397

 million net of after-tax issuance costs).

As at December 31, 2023, the following common shares were reserved for issuance:

6

 million (2022 –

6

million) under the senior management stock option plan,

2

 million (2022 –

2.7

 million) under the employee

common share purchase plan and

18

 million (2022 –

10

 million) under the DRIP. 

The issuance of common shares under the common share compensation arrangements does not allow

the plans to exceed

10

 per cent of Emera's outstanding common shares. As at December 31, 2023,

Emera was in compliance with this requirement.

ATM Equity Program

On October 3, 2023, Emera filed a short form base shelf prospectus, primarily in support of the renewal of

its ATM Program in Q4 2023 that will allow the Company to issue up to $

600

 million of common shares

from treasury to the public from time to time, at the Company’s discretion, at the prevailing market price.

This ATM Program is expected to remain in effect until November 4, 2025.

12. EARNINGS PER SHARE

Basic earnings per share is determined by dividing net income attributable to common shareholders by

the weighted average number of common shares outstanding during the period. Diluted EPS is computed

by dividing net income attributable to common shareholders by the weighted average number of common

shares outstanding during the period, adjusted for the exercise and/or conversion of all potentially dilutive

securities. Such dilutive items include Company contributions to the senior management stock option

plan, convertible debentures and shares issued under the DRIP.

Exhibit 99.3

40

The following table reconciles the computation of basic and diluted earnings per share:

For the

Year ended December 31

millions of dollars (except per share amounts)

2023

2022

Numerator

Net income attributable to common shareholders

$

977.7

$

945.1

Diluted numerator

977.7

945.1

Denominator

Weighted average shares of common stock outstanding – basic

273.6

265.5

Stock-based compensation 

0.2

0.4

Weighted average shares of common stock outstanding – diluted

273.8

265.9

Earnings per common share

Basic 

$

3.57

$

3.56

Diluted

$

3.57

$

3.55

13. ACCUMULATED OTHER COMPREHENSIVE INCOME

The components of AOCI are as follows:

millions of dollars

Unrealized

(loss) gain on

translation of

self-sustaining

foreign

operations

Net change in

net investment

hedges

Losses on

derivatives

recognized 

as cash flow

hedges

Net change

on available-

for-sale

investments

Net change in

unrecognized

pension and

post-retirement

benefit costs

Total 

AOCI

For the year ended December 31, 2023

Balance, January 1, 2023

$

639

$

(62)

$

16

$

(2)

$

(13)

$

578

Other comprehensive (loss) 

income before 

reclassifications

(270)

38

 - 

-

-

(232)

Amounts reclassified from 

AOCI

-

-

(2)

-

(39)

(41)

Net current period other

comprehensive (loss) income

(270)

38

(2)

-

(39)

(273)

Balance, December 31, 2023

$

369

$

(24)

$

14

$

(2)

$

(52)

$

305

For the year ended December 31, 2022

Balance, January 1, 2022

$

10

$

35

$

18

$

(1)

$

(37)

$

25

Other comprehensive 

income (loss) before 

reclassifications

629

(97)

-

(1)

-

531

Amounts reclassified from 

AOCI

-

-

(2)

-

24

22

Net current period other

comprehensive income (loss)

629

(97)

(2)

(1)

24

553

Balance, December 31, 2022

$

639

$

(62)

$

16

$

(2)

$

(13)

$

578

Exhibit 99.3

41

The reclassifications out of AOCI are as follows:

For the

Year ended December 31

millions of dollars

2023

2022

Affected line item in the Consolidated Financial Statements

Gains on derivatives recognized as cash flow hedges

 Interest rate hedge

Interest expense, net

$

(2)

$

(2)

Net change in unrecognized pension and post-retirement benefit costs

 Actuarial losses

Other income, net

$

-

$

10

 Past service costs

Other income, net

2

-

 Amounts reclassified into obligations

Pension and post-retirement benefits

(40)

15

Total before tax

(38)

25

Income tax expense

(1)

(1)

Total net of tax

$

(39)

$

24

Total reclassifications out of AOCI, net of tax, for the period

$

(41)

$

22

14. INVENTORY

As at

December 31

December 31

millions of dollars 

2023

2022

Fuel 

$

382

$

404

Materials 

408

365

Total

$

790

$

769

15. DERIVATIVE INSTRUMENTS

Derivative assets and liabilities relating to the foregoing categories consisted of the following:

Derivative Assets

Derivative Liabilities

As at

December 31

December 31

December 31

December 31

millions of dollars

2023

2022

2023

2022

Regulatory deferral:

 Commodity swaps and forwards

$

16

$

186

$

76

$

42

 FX forwards

3

18

3

1

 Physical natural gas purchases and sales

-

52

-

-

19

256

79

43

HFT derivatives:

 Power swaps and physical contracts

29

89

36

77

 Natural gas swaps, futures, forwards, physical 

 contracts

319

340

531

1,224

348

429

567

1,301

Other derivatives:

 Equity derivatives 

4

-

-

5

 FX forwards

18

5

7

23

22

5

7

28

Total gross current derivatives

389

690

653

1,372

Impact of master netting agreements:

 Regulatory deferral

(3)

(18)

(3)

(18)

 HFT derivatives

(146)

(276)

(146)

(276)

Total impact of master netting agreements

(149)

(294)

(149)

(294)

Total derivatives

$

240

$

396

$

504

$

1,078

Current

(1)

174

296

386

888

Long-term

(1)

66

100

118

190

Total derivatives

$

240

$

396

$

504

$

1,078

(1) Derivative assets and liabilities are classified as current or long-term based upon the maturities of the underlying contracts.

Exhibit 99.3

42

Cash Flow Hedges

On May 26, 2021, a treasury lock was settled for a gain of $

19

 million that is being amortized through

interest expense over

10 years

 as the underlying hedged item settles.

The amounts related to cash flow hedges recorded in AOCI consisted of the following:

For the

Year ended December 31

millions of dollars

2023

2022

Interest

Interest

rate hedge

rate hedge

Realized gain in interest expense, net

$

2

$

2

Total gains in net income

$

2

$

2

As at

December 31

December 31

millions of dollars

2023

2022

Interest

Interest

rate hedge

rate hedge

Total unrealized gain in AOCI – effective portion, net of tax

$

14

$

16

The Company expects $

2

 million of unrealized gains currently in AOCI to be reclassified into net income

within the next 12 months.

Regulatory Deferral

The Company has recorded the following changes with respect to derivatives receiving regulatory

deferral:

Physical

Commodity

Physical

Commodity

natural gas

swaps and

FX

natural gas

swaps and

FX

millions of dollars

purchases

forwards

forwards

purchases

forwards

forwards

For the year ended December 31

2023

2022

Unrealized gain (loss) in regulatory

assets

$

-

$

(109)

$

(3)

$

-

$

(69)

$

1

Unrealized gain (loss) in regulatory

liabilities

(3)

(73)

-

28

343

16

Realized (gain) loss in regulatory

assets

-

(5)

-

-

48

-

Realized (gain) loss in regulatory

liabilities

-

2

-

-

(41)

-

Realized (gain) loss in inventory

(1)

-

4

(10)

-

(121)

1

Realized (gain) in regulated fuel for

generation and purchased power

(2)

(49)

(9)

(4)

(64)

(146)

-

Other

-

(14)

-

-

-

-

Total change in derivative instruments

$

(52)

$

(204)

$

(17)

$

(36)

$

14

$

18

(1) Realized (gains) losses will be recognized in fuel for generation and purchased power when the hedged item is consumed.

(2) Realized (gains) losses on derivative instruments settled and consumed in the period and hedging relationships that have been

terminated or the hedged transaction is no longer probable.

Exhibit 99.3

43

As at December 31, 2023, the Company had the following notional volumes designated for regulatory

deferral that are expected to settle as outlined below:

millions

2024

2025-2026

Physical natural gas purchases:

Natural gas (MMBtu)

7

6

Commodity swaps and forwards purchases:

Natural gas (MMBtu)

16

10

Power (MWh)

1

1

Coal (metric tonnes)

1

-

FX swaps and forwards:

FX contracts (millions of USD)

$

241

$

70

Weighted average rate

1.3155

1.3197

% of USD requirements

63%

17%

HFT Derivatives

The Company has recognized the following realized and unrealized gains (losses) with respect to HFT

derivatives:

For the 

Year ended December 31

millions of dollars

2023

2022

Power swaps and physical contracts in non-regulated operating revenues

$

(6)

$

17

Natural gas swaps, forwards, futures and physical contracts in non-regulated

operating revenues

1,043

47

Total gains in net income

$

1,037

$

64

As at December 31, 2023, the Company had the following notional volumes of outstanding HFT

derivatives that are expected to settle as outlined below:

2028 and 

millions 

2024

2025

2026

2027

thereafter

Natural gas purchases (Mmbtu)

296

80

50

38

30

Natural gas sales (Mmbtu)

338

86

16

6

4

Power purchases (MWh)

1

-

-

-

-

Power sales (MWh)

1

-

-

-

-

Other Derivatives

As at December 31, 2023, the Company had equity derivatives in place to manage the cash flow risk

associated with forecasted future cash settlements of deferred compensation obligations and FX forwards

in place to manage cash flow risk associated with forecasted USD cash inflows.

The equity derivatives

hedge the return on

2.9

 million shares and extends until December 2024. The FX forwards have a

combined notional amount of $508 million USD and expire in 2023, 2024 and 2025.

For the

Year ended December 31

millions of dollars

2023

2022

FX

Equity

FX

Equity

Forwards

Derivatives

Forwards

Derivatives

Unrealized gain (loss) in OM&G

$

-

$

4

$

-

$

(5)

Unrealized gain (loss) in other income, net

28

-

(18)

-

Realized loss in OM&G

-

(13)

-

(17)

Realized loss in other income, net

(11)

-

(6)

-

Total gains (losses) in net income

$

17

$

(9)

$

(24)

$

(22)

Exhibit 99.3

44

Credit Risk

The Company is exposed to credit risk with respect to amounts receivable from customers, energy

marketing collateral deposits and derivative assets. Credit risk is the potential loss from a counterparty’s

non-performance under an agreement. The Company manages credit risk with policies and procedures

for counterparty analysis, exposure measurement, and exposure monitoring and mitigation. Credit

assessments are conducted on all new customers and counterparties, and deposits or collateral are

requested on any high-risk accounts. 

The Company assesses the potential for credit losses on a regular basis and, where appropriate,

maintains provisions. With respect to counterparties, the Company has implemented procedures to

monitor the creditworthiness and credit exposure of counterparties and to consider default probability in

valuing the counterparty positions. The Company monitors counterparties’ credit standing, including those

that are experiencing financial problems, have significant swings in default probability rates, have credit

rating changes by external rating agencies, or have changes in ownership. Net liability positions are

adjusted based on the Company’s current default probability. Net asset positions are adjusted based on

the counterparty’s current default probability. The Company assesses credit risk internally for

counterparties that are not rated.

As at December 31, 2023, the maximum exposure the Company had to credit risk was $

1.2

 billion (2022

– $

1.9

 billion), which included accounts receivable net of collateral/deposits and assets related to

derivatives. 

It is possible that volatility in commodity prices could cause the Company to have material credit risk

exposures with one or more counterparties. If such counterparties fail to perform their obligations under

one or more agreements, the Company could suffer a material financial loss. The Company transacts with

counterparties as part of its risk management strategy for managing commodity price, FX and interest

rate risk. Counterparties that exceed established credit limits can provide a cash deposit or letter of credit

to the Company for the value in excess of the credit limit where contractually required. The total cash

deposits/collateral on hand as at December 31, 2023 was $

310

 million (2022 – $

386

 million), which

mitigated the Company’s maximum credit risk exposure. The Company uses the cash as payment for the

amount receivable or returns the deposit/collateral to the customer/counterparty where it is no longer

required by the Company.

The Company enters into commodity master arrangements with its counterparties to manage certain

risks, including credit risk to these counterparties. The Company generally enters into International Swaps

and Derivatives Association agreements, North American Energy Standards Board agreements and, or

Edison Electric Institute agreements. The Company believes entering into such agreements offers

protection by creating contractual rights relating to creditworthiness, collateral, non-performance and

default.

As at December 31, 2023, the Company had $

142

 million (2022 – $

131

 million) in financial assets,

considered to be past due, which have been outstanding for an average

64

 days. The FV of these

financial assets was $

127

 million (2022 – $

114

 million), the difference of which was included in the

allowance for credit losses. These assets primarily relate to accounts receivable from electric and gas

revenue.

Exhibit 99.3

45

Concentration Risk

The Company's concentrations of risk consisted of the following:

As at

December 31, 2023

December 31, 2022

millions of

dollars

% of total

exposure

millions of

dollars

% of total

exposure

Receivables, net

Regulated utilities:

Residential

$

476

31%

$

455

19%

Commercial

194

13%

192

8%

Industrial

84

5%

121

5%

Other

103

7%

122

5%

Cash collateral

94

6%

-

0%

951

62%

890

37%

Trading group:

Credit rating of A- or above

47

3%

125

5%

Credit rating of BBB- to BBB+

33

2%

75

3%

Not rated

108

7%

307

13%

188

12%

507

21%

Other accounts receivable

151

10%

585

25%

1,290

84%

1,982

83%

Derivative Instruments

(current and long-term)

Credit rating of A- or above

138

9%

202

9%

Credit rating of BBB- to BBB+

7

1%

8

0%

Not rated

95

6%

186

8%

240

16%

396

17%

$

1,530

100%

$

2,378

100%

Cash Collateral

The Company’s cash collateral positions consisted of the following:

As at

December 31

December 31

millions of dollars

2023

2022

Cash collateral provided to others

$

101

$

224

Cash collateral received from others

$

22

$

112

Collateral is posted in the normal course of business based on the Company’s creditworthiness, including

its senior unsecured credit rating as determined by certain major credit rating agencies. Certain

derivatives contain financial assurance provisions that require collateral to be posted if a material adverse

credit-related event occurs. If a material adverse event resulted in the senior unsecured debt falling below

investment grade, the counterparties to such derivatives could request ongoing full collateralization.

As at December 31, 2023, the total FV of derivatives in a liability position was $

504

 million (December 31,

2022

–

 $

1,078

 million). If the credit ratings of the Company were reduced below investment grade, the full

value of the net liability position could be required to be posted as collateral for these derivatives.

Exhibit 99.3

46

16. FV MEASUREMENTS

The Company is required to determine the FV of all derivatives except those which qualify for the NPNS

exemption (see note 1) and uses a market approach to do so. The three levels of the FV hierarchy are

defined as follows:

Level 1 - Where possible, the Company bases the fair valuation of its financial assets and liabilities on

quoted prices in active markets (“quoted prices”) for identical assets and liabilities.

Level 2 - Where quoted prices for identical assets and liabilities are not available, the valuation of certain

contracts must be based on quoted prices for similar assets and liabilities with an adjustment related to

location differences. Also, certain derivatives are valued using quotes from over-the-counter clearing

houses.

Level 3 - Where the information required for a Level 1 or Level 2 valuation is not available, derivatives

must be valued using unobservable or internally-developed inputs. The primary reasons for a Level 3

classification are as follows:

●

 While valuations were based on quoted prices, significant assumptions were necessary to reflect

seasonal or monthly shaping and locational basis differentials.

●

 The term of certain transactions extends beyond the period when quoted prices are available and,

accordingly, assumptions were made to extrapolate prices from the last quoted period through the

end of the transaction term.

●

 The valuations of certain transactions were based on internal models, although quoted prices were

utilized in the valuations.

Derivative assets and liabilities are classified in their entirety based on the lowest level of input that is

significant to the FV measurement.

Exhibit 99.3

47

The following tables set out the classification of the methodology used by the Company to FV its

derivatives:

As at

December 31, 2023

millions of dollars

Level 1

Level 2

Level 3

Total

Assets

Regulatory deferral:

 Commodity swaps and forwards

$

7

$

6

$

-

$

13

 FX forwards

-

3

-

3

7

9

-

16

HFT derivatives:

 Power swaps and physical contracts

(5)

23

-

18

 Natural gas swaps, futures, forwards, physical 

 contracts and related transportation

42

108

34

184

37

131

34

202

Other derivatives:

 FX forwards

-

18

-

18

 Equity derivatives 

4

-

-

4

4

18

-

22

Total assets

48

158

34

240

Liabilities

Regulatory deferral:

 Commodity swaps and forwards

43

30

-

73

 FX forwards

-

3

-

3

43

33

-

76

HFT derivatives:

 Power swaps and physical contracts

-

24

-

24

 Natural gas swaps, futures, forwards and physical 

 contracts

13

19

365

397

13

43

365

421

Other derivatives:

 FX forwards

-

7

-

7

-

7

-

7

Total liabilities

56

83

365

504

Net assets (liabilities) 

$

(8)

$

75

$

(331)

$

(264)

Exhibit 99.3

48

As at

December 31, 2022

millions of dollars

Level 1

Level 2

Level 3

Total

Assets

Regulatory deferral:

 Commodity swaps and forwards

$

120

$

48

$

-

$

168

 FX forwards

-

18

-

18

 Physical natural gas purchases and sales

-

-

52

52

120

66

52

238

HFT derivatives:

 Power swaps and physical contracts

9

31

4

44

 Natural gas swaps, futures, forwards, physical 

 contracts and related transportation

3

72

34

109

12

103

38

153

Other derivatives:

 FX forwards

-

5

-

5

Total assets

132

174

90

396

Liabilities

Regulatory deferral:

 Commodity swaps and forwards

15

9

-

24

 FX forwards

-

1

-

1

15

10

-

25

HFT derivatives:

 Power swaps and physical contracts

2

28

1

31

 Natural gas swaps, futures, forwards and physical 

 contracts

51

118

825

994

53

146

826

1,025

Other derivatives:

 FX forwards

-

23

-

23

 Equity derivatives

5

-

-

5

Total liabilities

73

179

826

1,078

Net assets (liabilities)

$

59

$

(5)

$

(736)

$

(682)

The change in the FV of the Level 3 financial assets for the year ended December 31, 2023 was as

follows:

Regulatory Deferral

HFT Derivatives

Physical natural

Natural 

millions of dollars

gas purchases

Power 

gas

Total

Balance, January 1, 2023

$

52

$

4

$

34

$

90

Realized gains (losses) included in fuel for generation

and purchased power

(49)

-

-

(49)

Unrealized gains (losses) included in regulatory

assets and liabilities

(3)

-

-

(3)

Total realized and unrealized gains (losses) included

in non-regulated operating revenues

-

(4)

-

(4)

Balance, December 31, 2023

$

-

$

-

$

34

$

34

The change in the FV of the Level 3 financial liabilities for the year ended December 31, 2023 was as

follows:

 HFT Derivatives

Natural

millions of dollars

Power 

gas

Total

Balance, January 1, 2023

$

1

$

825

$

826

Total realized and unrealized gains included in non-

regulated operating revenues

(1)

(460)

(461)

Balance, December 31, 2023 

$

-

$

365

$

365

Exhibit 99.3

49

Significant unobservable inputs used in the FV measurement of Emera’s natural gas and power

derivatives include third-party sourced pricing for instruments based on illiquid markets. Significant

increases (decreases) in any of these inputs in isolation would result in a significantly lower (higher) FV

measurement. Other unobservable inputs used include internally developed correlation factors and basis

differentials; own credit risk; and discount rates. Internally developed correlations and basis differentials

are reviewed on a quarterly basis based on statistical analysis of the spot markets in the various illiquid

term markets. Discount rates may include a risk premium for those long-term forward contracts with

illiquid future price points to incorporate the inherent uncertainty of these points. Any risk premiums for

long-term contracts are evaluated by observing similar industry practices and in discussion with industry

peers.

The Company uses a modelled pricing valuation technique for determining the FV of Level 3 derivative

instruments. The following table outlines quantitative information about the significant unobservable

inputs used in the FV measurements categorized within Level 3 of the FV hierarchy:

Significant

Weighted 

millions of dollars

FV

Unobservable Input

Low

High

average

(1)

Assets

Liabilities

As at December 31, 2023

HFT derivatives – Natural 

34

365

Third-party pricing

$1.27

$16.25

$4.85

gas swaps, futures, forwards 

and physical contracts 

Total

$

34

$

365

Net liability

$

331

As at December 31, 2022

Regulatory deferral –

Physical

$

52

$

-

Third-party pricing

$5.79

$31.85

$12.27

natural gas purchases

HFT derivatives – Power 

4

1

Third-party pricing

$43.24

$269.10

$138.79

swaps and physical contracts

HFT derivatives – Natural 

34

825

Third-party pricing

$2.45

$33.88

$12.01

gas swaps, futures, forwards 

and physical contracts 

Total

$

90

$

826

Net liability

$

736

(1) Unobservable inputs were weighted by the relative FV of the instruments.

Long-term debt is a financial liability not measured at FV on the Consolidated Balance Sheets. The

balance consisted of the following:

As at

Carrying

millions of dollars

Amount

FV

Level 1

Level 2

Level 3

Total

December 31, 2023

$

18,365

$

16,621

$

-

$

16,363

$

258

$

16,621

December 31, 2022

$

16,318

$

14,670

$

-

$

14,284

$

386

$

14,670

The Company has designated $

1.2

 billion USD denominated Hybrid Notes as a hedge of the foreign

currency exposure of its ne

t investment

 in USD denominated operations. The Company’s Hybrid Notes

are contingently convertible into preferred shares in the event of bankruptcy or other related events. A

redemption option on or after June 15, 2026 is available and at the control of the Company. The Hybrid

Notes are classified as Level 2 financial assets. As at December 31, 2023, the FV of the Hybrid Notes

was $

1.2

 billion (2022 – $

1.1

 billion). An after-tax foreign currency gain of $

38

 million was recorded in

AOCI for the year ended December 31, 2023 (2022 – $

97

 million after-tax loss).

Exhibit 99.3

50

17. RELATED PARTY TRANSACTIONS

In the ordinary course of business, Emera provides energy and other services and enters into

transactions with its subsidiaries, associates and other related companies on terms similar to those

offered to non-related parties. Intercompany balances and intercompany transactions have been

eliminated on consolidation, except for the net profit on certain transactions between non-regulated and

regulated entities in accordance with accounting standards for rate-regulated entities. All material

amounts are under normal interest and credit terms. 

Significant transactions between Emera and its associated companies are as follows:

●

 Transactions between NSPI and NSPML related to the Maritime Link assessment are reported in the

Consolidated Statements of Income. NSPI’s expense is reported in Regulated fuel for generation and

purchased power, totalling $

163

 million for the year ended December 31, 2023 (2022 – $

157

 million).

NSPML is accounted for as an equity investment, and therefore corresponding earnings related to

this revenue are reflected in Income from equity investments.

●

Natural gas transportation capacity purchases from M&NP are reported in the Consolidated

Statements of Income. Purchases from M&NP reported net in Operating revenues, Non-regulated,

totalled $

14

 million for the year ended December 31, 2023 (2022

– $

9

 million).

There were no significant receivables or payables between Emera and its associated companies reported

on Emera’s Consolidated Balance Sheets as at December 31, 2023 and at December 31, 2022.

18. RECEIVABLES AND OTHER CURRENT ASSETS

As at

December 31

December 31

millions of dollars 

2023

2022

Customer accounts receivable – billed

$

805

$

1,096

Capitalized transportation capacity

(1)

358

781

Customer accounts receivable – unbilled

363

424

Prepaid expenses

105

82

Income tax receivable

10

9

Allowance for credit losses

(15)

(17)

NMGC gas hedge settlement receivable

 (2)

 - 

162

Other

191

360

Total receivables and other current assets

$

1,817

$

2,897

(1) Capitalized transportation capacity represents the value of transportation/storage received by EES on asset management

agreements at the inception of the contracts. The asset is amortized over the term of each contract.

(2) Offsetting amount is included in regulatory liabilities for NMGC as gas hedges are part of the PGAC. For more information, refer

to note 6.

19. LEASES

Lessee

The Company has operating leases for buildings, land, telecommunication services, and rail cars.

Emera’s leases have remaining lease terms of 1 year to 62 years, some of which include options to

extend the leases for up to 65 years. These options are included as part of the lease term when it is

considered reasonably certain they will be exercised.

Exhibit 99.3

51

As at

December 31

December 31

millions of dollars 

Classification

2023

2022

Right-of-use asset

Other long-term assets

$

54

$

58

Lease liabilities

 Current

Other current liabilities

3

3

 Long-term

Other long-term liabilities

55

59

Total lease liabilities

$

58

$

62

The Company recorded lease expense of $

127

 million for the year ended December 31, 2023 (2022 –

$

138

 million), of which $

119

 million (2022 – $

131

 million) related to variable costs for power generation

facility finance leases, recorded in “Regulated fuel for generation and purchased power” in the

Consolidated Statements of Income.

Future minimum lease payments under non-cancellable operating leases for each of the next five years

and in aggregate thereafter are as follows:

millions of dollars

2024

2025

2026

2027

2028

Thereafter

Total

Minimum lease payments

$

6

$

5

$

3

$

3

$

3

$

111

$

131

Less imputed interest

(73)

Total

$

58

Additional information related to Emera's leases is as follows:

Year ended December 31

For the

2023

2022

Cash paid for amounts included in the measurement of lease liabilities:

 Operating cash flows for operating leases (millions of dollars)

$

8

$

8

Right-of-use assets obtained in exchange for lease obligations:

 Operating leases (millions of dollars)

$

1

$

1

Weighted average remaining lease term (years)

44

44

Weighted average discount rate- operating leases

3.93%

3.98%

Lessor

The Company’s net investment in direct finance and sales-type leases primarily relates to Brunswick

Pipeline, Seacoast, compressed natural gas (“CNG”) stations, a renewable natural gas (“RNG”) facility

and heat pumps.

The Company manages its risk associated with the residual value of the Brunswick Pipeline lease

through proper routine maintenance of the asset.

Customers have the option to purchase CNG station assets by paying a make-whole payment at the date

of the purchase based on a targeted internal rate of return or may take possession of the CNG station

asset at the end of the lease term for no cost. Customers have the option to purchase heat pumps at the

end of the lease term for a nominal fee.

Commencing in October 2023, the Company leased a RNG facility to a biogas producer that is classified

as a sales-type lease. The term of the facility lease is

15 years

, with a nominal value purchase at the end

of the term and a net investment of approximately $

35

 million USD. 

Commencing in January 2022, the Company leased Seacoast pipeline, a 21-mile, 30-inch lateral that is

classified as a sales-type lease. The term of the pipeline lateral lease is

34

 years with a net investment of

$

100

 million USD. The lessee of the pipeline lateral has renewal options for an additional

16

 years. These

renewal options have not been included as part of the pipeline lateral lease term as it is not reasonably

certain that they will be exercised.

Exhibit 99.3

52

Direct finance and sales-type lease unearned income is recognized in income over the life of the lease

using a constant rate of interest equal to the internal rate of return on the lease and is recorded as

“Operating revenues – regulated gas” and “Other income, net” on the Consolidated Statements of

Income.

The total net investment in direct finance and sales-type leases consist of the following:

As at

December 31

December 31

millions of dollars 

2023

2022

Total minimum lease payment to be received

$

1,360

$

1,393

Less: amounts representing estimated executory costs

(190)

(205)

Minimum lease payments receivable

$

1,170

$

1,188

Estimated residual value of leased property (unguaranteed)

183

183

Less: Credit loss reserve

(2)

-

Less: unearned finance lease income

(693)

(733)

Net investment in direct finance and sales-type leases

$

658

$

638

Principal due within one year (included in "Receivables and other

current assets")

37

34

Net Investment in direct finance and sales type leases - long-term

$

621

$

604

As at December 31, 2023, future minimum lease payments to be received for each of the next five years

and in aggregate thereafter were as follows:

millions of dollars

2024

2025

2026

2027

2028

Thereafter

Total

Minimum lease payments to be

received

$

97

$

99

$

98

$

97

$

96

$

873

$

1,360

Less: executory costs

(190)

Total

$

1,170

20. PROPERTY, PLANT AND EQUIPMENT

PP&E consisted of the following regulated and non-regulated assets: 

As at

December 31

December 31

millions of dollars 

Estimated useful life

2023

2022

Generation

3

 to

131

$

13,500

$

13,083

Transmission

10

 to

80

2,835

2,731

Distribution

4

 to

80

7,417

6,978

Gas transmission and distribution

6

 to

92

5,536

5,061

General plant and other

 (1)

2

 to

71

2,985

2,723

Total cost

32,273

30,576

Less: Accumulated depreciation

(1)

(9,994)

(9,574)

22,279

21,002

Construction work in progress

(1)

2,097

1,994

Net book value

$

24,376

$

22,996

(1) SeaCoast owns a

50

% undivided ownership interest in a jointly owned

26

-mile pipeline lateral located in Florida, which went into

service in 2020. At December 31, 2023, SeaCoast’s share of plant in service was $

27

 million USD (2022 – $

27

 million USD), and

accumulated depreciation of $

2

 million USD (2022 – $

1

 million USD). SeaCoast’s undivided ownership interest is financed with its

funds and all operations are accounted for as if such participating interest were a wholly owned facility. SeaCoast’s share of direct

expenses of the jointly owned pipeline is included in "OM&G" in the Consolidated Statements of Income.

21. EMPLOYEE BENEFIT PLANS

Emera maintains a number of contributory defined-benefit (“DB”) and defined-contribution (“DC”) pension

plans, which cover substantially all of its employees. In addition, the Company provides non-pension

benefits for its retirees. These plans cover employees in Nova Scotia, New Brunswick, Newfoundland and

Labrador, Florida, New Mexico, Barbados, and Grand Bahama Island.

Exhibit 99.3

53

Emera’s net periodic benefit cost included the following:

Benefit Obligation and Plan Assets:

The changes in benefit obligation and plan assets, and the funded status for all plans were as follows:

For the 

Year ended December 31

millions of dollars

2023

2022

Change in Projected Benefit Obligation

("PBO") and Accumulated Post-

retirement Benefit Obligation ("APBO")

Defined benefit

pension plans

Non-pension

benefit plans

Defined benefit

pension plans

Non-pension

benefit plans

Balance, January 1

$

2,158

$

243

$

2,624

$

318

Service cost

30

3

41

4

Plan participant contributions

6

6

6

6

Interest cost

111

13

80

9

Plan amendments

-

(14)

-

-

Benefits paid 

(147)

(29)

(174)

(31)

Actuarial losses (gains)

146

10

(480)

(79)

Settlements and curtailments

(8)

-

(6)

-

FX translation adjustment

(23)

(5)

67

16

Balance, December 31

$

2,273

$

227

$

2,158

$

243

Change in plan assets

Balance, January 1

$

2,163

$

46

$

2,702

$

51

Employer contributions

42

23

45

24

Plan participant contributions 

6

6

6

6

Benefits paid

(147)

(29)

(174)

(31)

Actual return on assets, net of expenses

262

3

(489)

(7)

Settlements and curtailments

(8)

-

(6)

-

FX translation adjustment

(20)

(1)

79

3

Balance, December 31

$

2,298

$

48

$

2,163

$

46

Funded status, end of year 

$

25

$

(179)

$

5

$

(197)

The actuarial losses recognized in the period are primarily due to changes in the discount rate, higher

than expected indexation, and compensation-related assumption changes.

Plans with PBO/APBO

in Excess of Plan Assets:

The aggregate financial position for all pension plans where the PBO or APBO (for post-retirement benefit

plans) exceeded the plan assets for the years ended December 31 was as follows:

millions of dollars

2023

2022

Defined benefit

pension plans

Non-pension

benefit plans

Defined benefit

pension plans

Non-pension

benefit plans

PBO/APBO

$

120

$

205

$

1,006

$

221

FV of plan assets

37

-

914

-

Funded status

$

(83)

$

(205)

$

(92)

$

(221)

Plans with Accumulated Benefit Obligation (“ABO”)

in Excess of Plan Assets:

The ABO for the DB pension plans was $

2,172

 million as at December 31, 2023 (2022 – $

2,080

 million).

The aggregate financial position for those plans with an ABO in excess of the plan assets for the years

ended December 31 was as follows:

millions of dollars

2023

2022

Defined benefit

pension plans

Defined benefit

pension plans

ABO

$

114

$

111

FV of plan assets

37

33

Funded status

$

(77)

$

(78)

Exhibit 99.3

54

Balance Sheet:

The amounts recognized in the Consolidated Balance Sheets consisted of the following:

As at

December 31

December 31

millions of dollars

2023

2022

Defined benefit

pension plans

Non-pension

benefit plans

Defined benefit

pension plans

Non-pension

benefit plans

Other current liabilities

$

(5)

$

(18)

$

(13)

$

(20)

Long-term liabilities

(78)

(187)

(80)

(201)

Other long-term assets

108

26

98

24

AOCI, net of tax and regulatory assets

385

20

358

22

Less: Deferred income tax (expense)

recovery in AOCI

(8)

(1)

(7)

(1)

Net amount recognized

$

402

$

(160)

$

356

$

(176)

Amounts Recognized in AOCI and Regulatory Assets:

Unamortized gains and losses and past service costs arising on post-retirement benefits are recorded in

AOCI or regulatory assets. The following table summarizes the change in AOCI and regulatory assets:

Regulatory assets

Actuarial 

(gains) losses

Past service

(gains) costs

millions of dollars

Defined Benefit Pension Plans

Balance, January 1, 2023

$

336

$

15

$

-

Amortized in current period

(6)

(3)

-

Current year additions

1

41

-

Change in FX rate

(7)

-

-

Balance, December 31, 2023

$

324

$

53

$

-

Non-pension benefits plans

Balance, January 1, 2023

$

31

$

(10)

$

-

Amortized in current period

2

3

-

Current year reductions

(3)

(1)

(3)

Change in FX rate

(1)

-

1

Balance, December 31, 2023

$

29

$

(8)

$

(2)

As at

December

31

December

31

millions of dollars

2023

2022

Defined benefit

pension plans

Non-pension

benefit plans

Defined benefit

pension plans

Non-pension

benefit plans

Actuarial losses (gains)

$

53

(8)

$

15

$

(10)

Past service gains

-

(2)

-

-

Deferred income tax expense

8

1

7

1

AOCI, net of tax

61

(9)

22

(9)

Regulatory assets

324

29

336

31

AOCI, net of tax and regulatory assets

$

385

$

20

$

358

$

22

Exhibit 99.3

55

Benefit Cost Components:

Emera's net periodic benefit cost included the following:

As at

Year ended December 31

millions of dollars

2023

2022

Defined benefit

pension plans

Non-pension

benefit plans

Defined benefit

pension plans

Non-pension

benefit plans

Service cost

$

30

$

3

$

41

$

4

Interest cost

111

13

80

9

Expected return on plan assets

(161)

(2)

(144)

-

Current year amortization of:

 Actuarial losses (gains)

1

(3)

8

-

 Regulatory assets (liability)

6

(2)

21

2

Settlement, curtailments

2

-

2

-

Total

$

(11)

$

9

$

8

$

15

The expected return on plan assets is determined based on the market-related value of plan assets of

$

2,577

 million as at January 1, 2023 (2022 – $

2,482

 million), adjusted for interest on certain cash flows

during the year.

The market-related value of assets is based on a five-year smoothed asset value. Any

investment gains (or losses) in excess of (or less than) the expected return on plan assets are recognized

on a straight-line basis into the market-related value of assets over a five-year period.

Pension Plan Asset Allocations:

Emera’s investment policy includes discussion regarding the investment philosophy, the level of risk

which the Company is prepared to accept with respect to the investment of the Pension Funds, and the

basis for measuring the performance of the assets. Central to the policy is the target asset allocation by

major asset categories. The objective of the target asset allocation is to diversify risk and to achieve asset

returns that meet or exceed the plan’s actuarial assumptions. The diversification of assets reduces the

inherent risk in financial markets by requiring that assets be spread out amongst various asset classes.

Within each asset class, a further diversification is undertaken through the investment in a broad range of

investment and non-investment grade securities. Emera’s target asset allocation is as follows:

Canadian Pension Plans

Asset Class

Target Range at Market

Short-term securities

0%

to

10%

Fixed income

34%

to

49%

Equities:

 Canadian

7%

to

17%

 Non-Canadian

35%

to

59%

Non-Canadian Pension Plans

Asset Class

Target Range at Market

Weighted average

Cash and cash equivalents

0%

to

10%

Fixed income

29%

to

49%

Equities

48%

to

68%

Pension Plan assets are overseen by the respective Management Pension Committees in the sponsoring

companies. All pension investments are in accordance with policies approved by the respective Board of

Directors of each sponsoring company.

Exhibit 99.3

56

The following tables set out the classification of the methodology used by the Company to FV its

investments:

millions of dollars

NAV

Level 1

Level 2

Total

Percentage

As at

December 31, 2023

Cash and cash equivalents

$

-

$

40

$

-

$

40

2

%

Net in-transits

-

(9)

-

(9)

-

%

Equity securities:

 Canadian equity

-

96

-

96

4

%

 United States equity 

-

141

-

141

6

%

 Other equity

-

112

-

112

5

%

Fixed income securities:

 Government

-

-

172

172

8

%

 Corporate

-

-

90

90

4

%

 Other

-

4

5

9

-

%

Mutual funds

-

50

-

50

2

%

Other

-

6

(1)

5

-

%

Open-ended investments

measured at NAV

 (1)

1,006

-

-

1,006

44

%

Common collective trusts

measured at NAV

(2)

586

-

-

586

25

%

Total 

$

1,592

$

440

$

266

$

2,298

100

%

As at

December 31, 2022

Cash and cash equivalents

$

-

$

70

$

-

$

70

3

%

Net in-transits

-

(70)

-

(70)

(3)

%

Equity securities:

 Canadian equity

-

87

-

87

4

%

 United States equity 

-

233

-

233

11

%

 Other equity

-

186

-

186

8

%

Fixed income securities:

 Government

-

-

104

104

5

%

 Corporate

-

-

83

83

4

%

 Other

-

3

11

14

1

%

Mutual funds

-

68

-

68

3

%

Other

-

-

(3)

(3)

-

%

Open-ended investments

measured at NAV

 (1)

790

-

-

790

36

%

Common collective trusts

measured at NAV

(2)

601

-

-

601

28

%

Total 

$

1,391

$

577

$

195

$

2,163

100

%

(1) Net asset value ("NAV") investments are open-ended registered and non-registered mutual funds, collective investment trusts,

or pooled funds. NAV’s are calculated at least monthly and the funds honour subscription and redemption activity regularly.

(2) The common collective trusts are private funds valued at NAV. The NAVs are calculated based on bid prices of the underlying

securities. Since the prices are not published to external sources, NAV is used as a practical expedient. Certain funds invest

primarily in equity securities of domestic and foreign issuers while others invest in long duration U.S. investment grade fixed

income assets and seeks to increase return through active management of interest rate and credit risks. The funds honour

subscription and redemption activity regularly.

Refer to note 16 for more information on the FV hierarchy and inputs used to measure FV.

Post-Retirement Benefit Plans:

There are no assets set aside to pay for most of the Company’s post-retirement benefit plans. As is

common practice, post-retirement health benefits are paid from general accounts as required. The

primary exception to this is the NMGC Retiree Medical Plan, which is fully funded.

Exhibit 99.3

57

Investments in Emera:

As at December 31, 2023 and 2022, assets related to the pension funds and post-retirement benefit plans

did not hold any material investments in Emera or its subsidiaries securities. However, as a significant

portion of assets for the benefit plan are held in pooled assets, there may be indirect investments in these

securities.

Cash Flows:

The following table shows expected cash flows for DB pension and other post-retirement benefit plans:

millions of dollars

Defined benefit

pension plans

Non-pension

benefit plans

Expected employer contributions

2024

$

34

$

19

Expected benefit payments

2024

172

21

2025

163

21

2026

166

21

2027

171

21

2028

173

20

2029 – 2033

890

95

Assumptions:

The following table shows the assumptions that have been used in accounting for DB pension and other

post-retirement benefit plans:

2023

2022

(weighted average assumptions)

Defined benefit

pension plans

Non-pension

benefit plans

Defined benefit

pension plans

Non-pension

benefit plans

Benefit obligation – December 31:

Discount rate - past service

4.89

%

4.89

%

5.33

%

5.31

%

Discount rate - future service

4.88

%

4.89

%

5.34

%

5.32

%

Rate of compensation increase

3.87

%

3.85

%

3.62

%

3.61

%

Health care trend - initial (next year)

-

6.04

%

-

5.40

%

 - ultimate 

-

3.76

%

-

3.77

%

 - year ultimate reached

2043

2043

Benefit cost for year ended December 31:

Discount rate - past service

5.33

%

5.31

%

3.05

%

2.81

%

Discount rate - future service

5.34

%

5.32

%

3.18

%

2.92

%

Expected long-term return on plan assets

6.56

%

2.16

%

6.07

%

1.32

%

Rate of compensation increase

3.62

%

3.61

%

3.31

%

3.29

%

Health care trend - initial (current year)

-

5.40

%

-

5.09

%

 - ultimate 

-

3.77

%

-

3.77

%

 - year ultimate reached

2043

2042

Actual assumptions used differ by plan.

The expected long-term rate of return on plan assets is based on historical and projected real rates of

return for the plan’s current asset allocation, and assumed inflation. A real rate of return is determined for

each asset class. Based on the asset allocation, an overall expected real rate of return for all assets is

determined. The asset return assumption is equal to the overall real rate of return assumption added to

the inflation assumption, adjusted for assumed expenses to be paid from the plan.

The discount rate is based on high-quality long-term corporate bonds, with maturities matching the

estimated cash flows from the pension plan.

Defined Contribution Plan:

Emera also provides a DC pension plan for certain employees. The Company’s contribution for the year

ended December 31, 2023 was $

45

 million (2022 – $

41

 million).

Exhibit 99.3

58

22. GOODWILL

The change in goodwill for the year ended December 31 was due to the following:

millions of dollars 

2023

2022

Balance, January 1

$

6,012

$

5,696

Change in FX rate

(141)

389

GBPC impairment charge

-

(73)

Balance, December 31

$

5,871

$

6,012

Goodwill is subject to an annual assessment for impairment at the reporting unit level. The goodwill on

Emera’s Consolidated Balance Sheets at December 31, 2023, primarily related to TECO Energy

(reporting units with goodwill are TEC, PGS, and NMGC). 

In 2023, Emera performed qualitative impairment assessments for NMGC and PGS, concluding that the

FV of the reporting units exceeded their respective carrying amounts, and as such, no quantitative

assessments were performed and

no

 impairment charges were recognized. Given the length of time

passed since the last quantitative impairment test for the TEC reporting unit, Emera elected to bypass a

qualitative assessment and performed a quantitative impairment assessment in Q4 2023 using a

combination of the income approach and market approach. This assessment estimated that the FV of the

TEC reporting unit exceeded its carrying amount, including goodwill, and as a result

no

 impairment

charges were recognized.

In 2022, the Company elected to bypass a qualitative assessment and performed a quantitative

impairment assessment for GBPC, using the income approach. It was determined that the FV did not

exceed its carrying amount, including goodwill. As a result of this assessment, a goodwill impairment

charge of $

73

 million was recorded in 2022, reducing the GBPC goodwill balance to nil as at December

31, 2022. This non-cash charge is included in “GBPC impairment charge” on the Consolidated

Statements of Income.

23. SHORT-TERM DEBT

Emera’s short-term borrowings consist of commercial paper issuances, advances on revolving and non-

revolving credit facilities and short-term notes. Short-term debt and the related weighted-average interest

rates as at December 31 consisted of the following:

millions of dollars 

2023

Weighted

average 

interest rate

2022

Weighted

average 

interest rate

TEC

Advances on revolving credit facilities

$

277

5.68

%

$

1,380

5.00

%

Emera

Non-revolving term facilities

796

6.07

%

796

5.19

%

Bank indebtedness 

9

-

%

-

-

%

TECO Finance 

Advances on revolving credit and term facilities

245

6.54

%

481

5.47

%

PGS

Advances on revolving credit facilities

73

6.36

%

-

-

%

NMGC

Advances on revolving credit facilities

25

6.46

%

59

5.15

%

GBPC

Advances on revolving credit facilities

8

5.54

%

10

5.25

%

Short-term debt

$

1,433

$

2,726

Exhibit 99.3

59

The Company’s total short-term revolving and non-revolving credit facilities, outstanding borrowings and

available capacity as at December 31 were as follows: 

millions of dollars

Maturity

2023

2022

TEC - Unsecured committed revolving credit facility

2026

$

401

$

1,084

TECO Energy/TECO Finance - revolving credit facility

2026

-

542

TECO Finance - Unsecured committed revolving credit facility

2026

529

-

Emera - Unsecured non-revolving term facility

2024

400

400

Emera - Unsecured non-revolving term facility

2024

400

400

PGS - Unsecured revolving credit facility

2028

331

-

TEC - Unsecured revolving facility

2024

265

542

TEC - Unsecured revolving facility

2024

265

-

NMGC - Unsecured revolving credit facility

2026

165

169

Other - Unsecured committed revolving credit facilities

Various

17

18

Total

$

2,773

$

3,155

Less:

Advances under revolving credit and term facilities

1,433

2,731

Letters of credit issued within the credit facilities

3

4

Total advances under available facilities

1,436

2,735

Available capacity under existing agreements

$

1,337

$

420

The weighted average interest rate on outstanding short-term debt at December 31, 2023 was

5.95

 per

cent (2022 –

5.01

 per cent).

Recent Significant Financing Activity by Segment

Florida Electric Utilities 

On November 24, 2023, TEC repaid its $

400

 million USD unsecured non-revolving facility, which expired

on

December 13, 2023

. 

On April 3, 2023, TEC entered into a

364

-day, $

200

 million USD senior unsecured revolving credit facility

which matures on

April 1, 2024

. The credit agreement contains customary representations and

warranties, events of default and financial and other covenants, and bears interest at a variable interest

rate, based on either the term secured overnight financing rate (“SOFR”), Wells Fargo’s prime rate, the

federal funds rate or the one-month SOFR, plus a margin.

On March 1, 2023, TEC entered into a

364

-day, $

200

 million USD senior unsecured revolving credit

facility which matures on

February 28, 2024

. The credit facility contains customary representations and

warranties, events of default and financial and other covenants, and bears interest at a variable interest

rate, based on either the term SOFR, the Bank of Nova Scotia’s prime rate, the federal funds rate or the

one-month SOFR, plus a margin.

Gas Utilities and Infrastructure

On December 1, 2023, PGS entered into a $

250

 million USD senior unsecured revolving credit facility

with a group of banks, maturing on

December 1, 2028

. PGS has the ability to request the lenders to

increase their commitments under the credit facility by up to $

100

 million USD in the aggregate subject to

agreement from participating lenders. The credit agreement contains customary representations and

warranties, events of default and financial and other covenants, and bears interest at Bankers’

Acceptances or prime rate advances, plus a margin.

Exhibit 99.3

60

Other

On December 16, 2023, Emera amended its $

400

 million unsecured non-revolving facility to extend the

maturity date from

December 16, 2023

 to

December 16, 2024

. There were no other changes in

commercial terms from the prior agreement.

On June 30, 2023, Emera amended its $

400

 million unsecured non-revolving facility to extend the

maturity date from

August 2, 2023

 to

August 2, 2024

. There were no other changes in commercial terms

from the prior agreement.

24. OTHER CURRENT LIABILITIES

As at

December 31

December 31

millions of dollars 

2023

2022

Accrued charges

$

172

$

174

Nova Scotia Cap-and-Trade Program provision (note 6)

-

172

Accrued interest on long-term debt

107

97

Pension and post-retirement liabilities (note 21)

23

33

Sales and other taxes payable

11

14

Income tax payable

2

9

Other

112

80

$

427

$

579

Exhibit 99.3

61

25. LONG-TERM DEBT

Bonds, notes and debentures are at fixed interest rates and are unsecured unless noted below. Included

are certain bankers’ acceptances and commercial paper where the Company has the intention and the

unencumbered ability to refinance the obligations for a period greater than one year.

Long-term debt as at December 31 consisted of the following:

Weighted average interest

rate

(1)

millions of dollars

2023

2022

Maturity

2023

2022

Emera 

Bankers acceptances, SOFR loans 

Variable

Variable

2027

$

465

$

403

Unsecured fixed rate notes

4.84%

2.90%

2030

500

500

Fixed to floating subordinated notes

(2)

6.75%

6.75%

2076

1,587

1,625

$

2,552

$

2,528

Emera Finance 

Unsecured senior notes

3.65%

3.65%

2024 - 2046

$

3,637

$

3,725

TEC

(3)

Fixed rate notes and bonds

4.61%

4.15%

2024 - 2051

$

5,654

$

4,341

PGS

Fixed rate notes and bonds

5.63%

3.78%

2028 - 2053

$

1,223

$

772

NMGC

Fixed rate notes and bonds

3.78%

3.11%

2026 - 2051

$

642

$

521

Non-revolving term facility, floating rate

Variable

Variable

2024

30

108

$

672

$

629

NMGI

Fixed rate notes and bonds

3.64%

3.64%

2024

$

198

$

203

NSPI

Discount Notes

(4)

Variable

Variable

2024 - 2027

$

721

$

881

Medium term fixed rate notes

5.13%

5.14%

2025 - 2097

3,165

2,665

$

3,886

$

3,546

EBP

Senior secured credit facility

Variable

Variable

2026

$

246

$

249

ECI

Secured senior notes

Variable

Variable

2027

$

75

$

86

Amortizing fixed rate notes

4.00%

3.97%

2026

79

100

Non-revolving term facility, floating rate

Variable

Variable

2025

29

30

Non-revolving term facility, fixed rate

2.15%

2.05%

2025 - 2027

155

91

Secured fixed rate senior notes

(5)

3.09%

3.06%

2024 - 2029

84

142

$

422

$

449

Adjustments

Fair market value adjustment - TECO Energy acquisition

$

-

$

2

Debt issuance costs

(125)

(126)

Amount due within one year

(676)

(574)

$

(801)

$

(698)

Long-Term Debt

$

17,689

$

15,744

(1) Weighted average interest rate of fixed rate long-term debt.

(2) In 2023, the Company recognized $

109

 million in interest expense (2022 – $

110

 million) related to its fixed to floating

subordinated notes.

(3) A substantial part of TEC’s tangible assets are pledged as collateral to secure its first mortgage bonds. There are currently no

bonds outstanding under TEC’s first mortgage bond indenture.

(4) Discount notes are backed by a revolving credit facility which matures in 2027. Banker’s acceptances are issued under NSPI’s

non-revolving term facility which matures in 2024. NSPI has the intention and unencumbered ability to refinance bankers’

acceptances for a period of greater than one year.

(5) Notes are issued and payable in either USD or BBD.

Exhibit 99.3

62

The Company’s total long-term revolving credit facilities, outstanding borrowings and available capacity as

at December 31 were as follows:

millions of dollars

Maturity

2023

2022

Emera – revolving credit facility

(1)

June 2027

$

900

$

900

TEC - Unsecured committed revolving credit facility

December 2026

657

-

NSPI - revolving credit facility

(1)

December 2027

800

800

NSPI - non-revolving credit facility

July 2024

400

400

Emera - Unsecured non-revolving credit facility

February 2024

400

-

NMGC - Unsecured non-revolving credit facility

March 2024

30

108

ECI – revolving credit facilities

October 2024

10

11

Total

$

3,197

$

2,219

Less:

Borrowings under credit facilities

1,884

1,396

Letters of credit issued inside credit facilities

6

12

Use of available facilities

$

1,890

$

1,408

Available capacity under existing agreements

$

1,307

$

811

(1) Advances on the revolving credit facility can be made by way of overdraft on accounts up to $

50

 million.

Debt Covenants

Emera and its subsidiaries have debt covenants associated with their credit facilities. Covenants are

tested regularly and the Company is in compliance with covenant requirements. Emera’s significant

covenants are listed below:

As at

Financial Covenant

Requirement

December 31, 2023

Emera

Syndicated credit facilities

Debt to capital ratio

Less than or equal to

0.70

 to 1

0.57

 : 1

Recent Significant Financing Activity by Segment

Florida Electric Utility

On January 30, 2024, TEC issued $

500

 million USD of senior unsecured bonds that bear interest at

4.90

per cent with a maturity date of

March 1, 2029

. Proceeds from the issuance were primarily used for

repayment of short-term borrowings outstanding under the

5

-year credit facility. Therefore, $

497

 million

USD of short-term borrowings that were repaid was classified as long-term debt at December 31, 2023.

Canadian Electric Utilities

On March 24, 2023, NSPI issued $

500

 million in unsecured notes. The issuance included $

300

 million

unsecured notes that bear interest at

4.95

 per cent with a maturity date of

November 15, 2032

, and $

200

million unsecured notes that bear interest at

5.36

 per cent with a maturity date of

March 24, 2053

. 

Gas Utilities and Infrastructure

On December 19, 2023, PGS completed an issuance of $

925

 million USD in senior notes. The issuance

included $

350

 million USD senior notes that bear interest at

5.42

 per cent with a maturity date of

December 19, 2028

, $

350

 million USD senior notes that bear interest at

5.63

 per cent with a maturity date

of

December 19, 2033

 and $

225

 million USD senior notes that bear interest at

5.94

 per cent with a

maturity date of

December 19, 2053

.

On October 19, 2023, NMGC issued $

100

 million USD in senior unsecured notes that bear interest at

6.36

 per cent with a maturity date of

October 19, 2033

.

Exhibit 99.3

63

Other Electric Utilities 

On May 24, 2023, GBPC issued a $

28

 million USD non-revolving term loan that bears interest at

4.00

 per

cent with a maturity date of

May 24, 2028

. 

Other 

On August 18, 2023, Emera entered into a $

400

 million non-revolving term facility with a maturity date of

February 19, 2024

. The credit agreement contains customary representations and warranties, events of

default and financial and other covenants, and bears interest at Bankers’ Acceptances or prime rate

advances, plus a margin. On February 16, 2024, Emera extended the term of this agreement to a

maturity date of

February 19, 2025

.

On May 2, 2023, Emera issued $

500

 million in senior unsecured notes that bear interest at

4.84

 per cent

with a maturity date of

May 2, 2030

.

Long-Term Debt Maturities

As at December 31, long-term debt maturities, including capital lease obligations, for each of the next five

years and in aggregate thereafter are as follows:

millions of dollars

2024

2025

2026

2027

2028

Thereafter

Total

Emera

$

199

$

-

$

1,587

$

266

$

-

$

500

$

2,552

Emera US Finance LP

397

-

992

-

-

2,248

3,637

TEC

397

-

-

-

-

5,257

5,654

PGS

-

-

-

-

463

760

1,223

NMGC

30

-

93

-

-

549

672

NMGI

198

-

-

-

-

-

198

NSPI

398

125

40

323

-

3,000

3,886

EBP

-

-

246

-

-

-

246

ECI

51

139

89

77

62

4

422

Total

$

1,670

$

264

$

3,047

$

666

$

525

$

12,318

$

18,490

26. ASSET RETIREMENT OBLIGATIONS

AROs mostly relate to reclamation of land at the thermal, hydro and combustion turbine sites; and the

disposal of polychlorinated biphenyls in transmission and distribution equipment and a pipeline site.

Certain hydro, transmission and distribution assets may have additional AROs that cannot be measured

as these assets are expected to be used for an indefinite period and, as a result, a reasonable estimate of

the FV of any related ARO cannot be made.

The change in ARO for the years ended December 31 is as follows:

millions of dollars

2023

2022

Balance, January 1

$

174

$

174

Accretion included in depreciation expense

9

9

Change in FX rate

(1)

3

Additions

-

1

Accretion deferred to regulatory asset (included in PP&E)

18

1

Liabilities settled

(8)

(1)

Revisions in estimated cash flows

-

(13)

Balance, December 31

$

192

$

174

Exhibit 99.3

64

27. COMMITMENTS AND CONTINGENCIES

A.

Commitments

As at December 31, 2023, contractual commitments (excluding pensions and other post-retirement

obligations, long-term debt and asset retirement obligations) for each of the next five years and in

aggregate thereafter consisted of the following:

millions of dollars

2024

2025

2026

2027

2028

Thereafter

Total

Transportation

(1)

$

696

$

495

$

405

$

388

$

338

$

2,597

$

4,919

Purchased power

(2)

274

249

263

312

312

3,435

4,845

Fuel, gas supply and storage

556

215

62

-

5

-

838

Capital projects

778

111

70

1

-

-

960

Equity investment commitments

(3)

240

-

-

-

-

-

240

Other

154

147

56

46

35

221

659

$

2,698

$

1,217

$

856

$

747

$

690

$

6,253

$

12,461

(1) Purchasing commitments for transportation of fuel and transportation capacity on various pipelines. Includes a commitment of

$

134

 million related to a gas transportation contract between PGS and SeaCoast through 2040.

(2) Annual requirement to purchase electricity production from IPPs or other utilities over varying contract lengths.

(3) Emera has a commitment to make equity contributions to the LIL related to an investment true up in 2024 and sustaining capital

contributions over the life of the partnership. The commercial agreements between Emera and Nalcor require true ups to finalize the

respective investment obligations of the parties in relation the Maritime Link and LIL which is expected to be approximately $

240

million in 2024. In addition, Emera has future commitments to provide sustaining capital to the LIL for routine capital and major

maintenance.

NSPI has a contractual obligation to pay NSPML for use of the Maritime Link over approximately

38 years

from its January 15, 2018 in-service date. In February 2022, the UARB issued its decision and Board

Order approving NSPML’s requested rate base of approximately $

1.8

 billion. In December 2023, the

UARB approved the collection of up to $

164

 million from NSPI for the recovery of Maritime Link costs in

2024. The timing and amounts payable to NSPML for the remainder of the

38

-year commitment period

are subject to UARB approval.

Construction of the LIL is complete, and the Newfoundland Electrical System Operator confirmed the

asset to be operating suitably to support reliable system operation and full functionality at

700

MW, which

was validated by the Government of Canada’s Independent Engineer issuing its Commissioning

Certificate on April 13, 2023.

Emera has committed to obtain certain transmission rights for Nalcor, if requested, to enable it to transmit

energy which is not otherwise used in Newfoundland and Labrador or Nova Scotia. Nalcor has the right to

transmit this energy from Nova Scotia to New England energy markets effective August 15, 2021 and

continuing for

50 years

. As transmission rights are contracted, the obligations are included within “Other”

in the above table.

B.

Legal Proceedings

Superfund and Former Manufactured Gas Plant Sites

Previously, TEC had been a potentially responsible party (“PRP”) for certain superfund sites through its

Tampa Electric and former PGS divisions, as well as for certain former manufactured gas plant sites

through its PGS division. As a result of the separation of the PGS division into a separate legal entity,

Peoples Gas System, Inc. is also now a PRP for those sites (in addition to third party PRPs for certain

sites). While the aggregate joint and several liability associated with these sites has not changed as a

result of the PGS legal separation, the sites continue to present the potential for significant response

costs. As at December 31, 2023, the aggregate financial liability of the Florida utilities is estimated to be

$

15

 million ($

11

 million USD), primarily at PGS. This estimate assumes that other involved PRPs are

credit-worthy entities. This amount has been accrued and is primarily reflected in the long-term liability

section under “Other long-term liabilities” on the Consolidated Balance Sheets. The environmental

remediation costs associated with these sites are expected to be paid over many years. 

Exhibit 99.3

65

The estimated amounts represent only the portion of the cleanup costs attributable to the Florida utilities.

The estimates to perform the work are based on the Florida utilities’ experience with similar work,

adjusted for site-specific conditions and agreements with the respective governmental agencies. The

estimates are made in current dollars, are not discounted and do not assume any insurance recoveries.

In instances where other PRPs are involved, most of those PRPs are believed to be currently credit-

worthy and are likely to continue to be credit-worthy for the duration of the remediation work. However, in

those instances that they are not, the Florida utilities could be liable for more than their actual percentage

of the remediation costs. Other factors that could impact these estimates include additional testing and

investigation which could expand the scope of the cleanup activities, additional liability that might arise

from the cleanup activities themselves or changes in laws or regulations that could require additional

remediation. Under current regulations, these costs are recoverable through customer rates established

in base rate proceedings.

Other Legal Proceedings

Emera and its subsidiaries may, from time to time, be involved in other legal proceedings, claims and

litigation that arise in the ordinary course of business which the Company believes would not reasonably

be expected to have a material adverse effect on the financial condition of the Company.

C.

Principal Financial Risks and Uncertainties

Emera believes the following principal financial risks could materially affect the Company in the normal

course of business. Risks associated with derivative instruments and FV measurements are discussed in

note 15 and note 16. 

Sound risk management is an essential discipline for running the business efficiently and pursuing the

Company’s strategy successfully. Emera has an enterprise-wide risk management process, overseen by

its Enterprise Risk Management Committee (“ERMC”) and monitored by the Board of Directors, to ensure

an effective, consistent and coherent approach to risk management. The Board of Directors has a Risk

and Sustainability Committee (‘RSC”) with a mandate that includes oversight of the Company’s Enterprise

Risk Management framework, including the identification, assessment, monitoring and management of

enterprise risks. It also includes oversight of the Company’s approach to sustainability and its

performance relative to its sustainability objectives.

Regulatory and Political Risk

The Company’s rate-regulated subsidiaries and certain investments subject to significant influence are

subject to risk of the recovery of costs and investments. Regulatory and political risk can include changes

in regulatory frameworks, shifts in government policy, legislative changes, and regulatory decisions.

As cost-of-service utilities with an obligation to serve customers, Emera’s utilities operate under formal

regulatory frameworks, and must obtain regulatory approval to change or add rates and/or riders. Emera

also holds investments in entities in which it has significant influence, and which are subject to regulatory

and political risk including NSPML, LIL, and M&NP. As a regulated Group II pipeline, the tolls of

Brunswick Pipeline are regulated by the CER on a complaint basis, as opposed to the regulatory approval

process described above. In the absence of a complaint, the CER does not normally undertake a detailed

examination of Brunswick Pipeline’s tolls, which are subject to a firm service agreement, expiring in 2034,

with Repsol Energy North America Canada Partnership. 

Exhibit 99.3

66

Regulators administer the regulatory frameworks covering material aspects of the utilities’ businesses,

including applying market-based tests to determine the appropriate customer rates and/or riders, the

underlying allowed ROEs, deemed capital structures, capital investment, the terms and conditions for the

provision of service, performance standards, and affiliate transactions. Regulators also review the

prudency of costs and other decisions that impact customer rates and reliability of service and work to

ensure the financial health of the utility for the benefit of customers. Costs and investments can be

recovered upon approval by the respective regulator as an adjustment to rates and/or riders, which

normally require a public hearing process or may be mandated by other governmental bodies. During

public hearing processes, consultants and customer representatives scrutinize the costs, actions and

plans of these rate-regulated companies, and their respective regulators determine whether to allow

recovery and to adjust rates based upon the evidence and any contrary evidence from other parties. In

some circumstances, other government bodies may influence the setting of rates. Regulatory decisions,

legislative changes, and prolonged delays in the recovery of costs or regulatory assets could result in

decreased rate affordability for customers and could materially affect Emera and its utilities. 

Emera’s utilities generally manage this risk through transparent regulatory disclosure, ongoing

stakeholder and government consultation and multi-party engagement on aspects such as utility

operations, regulatory audits, rate filings and capital plans. The subsidiaries work to establish

collaborative relationships with regulatory stakeholders, including customer representatives, both through

its approach to filings and additional efforts with technical conferences and, where appropriate, negotiated

settlements. 

Changes in government and shifts in government policy and legislation can impact the commercial and

regulatory frameworks under which Emera and its subsidiaries operate. This includes initiatives regarding

deregulation or restructuring of the energy industry. Deregulation or restructuring of the energy industry

may result in increased competition and unrecovered costs that could adversely affect the Company’s

operations, net income and cash flows. State and local policies in some United States jurisdictions have

sought to prevent or limit the ability of utilities to provide customers the choice to use natural gas while in

other jurisdictions policies have been adopted to prevent limitations on the use of natural gas. Changes in

applicable state or local laws and regulations, including electrification legislation, could adversely impact

PGS and NMGC.

Emera cannot predict future legislative, policy, or regulatory changes, whether caused by economic,

political or other factors, or its ability to respond in an effective and timely manner or the resulting

compliance costs. Government interference in the regulatory process can undermine regulatory stability,

predictability, and independence, and could have a material adverse effect on the Company.

Foreign Exchange Risk 

The Company is exposed to foreign currency exchange rate changes. Emera operates internationally,

with an increasing amount of the Company’s net income earned outside of Canada. As such, Emera is

exposed to movements in exchange rates between the CAD and, particularly, the USD, which could

positively or adversely affect results. 

Consistent with the Company’s risk management policies, Emera manages currency risks through

matching United States denominated debt to finance its United States operations and may use foreign

currency derivative instruments to hedge specific transactions and earnings exposure. The Company may

enter FX forward and swap contracts to limit exposure on certain foreign currency transactions such as

fuel purchases, revenue streams and capital expenditures, and on net income earned outside of Canada.

The regulatory framework for the Company’s rate-regulated subsidiaries permits the recovery of prudently

incurred costs, including FX.

The Company does not utilize derivative financial instruments for foreign currency trading or speculative

purposes or to hedge the value of its investments in foreign subsidiaries. Exchange gains and losses on

net investments in foreign subsidiaries do not impact net income as they are reported in AOCI.

Exhibit 99.3

67

Liquidity and Capital Market Risk

Liquidity risk relates to Emera’s ability to ensure sufficient funds are available to meet its financial

obligations. Emera manages this risk by forecasting cash requirements on a continuous basis to

determine whether sufficient funds are available. Liquidity and capital needs could be financed through

internally generated cash flows, asset sales, short-term credit facilities, and ongoing access to capital

markets. 

Emera’s access to capital and cost of borrowing is subject to several risk factors, including financial

market conditions, market disruptions and ratings assigned by various market analysts, including credit

rating agencies. Disruptions in capital markets could prevent Emera from issuing new securities or cause

the Company to issue securities with less than preferred terms and conditions. Emera’s growth plan

requires significant capital investments in PP&E and the risk associated with changes in interest rates

could have an adverse effect on the cost of financing. The Company’s future access to capital and cost of

borrowing may be impacted by various market disruptions. The inability to access cost-effective capital

could have a material impact on Emera’s ability to fund its growth plan. 

Emera is subject to financial risk associated with changes in its credit ratings. There are a number of

factors that rating agencies evaluate to determine credit ratings, including the Company’s business, its

regulatory framework and legislative environment, political interference in the regulatory process, the

ability to recover costs and earn returns, diversification, leverage, liquidity and increased exposure to

climate change-related impacts, including increased frequency and severity of hurricanes and other

severe weather events. A decrease in a credit rating could result in higher interest rates in future

financings, increased borrowing costs under certain existing credit facilities, limit access to the

commercial paper market, or limit the availability of adequate credit support for subsidiary operations. For

more information on interest rate risk, refer to “General Economic Risk – Interest Rate Risk”. For certain

derivative instruments, if the credit ratings of the Company were reduced below investment grade, the full

value of the net liability of these positions could be required to be posted as collateral. Emera manages

these risks by actively monitoring and managing key financial metrics with the objective of sustaining

investment grade credit ratings.

The Company has exposure to its own common share price through the issuance of various forms of

stock-based compensation, which affect earnings through revaluation of the outstanding units every

period. The Company uses equity derivatives to reduce the earnings volatility derived from stock-based

compensation.

General Economic Risk

The Company has exposure to the macro-economic conditions in North America and in other geographic

regions in which Emera operates. Like most utilities, economic factors such as consumer income,

employment and housing affect demand for electricity and natural gas, and in turn the Company’s

financial results. Adverse changes in general economic conditions and inflation may impact the ability of

customers to afford rate increases arising from increases to fuel, operating, capital, environmental

compliance, and other costs, and therefore could materially affect Emera and its utilities. This may also

result in higher credit and counterparty risk, adverse shifts in government policy and legislation, and/or

increased risk to full and timely recovery of costs and regulatory assets.

Interest Rate Risk:

Emera utilizes a combination of fixed and floating rate debt financing for operations and capital

expenditures, resulting in an exposure to interest rate risk. Emera seeks to manage interest rate risk

through a portfolio approach that includes the use of fixed and floating rate debt with staggered

maturities. The Company will, from time to time, issue long-term debt or enter interest rate hedging

contracts to limit its exposure to fluctuations in floating interest rate debt.

Exhibit 99.3

68

For Emera’s regulated subsidiaries, the cost of debt is a component of rates and prudently incurred debt

costs are recovered from customers. Regulatory ROE will generally follow the direction of interest rates,

such that regulatory ROEs are likely to fall in times of reducing interest rates and rise in times of

increasing interest rates, albeit not directly and generally with a lag period reflecting the regulatory

process. Rising interest rates may also negatively affect the economic viability of project development

and acquisition initiatives.

Interest rates could also be impacted by changes in credit ratings. For more information, refer to “Liquidity

and Capital Market Risk”.

As with most other utilities and other similar yield-returning investments, Emera’s share price may be

affected by changes in interest rates and could underperform the market in an environment of rising

interest rates.

Inflation Risk: 

The Company may be exposed to changes in inflation that may result in increased operating and

maintenance costs, capital investment, and fuel costs compared to the revenues provided by customer

rates. Emera’s utilities have budgeting and forecasting processes to identify inflationary risk factors and

measure operating performance, as well as collective bargaining agreements that mitigate the short-term

impact of inflation on labour costs of unionized employees.

Commodity Price Risk

The Company’s utility fuel supply and purchase of other commodities is subject to commodity price risk.

In addition, Emera Energy is subject to commodity price risk through its portfolio of commodity contracts

and arrangements.

The Company manages this risk through established processes and practices to identify, monitor, report

and mitigate these risks. These include the Company’s commercial arrangements, such as the

combination of supply and purchase agreements, asset management agreements, pipeline transportation

agreements and financial hedging instruments. In addition, its credit policies, counterparty credit

assessments, market and credit position reporting, and other risk management and reporting practices,

are also used to manage and mitigate this risk.

Regulated Utilities:

The Company’s utility fuel supply is exposed to broader global conditions, which may include impacts on

delivery reliability and price, despite contracted terms. Supply and demand dynamics in fuel markets can

be affected by a wide range of factors which are difficult to predict and may change rapidly, including but

not limited to currency fluctuations, changes in global economic conditions, natural disasters,

transportation or production disruptions, and geo-political risks such as political instability, conflicts,

changes to international trade agreements, trade sanctions or embargos. The Company seeks to manage

this risk using financial hedging instruments and physical contracts and through contractual protection

with counterparties, where applicable. 

The majority of Emera’s regulated electric and gas utilities have adopted and implemented fuel

adjustment mechanisms and purchased gas adjustment mechanisms respectively, which further helps

manage commodity price risk, as the regulatory framework for the Company’s rate-regulated subsidiaries

permits the recovery of prudently incurred fuel and gas costs. There is no assurance that such

mechanisms and regulatory frameworks will continue to exist in the future. Prolonged and substantial

increases in fuel prices could result in decreased rate affordability, increased risk of recovery of costs or

regulatory assets, and/or negative impacts on customer consumption patterns and sales.

Exhibit 99.3

69

Emera Energy Marketing and Trading:

Emera Energy has employed further measures to manage commodity risk. The majority of Emera

Energy’s portfolio of electricity and gas marketing and trading contracts and, in particular, its natural gas

asset management arrangements, are contracted on a back-to-back basis, avoiding any material long or

short commodity positions. However, the portfolio is subject to commodity price risk, particularly with

respect to basis point differentials between relevant markets in the event of an operational issue or

counterparty default. Changes in commodity prices can also result in increased collateral requirements

associated with physical contracts and financial hedges, resulting in higher liquidity requirements and

increased costs to the business.

To measure commodity price risk exposure, Emera Energy employs a number of controls and processes,

including an estimated VaR analysis of its exposures. The VaR amount represents an estimate of the

potential change in FV that could occur from changes in Emera Energy’s portfolio or changes in market

factors within a given confidence level, if an instrument or portfolio is held for a specified time period. The

VaR calculation is used to quantify exposure to market risk associated with physical commodities,

primarily natural gas and power positions.

Income Tax Risk

The computation of the Company’s provision for income taxes is impacted by changes in tax legislation in

Canada, the United States and the Caribbean. Any such changes could affect the Company’s future

earnings, cash flows, and financial position. The value of Emera’s existing deferred income tax assets

and liabilities are determined by existing tax laws and could be negatively impacted by changes in laws.

Emera monitors the status of existing tax laws to ensure that changes impacting the Company are

appropriately reflected in the Company’s tax compliance filings and financial results.

D.

Guarantees and Letters of Credit

Emera has guarantees and letters of credit on behalf of third parties outstanding. The following significant

guarantees and letters of credit are not included within the Consolidated Balance Sheets as at December

31, 2023

:

TECO Energy has issued a guarantee in connection with SeaCoast’s performance of obligations under a

gas transportation precedent agreement. The guarantee is for a maximum potential amount of $

45

 million

USD if SeaCoast fails to pay or perform under the contract. The guarantee expires five years after the

gas transportation precedent agreement termination date, which was terminated on January 1, 2022. In

the event that TECO Energy’s and Emera’s long-term senior unsecured credit ratings are downgraded

below investment grade by Moody’s Investor Services (“Moody’s”) or S&P Global Ratings (“S&P”). TECO

Energy would be required to provide its counterparty a letter of credit or cash deposit of $

27

 million USD.

TECO Energy issued a guarantee in connection with SeaCoast’s performance obligations under a firm

service agreement, which expires on December 31, 2055, subject to two extension terms at the option of

the counterparty with a final expiration date of December 31, 2071. The guarantee is for a maximum

potential amount of $

13

 million USD if SeaCoast fails to pay or perform under the firm service agreement.

In the event that TECO Energy’s long-term senior unsecured credit ratings are downgraded below

investment grade by Moody’s or S&P, TECO Energy would need to provide either a substitute guarantee

from an affiliate with an investment grade credit rating or a letter of credit or cash deposit of $

13

 million

USD.

Emera Inc. has issued a guarantee of $

66

 million USD relating to outstanding notes of ECI. This

guarantee will automatically terminate on the date upon which the obligations have been repaid in full.

NSPI has issued guarantees on behalf of its subsidiary, NS Power Energy Marketing Incorporated, in the

amount of $

104

 million USD (2022 – $

119

 million USD) with terms of varying lengths.

Exhibit 99.3

70

The Company has standby letters of credit and surety bonds in the amount of $

103

 million USD

(December 31, 2022 – $

145

 million USD) to third parties that have extended credit to Emera and its

subsidiaries. These letters of credit and surety bonds typically have a one-year term and are renewed

annually as required.

Emera Inc., on behalf of NSPI, has a standby letter of credit to secure obligations under a supplementary

retirement plan. The expiry date of this letter of credit was extended to June 2024. The amount committed

as at December 31, 2023 was $

56

 million (December 31, 2022 – $

63

 million).

Collaborative Arrangements

For the years ended December 31, 2023 and 2022, the Company has identified the following material

collaborative arrangements:

Through NSPI, the Company is a participant in three wind energy projects in Nova Scotia. The

percentage ownership of the wind project assets is based on the relative value of each party’s project

assets by the total project assets. NSPI has power purchase arrangements to purchase the entire net

output of the projects and, therefore, NSPI’s portion of the revenues are recorded net within regulated fuel

for generation and purchased power. NSPI’s portion of operating expenses is recorded in “OM&G” on the

Consolidated Statements of Income. In 2023, NSPI recognized $

8

 million net expense (2022 – $

12

million) in “Regulated fuel for generation and purchased power” and $

3

 million (2022 – $

3

 million) in

“OM&G” on the Consolidated Statements of Income.

28. CUMULATIVE PREFERRED STOCK

Authorized:

Unlimited number of First Preferred shares, issuable in series.

Unlimited number of Second Preferred shares, issuable in series.

December 31, 2023

December 31, 2022

Annual Dividend

Redemption

Issued and

Net

Issued and

Net 

Per Share

Price per share

Outstanding

Proceeds

Outstanding

Proceeds

Series A

$

0.5456

$

25.00

4,866,814

$

119

4,866,814

$

119

Series B

Floating

$

25.00

1,133,186

$

28

1,133,186

$

28

Series C

$

1.6085

$

25.00

10,000,000

$

245

10,000,000

$

245

Series E

$

1.1250

$

25.00

5,000,000

$

122

5,000,000

$

122

Series F

$

1.0505

$

25.00

8,000,000

$

195

8,000,000

$

195

Series H

$

1.5810

$

25.00

12,000,000

$

295

12,000,000

$

295

Series J

$

1.0625

$

25.00

8,000,000

$

196

8,000,000

$

196

Series L

$

1.1500

$

26.00

9,000,000

$

222

9,000,000

$

222

Total

58,000,000

$

1,422

58,000,000

$

1,422

Exhibit 99.3

71

Characteristics of the First Preferred Shares:

First Preferred Shares

(1)(2)

Initial Yield 

(%)

Current

Annual

Dividend 

($)

Minimum 

Reset

Dividend

Yield (%)

Earliest Redemption

and/or Conversion

Option Date

Redemption

Value 

($)

Right to

Convert on

a one for

one basis

Fixed rate reset

(3)(4)

 Series A

4.400

0.5456

1.84

August 15, 2025

25.00

Series B

 Series C

 (5)(6)

4.100

1.6085

2.65

August 15, 2028

25.00

Series D

 Series F

4.202

1.0505

2.63

February 15, 2025

25.00

Series G

Minimum rate reset

(3)(4)

 Series B

2.393

Floating

1.84

August 15, 2025

25.00

Series A

 Series H

(5)(7)

4.900

1.5810

4.90

August 15, 2028

25.00

Series I

 Series J

4.250

1.0625

4.25

May 15, 2026

25.00

Series K

Perpetual fixed rate

 Series E

 (8)

4.500

1.1250

25.00

 Series L

(9)

4.600

1.1500

November 15, 2026

26.00

(1) Holders are entitled to receive fixed or floating cumulative cash dividends when declared by the Board of Directors of the

Corporation.

(2) On or after the specified redemption dates, the Corporation has the option to redeem for cash the outstanding First Preferred

Shares, in whole or in part, at the specified per share redemption value plus all accrued and unpaid dividends up to but excluding the

dates fixed for redemption.

(3) On the redemption and/or conversion option date the reset annual dividend per share will be determined by multiplying $

25.00

 per

share by the annual fixed or floating dividend rate, which for Series A, C, F and H is the sum of the five-year Government of Canada

Bond Yield on the applicable reset date, plus the applicable reset dividend yield (Series H annual reset rate must be a minimum of

4.90

 per cent) and for Series B equals the Government of Treasury Bill Rate on the applicable reset date, plus 1.84 per cent.

(4) On each conversion option date, the holders have the option, subject to certain conditions, to convert any or all of their Shares

into an equal number of Cumulative Redeemable First Preferred Shares of a specified series. The Company has the right to redeem 

the outstanding Preferred Shares, Series D, Series G and Series I shares without the consent of the holder every five years thereafter

for cash, in whole or in part at a price of $

25.00

 per share plus all accrued and unpaid dividends up to but excluding the date fixed for

redemption and $

25.50

 per share plus all accrued and unpaid dividends up to but excluding the date fixed for redemption in the case

of redemptions on any other date after August 15, 2028, February 15, 2025 and August 15, 2028, respectively. The reset dividend

yield for Series I equals the Government of Treasury Bill Rate on the applicable reset date, plus

2.54

 per cent.

(5) On July 6, 2023, Emera announced it would not redeem the outstanding Preferred Shares, Series C and Series H on August 15,

2023. On August 4, 2023, Emera announced after having taken into account all conversion notices received from holders, no Series

C Shares were converted into Series D Shares and no Series H Shares were converted into Series I shares. 

(6) The annual fixed dividend per share for Series C Shares was reset from $

1.1802

 to $

1.6085

 for the five-year period from and

including August 15, 2028.

(7) The annual fixed dividend per share for Series H Shares was reset from $

1.2250

 to $

1.5810

 for the five-year period from and

including August 15, 2028.

(8) First Preferred Shares, Series E are redeemable at $25.00 per share.

(9) First Preferred Shares, Series L are redeemable at $

26.00

 on or after November 15, 2026 to November 15, 2027, decreasing

$

0.25

 each year until November 15, 2030 and $

25.00

 per share thereafter.

First Preferred Shares are neither redeemable at the option of the shareholder nor have a mandatory

redemption date. They are classified as equity and the associated dividends are deducted on the

Consolidated Statements of Income before arriving at “Net income attributable to common shareholders”

and shown on the Consolidated Statement of Changes in Equity as a deduction from retained earnings.

The First Preferred Shares of each series rank on a parity with the First Preferred Shares of every other

series and are entitled to a preference over the Second Preferred Shares, the Common Shares, and any

other shares ranking junior to the First Preferred Shares with respect to the payment of dividends and the

distribution of the remaining property and assets or return of capital of the Company in the liquidation,

dissolution or wind-up, whether voluntary or involuntary.

In the event the Company fails to pay, in aggregate, eight quarterly dividends on any series of the First

Preferred Shares, the holders of the First Preferred Shares, for only so long as the dividends remain in

arrears, will be entitled to attend any meeting of shareholders of the Company at which directors are to be

elected and to vote for the election of two directors out of the total number of directors elected at any such

meeting.

Exhibit 99.3

72

29. NON-CONTROLLING INTEREST IN SUBSIDIARIES

As at

December 31

December 31

millions of dollars 

2023

2022

Preferred shares of GBPC 

$

14

$

14

$

14

$

14

Preferred shares of GBPC:

Authorized:

10,000

 non-voting cumulative redeemable variable perpetual preferred shares.

2023

2022

Issued and outstanding:

number of

shares

millions of

dollars

number of

shares

millions of

dollars

Outstanding as at December 31

10,000

$

14

10,000

$

14

GBPC Non–Voting Cumulative Variable Perpetual Preferred Stock:

The preferred shares are redeemable by GBPC after June 17, 2021

, at $

1,000

 Bahamian per share plus

accrued and unpaid dividends and are entitled to a

6.0 per cent per annum fixed cumulative preferential

dividend to be paid semi-annually

. 

The Preferred Shares rank behind GBPC’s current and future secured and unsecured debt and ahead of

all of GBPC’s current and future common stock.

30. SUPPLEMENTARY INFORMATION TO CONSOLIDATED STATEMENTS OF

CASH FLOWS

For the 

Year ended December 31

millions of dollars

2023

2022

Changes in non-cash working capital:

 Inventory

$

(31)

$

(214)

 Receivables and other current assets

(1)

653

(636)

 Accounts payable

(538)

423

 Other current liabilities

(2)

(179)

193

Total non-cash working capital 

$

(95)

$

(234)

(1) Includes $

162

 million related to the January 2023 settlement of NMGC gas hedges (2022 – ($

162

) million). Offsetting regulatory

liability is included in operating cash flow before working capital resulting in no impact to net cash provided by operating activities.

(2) Includes ($

166

) million related to the Nova Scotia Cap-and-Trade program (2022 – $

172

 million). For further detail, refer to note

6. Offsetting regulatory asset (FAM) balance is included in operating cash flow before working capital resulting in no impact to net

cash provided by operating activities.

For the 

Year ended December 31

millions of dollars

2023

2022

Supplemental disclosure of cash paid:

Interest

$

930

$

699

Income taxes

$

43

$

67

Supplemental disclosure of non-cash activities:

Common share dividends reinvested

$

271

$

237

Decrease in accrued capital expenditures

$

(19)

$

(13)

Reclassification of short-term debt to long-term debt

$

657

$

-

Reclassification of long-term debt to short-term debt

$

-

$

500

Supplemental disclosure of operating activities:

Net change in short-term regulatory assets and liabilities

$

123

$

(157)

Exhibit 99.3

73

31. STOCK-BASED COMPENSATION

Employee Common Share Purchase Plan and Common Shareholders Dividend

Reinvestment and Share Purchase Plan

Eligible employees may participate in the ECSPP. As of December 31, 2023, the plan allows employees

to make cash contributions of a minimum of $25 to a maximum of $20,000 CAD or $15,000 USD per year

for the purpose of purchasing common shares of Emera. The Company also contributes 20 per cent of

the employees’ contributions to the plan.

The plan allows reinvestment of dividends for all participants except where prohibited by law.

 The

maximum aggregate number of Emera common shares reserved for issuance under this plan is

7

 million

common shares. As at December 31, 2023, Emera was in compliance with this requirement.

Compensation cost for shares issued under the ECSPP for the year ended December 31, 2023 was $

3

million (2022 – $

3

 million) and was included in “OM&G” on the Consolidated Statements of Income. 

The Company also has a Common Shareholders DRIP, which provides an opportunity for shareholders

residing in Canada to reinvest dividends and purchase common shares. This plan provides for a discount

of up to 5 per cent from the average market price of Emera’s common shares for common shares

purchased in connection with the reinvestment of cash dividends. The discount was 2 per cent in 2023.

Stock-Based Compensation Plans

Stock Option Plan

The Company has a stock option plan that grants options to senior management of the Company for a

maximum term of 10 years. The option price of the stock options is the closing price of the Company’s

common shares on the Toronto Stock Exchange on the last business day on which such shares were

traded before the date on which the option is granted. The maximum aggregate number of shares

issuable under this plan is 14.7 million shares. As at December 31, 2023, Emera was in compliance with

this requirement.

Stock options granted in 2021 and prior vest in 25 per cent increments on the first, second, third and

fourth anniversaries of the date of the grant. Stock options granted in 2022 and thereafter vest in 20 per

cent increments on the first, second, third, fourth and fifth anniversaries of the date of the grant. If an

option is not exercised within 10 years, it expires and the optionee loses all rights thereunder. The holder

of the option has no rights as a shareholder until the option is exercised and shares have been issued.

The total number of stocks to be optioned to any optionee shall not exceed five per cent of the issued and

outstanding common stocks on the date the option is granted.

For stock options granted in 2021 and prior, unless a stock option has expired, vested options may be

exercised within the

27 months

 following the option holder’s date of retirement,

six months

 following a

termination without just cause or death, and within

sixty days

 following the date of termination for just

cause or resignation. Commencing with the 2022 stock option grant, vested options may be exercised

during the full term of the option following the option holders date of retirement,

six months

 following a

termination without just cause or death, and within

sixty days

 following the date of termination for just

cause or resignation. If stock options are not exercised within such time, they expire.

The Company uses the Black-Scholes valuation model to estimate the compensation expense related to

its stock-based compensation and recognizes the expense over the vesting period on a straight-line

basis.

The following table shows the weighted average FV per stock option along with the assumptions

incorporated into the valuation models for options granted, for the year-ended December 31:

Exhibit 99.3

74

2023

2022

Weighted average FV per option

$

6.32

$

5.35

Expected term

(1)

5

 years

5

 years

Risk-free interest rate

(2)

3.53

%

1.79

%

Expected dividend yield

(3)

5.05

%

4.55

%

Expected volatility

(4)

20.07

%

18.87

%

(1) The expected term of the option awards is calculated based on historical exercise behaviour and represents the period of time

that the options are expected to be outstanding.

(2) Based on the Bank of Canada five-year government bond yields.

(3) Incorporates current dividend rates and historical dividend increase patterns.

(4) Estimated using the five-year historical volatility.

The following table summarizes stock option information for 2023:

Total Options

Non-Vested Options

(1)

Number of

Options

 Weighted

average exercise

price per share

Number of

Options

Weighted

average grant

date fair-value

Outstanding as at December 31, 2022

2,853,879

$

50.41

1,348,400

$

4.08

Granted 

483,100

54.64

483,100

6.32

Exercised

(146,475)

43.94

N/A

N/A

Forfeited

(94,900)

56.32

(51,625)

3.61

Vested

N/A

N/A

(526,620)

3.58

Options outstanding December 31, 2023

3,095,604

$

51.20

1,253,255

$

5.17

Options exercisable December 31, 2023

(2)(3)

1,842,349

$

48.39

(1) As at December 31, 2023, there was $

5

 million of unrecognized compensation related to stock options not yet vested which is

expected to be recognized over a weighted average period of approximately

3

 years (2022 – $

4

 million,

3

 years).

(2) As at December 31, 2023, the weighted average remaining term of vested options was

5

 years with an aggregate intrinsic value of

$

8

 million (2022 –

5

 years, $

10

 million).

(3) As at December 31, 2023, the FV of options that vested in the year was $

2

 million (2022 – $

2

 million).

Compensation cost recognized for stock options for the year ended December 31, 2023 was $

2

 million

(2022 – $

2

 million), which was included in “OM&G” on the Consolidated Statements of Income. 

As at December 31, 2023, cash received from option exercises was $

6

 million (2022 – $

9

 million). The

total intrinsic value of options exercised for the year ended December 31, 2023 was $

2

 million (2022 – $

4

million). The range of exercise prices for the options outstanding as at December 31, 2023 was $

32.35

 to

$

60.03

 (2022 – $

32.35

 to $

60.03

).

Share Unit Plans

The Company has DSU, PSU and RSU plans. The plans and the liabilities are marked-to-market at the

end of each period based on an average common share price at the end of the period.

Deferred Share Unit Plans 

Under the Directors’ DSU plan, Directors of the Company may elect to receive all or any portion of their

compensation in DSUs in lieu of cash compensation, subject to requirements to receive a minimum

portion of their annual retainer in DSUs. Directors’ fees are paid on a quarterly basis and, at the time of

each payment of fees, the applicable amount is converted to DSUs. A DSU has a value equal to one

Emera common share. When a dividend is paid on Emera’s common shares, the Director’s DSU account

is credited with additional DSUs. DSUs cannot be redeemed for cash until the Director retires, resigns or

otherwise leaves the Board. The cash redemption value of a DSU equals the market value of a common

share at the time of redemption, pursuant to the plan. Following retirement or resignation from the Board,

the value of the DSUs credited to the participant’s account is calculated by multiplying the number of

DSUs in the participant’s account by Emera’s closing common share price on the date DSUs are

redeemed.

Exhibit 99.3

75

Under the executive and senior management DSU plan, each participant may elect to defer all or a

percentage of their annual incentive award in the form of DSUs with the understanding, for participants

who are subject to executive share ownership guidelines, a minimum of 50 per cent of the value of their

actual annual incentive award (25 per cent in the first year of the program) will be payable in DSUs until

the applicable guidelines are met.

When short-term incentive awards are determined, the amount elected is converted to DSUs, which have

a value equal to the market price of an Emera common share. When a dividend is paid on Emera’s

common shares, each participant’s DSU account is allocated additional DSUs equal in value to the

dividends paid on an equivalent number of Emera common shares. Following termination of employment

or retirement, and by December 15 of the calendar year after termination or retirement, the value of the

DSUs credited to the participant’s account is calculated by multiplying the number of DSUs in the

participant’s account by the average of Emera’s stock closing price for the fifty trading days prior to a

given calculation date. Payments are made in cash.

In addition, special DSU awards may be made from time to time by the Management Resources and

Compensation Committee (“MRCC”), to selected executives and senior management to recognize

singular achievements or by achieving certain corporate objectives.

A summary of the activity related to employee and director DSUs for the year ended December 31, 2023

is presented in the following table:

Employee

DSU

Weighted

Average

Grant Date

FV

Director 

DSU

Weighted

Average

Grant Date

FV

Outstanding as at December 31, 2022

627,223

$

41.55

664,258

$

45.83

Granted including DRIP

85,740

47.66

117,893

49.99

Exercised

N/A

N/A

(53,093)

49.39

Outstanding and exercisable as at December 31, 2023

712,963

$

42.29

729,058

$

46.24

Compensation cost recovery recognized for employee and director DSU’s for the year ended December

31, 2023 was $

2

 million (2022 – $

6

 million). Tax expense related to this compensation cost recovery for

share units realized for the year ended December 31, 2023 was $

1

 million (2022 – $

2

 million). The

aggregate intrinsic value of the outstanding shares for the year ended December 31, 2023 for employees

was $

36

 million (2022 – $

33

 million). The aggregate intrinsic value of the outstanding shares for the year

ended December 31, 2023 for directors was $

37

 million (2022 – $

34

 million). Cash payments made

during the year ended December 31, 2023 associated with the DSU plan were $

3

 million (2022 – $

8

million).

Performance Share Unit Plan 

Under the PSU plan, certain executive and senior employees are eligible for long-term incentives payable

through the plan. PSUs are granted annually for three-year overlapping performance cycles, resulting in a

cash payment. PSUs are granted based on the average of Emera’s stock closing price for the fifty trading

days prior to the effective grant date. Dividend equivalents are awarded and paid in the form of additional

PSUs. The PSU value varies according to the Emera common share market price and corporate

performance.

PSUs vest at the end of the three-year cycle and the payouts will be calculated and approved by the

MRCC early in the following year. The value of the payout considers actual service over the performance

cycle and may be pro-rated in certain departure scenarios. In the case of retirement, as defined in the

PSU plan, grants may continue to vest in full and payout in normal course post-retirement.

Exhibit 99.3

76

A summary of the activity related to employee PSUs for the year ended December 31, 2023 is presented

in the following table:

Employee PSU

Weighted Average

Grant Date FV

Aggregate intrinsic value

Outstanding as at December 31, 2022

690,446

$

56.24

$

40

Granted including DRIP

386,261

52.71

Exercised

(323,155)

54.62

Forfeited

(10,187)

55.15

Outstanding as at December 31, 2023

743,365

$

55.13

$

41

Compensation cost recognized for the PSU plan for the year ended December 31, 2023 was $

11

 million

(2022 – $

18

 million). Tax benefits related to this compensation cost for share units realized for the year

ended December 31, 2023 were $

3

 million (2022 – $

5

 million). Cash payments made during the year

ended December 31, 2023 associated with the PSU plan were $

19

 million (2022 – $

24

 million).

Restricted Share Unit Plan

Under the RSU plan, certain executive and senior employees are eligible for long-term incentives payable

through the plan. RSUs are granted annually for three-year overlapping performance cycles, resulting in a

cash payment. RSUs are granted based on the average of Emera’s stock closing price for the fifty trading

days prior to the effective grant date. Dividend equivalents are awarded and paid in the form of additional

RSUs. The RSU value varies according to the Emera common share market price.

RSUs vest at the end of the three-year cycle and the payouts will be calculated and approved by the

MRCC early in the following year. The value of the payout considers actual service over the performance

cycle and may be pro-rated in certain departure scenarios. In the case of retirement, as defined in the

RSU plan, grants may continue to vest in full and payout in normal course post-retirement.

A summary of the activity related to employee RSUs for the year ended December 31, 2023 is presented

in the following table:

Employee RSU

Weighted Average

Grant Date FV

Aggregate intrinsic value

Outstanding as at December 31, 2022

508,468

$

56.25

$

30

Granted including DRIP

236,537

52.07

Exercised

(171,537)

54.62

Forfeited

(10,827)

54.76

Outstanding as at December 31, 2023

562,641

$

55.01

$

32

Compensation cost recognized for the RSU plan for the year ended December 31, 2023 was $

10

 million

(2022 – $

9

 million). Tax benefits related to this compensation cost for share units realized for the year

ended December 31, 2023 were $

3

 million (2022 – $

2

 million). Cash payments made during the year

ended December 31, 2023 associated with the RSU plan were $

10

 million (2022–

nil

).

32. VARIABLE INTEREST ENTITIES

Emera holds a variable interest in NSPML, a VIE for which it was determined that Emera is not the

primary beneficiary since it does not have the controlling financial interest of NSPML. When the critical

milestones were achieved, Nalcor Energy was deemed the primary beneficiary of the asset for financial

reporting purposes as it has authority over the majority of the direct activities that are expected to most

significantly impact the economic performance of the Maritime Link. Thus, Emera began recording the

Maritime Link as an equity investment.

Exhibit 99.3

77

BLPC has established a SIF, primarily for the purpose of building a fund to cover risk against damage and

consequential loss to certain generating, transmission and distribution systems. ECI holds a variable

interest in the SIF for which it was determined that ECI was the primary beneficiary and, accordingly, the

SIF must be consolidated by ECI. In its determination that ECI controls the SIF, management considered

that, in substance, the activities of the SIF are being conducted on behalf of ECI’s subsidiary BLPC and

BLPC, alone, obtains the benefits from the SIF’s operations. Additionally, because ECI, through BLPC,

has rights to all the benefits of the SIF, it is also exposed to the risks related to the activities of the SIF.

Any withdrawal of SIF fund assets by the Company would be subject to existing regulations. Emera’s

consolidated VIE in the SIF is recorded as “Other long-term assets”, “Restricted cash” and “Regulatory

liabilities” on the Consolidated Balance Sheets. Amounts included in restricted cash represent the cash

portion of funds required to be set aside for the BLPC SIF.

The Company has identified certain long-term purchase power agreements that meet the definition of

variable interests as the Company has to purchase all or a majority of the electricity generation at a fixed

price. However, it was determined that the Company was not the primary beneficiary since it lacked the

power to direct the activities of the entity, including the ability to operate the generating facilities and make

management decisions.

The following table provides information about Emera’s portion of material unconsolidated VIEs:

As at

December 31, 2023

December 31, 2022

Maximum

Maximum

millions of dollars

Total

assets

exposure to

loss

Total

assets

 exposure to

loss

Unconsolidated VIEs in which Emera has variable interests

NSPML (equity accounted)

$

489

$

6

$

501

$

6

33. SUBSEQUENT EVENTS

These financial statements and notes reflect the Company’s evaluation of events occurring subsequent to

the balance sheet date through February 26, 2024, the date the financial statements were issued.

EX-99.4

Exhibit 99.4

Consent of Independent Registered Public Accounting Firm

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

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

EX-99.5

Exhibit 99.5

CERTIFICATION

I, Scott C. Balfour, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: February 26, 2024

/s/ Scott C. Balfour

Scott C. Balfour

President & Chief Executive Officer

EX-99.6

Exhibit 99.6

CERTIFICATION

I, Gregory W. Blunden, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: February 26, 2024

/s/ Gregory W. Blunden

Gregory W. Blunden

Chief Financial Officer

EX-99.7

Exhibit 99.7

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350

AS ENACTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

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

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

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

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

Date: February 26, 2024

/s/ Scott C. Balfour

Scott C. Balfour

President & Chief Executive Officer

EX-99.8

Exhibit 99.8

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350

AS ENACTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

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

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

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

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

Date: February 26, 2024

/s/ Gregory W. Blunden

Gregory W. Blunden

Chief Financial Officer

XML

Cover Page	12 Months Ended
	Dec. 31, 2023 shares
Cover [Abstract]
Entity Central Index Key	0001127248
Document Type	40-F
Document Registration Statement	false
Document Annual Report	true
Amendment Flag	false
Document Period End Date	Dec. 31, 2023
Document Fiscal Period Focus	FY
Document Fiscal Year Focus	2023
Current Fiscal Year End Date	--12-31
Entity File Number	000-54516
Entity Registrant Name	EMERA INCORPORATED
Entity Incorporation, State or Country Code	A5
Entity Listings [Line Items]
Entity Address, Address Line One	5151 Terminal Road
Entity Address, City or Town	Halifax
Entity Address, State or Province	NS
Entity Address, Country	CA
Entity Address, Postal Zip Code	B3J 1A1
City Area Code	902
Local Phone Number	428-6096
Annual Information Form	true
Audited Annual Financial Statements	true
Document Fin Stmt Error Correction Flag	false
Entity Current Reporting Status	No
Entity Interactive Data Current	Yes
Entity Emerging Growth Company	false
ICFR Auditor	false
Auditor Name	Ernst & Young LLP
Auditor Location	Halifax, Canada
Auditor Firm Id	1263
Business Contact [Member]
Entity Listings [Line Items]
Contact Personnel Name	Emera US Finance LP
Entity Address, Address Line One	c/o Corporation Service Company
Entity Address Address Line Two	251 Little Falls Drive
Entity Address, City or Town	Wilmington
Entity Address, State or Province	DE
Entity Address, Postal Zip Code	19808
City Area Code	302
Local Phone Number	636-5401
Common Stock
Entity Listings [Line Items]
Entity Common Stock, Shares Outstanding	284,117,511
Series A Preferred Stock
Entity Listings [Line Items]
Entity Common Stock, Shares Outstanding	4,866,814
Series B Preferred Stock
Entity Listings [Line Items]
Entity Common Stock, Shares Outstanding	1,133,186
Series C Preferred Stock
Entity Listings [Line Items]
Entity Common Stock, Shares Outstanding	10,000,000
Series E Preferred Stock
Entity Listings [Line Items]
Entity Common Stock, Shares Outstanding	5,000,000
Series F Preferred Stock
Entity Listings [Line Items]
Entity Common Stock, Shares Outstanding	8,000,000
Series H Preferred Stock
Entity Listings [Line Items]
Entity Common Stock, Shares Outstanding	12,000,000
Series J Preferred Stock [Member]
Entity Listings [Line Items]
Entity Common Stock, Shares Outstanding	8,000,000
Series L Preferred Stock [Member]
Entity Listings [Line Items]
Entity Common Stock, Shares Outstanding	9,000,000

XML

Consolidated Statements of Income - CAD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Operating revenues
Total operating revenues (note 5)	$ 7,563.0	$ 7,588.0
Operating expenses
Operating, maintenance and general expenses ("OM&G")	1,879.0	1,596.0
Provincial, state, and municipal taxes	433.0	367.0
Depreciation and amortization	1,049.0	952.0
GBPC Impairment charge (note 22)	0.0	73.0
Total operating expenses	5,769.0	5,959.0
Income from operations	1,794.0	1,629.0
Income from equity investments (note 7)	146.0	129.0
Other income, net (note 8)	158.0	145.0
Interest expense, net (note 9)	(925.0)	(709.0)
Income before provision for income taxes	1,173.0	1,194.0
Income tax expense (note 10)	128.0	185.0
Net income	1,045.0	1,009.0
Non-controlling interest in subsidiaries	1.0	1.0
Preferred stock dividends	66.0	63.0
Net income attributable to common shareholders	$ 977.7	$ 945.1
Earnings per common share (note 12)
Basic	$ 3.57	$ 3.56
Diluted	$ 3.57	$ 3.55
Weighted average shares of common stock outstanding (in millions) (note 12)
Basic	273.6	265.5
Diluted	273.8	265.9
Dividends per common share declared	$ 2.7875	$ 2.6775
Regulated | Gas Revenue
Operating revenues
Total operating revenues (note 5)	$ 1,489.0	$ 1,681.0
Operating expenses
Fuel for generation and purchased power	527.0	800.0
Regulated | Electric Revenue
Operating revenues
Total operating revenues (note 5)	5,746.0	5,473.0
Operating expenses
Fuel for generation and purchased power	1,881.0	2,171.0
Non-Regulated
Operating revenues
Total operating revenues (note 5)	$ 328.0	$ 434.0

XML

Consolidated Statements of Comprehensive Income - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Consolidated Statements of Comprehensive Income
Net income	$ 1,045	$ 1,009
Other comprehensive (loss) income, net of tax
Foreign currency translation adjustment	(270)	629
Unrealized gains (losses) on net investment hedges	38	(97)
Cash flow hedges - reclassification adjustment for gains included in income	(2)	(2)
Cash flow hedges
Unrealized losses on available-for-sale investment	0	(1)
Net change in unrecognized pension and post-retirement benefit obligation	(39)	24
Other comprehensive (loss) income	(273)	553
Comprehensive income	772	1,562
Comprehensive income attributable to non-controlling interest	1	1
Comprehensive Income of Emera Incorporated	$ 771	$ 1,561

XML

Consolidated Statements of Comprehensive Income (Parenthetical) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Foreign currency translation, tax expense (recovery)	$ (7)	$ 7
Hybrid Notes as a hedge of the foreign currency exposure	1,200	1,100
Unrealized gains (losses) on net investment hedges	0	(6)
Net derivative gain, tax	0	(1)
Net change in unrecognized pension and post-retirement benefit obligation	1	1
Other comprehensive loss, Tax	(6)	$ 1
Net investment in United States dollar denominated operations
Hybrid Notes as a hedge of the foreign currency exposure	$ 1,200

XML

Consolidated Balance Sheets - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Current assets
Cash and cash equivalents	$ 567	$ 310
Restricted cash (note 32)	21	22
Inventory (note 14)	790	769
Derivative instruments (notes 15 and 16)	174	296
Regulatory assets (note 6)	339	602
Receivables and other current assets (note 18)	1,817	2,897
Total current assets	3,708	4,896
Property, plant and equipment ("PP&E"), net of accumulated depreciation and amortization of $9,994 and $9,574, respectively (note 20)	24,376	22,996
Other assets
Deferred income taxes (note 10)	208	237
Derivative instruments (notes 15 and 16)	66	100
Regulatory assets (note 6)	2,766	3,018
Net investment in direct finance and sales type leases (note 19)	621	604
Investments subject to significant influence (note 7)	1,402	1,418
Goodwill (note 22)	5,871	6,012
Other long-term assets (note 32)	462	461
Total other assets	11,396	11,850
Total assets	39,480	39,742
Current liabilities
Short-term debt (note 23)	1,433	2,726
Current portion of long-term debt (note 25)	676	574
Accounts payable	1,454	2,025
Derivative instruments (notes 15 and 16)	386	888
Regulatory liabilities (note 6)	168	495
Other current liabilities (note 24)	427	579
Total current liabilities	4,544	7,287
Long-term liabilities
Long-term debt (note 25)	17,689	15,744
Deferred income taxes (note 10)	2,352	2,196
Derivative instruments (notes 15 and 16)	118	190
Regulatory liabilities (note 6)	1,604	1,778
Pension and post-retirement liabilities (note 21)	265	281
Other long-term liabilities (notes 7 and 26)	820	825
Total long-term liabilities	22,848	21,014
Equity
Common stock (note 11)	8,462	7,762
Cumulative preferred stock (note 28)	1,422	1,422
Contributed surplus	82	81
Accumulated other comprehensive income ("AOCI") (note 13)	305	578
Retained earnings	1,803	1,584
Total Emera Incorporated equity	12,074	11,427
Non-controlling interest in subsidiaries (note 29)	14	14
Total equity	12,088	11,441
Total liabilities and equity	$ 39,480	$ 39,742

XML

Consolidated Balance Sheets (Parenthetical) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Consolidated Balance Sheets
Accumulated depreciation and amortization on property, plant and equipment	$ 9,994	$ 9,574

XML

Consolidated Statements of Cash Flows - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Operating activities
Net income	$ 1,045	$ 1,009
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	1,060	959
Income from equity investments, net of dividends	(22)	(61)
Allowance for funds used during construction ("AFUDC") - equity	(38)	(52)
Deferred income taxes, net	97	152
Net change in pension and post-retirement liabilities	(68)	(48)
NSPI Fuel adjustment mechanism ("FAM")	(88)	(162)
Net change in Fair Value ("FV") of derivative instruments	(666)	206
Net change in regulatory assets and liabilities	554	(471)
Net change in capitalized transportation capacity	434	(445)
GBPC Impairment charge	0	73
Other operating activities, net	28	(13)
Changes in non-cash working capital (note 30)	(95)	(234)
Net cash provided by operating activities	2,241	913
Investing activities
Additions to PP&E	(2,937)	(2,596)
Other investing activities	20	27
Net cash used in investing activities	(2,917)	(2,569)
Financing activities
Change in short-term debt, net	(66)	1,028
Proceeds from short-term debt with maturities greater than 90 days	548	544
Repayment of short-term debt with maturities greater than 90 days	(1,086)	(680)
Proceeds from long-term debt, net of issuance costs	1,932	784
Retirement of long-term debt	(151)	(367)
Net (repayments) proceeds under committed credit facilities	(96)	511
Issuance of common stock, net of issuance costs	424	277
Dividends on common stock	(488)	(472)
Dividends on preferred stock	(66)	(63)
Other financing activities	(12)	(7)
Net cash provided by financing activities	939	1,555
Effect of exchange rate changes on cash, cash equivalents, and restricted cash	(7)	16
Net increase (decrease) in cash, cash equivalents, and restricted cash	256	(85)
Cash, cash equivalents, and restricted cash, beginning of year	332	417
Cash, cash equivalents, and restricted cash, end of year	$ 588	$ 332

XML

Consolidated Statements of Cash Flows (Parenthetical) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Cash, cash equivalents and restricted cash consists of:
Cash	$ 559	$ 302
Short-term investments	8	8
Restricted cash	21	22
Cash, cash equivalents, and restricted cash	$ 588	$ 332

XML

Consolidated Statements of Changes in Equity - CAD ($) $ in Millions	Total	Common Stock [Member]	Preferred Stock	Contributed Surplus	Accumulated Other Comprehensive Income (Loss)	Retained Earnings	Non-Controlling Interest
Beginning Balance at Dec. 31, 2021	$ 10,150	$ 7,242	$ 1,422	$ 79	$ 25	$ 1,348	$ 34
Net income of Emera Inc.	1,009	0	0	0	0	1,008	1
Other comprehensive income (loss), net of tax expense	553	0	0	0	553	0	0
Dividends declared on preferred stock (note 28)	(63)	0	0	0	0	(63)	0
Dividends declared on common stock	(709)	0	0	0	0	(709)	0
Issued under the at-the-market program ("ATM"), net of after-tax issuance costs	248	248	0	0	0	0	0
Issued under the Dividend Reinvestment Program ("DRIP"), net of discount	238	238	0	0	0	0	0
Senior management stock options exercised and Employee Share Purchase Plan ("ECSPP")	36	34	0	2	0	0	0
Disposal of non-controlling interest of Dominica Electricity Services Ltd ("Domlec")	(20)	0	0	0	0	0	(20)
Other	(1)	0	0	0	0	0	(1)
Ending Balance at Dec. 31, 2022	11,441	7,762	1,422	81	578	1,584	14
Net income of Emera Inc.	1,045	0	0	0	0	1,044	1
Other comprehensive income (loss), net of tax expense	(273)	0	0	0	(273)	0	0
Dividends declared on preferred stock (note 28)	(66)	0	0	0	0	(66)	0
Dividends declared on common stock	(759)	0	0	0	0	(759)	0
Issued under the at-the-market program ("ATM"), net of after-tax issuance costs	397	397	0	0	0	0	0
Issued under the Dividend Reinvestment Program ("DRIP"), net of discount	272	272	0	0	0	0	0
Senior management stock options exercised and Employee Share Purchase Plan ("ECSPP")	32	31	0	1	0	0	0
Other	(1)	0	0	0	0	0	(1)
Ending Balance at Dec. 31, 2023	$ 12,088	$ 8,462	$ 1,422	$ 82	$ 305	$ 1,803	$ 14

XML

Consolidated Statements of Changes in Equity (Parenthetical) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Consolidated Statements of Changes in Equity
Other comprehensive loss, tax expense/recovery	$ (6)	$ 1
Dividends per common share declared	$ 2.7875	$ 2.6775

XML

Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2023

Summary of Significant Accounting Policies [Abstract]

Summary of Significant Accounting Policies

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Operations

Emera Incorporated (“Emera” or the “Company”) is an energy and services company which invests in

electricity generation, transmission and distribution, and gas transmission and distribution. 

At December 31, 2023, Emera’s reportable segments include the following: 

●

 Florida Electric Utility, which consists of Tampa Electric (“TEC”), a vertically integrated regulated

electric utility, serving approximately

840,000

 customers in West Central Florida;

●

 Canadian Electric Utilities, which includes:

●

 Nova Scotia Power Inc. (“NSPI”), a vertically integrated regulated electric utility and the

primary electricity supplier in Nova Scotia, serving approximately

549,000

 customers; and

●

 Emera Newfoundland & Labrador Holdings Inc. (“ENL”), consisting of two transmission

investments related to an

824

 megawatt (“MW”) hydroelectric generating facility at Muskrat

Falls on the Lower Churchill River in Labrador, developed by Nalcor Energy. ENL’s two

investments are:

●

 a

100

 per cent equity interest in NSP Maritime Link Inc. (“NSPML”), which developed

the Maritime Link Project, a $

1.8

 billion transmission project, including AFUDC; and

●

 a

31

 per cent equity interest in the partnership capital of Labrador-Island Link Limited

Partnership (“LIL”), a $

3.7

 billion electricity transmission project in Newfoundland and

Labrador. 

●

 Gas Utilities and Infrastructure, which includes:

●

 Peoples Gas System Inc. (“PGS”), a regulated gas distribution utility, serving approximately

490,000

 customers across Florida. Effective January 1, 2023, Peoples Gas System ceased

to be a division of Tampa Electric Company and the gas utility was reorganized, resulting in a

separate legal entity called Peoples Gas System Inc., a wholly owned direct subsidiary of

TECO Gas Operations, Inc.;

●

 New Mexico Gas Company, Inc. (“NMGC”), a regulated gas distribution utility, serving

approximately

540,000

 customers in New Mexico; 

●

 Emera Brunswick Pipeline Company Limited (“Brunswick Pipeline”), a

145

-kilometre pipeline

delivering re-gasified liquefied natural gas from Saint John, New Brunswick to the United

States border under a

25

-year firm service agreement with Repsol Energy North America

Canada Partnership (“Repsol Energy”), which expires in 2034; 

●

 SeaCoast Gas Transmission, LLC (“SeaCoast”), a regulated intrastate natural gas

transmission company offering services in Florida; and

●

 a

12.9

 per cent equity interest in Maritimes & Northeast Pipeline (“M&NP”), a

1,400

-kilometre

pipeline that transports natural gas throughout markets in Atlantic Canada and the

northeastern United States. 

●

 Other Electric Utilities, which includes Emera (Caribbean) Incorporated (“ECI”), a holding company

with regulated electric utilities that include:

●

 The Barbados Light & Power Company Limited (“BLPC”), a vertically integrated regulated

electric utility on the island of Barbados, serving approximately

134,000

 customers; 

●

 Grand Bahama Power Company Limited (“GBPC”), a vertically integrated regulated electric

utility on Grand Bahama Island, serving approximately

19,000

 customers; and

●

 a

19.5

 per cent equity interest in St. Lucia Electricity Services Limited (“Lucelec”), a vertically

integrated regulated electric utility on the island of St. Lucia.

●

 Emera’s other reportable segment includes investments in energy-related non-regulated companies

which include:

●

 Emera Energy, which consists of:

●

 Emera Energy Services (“EES”), a physical energy business that purchases and sells

natural gas and electricity and provides related energy asset management services; 

●

 Brooklyn Power Corporation (“Brooklyn Energy”), a

30

 MW biomass co-generation

electricity facility in Brooklyn, Nova Scotia; and

●

 a

50.0

 per cent joint venture interest in Bear Swamp Power Company LLC (“Bear

Swamp”), a

660

 MW pumped storage hydroelectric facility in northwestern

Massachusetts. 

●

 Emera US Finance LP (“Emera Finance”) and TECO Finance, Inc. (“TECO Finance”),

financing subsidiaries of Emera;

●

 Block Energy LLC (previously Emera Technologies LLC), a wholly owned technology

company focused on finding ways to deliver renewable and resilient energy to customers;

●

 Emera US Holdings Inc., a wholly owned holding company for certain of Emera’s assets

located in the United States; and

●

 Other investments.

Basis of Presentation

These consolidated financial statements are prepared and presented in accordance with United States

Generally Accepted Accounting Principles (“USGAAP”) and in the opinion of management, include all

adjustments that are of a recurring nature and necessary to fairly state the financial position of Emera. 

All dollar amounts are presented in Canadian dollars (“CAD”), unless otherwise indicated.

Principles of Consolidation

These consolidated financial statements include the accounts of Emera Incorporated, its majority-owned

subsidiaries, and a variable interest entity (“VIE”) in which Emera is the primary beneficiary. Emera uses

the equity method of accounting to record investments in which the Company has the ability to exercise

significant influence, and for VIEs in which Emera is not the primary beneficiary.

The Company performs ongoing analysis to assess whether it holds any VIEs or whether any

reconsideration events have arisen with respect to existing VIEs. To identify potential VIEs, management

reviews contractual and ownership arrangements such as leases, long-term purchase power agreements,

tolling contracts, guarantees, jointly owned facilities and equity investments. VIEs of which the Company

is deemed the primary beneficiary must be consolidated. The primary beneficiary of a VIE has both the

power to direct the activities of the VIE that most significantly impacts its economic performance and the

obligation to absorb losses or the right to receive benefits of the VIE that could potentially be significant to

the VIE. In circumstances where Emera has an investment in a VIE but is not deemed the primary

beneficiary, the VIE is accounted for using the equity method. For further details on VIEs, refer to note 32.

Intercompany balances and transactions have been eliminated on consolidation, except for the net profit

on certain transactions between certain non-regulated and regulated entities in accordance with

accounting standards for rate-regulated entities. The net profit on these transactions, which would be

eliminated in the absence of the accounting standards for rate-regulated entities, is recorded in non-

regulated operating revenues. An offset is recorded to PP&E, regulatory assets, regulated fuel for

generation and purchased power, or OM&G, depending on the nature of the transaction.

Use of Management Estimates

The preparation of consolidated financial statements in accordance with USGAAP requires management

to make estimates and assumptions. These may affect reported amounts of assets and liabilities at the

date of the financial statements and reported amounts of revenues and expenses during the reporting

periods. Significant areas requiring use of management estimates relate to rate-regulated assets and

liabilities, accumulated reserve for cost of removal, pension and post-retirement benefits, unbilled

revenue, useful lives for depreciable assets, goodwill and long-lived assets impairment assessments,

income taxes, asset retirement obligations (“ARO”), and valuation of financial instruments. Management

evaluates the Company’s estimates on an ongoing basis based upon historical experience, current and

expected conditions and assumptions believed to be reasonable at the time the assumption is made, with

any adjustments recognized in income in the year they arise.

Regulatory Matters

Regulatory accounting applies where rates are established by, or subject to approval by, an independent

third-party regulator. Rates are designed to recover prudently incurred costs of providing regulated

products or services and provide an opportunity for a reasonable rate of return on invested capital, as

applicable. For further detail, refer to note 6.

Foreign Currency Translation 

Monetary assets and liabilities denominated in foreign currencies are converted to CAD at the rates of

exchange prevailing at the balance sheet date. The resulting differences between the translation at the

original transaction date and the balance sheet date are included in income.

Assets and liabilities of foreign operations whose functional currency is not the Canadian dollar are

translated using exchange rates in effect at the balance sheet date and the results of operations at the

average exchange rate in effect for the period. The resulting exchange gains and losses on the assets

and liabilities are deferred on the balance sheet in AOCI.

The Company designates certain USD denominated debt held in CAD functional currency companies as

hedges of net investments in USD denominated foreign operations. The change in the carrying amount of

these investments, measured at exchange rates in effect at the balance sheet date is recorded in Other

Comprehensive Income (“OCI”).

Revenue Recognition

Regulated Electric and Gas Revenue:

Electric and gas revenues, including energy charges, demand charges, basic facilities charges and

clauses and riders, are recognized when obligations under the terms of a contract are satisfied, which is

when electricity and gas are delivered to customers over time as the customer simultaneously receives

and consumes the benefits. Electric and gas revenues are recognized on an accrual basis and include

billed and unbilled revenues. Revenues related to the sale of electricity and gas are recognized at rates

approved by the respective regulators and recorded based on metered usage, which occurs on a

periodic, systematic basis, generally monthly or bi-monthly. At the end of each reporting period, electricity

and gas delivered to customers, but not billed, is estimated and corresponding unbilled revenue is

recognized. The Company’s estimate of unbilled revenue at the end of the reporting period is calculated

by estimating the megawatt hours (“MWh”) or therms delivered to customers at the established rates

expected to prevail in the upcoming billing cycle. This estimate includes assumptions as to the pattern of

energy demand, weather, line losses and inter-period changes to customer classes.

Non-regulated Revenue:

Marketing and trading margins are comprised of Emera Energy’s corresponding purchases and sales of

natural gas and electricity, pipeline capacity costs and energy asset management revenues. Revenues

are recorded when obligations under terms of the contract are satisfied and are presented on a net basis

reflecting the nature of contractual relationships with customers and suppliers.

Energy sales are recognized when obligations under the terms of the contracts are satisfied, which is

when electricity is delivered to customers over time. 

Other non-regulated revenues are recorded when obligations under the terms of the contract are

satisfied.

Other:

Sales, value add, and other taxes, except for gross receipts taxes discussed below, collected by the

Company concurrent with revenue-producing activities are excluded from revenue.

Franchise Fees and Gross Receipts

TEC and PGS recover from customers certain costs incurred, on a dollar-for-dollar basis, through prices

approved by the Florida Public Service Commission (“FPSC”). The amounts included in customers’ bills

for franchise fees and gross receipt taxes are included as “Regulated electric” and “Regulated gas”

revenues in the Consolidated Statements of Income. Franchise fees and gross receipt taxes payable by

TEC and PGS are included as an expense on the Consolidated Statements of Income in “Provincial, state

and municipal taxes”.

NMGC is an agent in the collection and payment of franchise fees and gross receipt taxes and is not

required by a tariff to present the amounts on a gross basis. Therefore, NMGC’s franchise fees and gross

receipt taxes are presented net with no line item impact on the Consolidated Statements of Income.

PP&E 

PP&E is recorded at original cost, including AFUDC or capitalized interest, net of contributions received in

aid of construction.

The cost of additions, including betterments and replacements of units, are included in “PP&E” on the

Consolidated Balance Sheets. When units of regulated PP&E are replaced, renewed or retired, their cost,

plus removal or disposal costs, less salvage proceeds, is charged to accumulated depreciation, with no

gain or loss reflected in income. Where a disposition of non-regulated PP&E occurs, gains and losses are

included in income as the dispositions occur.

The cost of PP&E represents the original cost of materials, contracted services, direct labour, AFUDC for

regulated property or interest for non-regulated property, ARO, and overhead attributable to the capital

project. Overhead includes corporate costs such as finance, information technology and labour costs,

along with other costs related to support functions, employee benefits, insurance, procurement, and fleet

operating and maintenance. Expenditures for project development are capitalized if they are expected to

have a future economic benefit.

Normal maintenance projects and major maintenance projects that do not increase overall life of the

related assets are expensed as incurred. When a major maintenance project increases the life or value of

the underlying asset, the cost is capitalized. 

Depreciation is determined by the straight-line method, based on the estimated remaining service lives of

the depreciable assets in each functional class of depreciable property. For some of Emera’s rate-

regulated subsidiaries, depreciation is calculated using the group remaining life method, which is applied

to the average investment, adjusted for anticipated costs of removal less salvage, in functional classes of

depreciable property. The service lives of regulated assets require regulatory approval.

Intangible assets, which are included in “PP&E” on the Consolidated Balance Sheets, consist primarily of

computer software and land rights. Amortization is determined by the straight-line method, based on the

estimated remaining service lives of the asset in each category. For some of Emera’s rate-regulated

subsidiaries, amortization is calculated using the amortizable life method which is applied to the net book

value to date over the remaining life of those assets. The service lives of regulated intangible assets

require regulatory approval.

Goodwill

Goodwill is calculated as the excess of the purchase price of an acquired entity over the estimated FV of

identifiable assets acquired and liabilities assumed at the acquisition date. Goodwill is carried at initial

cost less any write-down for impairment and is adjusted for the impact of foreign exchange (“FX”).

Goodwill is subject to assessment for impairment at the reporting unit level annually, or if an event or

change in circumstances indicates that the FV of a reporting unit may be below its carrying value. When

assessing goodwill for impairment, the Company has the option of first performing a qualitative

assessment to determine whether a quantitative assessment is necessary. In performing a qualitative

assessment management considers, among other factors, macroeconomic conditions, industry and

market considerations and overall financial performance.

If the Company performs a qualitative assessment and determines it is more likely than not that its FV is

less than its carrying amount, or if the Company chooses to bypass the qualitative assessment, a

quantitative test is performed. The quantitative test compares the FV of the reporting unit to its carrying

amount, including goodwill. If the carrying amount of the reporting unit exceeds its FV, an impairment loss

is recorded. Management estimates the FV of the reporting unit by using the income approach, or a

combination of the income and market approach. The income approach uses a discounted cash flow

analysis which relies on management’s best estimate of the reporting unit’s projected cash flows. The

analysis includes an estimate of terminal values based on these expected cash flows using a

methodology which derives a valuation using an assumed perpetual annuity based on the reporting unit’s

residual cash flows. The discount rate used is a market participant rate based on a peer group of publicly

traded comparable companies and represents the weighted average cost of capital of comparable

companies. For the market approach, management estimates FV based on comparable companies and

transactions within the utility industry. Significant assumptions used in estimating the FV of a reporting

unit using an income approach include discount and growth rates, rate case assumptions including future

cost of capital, valuation of the reporting unit’s net operating loss (“NOL”) and projected operating and

capital cash flows. Adverse changes in these assumptions could result in a future material impairment of

the goodwill assigned to Emera’s reporting units. 

As of December 31, 2023, $

5,868

 million of Emera’s goodwill represents the excess of the acquisition

purchase price for TECO Energy (TEC, PGS and NMGC reporting units) over the FV assigned to

identifiable assets acquired and liabilities assumed. In Q4 2023, qualitative assessments were performed

for NMGC and PGS given the significant excess of FV over carrying amounts calculated during the last

quantitative tests in Q4 2022 and Q4 2019, respectively. Management concluded it was more likely than

not that the FV of these reporting units exceeded their respective carrying amounts, including goodwill. As

such, no quantitative testing was required. Given the length of time passed since the last quantitative

impairment test for the TEC reporting unit, Emera elected to bypass a qualitative assessment and

performed a quantitative impairment assessment in Q4 2023 using a combination of the income and

market approach. This assessment estimated that the FV of the TEC reporting unit exceeded its carrying

amount, including goodwill, and as a result, no impairment charges were recognized.

In Q4 2022, as a result of a quantitative assessment, the Company recorded a goodwill impairment

charge of $

73

 million, reducing the GBPC goodwill balance to

nil

 as at December 31, 2022. For further

details, refer to note 22.

Income Taxes and Investment Tax Credits

Emera recognizes deferred income tax assets and liabilities for the future tax consequences of events

that have been included in financial statements or income tax returns. Deferred income tax assets and

liabilities are determined based on the difference between the carrying value of assets and liabilities on

the Consolidated Balance Sheets, and their respective tax bases using enacted tax rates in effect for the

year in which the differences are expected to reverse. The effect of a change in income tax rates on

deferred income tax assets and liabilities is recognized in earnings in the period when the change is

enacted, unless required to be offset to a regulatory asset or liability by law or by order of the regulator.

Emera recognizes the effect of income tax positions only when it is more likely than not that they will be

realized. Management reviews all readily available current and historical information, including forward-

looking information, and the likelihood that deferred income tax assets will be recovered from future

taxable income is assessed and assumptions are made about the expected timing of reversal of deferred

income tax assets and liabilities. If management subsequently determines it is likely that some or all of a

deferred income tax asset will not be realized, a valuation allowance is recorded to reflect the amount of

deferred income tax asset expected to be realized. 

Generally, investment tax credits are recorded as a reduction to income tax expense in the current or

future periods to the extent that realization of such benefit is more likely than not. Investment tax credits

earned on regulated assets by TEC, PGS and NMGC are deferred and amortized as required by

regulatory practices.

TEC, PGS, NMGC and BLPC collect income taxes from customers based on current and deferred income

taxes. NSPI, ENL and Brunswick Pipeline collect income taxes from customers based on income tax that

is currently payable, except for the deferred income taxes on certain regulatory balances specifically

prescribed by regulators. For the balance of regulated deferred income taxes, NSPI, ENL and Brunswick

Pipeline recognize regulatory assets or liabilities where the deferred income taxes are expected to be

recovered from or returned to customers in future years. These regulated assets or liabilities are grossed

up using the respective income tax rate to reflect the income tax associated with future revenues that are

required to fund these deferred income tax liabilities, and the income tax benefits associated with reduced

revenues resulting from the realization of deferred income tax assets. GBPC is not subject to income

taxes.

Emera classifies interest and penalties associated with unrecognized tax benefits as interest and

operating expense, respectively. For further detail, refer to note 10.

Derivatives and Hedging Activities

The Company manages its exposure to normal operating and market risks relating to commodity prices,

FX, interest rates and share prices through contractual protections with counterparties where practicable,

and by using financial instruments consisting mainly of FX forwards and swaps, interest rate options and

swaps, equity derivatives, and coal, oil and gas futures, options, forwards and swaps. In addition, the

Company has contracts for the physical purchase and sale of natural gas. These physical and financial

contracts are classified as HFT. Collectively, these contracts and financial instruments are considered

derivatives.

The Company recognizes the FV of all its derivatives on its balance sheet, except for non-financial

derivatives that meet the normal purchases and normal sales (“NPNS”) exception. Physical contracts that

meet the NPNS exception are not recognized on the balance sheet; these contracts are recognized in

income when they settle. A physical contract generally qualifies for the NPNS exception if the transaction

is reasonable in relation to the Company’s business needs, the counterparty owns or controls resources

within the proximity to allow for physical delivery, the Company intends to receive physical delivery of the

commodity, and the Company deems the counterparty creditworthy. The Company continually assesses

contracts designated under the NPNS exception and will discontinue the treatment of these contracts

under this exemption if the criteria are no longer met. 

Derivatives qualify for hedge accounting if they meet stringent documentation requirements and can be

proven to effectively hedge identified risk both at the inception and over the term of the instrument.

Specifically, for cash flow hedges, change in the FV of derivatives is deferred to AOCI and recognized in

income in the same period the related hedged item is realized. Where documentation or effectiveness

requirements are not met, the derivatives are recognized at FV with any changes in FV recognized in net

income in the reporting period, unless deferred as a result of regulatory accounting.

Derivatives entered into by NSPI, NMGC and GBPC that are documented as economic hedges or for

which the NPNS exception has not been taken, are subject to regulatory accounting treatment. The

change in FV of the derivatives is deferred to a regulatory asset or liability. The gain or loss is recognized

in the hedged item when the hedged item is settled. Management believes any gains or losses resulting

from settlement of these derivatives related to fuel for generation and purchased power will be refunded

to or collected from customers in future rates. TEC has no derivatives related to hedging as a result of a

FPSC approved five-year moratorium on hedging of natural gas purchases that ended on December 31,

2022 and was extended through December 31, 2024 as a result of TEC’s 2021 rate case settlement

agreement.

Derivatives that do not meet any of the above criteria are designated as HFT, with changes in FV

normally recorded in net income of the period. The Company has not elected to designate any derivatives

to be included in the HFT category where another accounting treatment would apply.

Emera classifies gains and losses on derivatives as a component of non-regulated operating revenues,

fuel for generation and purchased power, other expenses, inventory, and OM&G, depending on the

nature of the item being economically hedged. Transportation capacity arising as a result of marketing

and trading derivative transactions is recognized as an asset in “Receivables and other current assets”

and amortized over the period of the transportation contract term. Cash flows from derivative activities are

presented in the same category as the item being hedged within operating or investing activities on the

Consolidated Statements of Cash Flows. Non-hedged derivatives are included in operating cash flows on

the Consolidated Statements of Cash Flows.

Derivatives, as reflected on the Consolidated Balance Sheets, are not offset by the FV amounts of cash

collateral with the same counterparty. Rights to reclaim cash collateral are recognized in “Receivables

and other current assets” and obligations to return cash collateral are recognized in “Accounts payable”.

Leases

The Company determines whether a contract contains a lease at inception by evaluating whether the

contract conveys the right to control the use of an identified asset for a period of time in exchange for

consideration. 

Emera has leases with independent power producers (“IPP”) and other utilities for annual requirements to

purchase wind and hydro energy over varying contract lengths which are classified as finance leases.

These finance leases are not recorded on the Company’s Consolidated Balance Sheets as payments

associated with the leases are variable in nature and there are no minimum fixed lease payments. Lease

expense associated with these leases is recorded as “Regulated fuel for generation and purchased

power” on the Consolidated Statements of Income.

Operating lease liabilities and right-of-use assets are recognized on the Consolidated Balance Sheets

based on the present value of the future minimum lease payments over the lease term at commencement

date. As most of Emera’s leases do not provide an implicit rate, the incremental borrowing rate at

commencement of the lease is used in determining the present value of future lease payments. Lease

expense is recognized on a straight-line basis over the lease term and is recorded as “Operating,

maintenance and general” on the Consolidated Statements of Income.

Where the Company is the lessor, a lease is a sales-type lease if certain criteria are met and the

arrangement transfers control of the underlying asset to the lessee. For arrangements where the criteria

are met due to the presence of a third-party residual value guarantee, the lease is a direct financing

lease. 

For direct finance leases, a net investment in the lease is recorded that consists of the sum of the

minimum lease payments and residual value, net of estimated executory costs and unearned income.

The difference between the gross investment and the cost of the leased item is recorded as unearned

income at the inception of the lease. Unearned income is recognized in income over the life of the lease

using a constant rate of interest equal to the internal rate of return on the lease. 

For sales-type leases, the accounting is similar to the accounting for direct finance leases however, the

difference between the FV and the carrying value of the leased item is recorded at lease commencement

rather than deferred over the term of the lease. 

Emera has certain contractual agreements that include lease and non-lease components, which

management has elected to account for as a single lease component.

Cash, Cash Equivalents and Restricted Cash

Cash equivalents consist of highly liquid short-term investments with original maturities of three months or

less at acquisition.

Receivables and Allowance for Credit Losses

Utility customer receivables are recorded at the invoiced amount and do not bear interest. Standard

payment terms for electricity and gas sales are approximately 30 days. A late payment fee may be

assessed on account balances after the due date. The Company recognizes allowances for credit losses

to reduce accounts receivable for amounts expected to be uncollectable. Management estimates credit

losses related to accounts receivable by considering historical loss experience, customer deposits,

current events, the characteristics of existing accounts and reasonable and supportable forecasts that

affect the collectability of the reported amount. Provisions for credit losses on receivables are expensed

to maintain the allowance at a level considered adequate to cover expected losses. Receivables are

written off against the allowance when they are deemed uncollectible.

Inventory

Fuel and materials inventories are valued at the lower of weighted-average cost or net realizable value,

unless evidence indicates the weighted-average cost will be recovered in future customer rates.

Asset Impairment

Long-Lived Assets:

Emera assesses whether there has been an impairment of long-lived assets and intangibles when a

triggering event occurs, such as a significant market disruption or sale of a business. 

The assessment involves comparing undiscounted expected future cash flows to the carrying value of the

asset. When the undiscounted cash flow analysis indicates a long-lived asset is not recoverable, the

amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-

lived asset over its estimated FV. The Company’s assumptions relating to future results of operations or

other recoverable amounts, are based on a combination of historical experience, fundamental economic

analysis, observable market activity and independent market studies. The Company’s expectations

regarding uses and holding periods of assets are based on internal long-term budgets and projections,

which consider external factors and market forces, as of the end of each reporting period. The

assumptions made are consistent with generally accepted industry approaches and assumptions used for

valuation and pricing activities.

As at December 31, 2023, there are no indications of impairment of Emera’s long-lived assets.

No

impairment charges related to long-lived assets were recognized in 2023 or 2022. 

Equity Method Investments:

The carrying value of investments accounted for under the equity method are assessed for impairment by

comparing the FV of these investments to their carrying values, if a FV assessment was completed, or by

reviewing for the presence of impairment indicators. If an impairment exists, and it is determined to be

other-than-temporary, a charge is recognized in earnings equal to the amount the carrying value exceeds

the investment’s FV.

No

 impairment of equity method investments was required in either 2023 or 2022.

Financial Assets:

Equity investments, other than those accounted for under the equity method, are measured at FV, with

changes in FV recognized in the Consolidated Statements of Income. Equity investments that do not

have readily determinable FV are recorded at cost minus impairment, if any, plus or minus changes

resulting from observable price changes in orderly transactions for the identical or similar investments.

No

impairment of financial assets was required in either 2023 or 2022.

Asset Retirement Obligations

An ARO is recognized if a legal obligation exists in connection with the future disposal or removal costs

resulting from the permanent retirement, abandonment or sale of a long-lived asset. A legal obligation

may exist under an existing or enacted law or statute, written or oral contract, or by legal construction

under the doctrine of promissory estoppel.

An ARO represents the FV of estimated cash flows necessary to discharge the future obligation, using

the Company’s credit adjusted risk-free rate. The amounts are reduced by actual expenditures incurred.

Estimated future cash flows are based on completed depreciation studies, remediation reports, prior

experience, estimated useful lives, and governmental regulatory requirements. The present value of the

liability is recorded and the carrying amount of the related long-lived asset is correspondingly increased.

The amount capitalized at inception is depreciated in the same manner as the related long-lived asset.

Over time, the liability is accreted to its estimated future value. AROs are included in “Other long-term

liabilities” and accretion expense is included as part of “Depreciation and amortization”. Any regulated

accretion expense not yet approved by the regulator is recorded in “Property, plant and equipment” and

included in the next depreciation study.

Some of the Company’s transmission and distribution assets may have conditional AROs that are not

recognized in the consolidated financial statements, as the FV of these obligations could not be

reasonably estimated, given insufficient information to do so. A conditional ARO refers to a legal

obligation to perform an asset retirement activity in which the timing and/or method of settlement are

conditional on a future event that may or may not be within the control of the entity. Management

monitors these obligations and a liability is recognized at FV in the period in which an amount can be

determined.

Cost of Removal (“COR”)

TEC, PGS, NMGC and NSPI recognize non-ARO COR as regulatory liabilities. The non-ARO COR

represent funds received from customers through depreciation rates to cover estimated future non-legally

required COR of PP&E upon retirement. The companies accrue for COR over the life of the related

assets based on depreciation studies approved by their respective regulators. The costs are estimated

based on historical experience and future expectations, including expected timing and estimated future

cash outlays.

Stock-Based Compensation

The Company has several stock-based compensation plans: a common share option plan for senior

management; an employee common share purchase plan; a deferred share unit (“DSU”) plan; a

performance share unit (“PSU”) plan; and a restricted share unit (“RSU”) plan. The Company accounts for

its plans in accordance with the FV-based method of accounting for stock-based compensation. Stock-

based compensation cost is measured at the grant date, based on the calculated FV of the award, and is

recognized as an expense over the employee’s or director’s requisite service period using the graded

vesting method. Stock-based compensation plans recognized as liabilities are initially measured at FV

and re-measured at FV at each reporting date, with the change in liability recognized in income.

Employee Benefits

The costs of the Company’s pension and other post-retirement benefit programs for employees are

expensed over the periods during which employees render service. The Company recognizes the funded

status of its defined-benefit and other post-retirement plans on the balance sheet and recognizes

changes in funded status in the year the change occurs. The Company recognizes unamortized gains

and losses and past service costs in “AOCI” or “Regulatory assets” on the Consolidated Balance Sheets.

The components of net periodic benefit cost other than the service cost component are included in “Other

income, net” on the Consolidated Statements of Income. For further detail, refer to note 21.

XML

Future Accounting Pronouncements

12 Months Ended

Dec. 31, 2023

Future Accounting Pronouncements [Abstract]

Future Accounting Pronouncements

2. FUTURE ACCOUNTING PRONOUNCEMENTS

The Company considers the applicability and impact of all ASUs issued by the Financial Accounting

Standards Board (“FASB”). The following updates have been issued by the FASB, but as allowed, have

not yet been adopted by Emera. Any ASUs not included below were assessed and determined to be

either not applicable to the Company or to have an insignificant impact on the consolidated financial

statements.

Improvements to Income Tax Disclosures

In December 2023, the FASB issued ASU 2023-09, Income Taxes (Topic 740): Improvements to Income

Tax Disclosures. The standard enhances the transparency, decision usefulness and effectiveness of

income tax disclosures by requiring consistent categories and greater disaggregation of information in the

reconciliation of income taxes computed using the enacted statutory income tax rate to the actual income

tax provision and effective income tax rate, as well as the disaggregation of income taxes paid (refunded)

by jurisdiction. The standard also requires disclosure of income (loss) before provision for income taxes

and income tax expense (recovery) in accordance with U.S. Securities and Exchange Commission

Regulation S-X 210.4-08(h), Rules of General Application – General Notes to Financial Statements:

Income Tax Expense, and the removal of disclosures no longer considered cost beneficial or relevant.

The guidance will be effective for annual reporting periods beginning after December 15, 2024, and

interim periods within annual reporting periods beginning after December 15, 2025. Early adoption is

permitted. The standard will be applied on a prospective basis, with retrospective application permitted.

The Company is currently evaluating the impact of adoption of the standard on its consolidated financial

statements.

Improvements to Reportable Segment Disclosures

In November 2023, the FASB issued ASU 2023-07, Segment Reporting (Topic 280), Improvements to

Reportable Segment Disclosures. The change in the standard improves reportable segment disclosure

requirements, primarily through enhanced disclosures about significant segment expenses. The changes

improve financial reporting by requiring disclosure of incremental segment information on an annual and

interim basis for all public entities to enable investors to develop more decision-useful financial analyses.

The guidance will be effective for annual reporting periods beginning after December 15, 2023, and for

interim periods beginning after December 15, 2024. Early adoption is permitted. The standard will be

applied retrospectively. The Company is currently evaluating the impact of adoption of the standard on its

consolidated financial statements.

XML

Dispositions

12 Months Ended

Dec. 31, 2023

Dispositions [Abstract]

Dispositions

3.

DISPOSITIONS

On March 31, 2022, Emera completed the sale of its

51.9

 per cent interest in Domlec for proceeds which

approximated its carrying value. Domlec was included in the Company’s Other Electric reportable

segment up to its date of sale. The sale did not have a material impact on earnings.

XML

Segment Information

12 Months Ended

Dec. 31, 2023

Segment Information [Abstract]

Segment Information

4. SEGMENT INFORMATION

Emera manages its reportable segments separately due in part to their different operating, regulatory and

geographical environments. Segments are reported based on each subsidiary’s contribution of revenues,

net income attributable to common shareholders and total assets, as reported to the Company’s chief

operating decision maker.

Florida 

Canadian

Gas Utilities

Other

Inter-

Electric

Electric

and

Electric

Segment

millions of dollars

Utility

Utilities

Infrastructure

Utilities

Other

Eliminations

Total

For the year ended December 31, 2023 

Operating revenues from

external customers (1)

$

3,548

$

1,671

$

1,510

$

526

$

308

$

 - 

$

7,563

Inter-segment revenues

(1)

8

-

14

-

31

(53)

 - 

 Total operating revenues

3,556

1,671

1,524

526

339

(53)

7,563

Regulated fuel for generation

and purchased power

920

699

-

275

-

(13)

1,881

Regulated cost of natural gas

-

-

527

-

-

-

527

OM&G

830

384

405

130

151

(21)

1,879

Provincial, state and municipal

taxes

289

45

91

3

5

-

433

Depreciation and amortization

571

276

126

68

8

-

1,049

Income from equity

investments

-

109

21

4

12

-

146

Other income, net

69

32

11

7

20

19

158

Interest expense, net

(2)

271

170

129

23

332

-

925

Income tax expense

(recovery)

117

(9)

64

-

(44)

-

128

Non-controlling interest in

subsidiaries

-

-

-

1

-

-

1

Preferred stock dividends

-

-

-

-

66

-

66

Net income (loss) attributable

to common shareholders

$

627

$

247

$

214

$

37

$

(147)

$

-

$

978

Capital expenditures

$

1,736

$

450

$

664

$

63

$

8

$

-

$

2,921

As at December 31, 2023

Total assets

$

21,119

$

8,634

$

7,735

$

1,311

$

1,938

$

(1,257)

$

39,480

Investments subject to

significant influence

$

-

$

1,236

$

118

$

48

$

-

$

-

$

1,402

Goodwill

$

4,628

$

-

$

1,240

$

-

$

3

$

-

$

5,871

(1) All significant inter-company balances and transactions have been eliminated on consolidation except for certain transactions

between non-regulated and regulated entities. Management believes elimination of these transactions would understate PP&E,

OM&G, or regulated fuel for generation and purchased power. Inter-company transactions that have not been eliminated are

measured at the amount of consideration established and agreed to by the related parties. Eliminated transactions are included in

determining reportable segments.

(2) Segment net income is reported on a basis that includes internally allocated financing costs of $

95

 million for the year ended

December 31, 2023, between the Florida Electric Utility, Gas Utilities and Infrastructure and Other segments.

Florida 

Canadian

Gas Utilities

Other

Inter-

Electric

Electric

and

Electric

Segment

millions of dollars

Utility

Utilities

Infrastructure

Utilities

Other

Eliminations

Total

For the year ended December 31, 2022 

Operating revenues from

external customers

(1)

$

3,280

$

1,675

$

1,697

$

518

$

418

$

 - 

$

7,588

Inter-segment revenues

(1)

7

-

7

-

22

(36)

 - 

 Total operating revenues

3,287

1,675

1,704

518

440

(36)

7,588

Regulated fuel for generation

and purchased power

1,086

803

-

290

-

(8)

2,171

Regulated cost of natural gas

-

-

800

-

-

-

800

OM&G

625

338

365

123

156

(11)

1,596

Provincial, state and municipal

taxes

235

43

83

3

3

-

367

Depreciation and amortization

507

259

118

61

7

-

952

Income from equity

investments

-

87

21

4

17

-

129

Other income (expenses), net

68

24

13

-

23

17

145

Interest expense, net

(2)

185

136

81

19

288

-

709

GBPC impairment charge

-

-

-

73

-

-

73

Income tax expense (recovery)

121

(8)

70

-

2

-

185

Non-controlling interest in

subsidiaries

-

-

-

1

-

-

1

Preferred stock dividends

-

-

-

-

63

-

63

Net income (loss) attributable

to common shareholders

$

596

$

215

$

221

$

(48)

$

(39)

$

-

$

945

Capital expenditures

$

1,425

$

507

$

574

$

63

$

6

$

-

$

2,575

As at December 31, 2022

Total assets

$

21,053

$

8,223

$

7,737

$

1,337

$

2,835

$

(1,443)

$

39,742

Investments subject to

significant influence

$

-

$

1,241

$

128

$

49

$

-

$

-

$

1,418

Goodwill

$

4,739

$

-

$

1,270

$

-

$

3

$

-

$

6,012

(1) All significant inter-company balances and transactions have been eliminated on consolidation except for certain transactions

between non-regulated and regulated entities. Management believes elimination of these transactions would understate PP&E,

OM&G, or regulated fuel for generation and purchased power. Inter-company transactions that have not been eliminated are

measured at the amount of consideration established and agreed to by the related parties. Eliminated transactions are included in

determining reportable segments.

(2) Segment net income is reported on a basis that includes internally allocated financing costs of $

13

 million for the year ended

December 31, 2022, between the Gas Utilities and Infrastructure and Other segments.

Geographical Information

Revenues (based on country of origin of the product or service sold)

For the

Year ended December 31

millions of dollars

2023

2022

United States

5,310

$

5,346

Canada

1,727

1,725

Barbados

389

384

The Bahamas

137

122

Dominica

-

11

$

7,563

$

7,588

Property Plant and Equipment:

As at 

December 31

December 31

millions of dollars

2023

2022

United States

$

18,588

$

17,382

Canada

4,878

4,689

Barbados

576

583

The Bahamas

334

342

$

24,376

$

22,996

XML

Revenue

12 Months Ended

Dec. 31, 2023

Revenue [Abstract]

Revenue

5. REVENUE

The following disaggregates the Company’s revenue by major source:

Electric

Gas

Other

Florida

Canadian

Other 

Gas Utilities

Inter-

Electric

Electric

Electric

and 

Segment

millions of dollars

Utility

Utilities

Utilities

Infrastructure

Other

Eliminations

Total

For the year ended December 31, 2023 

Regulated Revenue

Residential

$

2,307

$

910

$

183

$

724

$

-

$

-

$

4,124

Commercial

1,083

463

285

425

-

-

2,256

Industrial

274

219

33

93

-

(13)

606

Other electric

395

41

7

-

-

-

443

Regulatory deferrals

(522)

-

12

-

-

-

(510)

Other (1) 

19

38

6

199

-

(8)

254

Finance income (2)(3)

-

-

-

62

-

62

 Regulated revenue

$

3,556

$

1,671

$

526

$

1,503

$

-

$

(21)

$

7,235

Non-Regulated Revenue

Marketing and trading margin (4)

-

-

-

-

96

-

96

Other non-regulated operating

revenue

-

-

-

21

27

(23)

25

Mark-to-market (3)

-

-

-

-

216

(9)

207

 Non-regulated revenue

$

-

$

-

$

-

$

21

$

339

$

(32)

$

328

Total operating revenues

$

3,556

$

1,671

$

526

$

1,524

$

339

$

(53)

$

7,563

For the year ended December 31, 2022 

Regulated Revenue

Residential

$

1,799

$

834

$

184

$

800

$

-

$

-

$

3,617

Commercial

869

427

282

461

-

-

2,039

Industrial

230

353

32

83

-

(7)

691

Other electric

398

28

6

-

-

-

432

Regulatory deferrals

(27)

-

6

-

-

-

(21)

Other (1) 

18

33

8

283

-

(7)

335

Finance income (2)(3)

-

-

-

61

-

-

61

 Regulated revenue

$

3,287

$

1,675

$

518

$

1,688

$

-

$

(14)

7,154

Non-Regulated 

Marketing and trading margin (4)

-

-

-

-

143

-

143

Other non-regulated operating

revenue

-

-

-

16

16

(10)

22

Mark-to-market (3)

-

-

-

-

281

(12)

269

 Non-regulated revenue

$

-

$

-

$

-

$

16

$

440

$

(22)

434

Total operating revenues

$

3,287

$

1,675

$

518

$

1,704

$

440

$

(36)

$

7,588

(1) Other includes rental revenues, which do not represent revenue from contracts with customers.

(2) Revenue related to Brunswick Pipeline's service agreement with Repsol Energy Canada.

(3) Revenue which does not represent revenues from contracts with customers.

(4) Includes gains (losses) on settlement of energy related derivatives, which do not represent revenue from contracts with

customers.

Remaining Performance Obligations:

Remaining performance obligations primarily represent gas transportation contracts, lighting contracts,

and long-term steam supply arrangements with fixed contract terms. As of December 31, 2023, the

aggregate amount of the transaction price allocated to remaining performance obligations was $

488

million (2022 – $

450

 million). This amount includes $

134

 million of future performance obligations related

to a gas transportation contract between SeaCoast and PGS through

2040

. This amount excludes

contracts with an original expected length of one year or less and variable amounts for which Emera

recognizes revenue at the amount to which it has the right to invoice for services performed. Emera

expects to recognize revenue for the remaining performance obligations through

2043

.

XML

Regulatory Assets and Liabilities

12 Months Ended

Dec. 31, 2023

Regulatory Assets and Liabilities [Abstract]

Regulatory Assets and Liabilities

6. REGULATORY ASSETS AND LIABILITIES

Regulatory assets represent prudently incurred costs that have been deferred because it is probable they

will be recovered through future rates or tolls collected from customers. Management believes existing

regulatory assets are probable for recovery either because the Company received specific approval from

the applicable regulator, or due to regulatory precedent established for similar circumstances. If

management no longer considers it probable that an asset will be recovered, deferred costs are charged

to income. 

Regulatory liabilities represent obligations to make refunds to customers or to reduce future revenues for

previous collections. If management no longer considers it probable that a liability will be settled, the

related amount is recognized in income.

For regulatory assets and liabilities that are amortized, the amortization is as approved by the respective

regulator.

As at

December 31

December 31

millions of dollars 

2023

2022

Regulatory assets

Deferred income tax regulatory assets

$

1,233

$

1,166

TEC capital cost recovery for early retired assets 

671

674

NSPI FAM

395

307

Pension and post-retirement medical plan

364

369

Cost recovery clauses

151

707

Deferrals related to derivative instruments

88

30

Storm cost recovery clauses 

52

138

Environmental remediations

26

27

Stranded cost recovery

25

27

NMGC winter event gas cost recovery

-

69

Other

100

106

$

3,105

$

3,620

Current

$

339

$

602

Long-term

2,766

3,018

Total regulatory assets 

$

3,105

$

3,620

Regulatory liabilities

Accumulated reserve – COR

849

895

Deferred income tax regulatory liabilities

830

877

Cost recovery clauses 

32

70

BLPC Self-insurance fund ("SIF") (note 32)

29

30

Deferrals related to derivative instruments

17

230

NMGC gas hedge settlements (note 18)

-

162

Other

15

9

$

1,772

$

2,273

Current

$

168

$

495

Long-term

1,604

1,778

Total regulatory liabilities

$

1,772

$

2,273

Deferred Income Tax Regulatory Assets and Liabilities

To the extent deferred income taxes are expected to be recovered from or returned to customers in future

years, a regulatory asset or liability is recognized as appropriate. 

TEC Capital Cost Recovery for Early Retired Assets

This regulatory asset is related to the remaining net book value of Big Bend Power Station Units 1

through 3 and smart meter assets that were retired. The balance earns a rate of return as permitted by

the FPSC and is recovered as a separate line item on customer bills for a period of

15 years

. This

recovery mechanism is authorized by and survives the term of the settlement agreement approved by the

FPSC in 2021. For further information, refer to “Big Bend Modernization Project” in the TEC section

below.

NSPI FAM

NSPI has a FAM, approved by the UARB, allowing NSPI to recover fluctuating fuel and certain fuel-

related costs from customers through regularly scheduled fuel rate adjustments. Differences between

prudently incurred fuel costs and amounts recovered from customers through electricity rates in a year

are deferred to a FAM regulatory asset or liability and recovered from or returned to customers in

subsequent periods. 

Pension and Post-Retirement Medical Plan 

This asset is primarily related to the deferred costs of pension and post-retirement benefits at TEC, PGS

and NMGC. It is included in rate base and earns a rate of return as permitted by the FPSC and NMPRC,

as applicable. It is amortized over the remaining service life of plan participants.

Cost Recovery Clauses 

These assets and liabilities are related to TEC, PGS and NMGC clauses and riders. They are recovered

or refunded through cost-recovery mechanisms approved by the FPSC or New Mexico Public Regulation

Commission (“NMPRC”), as applicable, on a dollar-for-dollar basis in a subsequent period.

Deferrals Related to Derivative Instruments

This asset is primarily related to NSPI deferring changes in FV of derivatives that are documented as

economic hedges or that do not qualify for NPNS exemption, as a regulatory asset or liability as approved

by the UARB. The realized gain or loss is recognized when the hedged item settles in regulated fuel for

generation and purchased power, other income, inventory, or OM&G, depending on the nature of the item

being economically hedged.

Storm Cost Recovery Clauses

TEC and PGS Storm Reserve:

The storm reserve is for hurricanes and other named storms that cause significant damage to TEC and

PGS systems. As allowed by the FPSC, if charges to the storm reserve exceed the storm liability, the

excess is to be carried as a regulatory asset. TEC and PGS can petition the FPSC to seek recovery of

restoration costs over a 12-month period or longer, as determined by the FPSC, as well as replenish the

reserve. In 2022, TEC and PGS were impacted by Hurricane Ian. For further information, refer to “TEC

Storm Reserve” in the Florida Electric Utility section below.

NSPI Storm Rider:

NSPI has a UARB approved storm rider for each of 2023, 2024 and 2025, which gives NSPI the option to

apply to the UARB for recovery of costs if major storm restoration expenses exceed approximately $

10

million in a given year. 

GBPC Storm Restoration:

This asset represents storm restoration costs incurred by GBPC. GBPC maintains insurance for its

generation facilities and, as with most utilities, its transmission and distribution networks are not covered

by commercial insurance. 

In January 2020, the Grand Bahama Port Authority (“GBPA”) approved recovery of $

15

 million USD of

2019 costs related to Hurricane Dorian, over a five-year period from 2021 through 2025.

Restoration costs associated with Hurricane Matthew in 2016 are being recovered through an approved

fuel charge. For further information, refer to “Storm Restoration Costs – Hurricane Matthew” in the GBPC

section below.

Environmental Remediations

This asset is primarily related to PGS costs associated with environmental remediation at Manufactured

Gas Plant sites. The balance is included in rate base, partially offsetting the related liability, and earns a

rate of return as permitted by the FPSC. The timing of recovery is based on a settlement agreement

approved by the FPSC.

Stranded Cost Recovery

Due to decommissioning of a GBPC steam turbine in 2012, the GBPA approved recovery of a $

21

 million

USD stranded cost through electricity rates; it is included in rate base and expected to be included in

rates in future years. 

NMGC Winter Event Gas Cost Recovery

In February 2021, the State of New Mexico experienced an extreme cold weather event that resulted in

an incremental $

108

 million USD for gas costs above what it would normally have paid during this period.

NMGC normally recovers gas supply and related costs through a purchased gas adjustment clause

(“PGAC”). On June 15, 2021, the NMPRC approved recovery of $

108

 million USD and related borrowing

costs in customer rates over a period of

30 months

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

Accumulated Reserve – COR

This regulatory liability represents the non-ARO COR reserve in TEC, PGS, NMGC and NSPI. AROs

represent the FV of estimated cash flows associated with the Company’s legal obligation to retire its

PP&E. Non-ARO COR represent estimated funds received from customers through depreciation rates to

cover future COR of PP&E value upon retirement that are not legally required. This reduces rate base for

ratemaking purposes. This liability is reduced as COR are incurred and increased as depreciation is

recorded for existing assets and as new assets are put into service.

NMGC Gas Hedge Settlements

This regulatory liability represents regulatory deferral of gas options exercised above strike price but

settled subsequent to the period end. The value from cash settlement of these options flows to customers

via the PGAC.

Other Regulatory Assets and Liabilities

Comprised of regulatory assets and liabilities that are not individually significant.

Regulatory Environments and Updates

Florida Electric Utility

TEC is regulated by the FPSC and is also subject to regulation by the Federal Energy Regulatory

Commission. The FPSC sets rates at a level that allows utilities such as TEC to collect total revenues or

revenue requirements equal to their cost of providing service, plus an appropriate return on invested

capital. Base rates are determined in FPSC rate setting hearings which can occur at the initiative of TEC,

the FPSC or other interested parties.

TEC’s approved regulated return on equity (“ROE”) range for 2023 and 2022 was

9.25

 per cent to

11.25

per cent based on an allowed equity capital structure of

54

 per cent. An ROE of

10.20

 per cent (2022 –

10.20

 per cent) is used for the calculation of the return on investments for clauses.

Base Rates:

On February 1, 2024, TEC notified the FPSC of its intent to seek a base rate increase effective January

2025, reflecting a revenue requirement increase of approximately $

290

 to $

320

 million USD and

additional adjustments of approximately $

100

 million USD and $

70

 million USD for 2026 and 2027,

respectively. TEC’s proposed rates include recovery of solar generation projects, energy storage

capacity, a more resilient and modernized energy control center, and numerous other resiliency and

reliability projects. The filing range amounts are estimates until TEC files its detailed case in April 2024.

The FPSC is scheduled to hear the case in Q3 2024.

On August 16, 2023, TEC filed a petition to implement the 2024 Generation Base Rate Adjustment

provisions pursuant to the 2021 rate case settlement agreement. Inclusive of TEC’s ROE adjustment, the

increase of $

22

 million USD was approved by the FPSC on November 17, 2023.

Fuel Recovery and Other Cost Recovery Clauses:

TEC has a fuel recovery clause approved by the FPSC, allowing the opportunity to recover fluctuating

fuel expenses from customers through annual fuel rate adjustments. The FPSC annually approves cost-

recovery rates for purchased power, capacity, environmental and conservation costs, including a return

on capital invested. Differences between prudently incurred fuel costs and the cost-recovery rates and

amounts recovered from customers through electricity rates in a year are deferred to a regulatory asset or

liability and recovered from or returned to customers in subsequent periods. 

On January 23, 2023, TEC requested an adjustment to its fuel charges to recover the 2022 fuel under-

recovery of $

518

 million USD over a period of

21 months

. The request also included an adjustment to

2023 projected fuel costs to reflect the reduction in natural gas prices since September 2022 for a

projected reduction of $

170

 million USD for the balance of 2023. The changes were approved by the

FPSC on March 7, 2023, and were effective beginning on April 1, 2023.

The mid-course fuel adjustment requested by TEC on January 19, 2022, was approved on March 1,

2022. The rate increase, effective with the first billing cycle in April 2022, covered higher fuel and capacity

costs of $

169

 million USD, and was spread over customer bills from April 1, 2022 through December

2022.

Big Bend Modernization Project:

TEC invested $

876

 million USD, including $

91

 million USD of AFUDC, between 2018 and 2022 to

modernize the Big Bend Power Station. The modernization project repowered Big Bend Unit 1 with

natural gas combined-cycle technology and eliminated coal as this unit’s fuel. As part of the

modernization project, TEC in 2020 retired the Unit 1 components that would not be used in the

modernized plant and did the same for Big Bend Unit 2 in 2021. TEC retired Big Bend Unit 3 in 2023 as it

was in the best interests of the customers from an economic, environmental risk and operational

perspective. On December 31, 2021, the remaining costs of the retired Big Bend coal generation assets,

Units 1 through 3, of $

636

 million USD and $

267

 million USD in accumulated depreciation were

reclassified to a regulatory asset on the balance sheet.

TEC’s 2021 settlement agreement provides for cost recovery of the Big Bend Modernization project in two

phases. The first phase was a revenue increase to cover the costs of the assets in service during 2022,

among other items. The remainder of the project costs were recovered as part of the 2023 subsequent

year adjustment. The settlement agreement also includes a new charge to recover the remaining costs of

the retired Big Bend coal generation assets, Units 1 through 3, which are spread over

15 years

, effective

January 1, 2022. This recovery mechanism was authorized by and survives the term of the settlement

agreement approved by the FPSC in 2021.

Storm Reserve:

In September 2022, TEC was impacted by Hurricane Ian, with $

119

 million USD of restoration costs

charged against TEC’s FPSC approved storm reserve. Total restoration costs charged to the storm

reserve exceeded the reserve balance and have been deferred as a regulatory asset for future recovery. 

On January 23, 2023, TEC petitioned the FPSC for recovery of the storm reserve regulatory asset and

the replenishment of the balance in the storm reserve to the approved storm reserve level of $

56

 million

USD, for a total of $

131

 million USD. The storm cost recovery surcharge was approved by the FPSC on

March 7, 2023, and TEC began applying the surcharge in April 2023. Subsequently, on November 9,

2023, the FPSC approved TEC’s petition, filed on August 16, 2023, to update the total storm cost

collection to $

134

 million USD. It also changed the collection of the expected remaining balance of $

29

million USD as of December 31, 2023, from over the first three months of 2024 to over the 12 months of

2024. The storm recovery is subject to review of the underlying costs for prudency and accuracy by the

FPSC.

In Q3 2023, TEC was impacted by Hurricane Idalia. The related storm restoration costs were

approximately $

35

 million USD, which were charged to the storm reserve regulatory asset, resulting in

minimal impact to earnings.

Storm Protection Cost Recovery Clause and Settlement Agreement:

The Storm Protection Plan (“SPP”) Cost Recovery Clause provides a process for Florida investor-owned

utilities, including TEC, to recover transmission and distribution storm hardening costs for incremental

activities not already included in base rates. Differences between prudently incurred clause-recoverable

costs and amounts recovered from customers through electricity rates in a year are deferred and

recovered from or returned to customers in a subsequent year. A settlement agreement was approved on

August 10, 2020, and TEC’s cost recovery began in January 2021. The current approved plan addressed

the years 2023, 2024 and 2025 and was approved by the FPSC on October 4, 2022.

Canadian Electric Utilities

NSPI

NSPI is a public utility as defined in the Public Utilities Act of Nova Scotia (“Public Utilities Act”) and is

subject to regulation under the Public Utilities Act by the UARB. The Public Utilities Act gives the UARB

supervisory powers over NSPI’s operations and expenditures. Electricity rates for NSPI’s customers are

also subject to UARB approval. NSPI is not subject to a general annual rate review process, but rather

participates in hearings held from time to time at NSPI’s or the UARB’s request.

NSPI is regulated under a cost-of-service model, with rates set to recover prudently incurred costs of

providing electricity service to customers and provide a reasonable return to investors. NSPI’s approved

regulated ROE range for 2023 and 2022 was

8.75

 per cent to

9.25

 per cent based on an actual five

quarter average regulated common equity component of up to

40

 per cent of approved rate base.

General Rate Application (“GRA”):

On February 2, 2023, the UARB approved the GRA settlement agreement between NSPI, key customer

representatives and participating interest groups. This resulted in average customer rate increases of

6.9

per cent effective on February 2, 2023, and further average increases of

6.5

 per cent on January 1, 2024,

with any under or over-recovery of fuel costs addressed through the UARB’s established FAM process. It

also established a storm rider and a demand-side management rider. On March 27, 2023, the UARB

issued a final order approving the electricity rates effective on February 2, 2023.

Fuel Recovery:

For the period of 2020 through 2022, NSPI operated under a three-year fuel stability plan with no fuel rate

adjustments related to the under-recovery of fuel and fuel-related costs in the period. 

On January 29, 2024, NSPI applied to the UARB for approval of a structure that would begin to recover

the outstanding FAM balance. As part of the application, NSPI requested approval for the sale of $

117

million of the FAM regulatory asset to Invest Nova Scotia, a provincial Crown corporation, with the

proceeds paid to NSPI upon approval. NSPI has requested approval to collect from customers the

amortization and financing costs of $

117

 million on behalf of Invest Nova Scotia over a

10

-year period,

and remit those amounts to Invest Nova Scotia as collected, reducing short-term customer rate increases

relative to the currently established FAM process. If approved, this portion of the FAM regulatory asset

would be removed from the Consolidated Balance Sheets and NSPI would collect the balance on behalf

of Invest Nova Scotia in NSPI rates beginning in 2024. 

Storm Rider:

The storm rider was effective as of the GRA decision date. The application for deferral and recovery of

the storm rider is made in the year following the year of the incurred cost, with recovery beginning in the

year after the application. Total major storm restoration expense for 2023 was $

31

 million, of which $

21

million was deferred to the storm rider.

Hurricane Fiona:

On October 31, 2023, NSPI submitted an application to the UARB to defer $

24

 million in incremental

operating costs incurred during Hurricane Fiona storm restoration efforts in September 2022. NSPI is

seeking amortization of the costs over a period to be approved by the UARB during a future rate setting

process. At December 31, 2023, the $

24

 million is deferred to “Other long-term assets”, pending UARB

approval. 

Maritime Link:

The Maritime Link is a $

1.8

 billion (including AFUDC) transmission project including

two

170

-kilometre

sub-sea cables, connecting the island of Newfoundland and Nova Scotia. The Maritime Link entered

service on January 15, 2018 and NSPI started interim assessment payments to NSPML at that time. 

Any difference between the amounts recovered from customers through rates and those approved by the

UARB through the NSPML interim assessment application will be addressed through the FAM. 

Nova Scotia Cap-and-Trade (“Cap-and-Trade”) Program:

As of December 31, 2022, the FAM included a cumulative $

166

 million in fuel costs related to the accrued

purchase of emissions credits and $

6

 million related to credits purchased from provincial auctions. On

March 16, 2023, the Province of Nova Scotia provided NSPI with emissions allowances sufficient to

achieve compliance for the 2019 through 2022 period. As such, compliance costs accrued of $

166

 million

were reversed in Q1 2023. The credits NSPI purchased from provincial auctions in the amount of $

6

million were not refunded and no further costs were incurred to achieve compliance with the Cap-and-

Trade Program.

Extra Large Industrial Active Demand Tariff:

On July 5, 2023, NSPI received approval from the UARB to change the methodology in which fuel cost

recovery from an industrial customer is calculated. Due to significant volatility in commodity prices in

2022, the previous methodology did not result in a reasonable determination of the fuel cost to serve this

customer. The change in methodology, effective January 1, 2022, results in a shifting of fuel costs from

this industrial customer to the FAM. This adjustment was recorded in Q2 2023 resulting in a $

51

 million

increase to the FAM regulatory asset and an offsetting decrease to unbilled revenue within Receivables

and other current assets. This adjustment had minimal impact on earnings.

NSPML

Equity earnings from the Maritime Link are dependent on the approved ROE and operational

performance of NSPML. NSPML’s approved regulated ROE range is

8.75

 per cent to

9.25

 per cent,

based on an actual five-quarter average regulated common equity component of up to

30

 per cent. 

Nalcor’s Nova Scotia Block (“NS Block”) delivery obligations commenced on August 15, 2021 and

delivery will continue over the next

35 years

 pursuant to the agreements. 

In February 2022, the UARB issued its decision and Board Order approving NSPML’s requested rate

base of approximately $

1.8

 billion less $

9

 million of costs ($

7

 million after-tax) that would not have

otherwise been recoverable if incurred by NSPI.

On October 4, 2023 and January 31, 2024, the UARB issued decisions providing clarification on

remaining aspects of the Maritime Link holdback mechanism primarily relating to release of past and

future holdback amounts and requirements to end the holdback mechanism. In these decisions, the

UARB agreed with the Company’s submission that $

12

 million ($

8

 million related to 2022 and $

4

 million

relating to 2023) of the previously recorded holdback remain credited to NSPI’s FAM, with the remainder

released to NSPML and recorded in Emera’s “Income from equity investments. NSPML did not record

any additional holdback in Q4 2023. The UARB also confirmed that the holdback mechanism will cease

once

90

 per cent of NS Block deliveries are achieved for 12 consecutive months (subject to potential

relief for planned outages or exceptional circumstances) and the net outstanding balance of previously

underdelivered NS Block energy is less than

10

 per cent of the contracted annual amount. In addition, the

UARB increased the monthly holdback amount from $

2

 million to $

4

 million beginning December 1, 2023. 

On December 21, 2023, NSPML received approval to collect up to $

164

 million (2023 – $

164

 million)

from NSPI for the recovery of costs associated with the Maritime Link in 2024; subject to a holdback of up

to $

4

 million a month, as discussed above.

Gas Utilities and Infrastructure

PGS

PGS is regulated by the FPSC. The FPSC sets rates at a level that allows utilities such as PGS to collect

total revenues or revenue requirements equal to their cost of providing service, plus an appropriate return

on invested capital.

PGS’s approved ROE range for 2023 and 2022 was

8.9

 per cent to

11.0

 per cent with a

9.9

 per cent

midpoint, based on an allowed equity capital structure of

54.7

 per cent. 

Base Rates:

On April 4, 2023, PGS filed a rate case with the FPSC and a hearing for the matter was held in

September 2023. On November 9, 2023, the FPSC approved a $

118

 million USD increase to base

revenues which includes $

11

 million USD transferred from the cast iron and bare steel replacement rider,

for a net incremental increase to base revenues of $

107

 million USD. This reflects a

10.15

 per cent

midpoint ROE with an allowed equity capital structure of

54.7

 per cent.  A final order was issued on

December 27, 2023, with the new rates effective January 2024.

The 2020 PGS rate case settlement provided the ability to reverse a total of $

34

 million USD of

accumulated depreciation through 2023. PGS reversed $

20

 million USD of accumulated depreciation in

2023 and $

14

 million USD in 2022.

Fuel Recovery:

PGS recovers the costs it pays for gas supply and interstate transportation for system supply through its

PGAC. This clause is designed to recover actual costs incurred by PGS for purchased gas, gas storage

services, interstate pipeline capacity, and other related items associated with the purchase, distribution,

and sale of natural gas to its customers. These charges may be adjusted monthly based on a cap

approved annually by the FPSC.

Recovery of Energy Conservation and Pipeline Replacement Programs:

The FPSC annually approves a conservation charge that is intended to permit PGS to recover prudently

incurred expenditures in developing and implementing cost effective energy conservation programs which

are required by Florida law and approved and monitored by the FPSC. PGS also has a Cast Iron/Bare

Steel Pipe Replacement clause to recover the cost of accelerating the replacement of cast iron and bare

steel distribution lines in the PGS system. In February 2017, the FPSC approved expansion of the Cast

Iron/Bare Steel clause to allow recovery of accelerated replacement of certain obsolete plastic pipe. The

majority of cast iron and bare steel pipe has been removed from its system, with replacement of obsolete

plastic pipe continuing until 2028 under the rider. 

NMGC

NMGC is subject to regulation by the NMPRC. The NMPRC sets rates at a level that allows NMGC to

collect total revenues equal to its cost of providing service, plus an appropriate return on invested capital. 

NMGC’s approved ROE for 2023 and 2022 was

9.375

 per cent on an allowed equity capital structure of

52

 per cent.

Base Rates:

On September 14, 2023, NMGC filed a rate case with the NMPRC for new base rates to become effective

Q4 2024. NMGC requested $

49

 million USD in annual base revenues primarily as a result of increased

operating costs and capital investments in pipeline projects and related infrastructure. The rate case

includes a requested ROE of

10.5

 per cent.

Fuel Recovery:

NMGC recovers gas supply costs through a PGAC. This clause recovers actual costs for purchased gas,

gas storage services, interstate pipeline capacity, and other related items associated with the purchase,

transmission, distribution, and sale of natural gas to its customers. On a monthly basis, NMGC can adjust

charges based on the next month’s expected cost of gas and any prior month under-recovery or over-

recovery. The NMPRC requires that NMGC annually file a reconciliation of the PGAC period costs and

recoveries. NMGC must file a PGAC Continuation Filing with the NMPRC every four years to establish

that the continued use of the PGAC is reasonable and necessary. NMGC received approval of its PGAC

Continuation in December 2020, for the four-year period ending December 2024.

Integrity Management Programs (“IMP”) Regulatory Asset:

A portion of NMGC’s annual spending on infrastructure is for IMP, or the replacement and update of

legacy systems. These programs are driven both by NMGC integrity management plans and federal and

state mandates. In December 2020, NMGC received approval through its rate case to defer costs through

an IMP regulatory asset for certain of its IMP capital investments occurring between January 1, 2022 and

December 31, 2023 and petitioned recovery of the regulatory asset in its rate case filed on December 13,

2021. On November 30, 2022, the NMPRC issued a Final Order that included approval of recovery of the

IMP regulatory asset.

Brunswick Pipeline 

Brunswick Pipeline is a

145

-kilometre pipeline delivering natural gas from the Saint John LNG import

terminal near Saint John, New Brunswick to markets in the northeastern United States. Brunswick

Pipeline entered into a

25

-year firm service agreement commencing in July 2009 with Repsol Energy

North America Canada Partnership. The agreement provides for a predetermined toll increase in the fifth

and fifteenth year of the contract. The pipeline is considered a Group II pipeline regulated by the Canada

Energy Regulator (“CER”). The CER Gas Transportation Tariff is filed by Brunswick Pipeline in

compliance with the requirements of the CER Act and sets forth the terms and conditions of the

transportation rendered by Brunswick Pipeline.

Other Electric Utilities

BLPC

BLPC is regulated by the Fair Trading Commission (“FTC”), under the Utilities Regulation (Procedural)

Rules 2003. BLPC is regulated under a cost-of-service model, with rates set to recover prudently incurred

costs of providing electricity service to customers plus an appropriate return on capital invested. BLPC’s

approved regulated return on rate base was

10

 per cent for 2023 and 2022.

Licenses:

BLPC currently operates pursuant to a single integrated license to generate, transmit and distribute

electricity on the island of Barbados until 2028. In 2019, the Government of Barbados passed legislation

requiring multiple licenses for the supply of electricity. In 2021, BLPC reached commercial agreement with

the Government of Barbados for each of the license types, subject to the passage of implementing

legislation. The timing of the final enactment is unknown at this time, but BLPC will work towards the

implementation of the licenses once enacted.

Base Rates:

In 2021, BLPC submitted a general rate review application to the FTC. In September 2022, the FTC

granted BLPC interim rate relief, allowing an increase in base rates of approximately $

1

 million USD per

month. On February 15, 2023, the FTC issued a decision on the application which included the following

significant items: an allowed regulatory ROE of

11.75

 per cent, an equity capital structure of

55

 per cent,

a directive to update the major components of rate base to September 16, 2022, and a directive to

establish regulatory liabilities related to the self-insurance fund of $

50

 million USD, prior year benefits

recognized on remeasurement of deferred income taxes of $

5

 million USD, and accumulated depreciation

of $

16

 million USD. On March 7, 2023, BLPC filed a Motion for Review and Variation (the “Motion”) and

applied for a stay of the FTC’s decision, which was subsequently granted. On November 20, 2023, the

FTC issued their decision dismissing the Motion. Interim rates continue to be in effect through to a date to

be determined in a final decision and order. 

On December 1, 2023, BLPC appealed certain aspects of the FTC’s February 15 and November 20,

2023, decisions to the Supreme Court of Barbados in the High Court of Justice (the “Court”) and

requested that they be stayed. On December 11, 2023, the Court granted the stay. BLPC’s position is

that the FTC made errors of law and jurisdiction in their decisions and believes the success of the appeal

is probable, and as a result, the adjustments to BLPC’s final rates and rate base, including any

adjustments to regulatory assets and liabilities, have not been recorded at this time.

Fuel Recovery:

BLPC’s fuel costs flow through a fuel pass-through mechanism which provides opportunity to recover all

prudently incurred fuel costs from customers in a timely manner. The calculation of the fuel charge is

adjusted on a monthly basis and reported to the FTC for approval.

Clean Energy Transition Program (“CETP”):

On May 31, 2023, the FTC approved BLPC’s application to establish an alternative cost recovery

mechanism to recover prudently incurred costs associated with its CETP (the “Decision”). The

mechanism is intended to facilitate the timely recovery between rate cases of costs associated with

approved renewable energy assets. BLPC will be required to submit an individual application for the

recovery of costs of each asset through the cost recovery mechanism, meeting the minimum criteria as

set out in the Decision. On October 5, 2023, BLPC applied to the FTC to recover the costs of a battery

storage system through the CETP.

Fuel Hedging:

On October 21, 2021, the FTC approved BLPC’s application to implement a fuel hedging program which

will be incorporated into the calculation of the fuel clause adjustment. On November 10, 2021, BLPC

requested the FTC review the required

50

/50 cost sharing arrangement between BLPC and customers in

relation to the hedging administrative costs, or any gains and losses associated with the hedging

program.

GBPC

GBPC is regulated by the GBPA. The GBPA has granted GBPC a licensed, regulated and exclusive

franchise to produce, transmit and distribute electricity on the island until 2054. Rates are set to recover

prudently incurred costs of providing electricity service to customers plus an appropriate return on rate

base. GBPC’s approved regulated return on rate base was

8.32

 per cent for 2023 (2022 –

8.23

 per cent).

Base Rates:

There is a fuel pass-through mechanism and tariff review policy with new rates submitted every three

years. On January 14, 2022, the GBPA issued its decision on GBPC’s application for rate review that was

filed with the GBPA on September 23, 2021. The decision, which became effective April 1, 2022, allows

for an increase in revenues of $

3.5

 million USD. The rates include a regulatory ROE of

12.84

 per cent.

Fuel Recovery:

GBPC’s fuel costs flow through a fuel pass-through mechanism which provides the opportunity to recover

all prudently incurred fuel costs from customers in a timely manner.

Effective November 1, 2022, GBPC’s fuel pass through charge was increased due to an increase in

global oil prices impacting the unhedged fuel cost. In 2023, the fuel pass through charge was adjusted

monthly, in-line with actual fuel costs.

Storm Restoration Costs – Hurricane Matthew:

As part of the recovery of costs incurred as a result of Hurricane Matthew, in 2016, the GBPA approved a

fixed per kWh fuel charge and allowed the difference between this and the actual cost of fuel to be

applied to the Hurricane Matthew regulatory asset. As part of its decision on GBPC’s application for rate

review, issued January 14, 2022, and effective April 1, 2022, the GBPA approved the continued

amortization of the remaining regulatory asset over the three year period ending December 31, 2024.

XML

Investments Subject to Significant Influence and Equity Income

12 Months Ended

Dec. 31, 2023

Investments Subject to Significant Influence and Equity Income [Abstract]

Investments Subject to Significant Influence and Equity Income

7. INVESTMENTS SUBJECT TO SIGNIFICANT INFLUENCE AND EQUITY INCOME

Equity Income

Percentage

Carrying Value

For the year ended

of

As at December 31

December 31

Ownership

millions of dollars

2023

2022

2023

2022

2023

LIL

(1)

$

747

$

740

$

63

$

58

31.0

NSPML

489

501

46

29

100.0

M&NP

 (2)

118

128

21

21

12.9

Lucelec

(2)

48

49

4

4

19.5

Bear Swamp

 (3)

-

-

12

17

50.0

$

1,402

$

1,418

$

146

$

129

(1) Emera indirectly owns

100

 per cent of the Class B units, which comprises

24.5

 per cent of the total units issued. Percentage

ownership in LIL is subject to change, based on the balance of capital investments required from Emera and Nalcor Energy to

complete construction of the LIL. Emera’s ultimate percentage investment in LIL will be determined upon final costing of 

all transmission projects related to the Muskrat Falls development, including the LIL, Labrador Transmission Assets and Maritime

Link Projects, such that Emera’s total investment in the Maritime Link and LIL will equal

49

 per cent of the cost of all of these

transmission developments.

(2) Emera has significant influence over the operating and financial decisions of these companies through Board representation and

therefore, records its investment in these entities using the equity method. 

(3) The investment balance in Bear Swamp is in a credit position primarily as a result of a $

179

 million distribution received in 2015.

Bear Swamp's credit investment balance of $

81

 million (2022 – $

95

 million) is recorded in Other long-term liabilities on the

Consolidated Balance Sheets.

Equity investments include a $

10

 million difference between the cost and the underlying FV of the

investees' assets as at the date of acquisition. The excess is attributable to goodwill.

Emera accounts for its variable interest investment in NSPML as an equity investment (note 32).

NSPML's consolidated summarized balance sheets are illustrated as follows:

As at

December 31

millions of dollars

2023

2022

Balance Sheets

Current assets

$

21

$

17

PP&E

1,473

1,517

Regulatory assets

272

265

Non-current assets

29

29

Total assets

$

1,795

$

1,828

Current liabilities

$

48

$

48

Long-term debt

(1)

1,109

1,149

Non-current liabilities

149

130

Equity

489

501

Total liabilities and equity

$

1,795

$

1,828

(1) The project debt has been guaranteed by the Government of Canada.

XML

Other Income, Net

12 Months Ended

Dec. 31, 2023

Other Income, Net [Abstract]

Other Income, Net

8. OTHER INCOME, NET

For the

Year ended December 31

millions of dollars

2023

2022

Interest income

$

43

$

25

AFUDC

38

52

Pension non-current service cost recovery

35

24

FX gains (losses)

20

(26)

TECO Guatemala Holdings award

(1)

-

63

Other 

22

7

$

158

$

145

(1) On December 15, 2022, a payment of $

63

 million was made by the Republic of Guatemala to TECO Energy in satisfaction of the

second and final award issued by the International Centre of the Settlement of Investment Disputes tribunal regarding a dispute over

an investment in TGH, a wholly-owned subsidiary of TECO Energy.

XML

Interest Expense, Net

12 Months Ended

Dec. 31, 2023

Interest Expense, Net [Abstract]

Interest Expense, Net

9. INTEREST EXPENSE, NET

Interest expense, net consisted of the following:

For the

Year ended December 31

millions of Canadian dollars

2023

2022

Interest on debt 

$

954

$

727

Allowance for borrowed funds used during construction

(16)

(21)

Other

(13)

3

$

925

$

709

XML

Income Taxes

12 Months Ended

Dec. 31, 2023

Income Taxes [Abstract]

Income Taxes

10. INCOME TAXES

The income tax provision, for the years ended December 31, differs from that computed using the

enacted combined Canadian federal and provincial statutory income tax rate for the following reasons:

millions of dollars

2023

2022

Income before provision for income taxes

$

1,173

$

1,194

Statutory income tax rate

29.0%

29.0%

Income taxes, at statutory income tax rate

340

346

Deferred income taxes on regulated income recorded as regulatory assets and

regulatory liabilities

(72)

(70)

Tax credits

(53)

(18)

Foreign tax rate variance

(36)

(44)

Amortization of deferred income tax regulatory liabilities

(33)

(33)

Tax effect of equity earnings

(15)

(10)

GBPC impairment charge 

-

21

Other

(3)

(7)

Income tax expense

$

128

$

185

Effective income tax rate

11%

15%

On August 16, 2022, the United States Inflation Reduction Act (“IRA”) was signed into legislation. The

IRA includes numerous tax incentives for clean energy, such as the extension and modification of existing

investment and production tax credits for projects placed in service through 2024 and introduces new

technology-neutral clean energy related tax credits beginning in 2025. As of December 31, 2023, the

Company has recorded a $

30

 million (2022 - $

9

 million) regulatory liability on the Consolidated Balance

Sheets in recognition of its obligation to pass the incremental tax benefits realized to customers.

The following table reflects the composition of taxes on income from continuing operations presented in

the Consolidated Statements of Income for the years ended December 31:

millions of dollars

2023

2022

Current income taxes

 Canada

$

26

$

25

 United States

5

8

Deferred income taxes

 Canada

93

122

 United States

128

252

Investment tax credits

 United States

(29)

(7)

Operating loss carryforwards

 Canada

(93)

(94)

 United States

(2)

(121)

Income tax expense

$

128

$

185

The following table reflects the composition of income before provision for income taxes presented in the

Consolidated Statements of Income for the years ended December 31:

millions of dollars

2023

2022

Canada

$

171

$

173

United States

964

1,063

Other

38

(42)

Income before provision for income taxes

$

1,173

$

1,194

The deferred income tax assets and liabilities presented in the Consolidated Balance Sheets as at

December 31 consisted of the following:

millions of dollars

2023

2022

Deferred income tax assets:

Tax loss carryforwards

$

1,195

$

1,207

Tax credit carryforwards

454

415

Derivative instruments

205

45

Regulatory liabilities 

175

264

Other

372

341

Total deferred income tax assets before valuation allowance

2,401

2,272

Valuation allowance

(363)

(312)

Total deferred income tax assets after valuation allowance

$

2,038

$

1,960

Deferred income tax (liabilities):

PP&E

$

(3,223)

$

(2,981)

Derivative instruments

(235)

(125)

Investments subject to significant influence

(216)

(181)

Regulatory assets

(196)

(310)

Other

(312)

(322)

Total deferred income tax liabilities 

$

(4,182)

$

(3,919)

Consolidated Balance Sheets presentation:

Long-term deferred income tax assets

$

208

$

237

Long-term deferred income tax liabilities

(2,352)

(2,196)

Net deferred income tax liabilities

$

(2,144)

$

(1,959)

Considering all evidence regarding the utilization of the Company’s deferred income tax assets, it has

been determined that Emera is more likely than not to realize all recorded deferred income tax assets,

except for certain loss carryforwards and unrealized capital losses on long-term debt and investments. A

valuation allowance of $

363

 million has been recorded as at December 31, 2023 (2022 – $

312

 million)

related to the loss carryforwards, long-term debt and investments.

The Company intends to indefinitely reinvest earnings from certain foreign operations. Accordingly, as at

December 31, 2023, $

4.7

 billion (2022 – $

3.8

 billion) in cumulative temporary differences for which

deferred taxes might otherwise be required, have not been recognized. It is impractical to estimate the

amount of income and withholding tax that might be payable if a reversal of temporary differences

occurred.

Emera’s NOL, capital loss and tax credit carryforwards and their expiration periods as at December 31,

2023 consisted of the following:

Subject to

Tax

Valuation

Net Tax

Expiration

millions of dollars

Carryforwards

Allowance

Carryforwards

Period

Canada

 NOL

$

2,914

$

(1,164)

$

1,750

2026 - 2043

 Capital loss

73

(73)

-

Indefinite

United States

 Federal NOL

$

1,360

$

(1)

$

1,359

2036 - Indefinite

 State NOL

1,003

(1)

1,002

2026 - Indefinite

 Tax credit

454

(3)

451

2025 - 2043

Other

 NOL

$

81

$

(28)

$

53

2024 - 2030

The following table provides details of the change in unrecognized tax benefits for the years ended

December 31 as follows:

millions of dollars

2023

2022

Balance, January 1

$

33

$

28

Increases due to tax positions related to current year

5

5

Increases due to tax positions related to a prior year

1

2

Decreases due to tax positions related to a prior year

(2)

(2)

Balance, December 31

$

37

$

33

Unrecognized tax benefits relate to the timing of certain tax deductions at NSPI and research and

development tax credits primarily at TEC. The total amount of unrecognized tax benefits as at December

31, 2023 was $

37

 million (2022 – $

33

 million), which would affect the effective tax rate if recognized. The

total amount of accrued interest with respect to unrecognized tax benefits was $

9

 million (2022 – $

7

million) with $

2

 million interest expense recognized in the Consolidated Statements of Income (2022 – $

1

million).

No

 penalties have been accrued. The balance of unrecognized tax benefits could change in the

next 12 months as a result of resolving Canada Revenue Agency (“CRA”) and Internal Revenue Service

audits. A reasonable estimate of any change cannot be made at this time.

During 2022, the CRA issued notices of reassessment to NSPI for the 2013 through 2016 taxation years.

NSPI and the CRA are currently in a dispute with respect to the timing of certain tax deductions for

its 2006 through 2010 and 2013 through 2016 taxation years. The ultimate permissibility of the tax

deductions is not in dispute; rather, it is the timing of those deductions. The cumulative net amount in

dispute to date is $

126

 million (2022 – $

126

 million), including interest. NSPI has prepaid $

55

 million of

the amount in dispute, as required by CRA.

On November 29, 2019, NSPI filed a Notice of Appeal with the Tax Court of Canada with respect to its

dispute of the 2006 through 2010 taxation years. Should NSPI be successful in defending its position, all

payments including applicable interest will be refunded. If NSPI is unsuccessful in defending any portion

of its position, the resulting taxes and applicable interest will be deducted from amounts previously paid,

with the difference, if any, either owed to, or refunded from, the CRA. The related tax deductions will be

available in subsequent years.

Should NSPI be similarly reassessed by the CRA for years not currently in dispute, further payments will

be required; however, the ultimate permissibility of these deductions would be similarly not in dispute.

NSPI and its advisors believe that NSPI has reported its tax position appropriately. NSPI continues to

assess its options to resolving the dispute; however, the outcome of the Notice of Appeal process is not

determinable at this time.

Emera files a Canadian federal income tax return, which includes its Nova Scotia provincial income tax.

Emera’s subsidiaries file Canadian, US, Barbados, and St. Lucia income tax returns. As at December 31,

2023, the Company’s tax years still open to examination by taxing authorities include 2005 and

subsequent years.

XML

Common Stock

12 Months Ended

Dec. 31, 2023

Common Stock [Abstract]

Common Stock

11. COMMON STOCK

Authorized

: Unlimited number of non-par value common shares.

2023

2022

Issued and outstanding:

millions

of shares

 millions of

dollars

millions of

shares

 millions of

dollars

Balance, January 1

269.95

$

7,762

261.07

$

7,242

Issuance of common stock under ATM program

(1)(2)

8.29

397

4.07

248

Issued under the DRIP, net of discounts

5.26

272

4.21

238

Senior management stock options exercised and Employee Share

Purchase Plan

0.62

31

0.60

34

Balance, December 31

284.12

$

8,462

269.95

$

7,762

(1) For the year ended December 31, 2022, a total of

4,072,469

 common shares were issued under Emera's ATM program at an

average price of $

61.31

 per share for gross proceeds of $

250

 million ($

248

 million net of after-tax issuance costs).

(2) For the year ended December 31, 2023, a total of

8,287,037

 common shares were issued under Emera's ATM program at an

average price of $

48.27

 per share for gross proceeds of $

400

 million ($

397

 million net of after-tax issuance costs).

As at December 31, 2023, the following common shares were reserved for issuance:

6

 million (2022 –

6

million) under the senior management stock option plan,

2

 million (2022 –

2.7

 million) under the employee

common share purchase plan and

18

 million (2022 –

10

 million) under the DRIP. 

The issuance of common shares under the common share compensation arrangements does not allow

the plans to exceed

10

 per cent of Emera's outstanding common shares. As at December 31, 2023,

Emera was in compliance with this requirement.

ATM Equity Program

On October 3, 2023, Emera filed a short form base shelf prospectus, primarily in support of the renewal of

its ATM Program in Q4 2023 that will allow the Company to issue up to $

600

 million of common shares

from treasury to the public from time to time, at the Company’s discretion, at the prevailing market price.

This ATM Program is expected to remain in effect until November 4, 2025.

XML

Earnings Per Share

12 Months Ended

Dec. 31, 2023

Earnings Per Share [Abstract]

Earnings Per Share

12. EARNINGS PER SHARE

Basic earnings per share is determined by dividing net income attributable to common shareholders by

the weighted average number of common shares outstanding during the period. Diluted EPS is computed

by dividing net income attributable to common shareholders by the weighted average number of common

shares outstanding during the period, adjusted for the exercise and/or conversion of all potentially dilutive

securities. Such dilutive items include Company contributions to the senior management stock option

plan, convertible debentures and shares issued under the DRIP.

The following table reconciles the computation of basic and diluted earnings per share:

For the

Year ended December 31

millions of dollars (except per share amounts)

2023

2022

Numerator

Net income attributable to common shareholders

$

977.7

$

945.1

Diluted numerator

977.7

945.1

Denominator

Weighted average shares of common stock outstanding – basic

273.6

265.5

Stock-based compensation 

0.2

0.4

Weighted average shares of common stock outstanding – diluted

273.8

265.9

Earnings per common share

Basic 

$

3.57

$

3.56

Diluted

$

3.57

$

3.55

XML

Accumulated Other Comprehensive Income

12 Months Ended

Dec. 31, 2023

Accumulated Other Comprehensive Income [Abstract]

Accumulated Other Comprehensive Income

13. ACCUMULATED OTHER COMPREHENSIVE INCOME

The components of AOCI are as follows:

millions of dollars

Unrealized

(loss) gain on

translation of

self-sustaining

foreign

operations

Net change in

net investment

hedges

Losses on

derivatives

recognized 

as cash flow

hedges

Net change

on available-

for-sale

investments

Net change in

unrecognized

pension and

post-retirement

benefit costs

Total 

AOCI

For the year ended December 31, 2023

Balance, January 1, 2023

$

639

$

(62)

$

16

$

(2)

$

(13)

$

578

Other comprehensive (loss) 

income before 

reclassifications

(270)

38

 - 

-

-

(232)

Amounts reclassified from 

AOCI

-

-

(2)

-

(39)

(41)

Net current period other

comprehensive (loss) income

(270)

38

(2)

-

(39)

(273)

Balance, December 31, 2023

$

369

$

(24)

$

14

$

(2)

$

(52)

$

305

For the year ended December 31, 2022

Balance, January 1, 2022

$

10

$

35

$

18

$

(1)

$

(37)

$

25

Other comprehensive 

income (loss) before 

reclassifications

629

(97)

-

(1)

-

531

Amounts reclassified from 

AOCI

-

-

(2)

-

24

22

Net current period other

comprehensive income (loss)

629

(97)

(2)

(1)

24

553

Balance, December 31, 2022

$

639

$

(62)

$

16

$

(2)

$

(13)

$

578

The reclassifications out of AOCI are as follows:

For the

Year ended December 31

millions of dollars

2023

2022

Affected line item in the Consolidated Financial Statements

Gains on derivatives recognized as cash flow hedges

 Interest rate hedge

Interest expense, net

$

(2)

$

(2)

Net change in unrecognized pension and post-retirement benefit costs

 Actuarial losses

Other income, net

$

-

$

10

 Past service costs

Other income, net

2

-

 Amounts reclassified into obligations

Pension and post-retirement benefits

(40)

15

Total before tax

(38)

25

Income tax expense

(1)

(1)

Total net of tax

$

(39)

$

24

Total reclassifications out of AOCI, net of tax, for the period

$

(41)

$

22

XML

Inventory

12 Months Ended

Dec. 31, 2023

Inventory [Abstract]

Inventory

14. INVENTORY

As at

December 31

December 31

millions of dollars 

2023

2022

Fuel 

$

382

$

404

Materials 

408

365

Total

$

790

$

769

XML

Derivative Instruments

12 Months Ended

Dec. 31, 2023

Derivative Instruments

Derivative Instruments

15. DERIVATIVE INSTRUMENTS

Derivative assets and liabilities relating to the foregoing categories consisted of the following:

Derivative Assets

Derivative Liabilities

As at

December 31

December 31

December 31

December 31

millions of dollars

2023

2022

2023

2022

Regulatory deferral:

 Commodity swaps and forwards

$

16

$

186

$

76

$

42

 FX forwards

3

18

3

1

 Physical natural gas purchases and sales

-

52

-

-

19

256

79

43

HFT derivatives:

 Power swaps and physical contracts

29

89

36

77

 Natural gas swaps, futures, forwards, physical 

 contracts

319

340

531

1,224

348

429

567

1,301

Other derivatives:

 Equity derivatives 

4

-

-

5

 FX forwards

18

5

7

23

22

5

7

28

Total gross current derivatives

389

690

653

1,372

Impact of master netting agreements:

 Regulatory deferral

(3)

(18)

(3)

(18)

 HFT derivatives

(146)

(276)

(146)

(276)

Total impact of master netting agreements

(149)

(294)

(149)

(294)

Total derivatives

$

240

$

396

$

504

$

1,078

Current

(1)

174

296

386

888

Long-term

(1)

66

100

118

190

Total derivatives

$

240

$

396

$

504

$

1,078

(1) Derivative assets and liabilities are classified as current or long-term based upon the maturities of the underlying contracts.

Cash Flow Hedges

On May 26, 2021, a treasury lock was settled for a gain of $

19

 million that is being amortized through

interest expense over

10 years

 as the underlying hedged item settles.

The amounts related to cash flow hedges recorded in AOCI consisted of the following:

For the

Year ended December 31

millions of dollars

2023

2022

Interest

Interest

rate hedge

rate hedge

Realized gain in interest expense, net

$

2

$

2

Total gains in net income

$

2

$

2

As at

December 31

December 31

millions of dollars

2023

2022

Interest

Interest

rate hedge

rate hedge

Total unrealized gain in AOCI – effective portion, net of tax

$

14

$

16

The Company expects $

2

 million of unrealized gains currently in AOCI to be reclassified into net income

within the next 12 months.

Regulatory Deferral

The Company has recorded the following changes with respect to derivatives receiving regulatory

deferral:

Physical

Commodity

Physical

Commodity

natural gas

swaps and

FX

natural gas

swaps and

FX

millions of dollars

purchases

forwards

forwards

purchases

forwards

forwards

For the year ended December 31

2023

2022

Unrealized gain (loss) in regulatory

assets

$

-

$

(109)

$

(3)

$

-

$

(69)

$

1

Unrealized gain (loss) in regulatory

liabilities

(3)

(73)

-

28

343

16

Realized (gain) loss in regulatory

assets

-

(5)

-

-

48

-

Realized (gain) loss in regulatory

liabilities

-

2

-

-

(41)

-

Realized (gain) loss in inventory

(1)

-

4

(10)

-

(121)

1

Realized (gain) in regulated fuel for

generation and purchased power

(2)

(49)

(9)

(4)

(64)

(146)

-

Other

-

(14)

-

-

-

-

Total change in derivative instruments

$

(52)

$

(204)

$

(17)

$

(36)

$

14

$

18

(1) Realized (gains) losses will be recognized in fuel for generation and purchased power when the hedged item is consumed.

(2) Realized (gains) losses on derivative instruments settled and consumed in the period and hedging relationships that have been

terminated or the hedged transaction is no longer probable.

As at December 31, 2023, the Company had the following notional volumes designated for regulatory

deferral that are expected to settle as outlined below:

millions

2024

2025-2026

Physical natural gas purchases:

Natural gas (MMBtu)

7

6

Commodity swaps and forwards purchases:

Natural gas (MMBtu)

16

10

Power (MWh)

1

1

Coal (metric tonnes)

1

-

FX swaps and forwards:

FX contracts (millions of USD)

$

241

$

70

Weighted average rate

1.3155

1.3197

% of USD requirements

63%

17%

HFT Derivatives

The Company has recognized the following realized and unrealized gains (losses) with respect to HFT

derivatives:

For the 

Year ended December 31

millions of dollars

2023

2022

Power swaps and physical contracts in non-regulated operating revenues

$

(6)

$

17

Natural gas swaps, forwards, futures and physical contracts in non-regulated

operating revenues

1,043

47

Total gains in net income

$

1,037

$

64

As at December 31, 2023, the Company had the following notional volumes of outstanding HFT

derivatives that are expected to settle as outlined below:

2028 and 

millions 

2024

2025

2026

2027

thereafter

Natural gas purchases (Mmbtu)

296

80

50

38

30

Natural gas sales (Mmbtu)

338

86

16

6

4

Power purchases (MWh)

1

-

-

-

-

Power sales (MWh)

1

-

-

-

-

Other Derivatives

As at December 31, 2023, the Company had equity derivatives in place to manage the cash flow risk

associated with forecasted future cash settlements of deferred compensation obligations and FX forwards

in place to manage cash flow risk associated with forecasted USD cash inflows.

The equity derivatives

hedge the return on

2.9

 million shares and extends until December 2024. The FX forwards have a

combined notional amount of $508 million USD and expire in 2023, 2024 and 2025.

For the

Year ended December 31

millions of dollars

2023

2022

FX

Equity

FX

Equity

Forwards

Derivatives

Forwards

Derivatives

Unrealized gain (loss) in OM&G

$

-

$

4

$

-

$

(5)

Unrealized gain (loss) in other income, net

28

-

(18)

-

Realized loss in OM&G

-

(13)

-

(17)

Realized loss in other income, net

(11)

-

(6)

-

Total gains (losses) in net income

$

17

$

(9)

$

(24)

$

(22)

Credit Risk

The Company is exposed to credit risk with respect to amounts receivable from customers, energy

marketing collateral deposits and derivative assets. Credit risk is the potential loss from a counterparty’s

non-performance under an agreement. The Company manages credit risk with policies and procedures

for counterparty analysis, exposure measurement, and exposure monitoring and mitigation. Credit

assessments are conducted on all new customers and counterparties, and deposits or collateral are

requested on any high-risk accounts. 

The Company assesses the potential for credit losses on a regular basis and, where appropriate,

maintains provisions. With respect to counterparties, the Company has implemented procedures to

monitor the creditworthiness and credit exposure of counterparties and to consider default probability in

valuing the counterparty positions. The Company monitors counterparties’ credit standing, including those

that are experiencing financial problems, have significant swings in default probability rates, have credit

rating changes by external rating agencies, or have changes in ownership. Net liability positions are

adjusted based on the Company’s current default probability. Net asset positions are adjusted based on

the counterparty’s current default probability. The Company assesses credit risk internally for

counterparties that are not rated.

As at December 31, 2023, the maximum exposure the Company had to credit risk was $

1.2

 billion (2022

– $

1.9

 billion), which included accounts receivable net of collateral/deposits and assets related to

derivatives. 

It is possible that volatility in commodity prices could cause the Company to have material credit risk

exposures with one or more counterparties. If such counterparties fail to perform their obligations under

one or more agreements, the Company could suffer a material financial loss. The Company transacts with

counterparties as part of its risk management strategy for managing commodity price, FX and interest

rate risk. Counterparties that exceed established credit limits can provide a cash deposit or letter of credit

to the Company for the value in excess of the credit limit where contractually required. The total cash

deposits/collateral on hand as at December 31, 2023 was $

310

 million (2022 – $

386

 million), which

mitigated the Company’s maximum credit risk exposure. The Company uses the cash as payment for the

amount receivable or returns the deposit/collateral to the customer/counterparty where it is no longer

required by the Company.

The Company enters into commodity master arrangements with its counterparties to manage certain

risks, including credit risk to these counterparties. The Company generally enters into International Swaps

and Derivatives Association agreements, North American Energy Standards Board agreements and, or

Edison Electric Institute agreements. The Company believes entering into such agreements offers

protection by creating contractual rights relating to creditworthiness, collateral, non-performance and

default.

As at December 31, 2023, the Company had $

142

 million (2022 – $

131

 million) in financial assets,

considered to be past due, which have been outstanding for an average

64

 days. The FV of these

financial assets was $

127

 million (2022 – $

114

 million), the difference of which was included in the

allowance for credit losses. These assets primarily relate to accounts receivable from electric and gas

revenue.

Concentration Risk

The Company's concentrations of risk consisted of the following:

As at

December 31, 2023

December 31, 2022

millions of

dollars

% of total

exposure

millions of

dollars

% of total

exposure

Receivables, net

Regulated utilities:

Residential

$

476

31%

$

455

19%

Commercial

194

13%

192

8%

Industrial

84

5%

121

5%

Other

103

7%

122

5%

Cash collateral

94

6%

-

0%

951

62%

890

37%

Trading group:

Credit rating of A- or above

47

3%

125

5%

Credit rating of BBB- to BBB+

33

2%

75

3%

Not rated

108

7%

307

13%

188

12%

507

21%

Other accounts receivable

151

10%

585

25%

1,290

84%

1,982

83%

Derivative Instruments

(current and long-term)

Credit rating of A- or above

138

9%

202

9%

Credit rating of BBB- to BBB+

7

1%

8

0%

Not rated

95

6%

186

8%

240

16%

396

17%

$

1,530

100%

$

2,378

100%

Cash Collateral

The Company’s cash collateral positions consisted of the following:

As at

December 31

December 31

millions of dollars

2023

2022

Cash collateral provided to others

$

101

$

224

Cash collateral received from others

$

22

$

112

Collateral is posted in the normal course of business based on the Company’s creditworthiness, including

its senior unsecured credit rating as determined by certain major credit rating agencies. Certain

derivatives contain financial assurance provisions that require collateral to be posted if a material adverse

credit-related event occurs. If a material adverse event resulted in the senior unsecured debt falling below

investment grade, the counterparties to such derivatives could request ongoing full collateralization.

As at December 31, 2023, the total FV of derivatives in a liability position was $

504

 million (December 31,

2022

–

 $

1,078

 million). If the credit ratings of the Company were reduced below investment grade, the full

value of the net liability position could be required to be posted as collateral for these derivatives.

XML

FV Measurements

12 Months Ended

Dec. 31, 2023

FV Measurements [Abstract]

Fair Value Measurements

16. FV MEASUREMENTS

The Company is required to determine the FV of all derivatives except those which qualify for the NPNS

exemption (see note 1) and uses a market approach to do so. The three levels of the FV hierarchy are

defined as follows:

Level 1 - Where possible, the Company bases the fair valuation of its financial assets and liabilities on

quoted prices in active markets (“quoted prices”) for identical assets and liabilities.

Level 2 - Where quoted prices for identical assets and liabilities are not available, the valuation of certain

contracts must be based on quoted prices for similar assets and liabilities with an adjustment related to

location differences. Also, certain derivatives are valued using quotes from over-the-counter clearing

houses.

Level 3 - Where the information required for a Level 1 or Level 2 valuation is not available, derivatives

must be valued using unobservable or internally-developed inputs. The primary reasons for a Level 3

classification are as follows:

●

 While valuations were based on quoted prices, significant assumptions were necessary to reflect

seasonal or monthly shaping and locational basis differentials.

●

 The term of certain transactions extends beyond the period when quoted prices are available and,

accordingly, assumptions were made to extrapolate prices from the last quoted period through the

end of the transaction term.

●

 The valuations of certain transactions were based on internal models, although quoted prices were

utilized in the valuations.

Derivative assets and liabilities are classified in their entirety based on the lowest level of input that is

significant to the FV measurement.

The following tables set out the classification of the methodology used by the Company to FV its

derivatives:

As at

December 31, 2023

millions of dollars

Level 1

Level 2

Level 3

Total

Assets

Regulatory deferral:

 Commodity swaps and forwards

$

7

$

6

$

-

$

13

 FX forwards

-

3

-

3

7

9

-

16

HFT derivatives:

 Power swaps and physical contracts

(5)

23

-

18

 Natural gas swaps, futures, forwards, physical 

 contracts and related transportation

42

108

34

184

37

131

34

202

Other derivatives:

 FX forwards

-

18

-

18

 Equity derivatives 

4

-

-

4

4

18

-

22

Total assets

48

158

34

240

Liabilities

Regulatory deferral:

 Commodity swaps and forwards

43

30

-

73

 FX forwards

-

3

-

3

43

33

-

76

HFT derivatives:

 Power swaps and physical contracts

-

24

-

24

 Natural gas swaps, futures, forwards and physical 

 contracts

13

19

365

397

13

43

365

421

Other derivatives:

 FX forwards

-

7

-

7

-

7

-

7

Total liabilities

56

83

365

504

Net assets (liabilities) 

$

(8)

$

75

$

(331)

$

(264)

As at

December 31, 2022

millions of dollars

Level 1

Level 2

Level 3

Total

Assets

Regulatory deferral:

 Commodity swaps and forwards

$

120

$

48

$

-

$

168

 FX forwards

-

18

-

18

 Physical natural gas purchases and sales

-

-

52

52

120

66

52

238

HFT derivatives:

 Power swaps and physical contracts

9

31

4

44

 Natural gas swaps, futures, forwards, physical 

 contracts and related transportation

3

72

34

109

12

103

38

153

Other derivatives:

 FX forwards

-

5

-

5

Total assets

132

174

90

396

Liabilities

Regulatory deferral:

 Commodity swaps and forwards

15

9

-

24

 FX forwards

-

1

-

1

15

10

-

25

HFT derivatives:

 Power swaps and physical contracts

2

28

1

31

 Natural gas swaps, futures, forwards and physical 

 contracts

51

118

825

994

53

146

826

1,025

Other derivatives:

 FX forwards

-

23

-

23

 Equity derivatives

5

-

-

5

Total liabilities

73

179

826

1,078

Net assets (liabilities)

$

59

$

(5)

$

(736)

$

(682)

The change in the FV of the Level 3 financial assets for the year ended December 31, 2023 was as

follows:

Regulatory Deferral

HFT Derivatives

Physical natural

Natural 

millions of dollars

gas purchases

Power 

gas

Total

Balance, January 1, 2023

$

52

$

4

$

34

$

90

Realized gains (losses) included in fuel for generation

and purchased power

(49)

-

-

(49)

Unrealized gains (losses) included in regulatory

assets and liabilities

(3)

-

-

(3)

Total realized and unrealized gains (losses) included

in non-regulated operating revenues

-

(4)

-

(4)

Balance, December 31, 2023

$

-

$

-

$

34

$

34

The change in the FV of the Level 3 financial liabilities for the year ended December 31, 2023 was as

follows:

 HFT Derivatives

Natural

millions of dollars

Power 

gas

Total

Balance, January 1, 2023

$

1

$

825

$

826

Total realized and unrealized gains included in non-

regulated operating revenues

(1)

(460)

(461)

Balance, December 31, 2023 

$

-

$

365

$

365

Significant unobservable inputs used in the FV measurement of Emera’s natural gas and power

derivatives include third-party sourced pricing for instruments based on illiquid markets. Significant

increases (decreases) in any of these inputs in isolation would result in a significantly lower (higher) FV

measurement. Other unobservable inputs used include internally developed correlation factors and basis

differentials; own credit risk; and discount rates. Internally developed correlations and basis differentials

are reviewed on a quarterly basis based on statistical analysis of the spot markets in the various illiquid

term markets. Discount rates may include a risk premium for those long-term forward contracts with

illiquid future price points to incorporate the inherent uncertainty of these points. Any risk premiums for

long-term contracts are evaluated by observing similar industry practices and in discussion with industry

peers.

The Company uses a modelled pricing valuation technique for determining the FV of Level 3 derivative

instruments. The following table outlines quantitative information about the significant unobservable

inputs used in the FV measurements categorized within Level 3 of the FV hierarchy:

Significant

Weighted 

millions of dollars

FV

Unobservable Input

Low

High

average

(1)

Assets

Liabilities

As at December 31, 2023

HFT derivatives – Natural 

34

365

Third-party pricing

$1.27

$16.25

$4.85

gas swaps, futures, forwards 

and physical contracts 

Total

$

34

$

365

Net liability

$

331

As at December 31, 2022

Regulatory deferral –

Physical

$

52

$

-

Third-party pricing

$5.79

$31.85

$12.27

natural gas purchases

HFT derivatives – Power 

4

1

Third-party pricing

$43.24

$269.10

$138.79

swaps and physical contracts

HFT derivatives – Natural 

34

825

Third-party pricing

$2.45

$33.88

$12.01

gas swaps, futures, forwards 

and physical contracts 

Total

$

90

$

826

Net liability

$

736

(1) Unobservable inputs were weighted by the relative FV of the instruments.

Long-term debt is a financial liability not measured at FV on the Consolidated Balance Sheets. The

balance consisted of the following:

As at

Carrying

millions of dollars

Amount

FV

Level 1

Level 2

Level 3

Total

December 31, 2023

$

18,365

$

16,621

$

-

$

16,363

$

258

$

16,621

December 31, 2022

$

16,318

$

14,670

$

-

$

14,284

$

386

$

14,670

The Company has designated $

1.2

 billion USD denominated Hybrid Notes as a hedge of the foreign

currency exposure of its ne

t investment

 in USD denominated operations. The Company’s Hybrid Notes

are contingently convertible into preferred shares in the event of bankruptcy or other related events. A

redemption option on or after June 15, 2026 is available and at the control of the Company. The Hybrid

Notes are classified as Level 2 financial assets. As at December 31, 2023, the FV of the Hybrid Notes

was $

1.2

 billion (2022 – $

1.1

 billion). An after-tax foreign currency gain of $

38

 million was recorded in

AOCI for the year ended December 31, 2023 (2022 – $

97

 million after-tax loss).

XML

Related Party Transactions

12 Months Ended

Dec. 31, 2023

Related Party Transactions [Abstract]

Related Party Transactions

17. RELATED PARTY TRANSACTIONS

In the ordinary course of business, Emera provides energy and other services and enters into

transactions with its subsidiaries, associates and other related companies on terms similar to those

offered to non-related parties. Intercompany balances and intercompany transactions have been

eliminated on consolidation, except for the net profit on certain transactions between non-regulated and

regulated entities in accordance with accounting standards for rate-regulated entities. All material

amounts are under normal interest and credit terms. 

Significant transactions between Emera and its associated companies are as follows:

●

 Transactions between NSPI and NSPML related to the Maritime Link assessment are reported in the

Consolidated Statements of Income. NSPI’s expense is reported in Regulated fuel for generation and

purchased power, totalling $

163

 million for the year ended December 31, 2023 (2022 – $

157

 million).

NSPML is accounted for as an equity investment, and therefore corresponding earnings related to

this revenue are reflected in Income from equity investments.

Natural gas transportation capacity purchases from M&NP are reported in the Consolidated

Statements of Income. Purchases from M&NP reported net in Operating revenues, Non-regulated,

totalled $

14

 million for the year ended December 31, 2023 (2022

– $

9

 million).

There were no significant receivables or payables between Emera and its associated companies reported

on Emera’s Consolidated Balance Sheets as at December 31, 2023 and at December 31, 2022.

XML

Receivables and Other Current Assets

12 Months Ended

Dec. 31, 2023

Receivables and Other Current Assets [Abstract]

Receivables and Other Current Assets

18. RECEIVABLES AND OTHER CURRENT ASSETS

As at

December 31

December 31

millions of dollars 

2023

2022

Customer accounts receivable – billed

$

805

$

1,096

Capitalized transportation capacity

(1)

358

781

Customer accounts receivable – unbilled

363

424

Prepaid expenses

105

82

Income tax receivable

10

9

Allowance for credit losses

(15)

(17)

NMGC gas hedge settlement receivable

 (2)

 - 

162

Other

191

360

Total receivables and other current assets

$

1,817

$

2,897

(1) Capitalized transportation capacity represents the value of transportation/storage received by EES on asset management

agreements at the inception of the contracts. The asset is amortized over the term of each contract.

(2) Offsetting amount is included in regulatory liabilities for NMGC as gas hedges are part of the PGAC. For more information, refer

to note 6.

XML

Leases

12 Months Ended

Dec. 31, 2023

Leases [Abstract]

Leases, Lessee

19. LEASES

Lessee

The Company has operating leases for buildings, land, telecommunication services, and rail cars.

Emera’s leases have remaining lease terms of 1 year to 62 years, some of which include options to

extend the leases for up to 65 years. These options are included as part of the lease term when it is

considered reasonably certain they will be exercised.

As at

December 31

December 31

millions of dollars 

Classification

2023

2022

Right-of-use asset

Other long-term assets

$

54

$

58

Lease liabilities

 Current

Other current liabilities

3

3

 Long-term

Other long-term liabilities

55

59

Total lease liabilities

$

58

$

62

The Company recorded lease expense of $

127

 million for the year ended December 31, 2023 (2022 –

$

138

 million), of which $

119

 million (2022 – $

131

 million) related to variable costs for power generation

facility finance leases, recorded in “Regulated fuel for generation and purchased power” in the

Consolidated Statements of Income.

Future minimum lease payments under non-cancellable operating leases for each of the next five years

and in aggregate thereafter are as follows:

millions of dollars

2024

2025

2026

2027

2028

Thereafter

Total

Minimum lease payments

$

6

$

5

$

3

$

3

$

3

$

111

$

131

Less imputed interest

(73)

Total

$

58

Additional information related to Emera's leases is as follows:

Year ended December 31

For the

2023

2022

Cash paid for amounts included in the measurement of lease liabilities:

 Operating cash flows for operating leases (millions of dollars)

$

8

$

8

Right-of-use assets obtained in exchange for lease obligations:

 Operating leases (millions of dollars)

$

1

$

1

Weighted average remaining lease term (years)

44

44

Weighted average discount rate- operating leases

3.93%

3.98%

Lessor

The Company’s net investment in direct finance and sales-type leases primarily relates to Brunswick

Pipeline, Seacoast, compressed natural gas (“CNG”) stations, a renewable natural gas (“RNG”) facility

and heat pumps.

The Company manages its risk associated with the residual value of the Brunswick Pipeline lease

through proper routine maintenance of the asset.

Customers have the option to purchase CNG station assets by paying a make-whole payment at the date

of the purchase based on a targeted internal rate of return or may take possession of the CNG station

asset at the end of the lease term for no cost. Customers have the option to purchase heat pumps at the

end of the lease term for a nominal fee.

Commencing in October 2023, the Company leased a RNG facility to a biogas producer that is classified

as a sales-type lease. The term of the facility lease is

15 years

, with a nominal value purchase at the end

of the term and a net investment of approximately $

35

 million USD. 

Commencing in January 2022, the Company leased Seacoast pipeline, a 21-mile, 30-inch lateral that is

classified as a sales-type lease. The term of the pipeline lateral lease is

34

 years with a net investment of

$

100

 million USD. The lessee of the pipeline lateral has renewal options for an additional

16

 years. These

renewal options have not been included as part of the pipeline lateral lease term as it is not reasonably

certain that they will be exercised.

Direct finance and sales-type lease unearned income is recognized in income over the life of the lease

using a constant rate of interest equal to the internal rate of return on the lease and is recorded as

“Operating revenues – regulated gas” and “Other income, net” on the Consolidated Statements of

Income.

The total net investment in direct finance and sales-type leases consist of the following:

As at

December 31

December 31

millions of dollars 

2023

2022

Total minimum lease payment to be received

$

1,360

$

1,393

Less: amounts representing estimated executory costs

(190)

(205)

Minimum lease payments receivable

$

1,170

$

1,188

Estimated residual value of leased property (unguaranteed)

183

183

Less: Credit loss reserve

(2)

-

Less: unearned finance lease income

(693)

(733)

Net investment in direct finance and sales-type leases

$

658

$

638

Principal due within one year (included in "Receivables and other

current assets")

37

34

Net Investment in direct finance and sales type leases - long-term

$

621

$

604

As at December 31, 2023, future minimum lease payments to be received for each of the next five years

and in aggregate thereafter were as follows:

millions of dollars

2024

2025

2026

2027

2028

Thereafter

Total

Minimum lease payments to be

received

$

97

$

99

$

98

$

97

$

96

$

873

$

1,360

Less: executory costs

(190)

Total

$

1,170

XML

Property, Plant and Equipment

12 Months Ended

Dec. 31, 2023

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

20. PROPERTY, PLANT AND EQUIPMENT

PP&E consisted of the following regulated and non-regulated assets: 

As at

December 31

December 31

millions of dollars 

Estimated useful life

2023

2022

Generation

3

 to

131

$

13,500

$

13,083

Transmission

10

 to

80

2,835

2,731

Distribution

4

 to

80

7,417

6,978

Gas transmission and distribution

6

 to

92

5,536

5,061

General plant and other

 (1)

2

 to

71

2,985

2,723

Total cost

32,273

30,576

Less: Accumulated depreciation

(1)

(9,994)

(9,574)

22,279

21,002

Construction work in progress

(1)

2,097

1,994

Net book value

$

24,376

$

22,996

(1) SeaCoast owns a

50

% undivided ownership interest in a jointly owned

26

-mile pipeline lateral located in Florida, which went into

service in 2020. At December 31, 2023, SeaCoast’s share of plant in service was $

27

 million USD (2022 – $

27

 million USD), and

accumulated depreciation of $

2

 million USD (2022 – $

1

 million USD). SeaCoast’s undivided ownership interest is financed with its

funds and all operations are accounted for as if such participating interest were a wholly owned facility. SeaCoast’s share of direct

expenses of the jointly owned pipeline is included in "OM&G" in the Consolidated Statements of Income.

XML

Employee Benefit Plans

12 Months Ended

Dec. 31, 2023

Employee Benefit Plans [Abstract]

Employee Benefit Plans

21. EMPLOYEE BENEFIT PLANS

Emera maintains a number of contributory defined-benefit (“DB”) and defined-contribution (“DC”) pension

plans, which cover substantially all of its employees. In addition, the Company provides non-pension

benefits for its retirees. These plans cover employees in Nova Scotia, New Brunswick, Newfoundland and

Labrador, Florida, New Mexico, Barbados, and Grand Bahama Island.

Emera’s net periodic benefit cost included the following:

Benefit Obligation and Plan Assets:

The changes in benefit obligation and plan assets, and the funded status for all plans were as follows:

For the 

Year ended December 31

millions of dollars

2023

2022

Change in Projected Benefit Obligation

("PBO") and Accumulated Post-

retirement Benefit Obligation ("APBO")

Defined benefit

pension plans

Non-pension

benefit plans

Defined benefit

pension plans

Non-pension

benefit plans

Balance, January 1

$

2,158

$

243

$

2,624

$

318

Service cost

30

3

41

4

Plan participant contributions

6

6

6

6

Interest cost

111

13

80

9

Plan amendments

-

(14)

-

-

Benefits paid 

(147)

(29)

(174)

(31)

Actuarial losses (gains)

146

10

(480)

(79)

Settlements and curtailments

(8)

-

(6)

-

FX translation adjustment

(23)

(5)

67

16

Balance, December 31

$

2,273

$

227

$

2,158

$

243

Change in plan assets

Balance, January 1

$

2,163

$

46

$

2,702

$

51

Employer contributions

42

23

45

24

Plan participant contributions 

6

6

6

6

Benefits paid

(147)

(29)

(174)

(31)

Actual return on assets, net of expenses

262

3

(489)

(7)

Settlements and curtailments

(8)

-

(6)

-

FX translation adjustment

(20)

(1)

79

3

Balance, December 31

$

2,298

$

48

$

2,163

$

46

Funded status, end of year 

$

25

$

(179)

$

5

$

(197)

The actuarial losses recognized in the period are primarily due to changes in the discount rate, higher

than expected indexation, and compensation-related assumption changes.

Plans with PBO/APBO

in Excess of Plan Assets:

The aggregate financial position for all pension plans where the PBO or APBO (for post-retirement benefit

plans) exceeded the plan assets for the years ended December 31 was as follows:

millions of dollars

2023

2022

Defined benefit

pension plans

Non-pension

benefit plans

Defined benefit

pension plans

Non-pension

benefit plans

PBO/APBO

$

120

$

205

$

1,006

$

221

FV of plan assets

37

-

914

-

Funded status

$

(83)

$

(205)

$

(92)

$

(221)

Plans with Accumulated Benefit Obligation (“ABO”)

in Excess of Plan Assets:

The ABO for the DB pension plans was $

2,172

 million as at December 31, 2023 (2022 – $

2,080

 million).

The aggregate financial position for those plans with an ABO in excess of the plan assets for the years

ended December 31 was as follows:

millions of dollars

2023

2022

Defined benefit

pension plans

Defined benefit

pension plans

ABO

$

114

$

111

FV of plan assets

37

33

Funded status

$

(77)

$

(78)

Balance Sheet:

The amounts recognized in the Consolidated Balance Sheets consisted of the following:

As at

December 31

December 31

millions of dollars

2023

2022

Defined benefit

pension plans

Non-pension

benefit plans

Defined benefit

pension plans

Non-pension

benefit plans

Other current liabilities

$

(5)

$

(18)

$

(13)

$

(20)

Long-term liabilities

(78)

(187)

(80)

(201)

Other long-term assets

108

26

98

24

AOCI, net of tax and regulatory assets

385

20

358

22

Less: Deferred income tax (expense)

recovery in AOCI

(8)

(1)

(7)

(1)

Net amount recognized

$

402

$

(160)

$

356

$

(176)

Amounts Recognized in AOCI and Regulatory Assets:

Unamortized gains and losses and past service costs arising on post-retirement benefits are recorded in

AOCI or regulatory assets. The following table summarizes the change in AOCI and regulatory assets:

Regulatory assets

Actuarial 

(gains) losses

Past service

(gains) costs

millions of dollars

Defined Benefit Pension Plans

Balance, January 1, 2023

$

336

$

15

$

-

Amortized in current period

(6)

(3)

-

Current year additions

1

41

-

Change in FX rate

(7)

-

-

Balance, December 31, 2023

$

324

$

53

$

-

Non-pension benefits plans

Balance, January 1, 2023

$

31

$

(10)

$

-

Amortized in current period

2

3

-

Current year reductions

(3)

(1)

(3)

Change in FX rate

(1)

-

1

Balance, December 31, 2023

$

29

$

(8)

$

(2)

As at

December

31

December

31

millions of dollars

2023

2022

Defined benefit

pension plans

Non-pension

benefit plans

Defined benefit

pension plans

Non-pension

benefit plans

Actuarial losses (gains)

$

53

(8)

$

15

$

(10)

Past service gains

-

(2)

-

-

Deferred income tax expense

8

1

7

1

AOCI, net of tax

61

(9)

22

(9)

Regulatory assets

324

29

336

31

AOCI, net of tax and regulatory assets

$

385

$

20

$

358

$

22

Benefit Cost Components:

Emera's net periodic benefit cost included the following:

As at

Year ended December 31

millions of dollars

2023

2022

Defined benefit

pension plans

Non-pension

benefit plans

Defined benefit

pension plans

Non-pension

benefit plans

Service cost

$

30

$

3

$

41

$

4

Interest cost

111

13

80

9

Expected return on plan assets

(161)

(2)

(144)

-

Current year amortization of:

 Actuarial losses (gains)

1

(3)

8

-

 Regulatory assets (liability)

6

(2)

21

2

Settlement, curtailments

2

-

2

-

Total

$

(11)

$

9

$

8

$

15

The expected return on plan assets is determined based on the market-related value of plan assets of

$

2,577

 million as at January 1, 2023 (2022 – $

2,482

 million), adjusted for interest on certain cash flows

during the year.

The market-related value of assets is based on a five-year smoothed asset value. Any

investment gains (or losses) in excess of (or less than) the expected return on plan assets are recognized

on a straight-line basis into the market-related value of assets over a five-year period.

Pension Plan Asset Allocations:

Emera’s investment policy includes discussion regarding the investment philosophy, the level of risk

which the Company is prepared to accept with respect to the investment of the Pension Funds, and the

basis for measuring the performance of the assets. Central to the policy is the target asset allocation by

major asset categories. The objective of the target asset allocation is to diversify risk and to achieve asset

returns that meet or exceed the plan’s actuarial assumptions. The diversification of assets reduces the

inherent risk in financial markets by requiring that assets be spread out amongst various asset classes.

Within each asset class, a further diversification is undertaken through the investment in a broad range of

investment and non-investment grade securities. Emera’s target asset allocation is as follows:

Canadian Pension Plans

Asset Class

Target Range at Market

Short-term securities

0%

to

10%

Fixed income

34%

to

49%

Equities:

 Canadian

7%

to

17%

 Non-Canadian

35%

to

59%

Non-Canadian Pension Plans

Asset Class

Target Range at Market

Weighted average

Cash and cash equivalents

0%

to

10%

Fixed income

29%

to

49%

Equities

48%

to

68%

Pension Plan assets are overseen by the respective Management Pension Committees in the sponsoring

companies. All pension investments are in accordance with policies approved by the respective Board of

Directors of each sponsoring company.

The following tables set out the classification of the methodology used by the Company to FV its

investments:

millions of dollars

NAV

Level 1

Level 2

Total

Percentage

As at

December 31, 2023

Cash and cash equivalents

$

-

$

40

$

-

$

40

2

%

Net in-transits

-

(9)

-

(9)

-

%

Equity securities:

 Canadian equity

-

96

-

96

4

%

 United States equity 

-

141

-

141

6

%

 Other equity

-

112

-

112

5

%

Fixed income securities:

 Government

-

-

172

172

8

%

 Corporate

-

-

90

90

4

%

 Other

-

4

5

9

-

%

Mutual funds

-

50

-

50

2

%

Other

-

6

(1)

5

-

%

Open-ended investments

measured at NAV

 (1)

1,006

-

-

1,006

44

%

Common collective trusts

measured at NAV

(2)

586

-

-

586

25

%

Total 

$

1,592

$

440

$

266

$

2,298

100

%

As at

December 31, 2022

Cash and cash equivalents

$

-

$

70

$

-

$

70

3

%

Net in-transits

-

(70)

-

(70)

(3)

%

Equity securities:

 Canadian equity

-

87

-

87

4

%

 United States equity 

-

233

-

233

11

%

 Other equity

-

186

-

186

8

%

Fixed income securities:

 Government

-

-

104

104

5

%

 Corporate

-

-

83

83

4

%

 Other

-

3

11

14

1

%

Mutual funds

-

68

-

68

3

%

Other

-

-

(3)

(3)

-

%

Open-ended investments

measured at NAV

 (1)

790

-

-

790

36

%

Common collective trusts

measured at NAV

(2)

601

-

-

601

28

%

Total 

$

1,391

$

577

$

195

$

2,163

100

%

(1) Net asset value ("NAV") investments are open-ended registered and non-registered mutual funds, collective investment trusts,

or pooled funds. NAV’s are calculated at least monthly and the funds honour subscription and redemption activity regularly.

(2) The common collective trusts are private funds valued at NAV. The NAVs are calculated based on bid prices of the underlying

securities. Since the prices are not published to external sources, NAV is used as a practical expedient. Certain funds invest

primarily in equity securities of domestic and foreign issuers while others invest in long duration U.S. investment grade fixed

income assets and seeks to increase return through active management of interest rate and credit risks. The funds honour

subscription and redemption activity regularly.

Refer to note 16 for more information on the FV hierarchy and inputs used to measure FV.

Post-Retirement Benefit Plans:

There are no assets set aside to pay for most of the Company’s post-retirement benefit plans. As is

common practice, post-retirement health benefits are paid from general accounts as required. The

primary exception to this is the NMGC Retiree Medical Plan, which is fully funded.

Investments in Emera:

As at December 31, 2023 and 2022, assets related to the pension funds and post-retirement benefit plans

did not hold any material investments in Emera or its subsidiaries securities. However, as a significant

portion of assets for the benefit plan are held in pooled assets, there may be indirect investments in these

securities.

Cash Flows:

The following table shows expected cash flows for DB pension and other post-retirement benefit plans:

millions of dollars

Defined benefit

pension plans

Non-pension

benefit plans

Expected employer contributions

2024

$

34

$

19

Expected benefit payments

2024

172

21

2025

163

21

2026

166

21

2027

171

21

2028

173

20

2029 – 2033

890

95

Assumptions:

The following table shows the assumptions that have been used in accounting for DB pension and other

post-retirement benefit plans:

2023

2022

(weighted average assumptions)

Defined benefit

pension plans

Non-pension

benefit plans

Defined benefit

pension plans

Non-pension

benefit plans

Benefit obligation – December 31:

Discount rate - past service

4.89

%

4.89

%

5.33

%

5.31

%

Discount rate - future service

4.88

%

4.89

%

5.34

%

5.32

%

Rate of compensation increase

3.87

%

3.85

%

3.62

%

3.61

%

Health care trend - initial (next year)

-

6.04

%

-

5.40

%

 - ultimate 

-

3.76

%

-

3.77

%

 - year ultimate reached

2043

2043

Benefit cost for year ended December 31:

Discount rate - past service

5.33

%

5.31

%

3.05

%

2.81

%

Discount rate - future service

5.34

%

5.32

%

3.18

%

2.92

%

Expected long-term return on plan assets

6.56

%

2.16

%

6.07

%

1.32

%

Rate of compensation increase

3.62

%

3.61

%

3.31

%

3.29

%

Health care trend - initial (current year)

-

5.40

%

-

5.09

%

 - ultimate 

-

3.77

%

-

3.77

%

 - year ultimate reached

2043

2042

Actual assumptions used differ by plan.

The expected long-term rate of return on plan assets is based on historical and projected real rates of

return for the plan’s current asset allocation, and assumed inflation. A real rate of return is determined for

each asset class. Based on the asset allocation, an overall expected real rate of return for all assets is

determined. The asset return assumption is equal to the overall real rate of return assumption added to

the inflation assumption, adjusted for assumed expenses to be paid from the plan.

The discount rate is based on high-quality long-term corporate bonds, with maturities matching the

estimated cash flows from the pension plan.

Defined Contribution Plan:

Emera also provides a DC pension plan for certain employees. The Company’s contribution for the year

ended December 31, 2023 was $

45

 million (2022 – $

41

 million).

XML

Goodwill

12 Months Ended

Dec. 31, 2023

Goodwill [Abstract]

Goodwill

22. GOODWILL

The change in goodwill for the year ended December 31 was due to the following:

millions of dollars 

2023

2022

Balance, January 1

$

6,012

$

5,696

Change in FX rate

(141)

389

GBPC impairment charge

-

(73)

Balance, December 31

$

5,871

$

6,012

Goodwill is subject to an annual assessment for impairment at the reporting unit level. The goodwill on

Emera’s Consolidated Balance Sheets at December 31, 2023, primarily related to TECO Energy

(reporting units with goodwill are TEC, PGS, and NMGC). 

In 2023, Emera performed qualitative impairment assessments for NMGC and PGS, concluding that the

FV of the reporting units exceeded their respective carrying amounts, and as such, no quantitative

assessments were performed and

no

 impairment charges were recognized. Given the length of time

passed since the last quantitative impairment test for the TEC reporting unit, Emera elected to bypass a

qualitative assessment and performed a quantitative impairment assessment in Q4 2023 using a

combination of the income approach and market approach. This assessment estimated that the FV of the

TEC reporting unit exceeded its carrying amount, including goodwill, and as a result

no

 impairment

charges were recognized.

In 2022, the Company elected to bypass a qualitative assessment and performed a quantitative

impairment assessment for GBPC, using the income approach. It was determined that the FV did not

exceed its carrying amount, including goodwill. As a result of this assessment, a goodwill impairment

charge of $

73

 million was recorded in 2022, reducing the GBPC goodwill balance to nil as at December

31, 2022. This non-cash charge is included in “GBPC impairment charge” on the Consolidated

Statements of Income.

XML

Short-Term Debt

12 Months Ended

Dec. 31, 2023

Short-Term Debt [Abstract]

Short-Term Debt

23. SHORT-TERM DEBT

Emera’s short-term borrowings consist of commercial paper issuances, advances on revolving and non-

revolving credit facilities and short-term notes. Short-term debt and the related weighted-average interest

rates as at December 31 consisted of the following:

millions of dollars 

2023

Weighted

average 

interest rate

2022

Weighted

average 

interest rate

TEC

Advances on revolving credit facilities

$

277

5.68

%

$

1,380

5.00

%

Emera

Non-revolving term facilities

796

6.07

%

796

5.19

%

Bank indebtedness 

9

-

%

-

-

%

TECO Finance 

Advances on revolving credit and term facilities

245

6.54

%

481

5.47

%

PGS

Advances on revolving credit facilities

73

6.36

%

-

-

%

NMGC

Advances on revolving credit facilities

25

6.46

%

59

5.15

%

GBPC

Advances on revolving credit facilities

8

5.54

%

10

5.25

%

Short-term debt

$

1,433

$

2,726

The Company’s total short-term revolving and non-revolving credit facilities, outstanding borrowings and

available capacity as at December 31 were as follows: 

millions of dollars

Maturity

2023

2022

TEC - Unsecured committed revolving credit facility

2026

$

401

$

1,084

TECO Energy/TECO Finance - revolving credit facility

2026

-

542

TECO Finance - Unsecured committed revolving credit facility

2026

529

-

Emera - Unsecured non-revolving term facility

2024

400

400

Emera - Unsecured non-revolving term facility

2024

400

400

PGS - Unsecured revolving credit facility

2028

331

-

TEC - Unsecured revolving facility

2024

265

542

TEC - Unsecured revolving facility

2024

265

-

NMGC - Unsecured revolving credit facility

2026

165

169

Other - Unsecured committed revolving credit facilities

Various

17

18

Total

$

2,773

$

3,155

Less:

Advances under revolving credit and term facilities

1,433

2,731

Letters of credit issued within the credit facilities

3

4

Total advances under available facilities

1,436

2,735

Available capacity under existing agreements

$

1,337

$

420

The weighted average interest rate on outstanding short-term debt at December 31, 2023 was

5.95

 per

cent (2022 –

5.01

 per cent).

Recent Significant Financing Activity by Segment

Florida Electric Utilities 

On November 24, 2023, TEC repaid its $

400

 million USD unsecured non-revolving facility, which expired

on

December 13, 2023

. 

On April 3, 2023, TEC entered into a

364

-day, $

200

 million USD senior unsecured revolving credit facility

which matures on

April 1, 2024

. The credit agreement contains customary representations and

warranties, events of default and financial and other covenants, and bears interest at a variable interest

rate, based on either the term secured overnight financing rate (“SOFR”), Wells Fargo’s prime rate, the

federal funds rate or the one-month SOFR, plus a margin.

On March 1, 2023, TEC entered into a

364

-day, $

200

 million USD senior unsecured revolving credit

facility which matures on

February 28, 2024

. The credit facility contains customary representations and

warranties, events of default and financial and other covenants, and bears interest at a variable interest

rate, based on either the term SOFR, the Bank of Nova Scotia’s prime rate, the federal funds rate or the

one-month SOFR, plus a margin.

Gas Utilities and Infrastructure

On December 1, 2023, PGS entered into a $

250

 million USD senior unsecured revolving credit facility

with a group of banks, maturing on

December 1, 2028

. PGS has the ability to request the lenders to

increase their commitments under the credit facility by up to $

100

 million USD in the aggregate subject to

agreement from participating lenders. The credit agreement contains customary representations and

warranties, events of default and financial and other covenants, and bears interest at Bankers’

Acceptances or prime rate advances, plus a margin.

Other

On December 16, 2023, Emera amended its $

400

 million unsecured non-revolving facility to extend the

maturity date from

December 16, 2023

 to

December 16, 2024

. There were no other changes in

commercial terms from the prior agreement.

On June 30, 2023, Emera amended its $

400

 million unsecured non-revolving facility to extend the

maturity date from

August 2, 2023

 to

August 2, 2024

. There were no other changes in commercial terms

from the prior agreement.

XML

Other Current Liabilities

12 Months Ended

Dec. 31, 2023

Other Current Liabilities

Other Current Liabilities

24. OTHER CURRENT LIABILITIES

As at

December 31

December 31

millions of dollars 

2023

2022

Accrued charges

$

172

$

174

Nova Scotia Cap-and-Trade Program provision (note 6)

-

172

Accrued interest on long-term debt

107

97

Pension and post-retirement liabilities (note 21)

23

33

Sales and other taxes payable

11

14

Income tax payable

2

9

Other

112

80

$

427

$

579

XML

Long-Term Debt

12 Months Ended

Dec. 31, 2023

Long-term Debt [Abstract]

Long-term Debt

25. LONG-TERM DEBT

Bonds, notes and debentures are at fixed interest rates and are unsecured unless noted below. Included

are certain bankers’ acceptances and commercial paper where the Company has the intention and the

unencumbered ability to refinance the obligations for a period greater than one year.

Long-term debt as at December 31 consisted of the following:

Weighted average interest

rate

(1)

millions of dollars

2023

2022

Maturity

2023

2022

Emera 

Bankers acceptances, SOFR loans 

Variable

Variable

2027

$

465

$

403

Unsecured fixed rate notes

4.84%

2.90%

2030

500

500

Fixed to floating subordinated notes

(2)

6.75%

6.75%

2076

1,587

1,625

$

2,552

$

2,528

Emera Finance 

Unsecured senior notes

3.65%

3.65%

2024 - 2046

$

3,637

$

3,725

TEC

(3)

Fixed rate notes and bonds

4.61%

4.15%

2024 - 2051

$

5,654

$

4,341

PGS

Fixed rate notes and bonds

5.63%

3.78%

2028 - 2053

$

1,223

$

772

NMGC

Fixed rate notes and bonds

3.78%

3.11%

2026 - 2051

$

642

$

521

Non-revolving term facility, floating rate

Variable

Variable

2024

30

108

$

672

$

629

NMGI

Fixed rate notes and bonds

3.64%

3.64%

2024

$

198

$

203

NSPI

Discount Notes

(4)

Variable

Variable

2024 - 2027

$

721

$

881

Medium term fixed rate notes

5.13%

5.14%

2025 - 2097

3,165

2,665

$

3,886

$

3,546

EBP

Senior secured credit facility

Variable

Variable

2026

$

246

$

249

ECI

Secured senior notes

Variable

Variable

2027

$

75

$

86

Amortizing fixed rate notes

4.00%

3.97%

2026

79

100

Non-revolving term facility, floating rate

Variable

Variable

2025

29

30

Non-revolving term facility, fixed rate

2.15%

2.05%

2025 - 2027

155

91

Secured fixed rate senior notes

(5)

3.09%

3.06%

2024 - 2029

84

142

$

422

$

449

Adjustments

Fair market value adjustment - TECO Energy acquisition

$

-

$

2

Debt issuance costs

(125)

(126)

Amount due within one year

(676)

(574)

$

(801)

$

(698)

Long-Term Debt

$

17,689

$

15,744

(1) Weighted average interest rate of fixed rate long-term debt.

(2) In 2023, the Company recognized $

109

 million in interest expense (2022 – $

110

 million) related to its fixed to floating

subordinated notes.

(3) A substantial part of TEC’s tangible assets are pledged as collateral to secure its first mortgage bonds. There are currently no

bonds outstanding under TEC’s first mortgage bond indenture.

(4) Discount notes are backed by a revolving credit facility which matures in 2027. Banker’s acceptances are issued under NSPI’s

non-revolving term facility which matures in 2024. NSPI has the intention and unencumbered ability to refinance bankers’

acceptances for a period of greater than one year.

(5) Notes are issued and payable in either USD or BBD.

The Company’s total long-term revolving credit facilities, outstanding borrowings and available capacity as

at December 31 were as follows:

millions of dollars

Maturity

2023

2022

Emera – revolving credit facility

(1)

June 2027

$

900

$

900

TEC - Unsecured committed revolving credit facility

December 2026

657

-

NSPI - revolving credit facility

(1)

December 2027

800

800

NSPI - non-revolving credit facility

July 2024

400

400

Emera - Unsecured non-revolving credit facility

February 2024

400

-

NMGC - Unsecured non-revolving credit facility

March 2024

30

108

ECI – revolving credit facilities

October 2024

10

11

Total

$

3,197

$

2,219

Less:

Borrowings under credit facilities

1,884

1,396

Letters of credit issued inside credit facilities

6

12

Use of available facilities

$

1,890

$

1,408

Available capacity under existing agreements

$

1,307

$

811

(1) Advances on the revolving credit facility can be made by way of overdraft on accounts up to $

50

 million.

Debt Covenants

Emera and its subsidiaries have debt covenants associated with their credit facilities. Covenants are

tested regularly and the Company is in compliance with covenant requirements. Emera’s significant

covenants are listed below:

As at

Financial Covenant

Requirement

December 31, 2023

Emera

Syndicated credit facilities

Debt to capital ratio

Less than or equal to

0.70

 to 1

0.57

 : 1

Recent Significant Financing Activity by Segment

Florida Electric Utility

On January 30, 2024, TEC issued $

500

 million USD of senior unsecured bonds that bear interest at

4.90

per cent with a maturity date of

March 1, 2029

. Proceeds from the issuance were primarily used for

repayment of short-term borrowings outstanding under the

5

-year credit facility. Therefore, $

497

 million

USD of short-term borrowings that were repaid was classified as long-term debt at December 31, 2023.

Canadian Electric Utilities

On March 24, 2023, NSPI issued $

500

 million in unsecured notes. The issuance included $

300

 million

unsecured notes that bear interest at

4.95

 per cent with a maturity date of

November 15, 2032

, and $

200

million unsecured notes that bear interest at

5.36

 per cent with a maturity date of

March 24, 2053

. 

Gas Utilities and Infrastructure

On December 19, 2023, PGS completed an issuance of $

925

 million USD in senior notes. The issuance

included $

350

 million USD senior notes that bear interest at

5.42

 per cent with a maturity date of

December 19, 2028

, $

350

 million USD senior notes that bear interest at

5.63

 per cent with a maturity date

of

December 19, 2033

 and $

225

 million USD senior notes that bear interest at

5.94

 per cent with a

maturity date of

December 19, 2053

.

On October 19, 2023, NMGC issued $

100

 million USD in senior unsecured notes that bear interest at

6.36

 per cent with a maturity date of

October 19, 2033

.

Other Electric Utilities 

On May 24, 2023, GBPC issued a $

28

 million USD non-revolving term loan that bears interest at

4.00

 per

cent with a maturity date of

May 24, 2028

. 

Other 

On August 18, 2023, Emera entered into a $

400

 million non-revolving term facility with a maturity date of

February 19, 2024

. The credit agreement contains customary representations and warranties, events of

default and financial and other covenants, and bears interest at Bankers’ Acceptances or prime rate

advances, plus a margin. On February 16, 2024, Emera extended the term of this agreement to a

maturity date of

February 19, 2025

.

On May 2, 2023, Emera issued $

500

 million in senior unsecured notes that bear interest at

4.84

 per cent

with a maturity date of

May 2, 2030

.

Long-Term Debt Maturities

As at December 31, long-term debt maturities, including capital lease obligations, for each of the next five

years and in aggregate thereafter are as follows:

millions of dollars

2024

2025

2026

2027

2028

Thereafter

Total

Emera

$

199

$

-

$

1,587

$

266

$

-

$

500

$

2,552

Emera US Finance LP

397

-

992

-

-

2,248

3,637

TEC

397

-

-

-

-

5,257

5,654

PGS

-

-

-

-

463

760

1,223

NMGC

30

-

93

-

-

549

672

NMGI

198

-

-

-

-

-

198

NSPI

398

125

40

323

-

3,000

3,886

EBP

-

-

246

-

-

-

246

ECI

51

139

89

77

62

4

422

Total

$

1,670

$

264

$

3,047

$

666

$

525

$

12,318

$

18,490

XML

Asset Retirement Obligations

12 Months Ended

Dec. 31, 2023

Asset Retirement Obligations [Abstract]

Asset Retirement Obligations

26. ASSET RETIREMENT OBLIGATIONS

AROs mostly relate to reclamation of land at the thermal, hydro and combustion turbine sites; and the

disposal of polychlorinated biphenyls in transmission and distribution equipment and a pipeline site.

Certain hydro, transmission and distribution assets may have additional AROs that cannot be measured

as these assets are expected to be used for an indefinite period and, as a result, a reasonable estimate of

the FV of any related ARO cannot be made.

The change in ARO for the years ended December 31 is as follows:

millions of dollars

2023

2022

Balance, January 1

$

174

$

174

Accretion included in depreciation expense

9

9

Change in FX rate

(1)

3

Additions

-

1

Accretion deferred to regulatory asset (included in PP&E)

18

1

Liabilities settled

(8)

(1)

Revisions in estimated cash flows

-

(13)

Balance, December 31

$

192

$

174

XML

Commitments and Contingencies

12 Months Ended

Dec. 31, 2023

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

27. COMMITMENTS AND CONTINGENCIES

Commitments

As at December 31, 2023, contractual commitments (excluding pensions and other post-retirement

obligations, long-term debt and asset retirement obligations) for each of the next five years and in

aggregate thereafter consisted of the following:

millions of dollars

2024

2025

2026

2027

2028

Thereafter

Total

Transportation

(1)

$

696

$

495

$

405

$

388

$

338

$

2,597

$

4,919

Purchased power

(2)

274

249

263

312

312

3,435

4,845

Fuel, gas supply and storage

556

215

62

-

5

-

838

Capital projects

778

111

70

1

-

-

960

Equity investment commitments

(3)

240

-

-

-

-

-

240

Other

154

147

56

46

35

221

659

$

2,698

$

1,217

$

856

$

747

$

690

$

6,253

$

12,461

(1) Purchasing commitments for transportation of fuel and transportation capacity on various pipelines. Includes a commitment of

$

134

 million related to a gas transportation contract between PGS and SeaCoast through 2040.

(2) Annual requirement to purchase electricity production from IPPs or other utilities over varying contract lengths.

(3) Emera has a commitment to make equity contributions to the LIL related to an investment true up in 2024 and sustaining capital

contributions over the life of the partnership. The commercial agreements between Emera and Nalcor require true ups to finalize the

respective investment obligations of the parties in relation the Maritime Link and LIL which is expected to be approximately $

240

million in 2024. In addition, Emera has future commitments to provide sustaining capital to the LIL for routine capital and major

maintenance.

NSPI has a contractual obligation to pay NSPML for use of the Maritime Link over approximately

38 years

from its January 15, 2018 in-service date. In February 2022, the UARB issued its decision and Board

Order approving NSPML’s requested rate base of approximately $

1.8

 billion. In December 2023, the

UARB approved the collection of up to $

164

 million from NSPI for the recovery of Maritime Link costs in

2024. The timing and amounts payable to NSPML for the remainder of the

38

-year commitment period

are subject to UARB approval.

Construction of the LIL is complete, and the Newfoundland Electrical System Operator confirmed the

asset to be operating suitably to support reliable system operation and full functionality at

700

MW, which

was validated by the Government of Canada’s Independent Engineer issuing its Commissioning

Certificate on April 13, 2023.

Emera has committed to obtain certain transmission rights for Nalcor, if requested, to enable it to transmit

energy which is not otherwise used in Newfoundland and Labrador or Nova Scotia. Nalcor has the right to

transmit this energy from Nova Scotia to New England energy markets effective August 15, 2021 and

continuing for

50 years

. As transmission rights are contracted, the obligations are included within “Other”

in the above table.

Legal Proceedings

Superfund and Former Manufactured Gas Plant Sites

Previously, TEC had been a potentially responsible party (“PRP”) for certain superfund sites through its

Tampa Electric and former PGS divisions, as well as for certain former manufactured gas plant sites

through its PGS division. As a result of the separation of the PGS division into a separate legal entity,

Peoples Gas System, Inc. is also now a PRP for those sites (in addition to third party PRPs for certain

sites). While the aggregate joint and several liability associated with these sites has not changed as a

result of the PGS legal separation, the sites continue to present the potential for significant response

costs. As at December 31, 2023, the aggregate financial liability of the Florida utilities is estimated to be

$

15

 million ($

11

 million USD), primarily at PGS. This estimate assumes that other involved PRPs are

credit-worthy entities. This amount has been accrued and is primarily reflected in the long-term liability

section under “Other long-term liabilities” on the Consolidated Balance Sheets. The environmental

remediation costs associated with these sites are expected to be paid over many years. 

The estimated amounts represent only the portion of the cleanup costs attributable to the Florida utilities.

The estimates to perform the work are based on the Florida utilities’ experience with similar work,

adjusted for site-specific conditions and agreements with the respective governmental agencies. The

estimates are made in current dollars, are not discounted and do not assume any insurance recoveries.

In instances where other PRPs are involved, most of those PRPs are believed to be currently credit-

worthy and are likely to continue to be credit-worthy for the duration of the remediation work. However, in

those instances that they are not, the Florida utilities could be liable for more than their actual percentage

of the remediation costs. Other factors that could impact these estimates include additional testing and

investigation which could expand the scope of the cleanup activities, additional liability that might arise

from the cleanup activities themselves or changes in laws or regulations that could require additional

remediation. Under current regulations, these costs are recoverable through customer rates established

in base rate proceedings.

Other Legal Proceedings

Emera and its subsidiaries may, from time to time, be involved in other legal proceedings, claims and

litigation that arise in the ordinary course of business which the Company believes would not reasonably

be expected to have a material adverse effect on the financial condition of the Company.

Principal Financial Risks and Uncertainties

Emera believes the following principal financial risks could materially affect the Company in the normal

course of business. Risks associated with derivative instruments and FV measurements are discussed in

note 15 and note 16. 

Sound risk management is an essential discipline for running the business efficiently and pursuing the

Company’s strategy successfully. Emera has an enterprise-wide risk management process, overseen by

its Enterprise Risk Management Committee (“ERMC”) and monitored by the Board of Directors, to ensure

an effective, consistent and coherent approach to risk management. The Board of Directors has a Risk

and Sustainability Committee (‘RSC”) with a mandate that includes oversight of the Company’s Enterprise

Risk Management framework, including the identification, assessment, monitoring and management of

enterprise risks. It also includes oversight of the Company’s approach to sustainability and its

performance relative to its sustainability objectives.

Regulatory and Political Risk

The Company’s rate-regulated subsidiaries and certain investments subject to significant influence are

subject to risk of the recovery of costs and investments. Regulatory and political risk can include changes

in regulatory frameworks, shifts in government policy, legislative changes, and regulatory decisions.

As cost-of-service utilities with an obligation to serve customers, Emera’s utilities operate under formal

regulatory frameworks, and must obtain regulatory approval to change or add rates and/or riders. Emera

also holds investments in entities in which it has significant influence, and which are subject to regulatory

and political risk including NSPML, LIL, and M&NP. As a regulated Group II pipeline, the tolls of

Brunswick Pipeline are regulated by the CER on a complaint basis, as opposed to the regulatory approval

process described above. In the absence of a complaint, the CER does not normally undertake a detailed

examination of Brunswick Pipeline’s tolls, which are subject to a firm service agreement, expiring in 2034,

with Repsol Energy North America Canada Partnership. 

Regulators administer the regulatory frameworks covering material aspects of the utilities’ businesses,

including applying market-based tests to determine the appropriate customer rates and/or riders, the

underlying allowed ROEs, deemed capital structures, capital investment, the terms and conditions for the

provision of service, performance standards, and affiliate transactions. Regulators also review the

prudency of costs and other decisions that impact customer rates and reliability of service and work to

ensure the financial health of the utility for the benefit of customers. Costs and investments can be

recovered upon approval by the respective regulator as an adjustment to rates and/or riders, which

normally require a public hearing process or may be mandated by other governmental bodies. During

public hearing processes, consultants and customer representatives scrutinize the costs, actions and

plans of these rate-regulated companies, and their respective regulators determine whether to allow

recovery and to adjust rates based upon the evidence and any contrary evidence from other parties. In

some circumstances, other government bodies may influence the setting of rates. Regulatory decisions,

legislative changes, and prolonged delays in the recovery of costs or regulatory assets could result in

decreased rate affordability for customers and could materially affect Emera and its utilities. 

Emera’s utilities generally manage this risk through transparent regulatory disclosure, ongoing

stakeholder and government consultation and multi-party engagement on aspects such as utility

operations, regulatory audits, rate filings and capital plans. The subsidiaries work to establish

collaborative relationships with regulatory stakeholders, including customer representatives, both through

its approach to filings and additional efforts with technical conferences and, where appropriate, negotiated

settlements. 

Changes in government and shifts in government policy and legislation can impact the commercial and

regulatory frameworks under which Emera and its subsidiaries operate. This includes initiatives regarding

deregulation or restructuring of the energy industry. Deregulation or restructuring of the energy industry

may result in increased competition and unrecovered costs that could adversely affect the Company’s

operations, net income and cash flows. State and local policies in some United States jurisdictions have

sought to prevent or limit the ability of utilities to provide customers the choice to use natural gas while in

other jurisdictions policies have been adopted to prevent limitations on the use of natural gas. Changes in

applicable state or local laws and regulations, including electrification legislation, could adversely impact

PGS and NMGC.

Emera cannot predict future legislative, policy, or regulatory changes, whether caused by economic,

political or other factors, or its ability to respond in an effective and timely manner or the resulting

compliance costs. Government interference in the regulatory process can undermine regulatory stability,

predictability, and independence, and could have a material adverse effect on the Company.

Foreign Exchange Risk 

The Company is exposed to foreign currency exchange rate changes. Emera operates internationally,

with an increasing amount of the Company’s net income earned outside of Canada. As such, Emera is

exposed to movements in exchange rates between the CAD and, particularly, the USD, which could

positively or adversely affect results. 

Consistent with the Company’s risk management policies, Emera manages currency risks through

matching United States denominated debt to finance its United States operations and may use foreign

currency derivative instruments to hedge specific transactions and earnings exposure. The Company may

enter FX forward and swap contracts to limit exposure on certain foreign currency transactions such as

fuel purchases, revenue streams and capital expenditures, and on net income earned outside of Canada.

The regulatory framework for the Company’s rate-regulated subsidiaries permits the recovery of prudently

incurred costs, including FX.

The Company does not utilize derivative financial instruments for foreign currency trading or speculative

purposes or to hedge the value of its investments in foreign subsidiaries. Exchange gains and losses on

net investments in foreign subsidiaries do not impact net income as they are reported in AOCI.

Liquidity and Capital Market Risk

Liquidity risk relates to Emera’s ability to ensure sufficient funds are available to meet its financial

obligations. Emera manages this risk by forecasting cash requirements on a continuous basis to

determine whether sufficient funds are available. Liquidity and capital needs could be financed through

internally generated cash flows, asset sales, short-term credit facilities, and ongoing access to capital

markets. 

Emera’s access to capital and cost of borrowing is subject to several risk factors, including financial

market conditions, market disruptions and ratings assigned by various market analysts, including credit

rating agencies. Disruptions in capital markets could prevent Emera from issuing new securities or cause

the Company to issue securities with less than preferred terms and conditions. Emera’s growth plan

requires significant capital investments in PP&E and the risk associated with changes in interest rates

could have an adverse effect on the cost of financing. The Company’s future access to capital and cost of

borrowing may be impacted by various market disruptions. The inability to access cost-effective capital

could have a material impact on Emera’s ability to fund its growth plan. 

Emera is subject to financial risk associated with changes in its credit ratings. There are a number of

factors that rating agencies evaluate to determine credit ratings, including the Company’s business, its

regulatory framework and legislative environment, political interference in the regulatory process, the

ability to recover costs and earn returns, diversification, leverage, liquidity and increased exposure to

climate change-related impacts, including increased frequency and severity of hurricanes and other

severe weather events. A decrease in a credit rating could result in higher interest rates in future

financings, increased borrowing costs under certain existing credit facilities, limit access to the

commercial paper market, or limit the availability of adequate credit support for subsidiary operations. For

more information on interest rate risk, refer to “General Economic Risk – Interest Rate Risk”. For certain

derivative instruments, if the credit ratings of the Company were reduced below investment grade, the full

value of the net liability of these positions could be required to be posted as collateral. Emera manages

these risks by actively monitoring and managing key financial metrics with the objective of sustaining

investment grade credit ratings.

The Company has exposure to its own common share price through the issuance of various forms of

stock-based compensation, which affect earnings through revaluation of the outstanding units every

period. The Company uses equity derivatives to reduce the earnings volatility derived from stock-based

compensation.

General Economic Risk

The Company has exposure to the macro-economic conditions in North America and in other geographic

regions in which Emera operates. Like most utilities, economic factors such as consumer income,

employment and housing affect demand for electricity and natural gas, and in turn the Company’s

financial results. Adverse changes in general economic conditions and inflation may impact the ability of

customers to afford rate increases arising from increases to fuel, operating, capital, environmental

compliance, and other costs, and therefore could materially affect Emera and its utilities. This may also

result in higher credit and counterparty risk, adverse shifts in government policy and legislation, and/or

increased risk to full and timely recovery of costs and regulatory assets.

Interest Rate Risk:

Emera utilizes a combination of fixed and floating rate debt financing for operations and capital

expenditures, resulting in an exposure to interest rate risk. Emera seeks to manage interest rate risk

through a portfolio approach that includes the use of fixed and floating rate debt with staggered

maturities. The Company will, from time to time, issue long-term debt or enter interest rate hedging

contracts to limit its exposure to fluctuations in floating interest rate debt.

For Emera’s regulated subsidiaries, the cost of debt is a component of rates and prudently incurred debt

costs are recovered from customers. Regulatory ROE will generally follow the direction of interest rates,

such that regulatory ROEs are likely to fall in times of reducing interest rates and rise in times of

increasing interest rates, albeit not directly and generally with a lag period reflecting the regulatory

process. Rising interest rates may also negatively affect the economic viability of project development

and acquisition initiatives.

Interest rates could also be impacted by changes in credit ratings. For more information, refer to “Liquidity

and Capital Market Risk”.

As with most other utilities and other similar yield-returning investments, Emera’s share price may be

affected by changes in interest rates and could underperform the market in an environment of rising

interest rates.

Inflation Risk: 

The Company may be exposed to changes in inflation that may result in increased operating and

maintenance costs, capital investment, and fuel costs compared to the revenues provided by customer

rates. Emera’s utilities have budgeting and forecasting processes to identify inflationary risk factors and

measure operating performance, as well as collective bargaining agreements that mitigate the short-term

impact of inflation on labour costs of unionized employees.

Commodity Price Risk

The Company’s utility fuel supply and purchase of other commodities is subject to commodity price risk.

In addition, Emera Energy is subject to commodity price risk through its portfolio of commodity contracts

and arrangements.

The Company manages this risk through established processes and practices to identify, monitor, report

and mitigate these risks. These include the Company’s commercial arrangements, such as the

combination of supply and purchase agreements, asset management agreements, pipeline transportation

agreements and financial hedging instruments. In addition, its credit policies, counterparty credit

assessments, market and credit position reporting, and other risk management and reporting practices,

are also used to manage and mitigate this risk.

Regulated Utilities:

The Company’s utility fuel supply is exposed to broader global conditions, which may include impacts on

delivery reliability and price, despite contracted terms. Supply and demand dynamics in fuel markets can

be affected by a wide range of factors which are difficult to predict and may change rapidly, including but

not limited to currency fluctuations, changes in global economic conditions, natural disasters,

transportation or production disruptions, and geo-political risks such as political instability, conflicts,

changes to international trade agreements, trade sanctions or embargos. The Company seeks to manage

this risk using financial hedging instruments and physical contracts and through contractual protection

with counterparties, where applicable. 

The majority of Emera’s regulated electric and gas utilities have adopted and implemented fuel

adjustment mechanisms and purchased gas adjustment mechanisms respectively, which further helps

manage commodity price risk, as the regulatory framework for the Company’s rate-regulated subsidiaries

permits the recovery of prudently incurred fuel and gas costs. There is no assurance that such

mechanisms and regulatory frameworks will continue to exist in the future. Prolonged and substantial

increases in fuel prices could result in decreased rate affordability, increased risk of recovery of costs or

regulatory assets, and/or negative impacts on customer consumption patterns and sales.

Emera Energy Marketing and Trading:

Emera Energy has employed further measures to manage commodity risk. The majority of Emera

Energy’s portfolio of electricity and gas marketing and trading contracts and, in particular, its natural gas

asset management arrangements, are contracted on a back-to-back basis, avoiding any material long or

short commodity positions. However, the portfolio is subject to commodity price risk, particularly with

respect to basis point differentials between relevant markets in the event of an operational issue or

counterparty default. Changes in commodity prices can also result in increased collateral requirements

associated with physical contracts and financial hedges, resulting in higher liquidity requirements and

increased costs to the business.

To measure commodity price risk exposure, Emera Energy employs a number of controls and processes,

including an estimated VaR analysis of its exposures. The VaR amount represents an estimate of the

potential change in FV that could occur from changes in Emera Energy’s portfolio or changes in market

factors within a given confidence level, if an instrument or portfolio is held for a specified time period. The

VaR calculation is used to quantify exposure to market risk associated with physical commodities,

primarily natural gas and power positions.

Income Tax Risk

The computation of the Company’s provision for income taxes is impacted by changes in tax legislation in

Canada, the United States and the Caribbean. Any such changes could affect the Company’s future

earnings, cash flows, and financial position. The value of Emera’s existing deferred income tax assets

and liabilities are determined by existing tax laws and could be negatively impacted by changes in laws.

Emera monitors the status of existing tax laws to ensure that changes impacting the Company are

appropriately reflected in the Company’s tax compliance filings and financial results.

Guarantees and Letters of Credit

Emera has guarantees and letters of credit on behalf of third parties outstanding. The following significant

guarantees and letters of credit are not included within the Consolidated Balance Sheets as at December

31, 2023

:

TECO Energy has issued a guarantee in connection with SeaCoast’s performance of obligations under a

gas transportation precedent agreement. The guarantee is for a maximum potential amount of $

45

 million

USD if SeaCoast fails to pay or perform under the contract. The guarantee expires five years after the

gas transportation precedent agreement termination date, which was terminated on January 1, 2022. In

the event that TECO Energy’s and Emera’s long-term senior unsecured credit ratings are downgraded

below investment grade by Moody’s Investor Services (“Moody’s”) or S&P Global Ratings (“S&P”). TECO

Energy would be required to provide its counterparty a letter of credit or cash deposit of $

27

 million USD.

TECO Energy issued a guarantee in connection with SeaCoast’s performance obligations under a firm

service agreement, which expires on December 31, 2055, subject to two extension terms at the option of

the counterparty with a final expiration date of December 31, 2071. The guarantee is for a maximum

potential amount of $

13

 million USD if SeaCoast fails to pay or perform under the firm service agreement.

In the event that TECO Energy’s long-term senior unsecured credit ratings are downgraded below

investment grade by Moody’s or S&P, TECO Energy would need to provide either a substitute guarantee

from an affiliate with an investment grade credit rating or a letter of credit or cash deposit of $

13

 million

USD.

Emera Inc. has issued a guarantee of $

66

 million USD relating to outstanding notes of ECI. This

guarantee will automatically terminate on the date upon which the obligations have been repaid in full.

NSPI has issued guarantees on behalf of its subsidiary, NS Power Energy Marketing Incorporated, in the

amount of $

104

 million USD (2022 – $

119

 million USD) with terms of varying lengths.

The Company has standby letters of credit and surety bonds in the amount of $

103

 million USD

(December 31, 2022 – $

145

 million USD) to third parties that have extended credit to Emera and its

subsidiaries. These letters of credit and surety bonds typically have a one-year term and are renewed

annually as required.

Emera Inc., on behalf of NSPI, has a standby letter of credit to secure obligations under a supplementary

retirement plan. The expiry date of this letter of credit was extended to June 2024. The amount committed

as at December 31, 2023 was $

56

 million (December 31, 2022 – $

63

 million).

Collaborative Arrangements

For the years ended December 31, 2023 and 2022, the Company has identified the following material

collaborative arrangements:

Through NSPI, the Company is a participant in three wind energy projects in Nova Scotia. The

percentage ownership of the wind project assets is based on the relative value of each party’s project

assets by the total project assets. NSPI has power purchase arrangements to purchase the entire net

output of the projects and, therefore, NSPI’s portion of the revenues are recorded net within regulated fuel

for generation and purchased power. NSPI’s portion of operating expenses is recorded in “OM&G” on the

Consolidated Statements of Income. In 2023, NSPI recognized $

8

 million net expense (2022 – $

12

million) in “Regulated fuel for generation and purchased power” and $

3

 million (2022 – $

3

 million) in

“OM&G” on the Consolidated Statements of Income.

XML

Cumulative Preferred Stock

12 Months Ended

Dec. 31, 2023

Cumulative Preferred Stock [Abstract]

Cumulative Preferred Stock

28. CUMULATIVE PREFERRED STOCK

Authorized:

Unlimited number of First Preferred shares, issuable in series.

Unlimited number of Second Preferred shares, issuable in series.

December 31, 2023

December 31, 2022

Annual Dividend

Redemption

Issued and

Net

Issued and

Net 

Per Share

Price per share

Outstanding

Proceeds

Outstanding

Proceeds

Series A

$

0.5456

$

25.00

4,866,814

$

119

4,866,814

$

119

Series B

Floating

$

25.00

1,133,186

$

28

1,133,186

$

28

Series C

$

1.6085

$

25.00

10,000,000

$

245

10,000,000

$

245

Series E

$

1.1250

$

25.00

5,000,000

$

122

5,000,000

$

122

Series F

$

1.0505

$

25.00

8,000,000

$

195

8,000,000

$

195

Series H

$

1.5810

$

25.00

12,000,000

$

295

12,000,000

$

295

Series J

$

1.0625

$

25.00

8,000,000

$

196

8,000,000

$

196

Series L

$

1.1500

$

26.00

9,000,000

$

222

9,000,000

$

222

Total

58,000,000

$

1,422

58,000,000

$

1,422

Characteristics of the First Preferred Shares:

First Preferred Shares

(1)(2)

Initial Yield 

(%)

Current

Annual

Dividend 

($)

Minimum 

Reset

Dividend

Yield (%)

Earliest Redemption

and/or Conversion

Option Date

Redemption

Value 

($)

Right to

Convert on

a one for

one basis

Fixed rate reset

(3)(4)

 Series A

4.400

0.5456

1.84

August 15, 2025

25.00

Series B

 Series C

 (5)(6)

4.100

1.6085

2.65

August 15, 2028

25.00

Series D

 Series F

4.202

1.0505

2.63

February 15, 2025

25.00

Series G

Minimum rate reset

(3)(4)

 Series B

2.393

Floating

1.84

August 15, 2025

25.00

Series A

 Series H

(5)(7)

4.900

1.5810

4.90

August 15, 2028

25.00

Series I

 Series J

4.250

1.0625

4.25

May 15, 2026

25.00

Series K

Perpetual fixed rate

 Series E

 (8)

4.500

1.1250

25.00

 Series L

(9)

4.600

1.1500

November 15, 2026

26.00

(1) Holders are entitled to receive fixed or floating cumulative cash dividends when declared by the Board of Directors of the

Corporation.

(2) On or after the specified redemption dates, the Corporation has the option to redeem for cash the outstanding First Preferred

Shares, in whole or in part, at the specified per share redemption value plus all accrued and unpaid dividends up to but excluding the

dates fixed for redemption.

(3) On the redemption and/or conversion option date the reset annual dividend per share will be determined by multiplying $

25.00

 per

share by the annual fixed or floating dividend rate, which for Series A, C, F and H is the sum of the five-year Government of Canada

Bond Yield on the applicable reset date, plus the applicable reset dividend yield (Series H annual reset rate must be a minimum of

4.90

 per cent) and for Series B equals the Government of Treasury Bill Rate on the applicable reset date, plus 1.84 per cent.

(4) On each conversion option date, the holders have the option, subject to certain conditions, to convert any or all of their Shares

into an equal number of Cumulative Redeemable First Preferred Shares of a specified series. The Company has the right to redeem 

the outstanding Preferred Shares, Series D, Series G and Series I shares without the consent of the holder every five years thereafter

for cash, in whole or in part at a price of $

25.00

 per share plus all accrued and unpaid dividends up to but excluding the date fixed for

redemption and $

25.50

 per share plus all accrued and unpaid dividends up to but excluding the date fixed for redemption in the case

of redemptions on any other date after August 15, 2028, February 15, 2025 and August 15, 2028, respectively. The reset dividend

yield for Series I equals the Government of Treasury Bill Rate on the applicable reset date, plus

2.54

 per cent.

(5) On July 6, 2023, Emera announced it would not redeem the outstanding Preferred Shares, Series C and Series H on August 15,

2023. On August 4, 2023, Emera announced after having taken into account all conversion notices received from holders, no Series

C Shares were converted into Series D Shares and no Series H Shares were converted into Series I shares. 

(6) The annual fixed dividend per share for Series C Shares was reset from $

1.1802

 to $

1.6085

 for the five-year period from and

including August 15, 2028.

(7) The annual fixed dividend per share for Series H Shares was reset from $

1.2250

 to $

1.5810

 for the five-year period from and

including August 15, 2028.

(8) First Preferred Shares, Series E are redeemable at $25.00 per share.

(9) First Preferred Shares, Series L are redeemable at $

26.00

 on or after November 15, 2026 to November 15, 2027, decreasing

$

0.25

 each year until November 15, 2030 and $

25.00

 per share thereafter.

First Preferred Shares are neither redeemable at the option of the shareholder nor have a mandatory

redemption date. They are classified as equity and the associated dividends are deducted on the

Consolidated Statements of Income before arriving at “Net income attributable to common shareholders”

and shown on the Consolidated Statement of Changes in Equity as a deduction from retained earnings.

The First Preferred Shares of each series rank on a parity with the First Preferred Shares of every other

series and are entitled to a preference over the Second Preferred Shares, the Common Shares, and any

other shares ranking junior to the First Preferred Shares with respect to the payment of dividends and the

distribution of the remaining property and assets or return of capital of the Company in the liquidation,

dissolution or wind-up, whether voluntary or involuntary.

In the event the Company fails to pay, in aggregate, eight quarterly dividends on any series of the First

Preferred Shares, the holders of the First Preferred Shares, for only so long as the dividends remain in

arrears, will be entitled to attend any meeting of shareholders of the Company at which directors are to be

elected and to vote for the election of two directors out of the total number of directors elected at any such

meeting.

XML

Non-Controlling Interest in Subsidiaries

12 Months Ended

Dec. 31, 2023

Non-Controlling Interest in Subsidiaries [Abstract]

Non-Controlling Interest in Subsidiaries

29. NON-CONTROLLING INTEREST IN SUBSIDIARIES

As at

December 31

December 31

millions of dollars 

2023

2022

Preferred shares of GBPC 

$

14

$

14

$

14

$

14

Preferred shares of GBPC:

Authorized:

10,000

 non-voting cumulative redeemable variable perpetual preferred shares.

2023

2022

Issued and outstanding:

number of

shares

millions of

dollars

number of

shares

millions of

dollars

Outstanding as at December 31

10,000

$

14

10,000

$

14

GBPC Non–Voting Cumulative Variable Perpetual Preferred Stock:

The preferred shares are redeemable by GBPC after June 17, 2021

, at $

1,000

 Bahamian per share plus

accrued and unpaid dividends and are entitled to a

6.0 per cent per annum fixed cumulative preferential

dividend to be paid semi-annually

. 

The Preferred Shares rank behind GBPC’s current and future secured and unsecured debt and ahead of

all of GBPC’s current and future common stock.

XML

Supplementary Information to Consolidated Statements of Cash Flows

12 Months Ended

Dec. 31, 2023

Supplementary Information to Consolidated Statements of Cash Flows [Abstract]

Supplementary Information to Consolidated Statements of Cash Flows

30. SUPPLEMENTARY INFORMATION TO CONSOLIDATED STATEMENTS OF

CASH FLOWS

For the 

Year ended December 31

millions of dollars

2023

2022

Changes in non-cash working capital:

 Inventory

$

(31)

$

(214)

 Receivables and other current assets

(1)

653

(636)

 Accounts payable

(538)

423

 Other current liabilities

(2)

(179)

193

Total non-cash working capital 

$

(95)

$

(234)

(1) Includes $

162

 million related to the January 2023 settlement of NMGC gas hedges (2022 – ($

162

) million). Offsetting regulatory

liability is included in operating cash flow before working capital resulting in no impact to net cash provided by operating activities.

(2) Includes ($

166

) million related to the Nova Scotia Cap-and-Trade program (2022 – $

172

 million). For further detail, refer to note

6. Offsetting regulatory asset (FAM) balance is included in operating cash flow before working capital resulting in no impact to net

cash provided by operating activities.

For the 

Year ended December 31

millions of dollars

2023

2022

Supplemental disclosure of cash paid:

Interest

$

930

$

699

Income taxes

$

43

$

67

Supplemental disclosure of non-cash activities:

Common share dividends reinvested

$

271

$

237

Decrease in accrued capital expenditures

$

(19)

$

(13)

Reclassification of short-term debt to long-term debt

$

657

$

-

Reclassification of long-term debt to short-term debt

$

-

$

500

Supplemental disclosure of operating activities:

Net change in short-term regulatory assets and liabilities

$

123

$

(157)

XML

Stock Based Compensation

12 Months Ended

Dec. 31, 2023

Stock-Based Compensation [Abstract]

Stock-based Compensation

31. STOCK-BASED COMPENSATION

Employee Common Share Purchase Plan and Common Shareholders Dividend

Reinvestment and Share Purchase Plan

Eligible employees may participate in the ECSPP. As of December 31, 2023, the plan allows employees

to make cash contributions of a minimum of $25 to a maximum of $20,000 CAD or $15,000 USD per year

for the purpose of purchasing common shares of Emera. The Company also contributes 20 per cent of

the employees’ contributions to the plan.

The plan allows reinvestment of dividends for all participants except where prohibited by law.

 The

maximum aggregate number of Emera common shares reserved for issuance under this plan is

7

 million

common shares. As at December 31, 2023, Emera was in compliance with this requirement.

Compensation cost for shares issued under the ECSPP for the year ended December 31, 2023 was $

3

million (2022 – $

3

 million) and was included in “OM&G” on the Consolidated Statements of Income. 

The Company also has a Common Shareholders DRIP, which provides an opportunity for shareholders

residing in Canada to reinvest dividends and purchase common shares. This plan provides for a discount

of up to 5 per cent from the average market price of Emera’s common shares for common shares

purchased in connection with the reinvestment of cash dividends. The discount was 2 per cent in 2023.

Stock-Based Compensation Plans

Stock Option Plan

The Company has a stock option plan that grants options to senior management of the Company for a

maximum term of 10 years. The option price of the stock options is the closing price of the Company’s

common shares on the Toronto Stock Exchange on the last business day on which such shares were

traded before the date on which the option is granted. The maximum aggregate number of shares

issuable under this plan is 14.7 million shares. As at December 31, 2023, Emera was in compliance with

this requirement.

Stock options granted in 2021 and prior vest in 25 per cent increments on the first, second, third and

fourth anniversaries of the date of the grant. Stock options granted in 2022 and thereafter vest in 20 per

cent increments on the first, second, third, fourth and fifth anniversaries of the date of the grant. If an

option is not exercised within 10 years, it expires and the optionee loses all rights thereunder. The holder

of the option has no rights as a shareholder until the option is exercised and shares have been issued.

The total number of stocks to be optioned to any optionee shall not exceed five per cent of the issued and

outstanding common stocks on the date the option is granted.

For stock options granted in 2021 and prior, unless a stock option has expired, vested options may be

exercised within the

27 months

 following the option holder’s date of retirement,

six months

 following a

termination without just cause or death, and within

sixty days

 following the date of termination for just

cause or resignation. Commencing with the 2022 stock option grant, vested options may be exercised

during the full term of the option following the option holders date of retirement,

six months

 following a

termination without just cause or death, and within

sixty days

 following the date of termination for just

cause or resignation. If stock options are not exercised within such time, they expire.

The Company uses the Black-Scholes valuation model to estimate the compensation expense related to

its stock-based compensation and recognizes the expense over the vesting period on a straight-line

basis.

The following table shows the weighted average FV per stock option along with the assumptions

incorporated into the valuation models for options granted, for the year-ended December 31:

2023

2022

Weighted average FV per option

$

6.32

$

5.35

Expected term

(1)

5

 years

5

 years

Risk-free interest rate

(2)

3.53

%

1.79

%

Expected dividend yield

(3)

5.05

%

4.55

%

Expected volatility

(4)

20.07

%

18.87

%

(1) The expected term of the option awards is calculated based on historical exercise behaviour and represents the period of time

that the options are expected to be outstanding.

(2) Based on the Bank of Canada five-year government bond yields.

(3) Incorporates current dividend rates and historical dividend increase patterns.

(4) Estimated using the five-year historical volatility.

The following table summarizes stock option information for 2023:

Total Options

Non-Vested Options

(1)

Number of

Options

 Weighted

average exercise

price per share

Number of

Options

Weighted

average grant

date fair-value

Outstanding as at December 31, 2022

2,853,879

$

50.41

1,348,400

$

4.08

Granted 

483,100

54.64

483,100

6.32

Exercised

(146,475)

43.94

N/A

N/A

Forfeited

(94,900)

56.32

(51,625)

3.61

Vested

N/A

N/A

(526,620)

3.58

Options outstanding December 31, 2023

3,095,604

$

51.20

1,253,255

$

5.17

Options exercisable December 31, 2023

(2)(3)

1,842,349

$

48.39

(1) As at December 31, 2023, there was $

5

 million of unrecognized compensation related to stock options not yet vested which is

expected to be recognized over a weighted average period of approximately

3

 years (2022 – $

4

 million,

3

 years).

(2) As at December 31, 2023, the weighted average remaining term of vested options was

5

 years with an aggregate intrinsic value of

$

8

 million (2022 –

5

 years, $

10

 million).

(3) As at December 31, 2023, the FV of options that vested in the year was $

2

 million (2022 – $

2

 million).

Compensation cost recognized for stock options for the year ended December 31, 2023 was $

2

 million

(2022 – $

2

 million), which was included in “OM&G” on the Consolidated Statements of Income. 

As at December 31, 2023, cash received from option exercises was $

6

 million (2022 – $

9

 million). The

total intrinsic value of options exercised for the year ended December 31, 2023 was $

2

 million (2022 – $

4

million). The range of exercise prices for the options outstanding as at December 31, 2023 was $

32.35

 to

$

60.03

 (2022 – $

32.35

 to $

60.03

).

Share Unit Plans

The Company has DSU, PSU and RSU plans. The plans and the liabilities are marked-to-market at the

end of each period based on an average common share price at the end of the period.

Deferred Share Unit Plans 

Under the Directors’ DSU plan, Directors of the Company may elect to receive all or any portion of their

compensation in DSUs in lieu of cash compensation, subject to requirements to receive a minimum

portion of their annual retainer in DSUs. Directors’ fees are paid on a quarterly basis and, at the time of

each payment of fees, the applicable amount is converted to DSUs. A DSU has a value equal to one

Emera common share. When a dividend is paid on Emera’s common shares, the Director’s DSU account

is credited with additional DSUs. DSUs cannot be redeemed for cash until the Director retires, resigns or

otherwise leaves the Board. The cash redemption value of a DSU equals the market value of a common

share at the time of redemption, pursuant to the plan. Following retirement or resignation from the Board,

the value of the DSUs credited to the participant’s account is calculated by multiplying the number of

DSUs in the participant’s account by Emera’s closing common share price on the date DSUs are

redeemed.

Under the executive and senior management DSU plan, each participant may elect to defer all or a

percentage of their annual incentive award in the form of DSUs with the understanding, for participants

who are subject to executive share ownership guidelines, a minimum of 50 per cent of the value of their

actual annual incentive award (25 per cent in the first year of the program) will be payable in DSUs until

the applicable guidelines are met.

When short-term incentive awards are determined, the amount elected is converted to DSUs, which have

a value equal to the market price of an Emera common share. When a dividend is paid on Emera’s

common shares, each participant’s DSU account is allocated additional DSUs equal in value to the

dividends paid on an equivalent number of Emera common shares. Following termination of employment

or retirement, and by December 15 of the calendar year after termination or retirement, the value of the

DSUs credited to the participant’s account is calculated by multiplying the number of DSUs in the

participant’s account by the average of Emera’s stock closing price for the fifty trading days prior to a

given calculation date. Payments are made in cash.

In addition, special DSU awards may be made from time to time by the Management Resources and

Compensation Committee (“MRCC”), to selected executives and senior management to recognize

singular achievements or by achieving certain corporate objectives.

A summary of the activity related to employee and director DSUs for the year ended December 31, 2023

is presented in the following table:

Employee

DSU

Weighted

Average

Grant Date

FV

Director 

DSU

Weighted

Average

Grant Date

FV

Outstanding as at December 31, 2022

627,223

$

41.55

664,258

$

45.83

Granted including DRIP

85,740

47.66

117,893

49.99

Exercised

N/A

N/A

(53,093)

49.39

Outstanding and exercisable as at December 31, 2023

712,963

$

42.29

729,058

$

46.24

Compensation cost recovery recognized for employee and director DSU’s for the year ended December

31, 2023 was $

2

 million (2022 – $

6

 million). Tax expense related to this compensation cost recovery for

share units realized for the year ended December 31, 2023 was $

1

 million (2022 – $

2

 million). The

aggregate intrinsic value of the outstanding shares for the year ended December 31, 2023 for employees

was $

36

 million (2022 – $

33

 million). The aggregate intrinsic value of the outstanding shares for the year

ended December 31, 2023 for directors was $

37

 million (2022 – $

34

 million). Cash payments made

during the year ended December 31, 2023 associated with the DSU plan were $

3

 million (2022 – $

8

million).

Performance Share Unit Plan 

Under the PSU plan, certain executive and senior employees are eligible for long-term incentives payable

through the plan. PSUs are granted annually for three-year overlapping performance cycles, resulting in a

cash payment. PSUs are granted based on the average of Emera’s stock closing price for the fifty trading

days prior to the effective grant date. Dividend equivalents are awarded and paid in the form of additional

PSUs. The PSU value varies according to the Emera common share market price and corporate

performance.

PSUs vest at the end of the three-year cycle and the payouts will be calculated and approved by the

MRCC early in the following year. The value of the payout considers actual service over the performance

cycle and may be pro-rated in certain departure scenarios. In the case of retirement, as defined in the

PSU plan, grants may continue to vest in full and payout in normal course post-retirement.

A summary of the activity related to employee PSUs for the year ended December 31, 2023 is presented

in the following table:

Employee PSU

Weighted Average

Grant Date FV

Aggregate intrinsic value

Outstanding as at December 31, 2022

690,446

$

56.24

$

40

Granted including DRIP

386,261

52.71

Exercised

(323,155)

54.62

Forfeited

(10,187)

55.15

Outstanding as at December 31, 2023

743,365

$

55.13

$

41

Compensation cost recognized for the PSU plan for the year ended December 31, 2023 was $

11

 million

(2022 – $

18

 million). Tax benefits related to this compensation cost for share units realized for the year

ended December 31, 2023 were $

3

 million (2022 – $

5

 million). Cash payments made during the year

ended December 31, 2023 associated with the PSU plan were $

19

 million (2022 – $

24

 million).

Restricted Share Unit Plan

Under the RSU plan, certain executive and senior employees are eligible for long-term incentives payable

through the plan. RSUs are granted annually for three-year overlapping performance cycles, resulting in a

cash payment. RSUs are granted based on the average of Emera’s stock closing price for the fifty trading

days prior to the effective grant date. Dividend equivalents are awarded and paid in the form of additional

RSUs. The RSU value varies according to the Emera common share market price.

RSUs vest at the end of the three-year cycle and the payouts will be calculated and approved by the

MRCC early in the following year. The value of the payout considers actual service over the performance

cycle and may be pro-rated in certain departure scenarios. In the case of retirement, as defined in the

RSU plan, grants may continue to vest in full and payout in normal course post-retirement.

A summary of the activity related to employee RSUs for the year ended December 31, 2023 is presented

in the following table:

Employee RSU

Weighted Average

Grant Date FV

Aggregate intrinsic value

Outstanding as at December 31, 2022

508,468

$

56.25

$

30

Granted including DRIP

236,537

52.07

Exercised

(171,537)

54.62

Forfeited

(10,827)

54.76

Outstanding as at December 31, 2023

562,641

$

55.01

$

32

Compensation cost recognized for the RSU plan for the year ended December 31, 2023 was $

10

 million

(2022 – $

9

 million). Tax benefits related to this compensation cost for share units realized for the year

ended December 31, 2023 were $

3

 million (2022 – $

2

 million). Cash payments made during the year

ended December 31, 2023 associated with the RSU plan were $

10

 million (2022–

nil

).

XML

Variable Interest Entities

12 Months Ended

Dec. 31, 2023

Variable Interest Entities [Abstract]

Variable Interest Entities

32. VARIABLE INTEREST ENTITIES

Emera holds a variable interest in NSPML, a VIE for which it was determined that Emera is not the

primary beneficiary since it does not have the controlling financial interest of NSPML. When the critical

milestones were achieved, Nalcor Energy was deemed the primary beneficiary of the asset for financial

reporting purposes as it has authority over the majority of the direct activities that are expected to most

significantly impact the economic performance of the Maritime Link. Thus, Emera began recording the

Maritime Link as an equity investment.

BLPC has established a SIF, primarily for the purpose of building a fund to cover risk against damage and

consequential loss to certain generating, transmission and distribution systems. ECI holds a variable

interest in the SIF for which it was determined that ECI was the primary beneficiary and, accordingly, the

SIF must be consolidated by ECI. In its determination that ECI controls the SIF, management considered

that, in substance, the activities of the SIF are being conducted on behalf of ECI’s subsidiary BLPC and

BLPC, alone, obtains the benefits from the SIF’s operations. Additionally, because ECI, through BLPC,

has rights to all the benefits of the SIF, it is also exposed to the risks related to the activities of the SIF.

Any withdrawal of SIF fund assets by the Company would be subject to existing regulations. Emera’s

consolidated VIE in the SIF is recorded as “Other long-term assets”, “Restricted cash” and “Regulatory

liabilities” on the Consolidated Balance Sheets. Amounts included in restricted cash represent the cash

portion of funds required to be set aside for the BLPC SIF.

The Company has identified certain long-term purchase power agreements that meet the definition of

variable interests as the Company has to purchase all or a majority of the electricity generation at a fixed

price. However, it was determined that the Company was not the primary beneficiary since it lacked the

power to direct the activities of the entity, including the ability to operate the generating facilities and make

management decisions.

The following table provides information about Emera’s portion of material unconsolidated VIEs:

As at

December 31, 2023

December 31, 2022

Maximum

Maximum

millions of dollars

Total

assets

exposure to

loss

Total

assets

 exposure to

loss

Unconsolidated VIEs in which Emera has variable interests

NSPML (equity accounted)

$

489

$

6

$

501

$

6

XML

Subsequent Events

12 Months Ended

Dec. 31, 2023

Subsequent Events [Abstract]

Subsequent Events

33. SUBSEQUENT EVENTS

These financial statements and notes reflect the Company’s evaluation of events occurring subsequent to

the balance sheet date through February 26, 2024, the date the financial statements were issued.

XML

Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2023

Summary of Significant Accounting Policies [Abstract]

Basis of Presentation

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

Principles of Consolidation

These consolidated financial statements include the accounts of Emera Incorporated, its majority-owned

subsidiaries, and a variable interest entity (“VIE”) in which Emera is the primary beneficiary. Emera uses

the equity method of accounting to record investments in which the Company has the ability to exercise

significant influence, and for VIEs in which Emera is not the primary beneficiary.

The Company performs ongoing analysis to assess whether it holds any VIEs or whether any

reconsideration events have arisen with respect to existing VIEs. To identify potential VIEs, management

reviews contractual and ownership arrangements such as leases, long-term purchase power agreements,

tolling contracts, guarantees, jointly owned facilities and equity investments. VIEs of which the Company

is deemed the primary beneficiary must be consolidated. The primary beneficiary of a VIE has both the

power to direct the activities of the VIE that most significantly impacts its economic performance and the

obligation to absorb losses or the right to receive benefits of the VIE that could potentially be significant to

the VIE. In circumstances where Emera has an investment in a VIE but is not deemed the primary

beneficiary, the VIE is accounted for using the equity method. For further details on VIEs, refer to note 32.

Intercompany balances and transactions have been eliminated on consolidation, except for the net profit

on certain transactions between certain non-regulated and regulated entities in accordance with

accounting standards for rate-regulated entities. The net profit on these transactions, which would be

eliminated in the absence of the accounting standards for rate-regulated entities, is recorded in non-

regulated operating revenues. An offset is recorded to PP&E, regulatory assets, regulated fuel for

generation and purchased power, or OM&G, depending on the nature of the transaction.

Use of Management Estimates

Use of Management Estimates

The preparation of consolidated financial statements in accordance with USGAAP requires management

to make estimates and assumptions. These may affect reported amounts of assets and liabilities at the

date of the financial statements and reported amounts of revenues and expenses during the reporting

periods. Significant areas requiring use of management estimates relate to rate-regulated assets and

liabilities, accumulated reserve for cost of removal, pension and post-retirement benefits, unbilled

revenue, useful lives for depreciable assets, goodwill and long-lived assets impairment assessments,

income taxes, asset retirement obligations (“ARO”), and valuation of financial instruments. Management

evaluates the Company’s estimates on an ongoing basis based upon historical experience, current and

expected conditions and assumptions believed to be reasonable at the time the assumption is made, with

any adjustments recognized in income in the year they arise.

Regulatory Matters

Regulatory Matters

Regulatory accounting applies where rates are established by, or subject to approval by, an independent

third-party regulator. Rates are designed to recover prudently incurred costs of providing regulated

products or services and provide an opportunity for a reasonable rate of return on invested capital, as

applicable. For further detail, refer to note 6.

Foreign Currency Translation

Foreign Currency Translation 

Monetary assets and liabilities denominated in foreign currencies are converted to CAD at the rates of

exchange prevailing at the balance sheet date. The resulting differences between the translation at the

original transaction date and the balance sheet date are included in income.

Assets and liabilities of foreign operations whose functional currency is not the Canadian dollar are

translated using exchange rates in effect at the balance sheet date and the results of operations at the

average exchange rate in effect for the period. The resulting exchange gains and losses on the assets

and liabilities are deferred on the balance sheet in AOCI.

The Company designates certain USD denominated debt held in CAD functional currency companies as

hedges of net investments in USD denominated foreign operations. The change in the carrying amount of

these investments, measured at exchange rates in effect at the balance sheet date is recorded in Other

Comprehensive Income (“OCI”).

Revenue Recognition

Revenue Recognition

Regulated Electric and Gas Revenue:

Electric and gas revenues, including energy charges, demand charges, basic facilities charges and

clauses and riders, are recognized when obligations under the terms of a contract are satisfied, which is

when electricity and gas are delivered to customers over time as the customer simultaneously receives

and consumes the benefits. Electric and gas revenues are recognized on an accrual basis and include

billed and unbilled revenues. Revenues related to the sale of electricity and gas are recognized at rates

approved by the respective regulators and recorded based on metered usage, which occurs on a

periodic, systematic basis, generally monthly or bi-monthly. At the end of each reporting period, electricity

and gas delivered to customers, but not billed, is estimated and corresponding unbilled revenue is

recognized. The Company’s estimate of unbilled revenue at the end of the reporting period is calculated

by estimating the megawatt hours (“MWh”) or therms delivered to customers at the established rates

expected to prevail in the upcoming billing cycle. This estimate includes assumptions as to the pattern of

energy demand, weather, line losses and inter-period changes to customer classes.

Non-regulated Revenue:

Marketing and trading margins are comprised of Emera Energy’s corresponding purchases and sales of

natural gas and electricity, pipeline capacity costs and energy asset management revenues. Revenues

are recorded when obligations under terms of the contract are satisfied and are presented on a net basis

reflecting the nature of contractual relationships with customers and suppliers.

Energy sales are recognized when obligations under the terms of the contracts are satisfied, which is

when electricity is delivered to customers over time. 

Other non-regulated revenues are recorded when obligations under the terms of the contract are

satisfied.

Other:

Sales, value add, and other taxes, except for gross receipts taxes discussed below, collected by the

Company concurrent with revenue-producing activities are excluded from revenue.

Franchise Fees and Gross Receipts

Franchise Fees and Gross Receipts

TEC and PGS recover from customers certain costs incurred, on a dollar-for-dollar basis, through prices

approved by the Florida Public Service Commission (“FPSC”). The amounts included in customers’ bills

for franchise fees and gross receipt taxes are included as “Regulated electric” and “Regulated gas”

revenues in the Consolidated Statements of Income. Franchise fees and gross receipt taxes payable by

TEC and PGS are included as an expense on the Consolidated Statements of Income in “Provincial, state

and municipal taxes”.

NMGC is an agent in the collection and payment of franchise fees and gross receipt taxes and is not

required by a tariff to present the amounts on a gross basis. Therefore, NMGC’s franchise fees and gross

receipt taxes are presented net with no line item impact on the Consolidated Statements of Income.

PP&E

PP&E 

PP&E is recorded at original cost, including AFUDC or capitalized interest, net of contributions received in

aid of construction.

The cost of additions, including betterments and replacements of units, are included in “PP&E” on the

Consolidated Balance Sheets. When units of regulated PP&E are replaced, renewed or retired, their cost,

plus removal or disposal costs, less salvage proceeds, is charged to accumulated depreciation, with no

gain or loss reflected in income. Where a disposition of non-regulated PP&E occurs, gains and losses are

included in income as the dispositions occur.

The cost of PP&E represents the original cost of materials, contracted services, direct labour, AFUDC for

regulated property or interest for non-regulated property, ARO, and overhead attributable to the capital

project. Overhead includes corporate costs such as finance, information technology and labour costs,

along with other costs related to support functions, employee benefits, insurance, procurement, and fleet

operating and maintenance. Expenditures for project development are capitalized if they are expected to

have a future economic benefit.

Normal maintenance projects and major maintenance projects that do not increase overall life of the

related assets are expensed as incurred. When a major maintenance project increases the life or value of

the underlying asset, the cost is capitalized. 

Depreciation is determined by the straight-line method, based on the estimated remaining service lives of

the depreciable assets in each functional class of depreciable property. For some of Emera’s rate-

regulated subsidiaries, depreciation is calculated using the group remaining life method, which is applied

to the average investment, adjusted for anticipated costs of removal less salvage, in functional classes of

depreciable property. The service lives of regulated assets require regulatory approval.

Intangible assets, which are included in “PP&E” on the Consolidated Balance Sheets, consist primarily of

computer software and land rights. Amortization is determined by the straight-line method, based on the

estimated remaining service lives of the asset in each category. For some of Emera’s rate-regulated

subsidiaries, amortization is calculated using the amortizable life method which is applied to the net book

value to date over the remaining life of those assets. The service lives of regulated intangible assets

require regulatory approval.

Goodwill

Goodwill

Goodwill is calculated as the excess of the purchase price of an acquired entity over the estimated FV of

identifiable assets acquired and liabilities assumed at the acquisition date. Goodwill is carried at initial

cost less any write-down for impairment and is adjusted for the impact of foreign exchange (“FX”).

Goodwill is subject to assessment for impairment at the reporting unit level annually, or if an event or

change in circumstances indicates that the FV of a reporting unit may be below its carrying value. When

assessing goodwill for impairment, the Company has the option of first performing a qualitative

assessment to determine whether a quantitative assessment is necessary. In performing a qualitative

assessment management considers, among other factors, macroeconomic conditions, industry and

market considerations and overall financial performance.

If the Company performs a qualitative assessment and determines it is more likely than not that its FV is

less than its carrying amount, or if the Company chooses to bypass the qualitative assessment, a

quantitative test is performed. The quantitative test compares the FV of the reporting unit to its carrying

amount, including goodwill. If the carrying amount of the reporting unit exceeds its FV, an impairment loss

is recorded. Management estimates the FV of the reporting unit by using the income approach, or a

combination of the income and market approach. The income approach uses a discounted cash flow

analysis which relies on management’s best estimate of the reporting unit’s projected cash flows. The

analysis includes an estimate of terminal values based on these expected cash flows using a

methodology which derives a valuation using an assumed perpetual annuity based on the reporting unit’s

residual cash flows. The discount rate used is a market participant rate based on a peer group of publicly

traded comparable companies and represents the weighted average cost of capital of comparable

companies. For the market approach, management estimates FV based on comparable companies and

transactions within the utility industry. Significant assumptions used in estimating the FV of a reporting

unit using an income approach include discount and growth rates, rate case assumptions including future

cost of capital, valuation of the reporting unit’s net operating loss (“NOL”) and projected operating and

capital cash flows. Adverse changes in these assumptions could result in a future material impairment of

the goodwill assigned to Emera’s reporting units. 

As of December 31, 2023, $

5,868

 million of Emera’s goodwill represents the excess of the acquisition

purchase price for TECO Energy (TEC, PGS and NMGC reporting units) over the FV assigned to

identifiable assets acquired and liabilities assumed. In Q4 2023, qualitative assessments were performed

for NMGC and PGS given the significant excess of FV over carrying amounts calculated during the last

quantitative tests in Q4 2022 and Q4 2019, respectively. Management concluded it was more likely than

not that the FV of these reporting units exceeded their respective carrying amounts, including goodwill. As

such, no quantitative testing was required. Given the length of time passed since the last quantitative

impairment test for the TEC reporting unit, Emera elected to bypass a qualitative assessment and

performed a quantitative impairment assessment in Q4 2023 using a combination of the income and

market approach. This assessment estimated that the FV of the TEC reporting unit exceeded its carrying

amount, including goodwill, and as a result, no impairment charges were recognized.

In Q4 2022, as a result of a quantitative assessment, the Company recorded a goodwill impairment

charge of $

73

 million, reducing the GBPC goodwill balance to

nil

 as at December 31, 2022. For further

details, refer to note 22.

Income Taxes and Investment Tax Credits

Income Taxes and Investment Tax Credits

Emera recognizes deferred income tax assets and liabilities for the future tax consequences of events

that have been included in financial statements or income tax returns. Deferred income tax assets and

liabilities are determined based on the difference between the carrying value of assets and liabilities on

the Consolidated Balance Sheets, and their respective tax bases using enacted tax rates in effect for the

year in which the differences are expected to reverse. The effect of a change in income tax rates on

deferred income tax assets and liabilities is recognized in earnings in the period when the change is

enacted, unless required to be offset to a regulatory asset or liability by law or by order of the regulator.

Emera recognizes the effect of income tax positions only when it is more likely than not that they will be

realized. Management reviews all readily available current and historical information, including forward-

looking information, and the likelihood that deferred income tax assets will be recovered from future

taxable income is assessed and assumptions are made about the expected timing of reversal of deferred

income tax assets and liabilities. If management subsequently determines it is likely that some or all of a

deferred income tax asset will not be realized, a valuation allowance is recorded to reflect the amount of

deferred income tax asset expected to be realized. 

Generally, investment tax credits are recorded as a reduction to income tax expense in the current or

future periods to the extent that realization of such benefit is more likely than not. Investment tax credits

earned on regulated assets by TEC, PGS and NMGC are deferred and amortized as required by

regulatory practices.

TEC, PGS, NMGC and BLPC collect income taxes from customers based on current and deferred income

taxes. NSPI, ENL and Brunswick Pipeline collect income taxes from customers based on income tax that

is currently payable, except for the deferred income taxes on certain regulatory balances specifically

prescribed by regulators. For the balance of regulated deferred income taxes, NSPI, ENL and Brunswick

Pipeline recognize regulatory assets or liabilities where the deferred income taxes are expected to be

recovered from or returned to customers in future years. These regulated assets or liabilities are grossed

up using the respective income tax rate to reflect the income tax associated with future revenues that are

required to fund these deferred income tax liabilities, and the income tax benefits associated with reduced

revenues resulting from the realization of deferred income tax assets. GBPC is not subject to income

taxes.

Emera classifies interest and penalties associated with unrecognized tax benefits as interest and

operating expense, respectively. For further detail, refer to note 10.

Derivatives and Hedging Activities

Derivatives and Hedging Activities

The Company manages its exposure to normal operating and market risks relating to commodity prices,

FX, interest rates and share prices through contractual protections with counterparties where practicable,

and by using financial instruments consisting mainly of FX forwards and swaps, interest rate options and

swaps, equity derivatives, and coal, oil and gas futures, options, forwards and swaps. In addition, the

Company has contracts for the physical purchase and sale of natural gas. These physical and financial

contracts are classified as HFT. Collectively, these contracts and financial instruments are considered

derivatives.

The Company recognizes the FV of all its derivatives on its balance sheet, except for non-financial

derivatives that meet the normal purchases and normal sales (“NPNS”) exception. Physical contracts that

meet the NPNS exception are not recognized on the balance sheet; these contracts are recognized in

income when they settle. A physical contract generally qualifies for the NPNS exception if the transaction

is reasonable in relation to the Company’s business needs, the counterparty owns or controls resources

within the proximity to allow for physical delivery, the Company intends to receive physical delivery of the

commodity, and the Company deems the counterparty creditworthy. The Company continually assesses

contracts designated under the NPNS exception and will discontinue the treatment of these contracts

under this exemption if the criteria are no longer met. 

Derivatives qualify for hedge accounting if they meet stringent documentation requirements and can be

proven to effectively hedge identified risk both at the inception and over the term of the instrument.

Specifically, for cash flow hedges, change in the FV of derivatives is deferred to AOCI and recognized in

income in the same period the related hedged item is realized. Where documentation or effectiveness

requirements are not met, the derivatives are recognized at FV with any changes in FV recognized in net

income in the reporting period, unless deferred as a result of regulatory accounting.

Derivatives entered into by NSPI, NMGC and GBPC that are documented as economic hedges or for

which the NPNS exception has not been taken, are subject to regulatory accounting treatment. The

change in FV of the derivatives is deferred to a regulatory asset or liability. The gain or loss is recognized

in the hedged item when the hedged item is settled. Management believes any gains or losses resulting

from settlement of these derivatives related to fuel for generation and purchased power will be refunded

to or collected from customers in future rates. TEC has no derivatives related to hedging as a result of a

FPSC approved five-year moratorium on hedging of natural gas purchases that ended on December 31,

2022 and was extended through December 31, 2024 as a result of TEC’s 2021 rate case settlement

agreement.

Derivatives that do not meet any of the above criteria are designated as HFT, with changes in FV

normally recorded in net income of the period. The Company has not elected to designate any derivatives

to be included in the HFT category where another accounting treatment would apply.

Emera classifies gains and losses on derivatives as a component of non-regulated operating revenues,

fuel for generation and purchased power, other expenses, inventory, and OM&G, depending on the

nature of the item being economically hedged. Transportation capacity arising as a result of marketing

and trading derivative transactions is recognized as an asset in “Receivables and other current assets”

and amortized over the period of the transportation contract term. Cash flows from derivative activities are

presented in the same category as the item being hedged within operating or investing activities on the

Consolidated Statements of Cash Flows. Non-hedged derivatives are included in operating cash flows on

the Consolidated Statements of Cash Flows.

Derivatives, as reflected on the Consolidated Balance Sheets, are not offset by the FV amounts of cash

collateral with the same counterparty. Rights to reclaim cash collateral are recognized in “Receivables

and other current assets” and obligations to return cash collateral are recognized in “Accounts payable”.

Lessee, Leases

Leases

The Company determines whether a contract contains a lease at inception by evaluating whether the

contract conveys the right to control the use of an identified asset for a period of time in exchange for

consideration. 

Emera has leases with independent power producers (“IPP”) and other utilities for annual requirements to

purchase wind and hydro energy over varying contract lengths which are classified as finance leases.

These finance leases are not recorded on the Company’s Consolidated Balance Sheets as payments

associated with the leases are variable in nature and there are no minimum fixed lease payments. Lease

expense associated with these leases is recorded as “Regulated fuel for generation and purchased

power” on the Consolidated Statements of Income.

Operating lease liabilities and right-of-use assets are recognized on the Consolidated Balance Sheets

based on the present value of the future minimum lease payments over the lease term at commencement

date. As most of Emera’s leases do not provide an implicit rate, the incremental borrowing rate at

commencement of the lease is used in determining the present value of future lease payments. Lease

expense is recognized on a straight-line basis over the lease term and is recorded as “Operating,

maintenance and general” on the Consolidated Statements of Income.

Lessor, Leases

Where the Company is the lessor, a lease is a sales-type lease if certain criteria are met and the

arrangement transfers control of the underlying asset to the lessee. For arrangements where the criteria

are met due to the presence of a third-party residual value guarantee, the lease is a direct financing

lease. 

For direct finance leases, a net investment in the lease is recorded that consists of the sum of the

minimum lease payments and residual value, net of estimated executory costs and unearned income.

The difference between the gross investment and the cost of the leased item is recorded as unearned

income at the inception of the lease. Unearned income is recognized in income over the life of the lease

using a constant rate of interest equal to the internal rate of return on the lease. 

For sales-type leases, the accounting is similar to the accounting for direct finance leases however, the

difference between the FV and the carrying value of the leased item is recorded at lease commencement

rather than deferred over the term of the lease. 

Emera has certain contractual agreements that include lease and non-lease components, which

management has elected to account for as a single lease component.

Cash, Cash Equivalents and Restricted Cash

Cash, 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

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.

Allowance for Credit Losses

Receivables and Allowance for Credit Losses

Utility customer receivables are recorded at the invoiced amount and do not bear interest. Standard

payment terms for electricity and gas sales are approximately 30 days. A late payment fee may be

assessed on account balances after the due date. The Company recognizes allowances for credit losses

to reduce accounts receivable for amounts expected to be uncollectable. Management estimates credit

losses related to accounts receivable by considering historical loss experience, customer deposits,

current events, the characteristics of existing accounts and reasonable and supportable forecasts that

affect the collectability of the reported amount. Provisions for credit losses on receivables are expensed

to maintain the allowance at a level considered adequate to cover expected losses. Receivables are

written off against the allowance when they are deemed uncollectible.

Inventory

Inventory

Fuel and materials inventories are valued at the lower of weighted-average cost or net realizable value,

unless evidence indicates the weighted-average cost will be recovered in future customer rates.

Asset Impairment

Asset Impairment

Long-Lived Assets:

Emera assesses whether there has been an impairment of long-lived assets and intangibles when a

triggering event occurs, such as a significant market disruption or sale of a business. 

The assessment involves comparing undiscounted expected future cash flows to the carrying value of the

asset. When the undiscounted cash flow analysis indicates a long-lived asset is not recoverable, the

amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-

lived asset over its estimated FV. The Company’s assumptions relating to future results of operations or

other recoverable amounts, are based on a combination of historical experience, fundamental economic

analysis, observable market activity and independent market studies. The Company’s expectations

regarding uses and holding periods of assets are based on internal long-term budgets and projections,

which consider external factors and market forces, as of the end of each reporting period. The

assumptions made are consistent with generally accepted industry approaches and assumptions used for

valuation and pricing activities.

As at December 31, 2023, there are no indications of impairment of Emera’s long-lived assets.

No

impairment charges related to long-lived assets were recognized in 2023 or 2022. 

Equity Method Investments:

The carrying value of investments accounted for under the equity method are assessed for impairment by

comparing the FV of these investments to their carrying values, if a FV assessment was completed, or by

reviewing for the presence of impairment indicators. If an impairment exists, and it is determined to be

other-than-temporary, a charge is recognized in earnings equal to the amount the carrying value exceeds

the investment’s FV.

No

 impairment of equity method investments was required in either 2023 or 2022.

Financial Assets:

Equity investments, other than those accounted for under the equity method, are measured at FV, with

changes in FV recognized in the Consolidated Statements of Income. Equity investments that do not

have readily determinable FV are recorded at cost minus impairment, if any, plus or minus changes

resulting from observable price changes in orderly transactions for the identical or similar investments.

No

impairment of financial assets was required in either 2023 or 2022.

Asset Retirement Obligations and Cost of Removal

Asset Retirement Obligations

An ARO is recognized if a legal obligation exists in connection with the future disposal or removal costs

resulting from the permanent retirement, abandonment or sale of a long-lived asset. A legal obligation

may exist under an existing or enacted law or statute, written or oral contract, or by legal construction

under the doctrine of promissory estoppel.

An ARO represents the FV of estimated cash flows necessary to discharge the future obligation, using

the Company’s credit adjusted risk-free rate. The amounts are reduced by actual expenditures incurred.

Estimated future cash flows are based on completed depreciation studies, remediation reports, prior

experience, estimated useful lives, and governmental regulatory requirements. The present value of the

liability is recorded and the carrying amount of the related long-lived asset is correspondingly increased.

The amount capitalized at inception is depreciated in the same manner as the related long-lived asset.

Over time, the liability is accreted to its estimated future value. AROs are included in “Other long-term

liabilities” and accretion expense is included as part of “Depreciation and amortization”. Any regulated

accretion expense not yet approved by the regulator is recorded in “Property, plant and equipment” and

included in the next depreciation study.

Some of the Company’s transmission and distribution assets may have conditional AROs that are not

recognized in the consolidated financial statements, as the FV of these obligations could not be

reasonably estimated, given insufficient information to do so. A conditional ARO refers to a legal

obligation to perform an asset retirement activity in which the timing and/or method of settlement are

conditional on a future event that may or may not be within the control of the entity. Management

monitors these obligations and a liability is recognized at FV in the period in which an amount can be

determined.

Cost of Removal (“COR”)

TEC, PGS, NMGC and NSPI recognize non-ARO COR as regulatory liabilities. The non-ARO COR

represent funds received from customers through depreciation rates to cover estimated future non-legally

required COR of PP&E upon retirement. The companies accrue for COR over the life of the related

assets based on depreciation studies approved by their respective regulators. The costs are estimated

based on historical experience and future expectations, including expected timing and estimated future

cash outlays.

Stock-Based Compensation

Stock-Based Compensation

The Company has several stock-based compensation plans: a common share option plan for senior

management; an employee common share purchase plan; a deferred share unit (“DSU”) plan; a

performance share unit (“PSU”) plan; and a restricted share unit (“RSU”) plan. The Company accounts for

its plans in accordance with the FV-based method of accounting for stock-based compensation. Stock-

based compensation cost is measured at the grant date, based on the calculated FV of the award, and is

recognized as an expense over the employee’s or director’s requisite service period using the graded

vesting method. Stock-based compensation plans recognized as liabilities are initially measured at FV

and re-measured at FV at each reporting date, with the change in liability recognized in income.

Employee Benefits

Employee Benefits

The costs of the Company’s pension and other post-retirement benefit programs for employees are

expensed over the periods during which employees render service. The Company recognizes the funded

status of its defined-benefit and other post-retirement plans on the balance sheet and recognizes

changes in funded status in the year the change occurs. The Company recognizes unamortized gains

and losses and past service costs in “AOCI” or “Regulatory assets” on the Consolidated Balance Sheets.

The components of net periodic benefit cost other than the service cost component are included in “Other

income, net” on the Consolidated Statements of Income. For further detail, refer to note 21.

XML

Segment Information (Tables)

12 Months Ended

Dec. 31, 2023

Segment Information [Abstract]

Segment Information

Florida 

Canadian

Gas Utilities

Other

Inter-

Electric

Electric

and

Electric

Segment

millions of dollars

Utility

Utilities

Infrastructure

Utilities

Other

Eliminations

Total

For the year ended December 31, 2023 

Operating revenues from

external customers (1)

$

3,548

$

1,671

$

1,510

$

526

$

308

$

 - 

$

7,563

Inter-segment revenues

(1)

8

-

14

-

31

(53)

 - 

 Total operating revenues

3,556

1,671

1,524

526

339

(53)

7,563

Regulated fuel for generation

and purchased power

920

699

-

275

-

(13)

1,881

Regulated cost of natural gas

-

-

527

-

-

-

527

OM&G

830

384

405

130

151

(21)

1,879

Provincial, state and municipal

taxes

289

45

91

3

5

-

433

Depreciation and amortization

571

276

126

68

8

-

1,049

Income from equity

investments

-

109

21

4

12

-

146

Other income, net

69

32

11

7

20

19

158

Interest expense, net

(2)

271

170

129

23

332

-

925

Income tax expense

(recovery)

117

(9)

64

-

(44)

-

128

Non-controlling interest in

subsidiaries

-

-

-

1

-

-

1

Preferred stock dividends

-

-

-

-

66

-

66

Net income (loss) attributable

to common shareholders

$

627

$

247

$

214

$

37

$

(147)

$

-

$

978

Capital expenditures

$

1,736

$

450

$

664

$

63

$

8

$

-

$

2,921

As at December 31, 2023

Total assets

$

21,119

$

8,634

$

7,735

$

1,311

$

1,938

$

(1,257)

$

39,480

Investments subject to

significant influence

$

-

$

1,236

$

118

$

48

$

-

$

-

$

1,402

Goodwill

$

4,628

$

-

$

1,240

$

-

$

3

$

-

$

5,871

(1) All significant inter-company balances and transactions have been eliminated on consolidation except for certain transactions

between non-regulated and regulated entities. Management believes elimination of these transactions would understate PP&E,

OM&G, or regulated fuel for generation and purchased power. Inter-company transactions that have not been eliminated are

measured at the amount of consideration established and agreed to by the related parties. Eliminated transactions are included in

determining reportable segments.

(2) Segment net income is reported on a basis that includes internally allocated financing costs of $

95

 million for the year ended

December 31, 2023, between the Florida Electric Utility, Gas Utilities and Infrastructure and Other segments.

Florida 

Canadian

Gas Utilities

Other

Inter-

Electric

Electric

and

Electric

Segment

millions of dollars

Utility

Utilities

Infrastructure

Utilities

Other

Eliminations

Total

For the year ended December 31, 2022 

Operating revenues from

external customers

(1)

$

3,280

$

1,675

$

1,697

$

518

$

418

$

 - 

$

7,588

Inter-segment revenues

(1)

7

-

7

-

22

(36)

 - 

 Total operating revenues

3,287

1,675

1,704

518

440

(36)

7,588

Regulated fuel for generation

and purchased power

1,086

803

-

290

-

(8)

2,171

Regulated cost of natural gas

-

-

800

-

-

-

800

OM&G

625

338

365

123

156

(11)

1,596

Provincial, state and municipal

taxes

235

43

83

3

3

-

367

Depreciation and amortization

507

259

118

61

7

-

952

Income from equity

investments

-

87

21

4

17

-

129

Other income (expenses), net

68

24

13

-

23

17

145

Interest expense, net

(2)

185

136

81

19

288

-

709

GBPC impairment charge

-

-

-

73

-

-

73

Income tax expense (recovery)

121

(8)

70

-

2

-

185

Non-controlling interest in

subsidiaries

-

-

-

1

-

-

1

Preferred stock dividends

-

-

-

-

63

-

63

Net income (loss) attributable

to common shareholders

$

596

$

215

$

221

$

(48)

$

(39)

$

-

$

945

Capital expenditures

$

1,425

$

507

$

574

$

63

$

6

$

-

$

2,575

As at December 31, 2022

Total assets

$

21,053

$

8,223

$

7,737

$

1,337

$

2,835

$

(1,443)

$

39,742

Investments subject to

significant influence

$

-

$

1,241

$

128

$

49

$

-

$

-

$

1,418

Goodwill

$

4,739

$

-

$

1,270

$

-

$

3

$

-

$

6,012

(1) All significant inter-company balances and transactions have been eliminated on consolidation except for certain transactions

between non-regulated and regulated entities. Management believes elimination of these transactions would understate PP&E,

OM&G, or regulated fuel for generation and purchased power. Inter-company transactions that have not been eliminated are

measured at the amount of consideration established and agreed to by the related parties. Eliminated transactions are included in

determining reportable segments.

(2) Segment net income is reported on a basis that includes internally allocated financing costs of $

13

 million for the year ended

December 31, 2022, between the Gas Utilities and Infrastructure and Other segments.

Geographical Information

Revenues (based on country of origin of the product or service sold)

For the

Year ended December 31

millions of dollars

2023

2022

United States

5,310

$

5,346

Canada

1,727

1,725

Barbados

389

384

The Bahamas

137

122

Dominica

-

11

$

7,563

$

7,588

Property Plant and Equipment:

As at 

December 31

December 31

millions of dollars

2023

2022

United States

$

18,588

$

17,382

Canada

4,878

4,689

Barbados

576

583

The Bahamas

334

342

$

24,376

$

22,996

XML

Revenue (Tables)

12 Months Ended

Dec. 31, 2023

Revenue [Abstract]

Disaggregation of Revenue by Major Source

Electric

Gas

Other

Florida

Canadian

Other 

Gas Utilities

Inter-

Electric

Electric

Electric

and 

Segment

millions of dollars

Utility

Utilities

Utilities

Infrastructure

Other

Eliminations

Total

For the year ended December 31, 2023 

Regulated Revenue

Residential

$

2,307

$

910

$

183

$

724

$

-

$

-

$

4,124

Commercial

1,083

463

285

425

-

-

2,256

Industrial

274

219

33

93

-

(13)

606

Other electric

395

41

7

-

-

-

443

Regulatory deferrals

(522)

-

12

-

-

-

(510)

Other (1) 

19

38

6

199

-

(8)

254

Finance income (2)(3)

-

-

-

62

-

62

 Regulated revenue

$

3,556

$

1,671

$

526

$

1,503

$

-

$

(21)

$

7,235

Non-Regulated Revenue

Marketing and trading margin (4)

-

-

-

-

96

-

96

Other non-regulated operating

revenue

-

-

-

21

27

(23)

25

Mark-to-market (3)

-

-

-

-

216

(9)

207

 Non-regulated revenue

$

-

$

-

$

-

$

21

$

339

$

(32)

$

328

Total operating revenues

$

3,556

$

1,671

$

526

$

1,524

$

339

$

(53)

$

7,563

For the year ended December 31, 2022 

Regulated Revenue

Residential

$

1,799

$

834

$

184

$

800

$

-

$

-

$

3,617

Commercial

869

427

282

461

-

-

2,039

Industrial

230

353

32

83

-

(7)

691

Other electric

398

28

6

-

-

-

432

Regulatory deferrals

(27)

-

6

-

-

-

(21)

Other (1) 

18

33

8

283

-

(7)

335

Finance income (2)(3)

-

-

-

61

-

-

61

 Regulated revenue

$

3,287

$

1,675

$

518

$

1,688

$

-

$

(14)

7,154

Non-Regulated 

Marketing and trading margin (4)

-

-

-

-

143

-

143

Other non-regulated operating

revenue

-

-

-

16

16

(10)

22

Mark-to-market (3)

-

-

-

-

281

(12)

269

 Non-regulated revenue

$

-

$

-

$

-

$

16

$

440

$

(22)

434

Total operating revenues

$

3,287

$

1,675

$

518

$

1,704

$

440

$

(36)

$

7,588

(1) Other includes rental revenues, which do not represent revenue from contracts with customers.

(2) Revenue related to Brunswick Pipeline's service agreement with Repsol Energy Canada.

(3) Revenue which does not represent revenues from contracts with customers.

(4) Includes gains (losses) on settlement of energy related derivatives, which do not represent revenue from contracts with

customers.

XML

Regulatory Assets and Liabilities (Tables)

12 Months Ended

Dec. 31, 2023

Regulatory Assets and Liabilities [Abstract]

Regulatory Assets

As at

December 31

December 31

millions of dollars 

2023

2022

Regulatory assets

Deferred income tax regulatory assets

$

1,233

$

1,166

TEC capital cost recovery for early retired assets 

671

674

NSPI FAM

395

307

Pension and post-retirement medical plan

364

369

Cost recovery clauses

151

707

Deferrals related to derivative instruments

88

30

Storm cost recovery clauses 

52

138

Environmental remediations

26

27

Stranded cost recovery

25

27

NMGC winter event gas cost recovery

-

69

Other

100

106

$

3,105

$

3,620

Current

$

339

$

602

Long-term

2,766

3,018

Total regulatory assets 

$

3,105

$

3,620

Regulatory liabilities

Accumulated reserve – COR

849

895

Deferred income tax regulatory liabilities

830

877

Cost recovery clauses 

32

70

BLPC Self-insurance fund ("SIF") (note 32)

29

30

Deferrals related to derivative instruments

17

230

NMGC gas hedge settlements (note 18)

-

162

Other

15

9

$

1,772

$

2,273

Current

$

168

$

495

Long-term

1,604

1,778

Total regulatory liabilities

$

1,772

$

2,273

Regulatory Liabilities

As at

December 31

December 31

millions of dollars 

2023

2022

Regulatory assets

Deferred income tax regulatory assets

$

1,233

$

1,166

TEC capital cost recovery for early retired assets 

671

674

NSPI FAM

395

307

Pension and post-retirement medical plan

364

369

Cost recovery clauses

151

707

Deferrals related to derivative instruments

88

30

Storm cost recovery clauses 

52

138

Environmental remediations

26

27

Stranded cost recovery

25

27

NMGC winter event gas cost recovery

-

69

Other

100

106

$

3,105

$

3,620

Current

$

339

$

602

Long-term

2,766

3,018

Total regulatory assets 

$

3,105

$

3,620

Regulatory liabilities

Accumulated reserve – COR

849

895

Deferred income tax regulatory liabilities

830

877

Cost recovery clauses 

32

70

BLPC Self-insurance fund ("SIF") (note 32)

29

30

Deferrals related to derivative instruments

17

230

NMGC gas hedge settlements (note 18)

-

162

Other

15

9

$

1,772

$

2,273

Current

$

168

$

495

Long-term

1,604

1,778

Total regulatory liabilities

$

1,772

$

2,273

XML

Investments Subject to Significant Influence and Equity Income (Tables)

12 Months Ended

Dec. 31, 2023

Variable Interest Entity [Line Items]

Summary of Investments Subject to Significant Influence

Equity Income

Percentage

Carrying Value

For the year ended

of

As at December 31

December 31

Ownership

millions of dollars

2023

2022

2023

2022

2023

LIL

(1)

$

747

$

740

$

63

$

58

31.0

NSPML

489

501

46

29

100.0

M&NP

 (2)

118

128

21

21

12.9

Lucelec

(2)

48

49

4

4

19.5

Bear Swamp

 (3)

-

-

12

17

50.0

$

1,402

$

1,418

$

146

$

129

(1) Emera indirectly owns

100

 per cent of the Class B units, which comprises

24.5

 per cent of the total units issued. Percentage

ownership in LIL is subject to change, based on the balance of capital investments required from Emera and Nalcor Energy to

complete construction of the LIL. Emera’s ultimate percentage investment in LIL will be determined upon final costing of 

all transmission projects related to the Muskrat Falls development, including the LIL, Labrador Transmission Assets and Maritime

Link Projects, such that Emera’s total investment in the Maritime Link and LIL will equal

49

 per cent of the cost of all of these

transmission developments.

(2) Emera has significant influence over the operating and financial decisions of these companies through Board representation and

therefore, records its investment in these entities using the equity method. 

(3) The investment balance in Bear Swamp is in a credit position primarily as a result of a $

179

 million distribution received in 2015.

Bear Swamp's credit investment balance of $

81

 million (2022 – $

95

 million) is recorded in Other long-term liabilities on the

Consolidated Balance Sheets.

NSP Maritime Link Inc. [Member]

Variable Interest Entity [Line Items]

Summary of Investments Subject to Significant Influence

Emera accounts for its variable interest investment in NSPML as an equity investment (note 32).

NSPML's consolidated summarized balance sheets are illustrated as follows:

As at

December 31

millions of dollars

2023

2022

Balance Sheets

Current assets

$

21

$

17

PP&E

1,473

1,517

Regulatory assets

272

265

Non-current assets

29

29

Total assets

$

1,795

$

1,828

Current liabilities

$

48

$

48

Long-term debt

(1)

1,109

1,149

Non-current liabilities

149

130

Equity

489

501

Total liabilities and equity

$

1,795

$

1,828

(1) The project debt has been guaranteed by the Government of Canada.

XML

Other Income, Net (Tables)

12 Months Ended

Dec. 31, 2023

Other Income, Net [Abstract]

Components of Other Expense, Net

For the

Year ended December 31

millions of dollars

2023

2022

Interest income

$

43

$

25

AFUDC

38

52

Pension non-current service cost recovery

35

24

FX gains (losses)

20

(26)

TECO Guatemala Holdings award

(1)

-

63

Other 

22

7

$

158

$

145

(1) On December 15, 2022, a payment of $

63

 million was made by the Republic of Guatemala to TECO Energy in satisfaction of the

second and final award issued by the International Centre of the Settlement of Investment Disputes tribunal regarding a dispute over

an investment in TGH, a wholly-owned subsidiary of TECO Energy.

XML

Interest Expense, Net (Tables)

12 Months Ended

Dec. 31, 2023

Interest Expense, Net [Abstract]

Components of Interest Expense, Net

Interest expense, net consisted of the following:

For the

Year ended December 31

millions of Canadian dollars

2023

2022

Interest on debt 

$

954

$

727

Allowance for borrowed funds used during construction

(16)

(21)

Other

(13)

3

$

925

$

709

XML

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2023

Income Taxes [Abstract]

Reconciliation of Effective Income Tax Rate

The income tax provision, for the years ended December 31, differs from that computed using the

enacted combined Canadian federal and provincial statutory income tax rate for the following reasons:

millions of dollars

2023

2022

Income before provision for income taxes

$

1,173

$

1,194

Statutory income tax rate

29.0%

29.0%

Income taxes, at statutory income tax rate

340

346

Deferred income taxes on regulated income recorded as regulatory assets and

regulatory liabilities

(72)

(70)

Tax credits

(53)

(18)

Foreign tax rate variance

(36)

(44)

Amortization of deferred income tax regulatory liabilities

(33)

(33)

Tax effect of equity earnings

(15)

(10)

GBPC impairment charge 

-

21

Other

(3)

(7)

Income tax expense

$

128

$

185

Effective income tax rate

11%

15%

Composition of Taxes on Income from Continuing Operations

millions of dollars

2023

2022

Current income taxes

 Canada

$

26

$

25

 United States

5

8

Deferred income taxes

 Canada

93

122

 United States

128

252

Investment tax credits

 United States

(29)

(7)

Operating loss carryforwards

 Canada

(93)

(94)

 United States

(2)

(121)

Income tax expense

$

128

$

185

The following table reflects the composition of income before provision for income taxes presented in the

Consolidated Statements of Income for the years ended December 31:

millions of dollars

2023

2022

Canada

$

171

$

173

United States

964

1,063

Other

38

(42)

Income before provision for income taxes

$

1,173

$

1,194

Schedule of Deferred Income Tax Assets and Liabilities

The deferred income tax assets and liabilities presented in the Consolidated Balance Sheets as at

December 31 consisted of the following:

millions of dollars

2023

2022

Deferred income tax assets:

Tax loss carryforwards

$

1,195

$

1,207

Tax credit carryforwards

454

415

Derivative instruments

205

45

Regulatory liabilities 

175

264

Other

372

341

Total deferred income tax assets before valuation allowance

2,401

2,272

Valuation allowance

(363)

(312)

Total deferred income tax assets after valuation allowance

$

2,038

$

1,960

Deferred income tax (liabilities):

PP&E

$

(3,223)

$

(2,981)

Derivative instruments

(235)

(125)

Investments subject to significant influence

(216)

(181)

Regulatory assets

(196)

(310)

Other

(312)

(322)

Total deferred income tax liabilities 

$

(4,182)

$

(3,919)

Consolidated Balance Sheets presentation:

Long-term deferred income tax assets

$

208

$

237

Long-term deferred income tax liabilities

(2,352)

(2,196)

Net deferred income tax liabilities

$

(2,144)

$

(1,959)

Net Operating Loss ("NOL"), Capital Loss and Tax Credit Carryforwards and Their Expiration Periods

Emera’s NOL, capital loss and tax credit carryforwards and their expiration periods as at December 31,

2023 consisted of the following:

Subject to

Tax

Valuation

Net Tax

Expiration

millions of dollars

Carryforwards

Allowance

Carryforwards

Period

Canada

 NOL

$

2,914

$

(1,164)

$

1,750

2026 - 2043

 Capital loss

73

(73)

-

Indefinite

United States

 Federal NOL

$

1,360

$

(1)

$

1,359

2036 - Indefinite

 State NOL

1,003

(1)

1,002

2026 - Indefinite

 Tax credit

454

(3)

451

2025 - 2043

Other

 NOL

$

81

$

(28)

$

53

2024 - 2030

Details of Change in Unrecognized Tax Benefits

millions of dollars

2023

2022

Balance, January 1

$

33

$

28

Increases due to tax positions related to current year

5

5

Increases due to tax positions related to a prior year

1

2

Decreases due to tax positions related to a prior year

(2)

(2)

Balance, December 31

$

37

$

33

XML

Common Stock (Tables)

12 Months Ended

Dec. 31, 2023

Common Stock [Abstract]

Summary of Issued and Outstanding Common Stock

Authorized

: Unlimited number of non-par value common shares.

2023

2022

Issued and outstanding:

millions

of shares

 millions of

dollars

millions of

shares

 millions of

dollars

Balance, January 1

269.95

$

7,762

261.07

$

7,242

Issuance of common stock under ATM program

(1)(2)

8.29

397

4.07

248

Issued under the DRIP, net of discounts

5.26

272

4.21

238

Senior management stock options exercised and Employee Share

Purchase Plan

0.62

31

0.60

34

Balance, December 31

284.12

$

8,462

269.95

$

7,762

(1) For the year ended December 31, 2022, a total of

4,072,469

 common shares were issued under Emera's ATM program at an

average price of $

61.31

 per share for gross proceeds of $

250

 million ($

248

 million net of after-tax issuance costs).

(2) For the year ended December 31, 2023, a total of

8,287,037

 common shares were issued under Emera's ATM program at an

average price of $

48.27

 per share for gross proceeds of $

400

 million ($

397

 million net of after-tax issuance costs).

XML

Earnings Per Share (Tables)

12 Months Ended

Dec. 31, 2023

Earnings Per Share [Abstract]

Computation of Basic and Diluted Earnings per Share

The following table reconciles the computation of basic and diluted earnings per share:

For the

Year ended December 31

millions of dollars (except per share amounts)

2023

2022

Numerator

Net income attributable to common shareholders

$

977.7

$

945.1

Diluted numerator

977.7

945.1

Denominator

Weighted average shares of common stock outstanding – basic

273.6

265.5

Stock-based compensation 

0.2

0.4

Weighted average shares of common stock outstanding – diluted

273.8

265.9

Earnings per common share

Basic 

$

3.57

$

3.56

Diluted

$

3.57

$

3.55

XML

Accumulated Other Comprehensive Income (Tables)

12 Months Ended

Dec. 31, 2023

Accumulated Other Comprehensive Income [Abstract]

Components of Accumulated Other Comprehensive Income

The components of AOCI are as follows:

millions of dollars

Unrealized

(loss) gain on

translation of

self-sustaining

foreign

operations

Net change in

net investment

hedges

Losses on

derivatives

recognized 

as cash flow

hedges

Net change

on available-

for-sale

investments

Net change in

unrecognized

pension and

post-retirement

benefit costs

Total 

AOCI

For the year ended December 31, 2023

Balance, January 1, 2023

$

639

$

(62)

$

16

$

(2)

$

(13)

$

578

Other comprehensive (loss) 

income before 

reclassifications

(270)

38

 - 

-

-

(232)

Amounts reclassified from 

AOCI

-

-

(2)

-

(39)

(41)

Net current period other

comprehensive (loss) income

(270)

38

(2)

-

(39)

(273)

Balance, December 31, 2023

$

369

$

(24)

$

14

$

(2)

$

(52)

$

305

For the year ended December 31, 2022

Balance, January 1, 2022

$

10

$

35

$

18

$

(1)

$

(37)

$

25

Other comprehensive 

income (loss) before 

reclassifications

629

(97)

-

(1)

-

531

Amounts reclassified from 

AOCI

-

-

(2)

-

24

22

Net current period other

comprehensive income (loss)

629

(97)

(2)

(1)

24

553

Balance, December 31, 2022

$

639

$

(62)

$

16

$

(2)

$

(13)

$

578

Reclassifications out of Accumulated Other Comprehensive Income (Loss)

The reclassifications out of AOCI are as follows:

For the

Year ended December 31

millions of dollars

2023

2022

Affected line item in the Consolidated Financial Statements

Gains on derivatives recognized as cash flow hedges

 Interest rate hedge

Interest expense, net

$

(2)

$

(2)

Net change in unrecognized pension and post-retirement benefit costs

 Actuarial losses

Other income, net

$

-

$

10

 Past service costs

Other income, net

2

-

 Amounts reclassified into obligations

Pension and post-retirement benefits

(40)

15

Total before tax

(38)

25

Income tax expense

(1)

(1)

Total net of tax

$

(39)

$

24

Total reclassifications out of AOCI, net of tax, for the period

$

(41)

$

22

XML

Inventory (Tables)

12 Months Ended

Dec. 31, 2023

Inventory [Abstract]

Components of Inventory

As at

December 31

December 31

millions of dollars 

2023

2022

Fuel 

$

382

$

404

Materials 

408

365

Total

$

790

$

769

XML

Derivative Instruments (Tables)

12 Months Ended

Dec. 31, 2023

Derivative Instruments

Derivative Assets and Liabilities

Derivative assets and liabilities relating to the foregoing categories consisted of the following:

Derivative Assets

Derivative Liabilities

As at

December 31

December 31

December 31

December 31

millions of dollars

2023

2022

2023

2022

Regulatory deferral:

 Commodity swaps and forwards

$

16

$

186

$

76

$

42

 FX forwards

3

18

3

1

 Physical natural gas purchases and sales

-

52

-

-

19

256

79

43

HFT derivatives:

 Power swaps and physical contracts

29

89

36

77

 Natural gas swaps, futures, forwards, physical 

 contracts

319

340

531

1,224

348

429

567

1,301

Other derivatives:

 Equity derivatives 

4

-

-

5

 FX forwards

18

5

7

23

22

5

7

28

Total gross current derivatives

389

690

653

1,372

Impact of master netting agreements:

 Regulatory deferral

(3)

(18)

(3)

(18)

 HFT derivatives

(146)

(276)

(146)

(276)

Total impact of master netting agreements

(149)

(294)

(149)

(294)

Total derivatives

$

240

$

396

$

504

$

1,078

Current

(1)

174

296

386

888

Long-term

(1)

66

100

118

190

Total derivatives

$

240

$

396

$

504

$

1,078

(1) Derivative assets and liabilities are classified as current or long-term based upon the maturities of the underlying contracts.

Cash Flow Hedges Recorded in AOCI

For the

Year ended December 31

millions of dollars

2023

2022

Interest

Interest

rate hedge

rate hedge

Realized gain in interest expense, net

$

2

$

2

Total gains in net income

$

2

$

2

As at

December 31

December 31

millions of dollars

2023

2022

Interest

Interest

rate hedge

rate hedge

Total unrealized gain in AOCI – effective portion, net of tax

$

14

$

16

Changes in Realized and Unrealized Gains (Losses) on Derivatives

Physical

Commodity

Physical

Commodity

natural gas

swaps and

FX

natural gas

swaps and

FX

millions of dollars

purchases

forwards

forwards

purchases

forwards

forwards

For the year ended December 31

2023

2022

Unrealized gain (loss) in regulatory

assets

$

-

$

(109)

$

(3)

$

-

$

(69)

$

1

Unrealized gain (loss) in regulatory

liabilities

(3)

(73)

-

28

343

16

Realized (gain) loss in regulatory

assets

-

(5)

-

-

48

-

Realized (gain) loss in regulatory

liabilities

-

2

-

-

(41)

-

Realized (gain) loss in inventory

(1)

-

4

(10)

-

(121)

1

Realized (gain) in regulated fuel for

generation and purchased power

(2)

(49)

(9)

(4)

(64)

(146)

-

Other

-

(14)

-

-

-

-

Total change in derivative instruments

$

(52)

$

(204)

$

(17)

$

(36)

$

14

$

18

(1) Realized (gains) losses will be recognized in fuel for generation and purchased power when the hedged item is consumed.

(2) Realized (gains) losses on derivative instruments settled and consumed in the period and hedging relationships that have been

terminated or the hedged transaction is no longer probable.

For the 

Year ended December 31

millions of dollars

2023

2022

Power swaps and physical contracts in non-regulated operating revenues

$

(6)

$

17

Natural gas swaps, forwards, futures and physical contracts in non-regulated

operating revenues

1,043

47

Total gains in net income

$

1,037

$

64

For the

Year ended December 31

millions of dollars

2023

2022

FX

Equity

FX

Equity

Forwards

Derivatives

Forwards

Derivatives

Unrealized gain (loss) in OM&G

$

-

$

4

$

-

$

(5)

Unrealized gain (loss) in other income, net

28

-

(18)

-

Realized loss in OM&G

-

(13)

-

(17)

Realized loss in other income, net

(11)

-

(6)

-

Total gains (losses) in net income

$

17

$

(9)

$

(24)

$

(22)

Notional Volumes of Outstanding Derivatives

millions

2024

2025-2026

Physical natural gas purchases:

Natural gas (MMBtu)

7

6

Commodity swaps and forwards purchases:

Natural gas (MMBtu)

16

10

Power (MWh)

1

1

Coal (metric tonnes)

1

-

FX swaps and forwards:

FX contracts (millions of USD)

$

241

$

70

Weighted average rate

1.3155

1.3197

% of USD requirements

63%

17%

2028 and 

millions 

2024

2025

2026

2027

thereafter

Natural gas purchases (Mmbtu)

296

80

50

38

30

Natural gas sales (Mmbtu)

338

86

16

6

4

Power purchases (MWh)

1

-

-

-

-

Power sales (MWh)

1

-

-

-

-

Summary of Concentration Risk

Concentration Risk

The Company's concentrations of risk consisted of the following:

As at

December 31, 2023

December 31, 2022

millions of

dollars

% of total

exposure

millions of

dollars

% of total

exposure

Receivables, net

Regulated utilities:

Residential

$

476

31%

$

455

19%

Commercial

194

13%

192

8%

Industrial

84

5%

121

5%

Other

103

7%

122

5%

Cash collateral

94

6%

-

0%

951

62%

890

37%

Trading group:

Credit rating of A- or above

47

3%

125

5%

Credit rating of BBB- to BBB+

33

2%

75

3%

Not rated

108

7%

307

13%

188

12%

507

21%

Other accounts receivable

151

10%

585

25%

1,290

84%

1,982

83%

Derivative Instruments

(current and long-term)

Credit rating of A- or above

138

9%

202

9%

Credit rating of BBB- to BBB+

7

1%

8

0%

Not rated

95

6%

186

8%

240

16%

396

17%

$

1,530

100%

$

2,378

100%

Cash Collateral Positions

As at

December 31

December 31

millions of dollars

2023

2022

Cash collateral provided to others

$

101

$

224

Cash collateral received from others

$

22

$

112

XML

FV Measurements (Tables)

12 Months Ended

Dec. 31, 2023

FV Measurements [Abstract]

Classification of Fair Value of Derivatives

As at

December 31, 2023

millions of dollars

Level 1

Level 2

Level 3

Total

Assets

Regulatory deferral:

 Commodity swaps and forwards

$

7

$

6

$

-

$

13

 FX forwards

-

3

-

3

7

9

-

16

HFT derivatives:

 Power swaps and physical contracts

(5)

23

-

18

 Natural gas swaps, futures, forwards, physical 

 contracts and related transportation

42

108

34

184

37

131

34

202

Other derivatives:

 FX forwards

-

18

-

18

 Equity derivatives 

4

-

-

4

4

18

-

22

Total assets

48

158

34

240

Liabilities

Regulatory deferral:

 Commodity swaps and forwards

43

30

-

73

 FX forwards

-

3

-

3

43

33

-

76

HFT derivatives:

 Power swaps and physical contracts

-

24

-

24

 Natural gas swaps, futures, forwards and physical 

 contracts

13

19

365

397

13

43

365

421

Other derivatives:

 FX forwards

-

7

-

7

-

7

-

7

Total liabilities

56

83

365

504

Net assets (liabilities) 

$

(8)

$

75

$

(331)

$

(264)

As at

December 31, 2022

millions of dollars

Level 1

Level 2

Level 3

Total

Assets

Regulatory deferral:

 Commodity swaps and forwards

$

120

$

48

$

-

$

168

 FX forwards

-

18

-

18

 Physical natural gas purchases and sales

-

-

52

52

120

66

52

238

HFT derivatives:

 Power swaps and physical contracts

9

31

4

44

 Natural gas swaps, futures, forwards, physical 

 contracts and related transportation

3

72

34

109

12

103

38

153

Other derivatives:

 FX forwards

-

5

-

5

Total assets

132

174

90

396

Liabilities

Regulatory deferral:

 Commodity swaps and forwards

15

9

-

24

 FX forwards

-

1

-

1

15

10

-

25

HFT derivatives:

 Power swaps and physical contracts

2

28

1

31

 Natural gas swaps, futures, forwards and physical 

 contracts

51

118

825

994

53

146

826

1,025

Other derivatives:

 FX forwards

-

23

-

23

 Equity derivatives

5

-

-

5

Total liabilities

73

179

826

1,078

Net assets (liabilities)

$

59

$

(5)

$

(736)

$

(682)

Change in Fair Value of Level 3 Financial Assets

The change in the FV of the Level 3 financial assets for the year ended December 31, 2023 was as

follows:

Regulatory Deferral

HFT Derivatives

Physical natural

Natural 

millions of dollars

gas purchases

Power 

gas

Total

Balance, January 1, 2023

$

52

$

4

$

34

$

90

Realized gains (losses) included in fuel for generation

and purchased power

(49)

-

-

(49)

Unrealized gains (losses) included in regulatory

assets and liabilities

(3)

-

-

(3)

Total realized and unrealized gains (losses) included

in non-regulated operating revenues

-

(4)

-

(4)

Balance, December 31, 2023

$

-

$

-

$

34

$

34

Change in Fair Value of Level 3 Financial Liabilities

The change in the FV of the Level 3 financial liabilities for the year ended December 31, 2023 was as

follows:

 HFT Derivatives

Natural

millions of dollars

Power 

gas

Total

Balance, January 1, 2023

$

1

$

825

$

826

Total realized and unrealized gains included in non-

regulated operating revenues

(1)

(460)

(461)

Balance, December 31, 2023 

$

-

$

365

$

365

Quantitative Information About Significant Unobservable Inputs Used in Level 3 Measurements

Significant

Weighted 

millions of dollars

FV

Unobservable Input

Low

High

average

(1)

Assets

Liabilities

As at December 31, 2023

HFT derivatives – Natural 

34

365

Third-party pricing

$1.27

$16.25

$4.85

gas swaps, futures, forwards 

and physical contracts 

Total

$

34

$

365

Net liability

$

331

As at December 31, 2022

Regulatory deferral –

Physical

$

52

$

-

Third-party pricing

$5.79

$31.85

$12.27

natural gas purchases

HFT derivatives – Power 

4

1

Third-party pricing

$43.24

$269.10

$138.79

swaps and physical contracts

HFT derivatives – Natural 

34

825

Third-party pricing

$2.45

$33.88

$12.01

gas swaps, futures, forwards 

and physical contracts 

Total

$

90

$

826

Net liability

$

736

(1) Unobservable inputs were weighted by the relative FV of the instruments.

Financial Liabilities not Measured at Fair Value on Consolidated Balance Sheets

Long-term debt is a financial liability not measured at FV on the Consolidated Balance Sheets. The

balance consisted of the following:

As at

Carrying

millions of dollars

Amount

FV

Level 1

Level 2

Level 3

Total

December 31, 2023

$

18,365

$

16,621

$

-

$

16,363

$

258

$

16,621

December 31, 2022

$

16,318

$

14,670

$

-

$

14,284

$

386

$

14,670

XML

Receivables and Other Current Assets (Tables)

12 Months Ended

Dec. 31, 2023

Receivables and Other Current Assets [Abstract]

Summary of Receivables and Other Current Assets

18. RECEIVABLES AND OTHER CURRENT ASSETS

As at

December 31

December 31

millions of dollars 

2023

2022

Customer accounts receivable – billed

$

805

$

1,096

Capitalized transportation capacity

(1)

358

781

Customer accounts receivable – unbilled

363

424

Prepaid expenses

105

82

Income tax receivable

10

9

Allowance for credit losses

(15)

(17)

NMGC gas hedge settlement receivable

 (2)

 - 

162

Other

191

360

Total receivables and other current assets

$

1,817

$

2,897

(1) Capitalized transportation capacity represents the value of transportation/storage received by EES on asset management

agreements at the inception of the contracts. The asset is amortized over the term of each contract.

(2) Offsetting amount is included in regulatory liabilities for NMGC as gas hedges are part of the PGAC. For more information, refer

to note 6.

XML

Leases (Tables)

12 Months Ended

Dec. 31, 2023

Leases [Abstract]

Lessee, Operating Leases and Additional Information

As at

December 31

December 31

millions of dollars 

Classification

2023

2022

Right-of-use asset

Other long-term assets

$

54

$

58

Lease liabilities

 Current

Other current liabilities

3

3

 Long-term

Other long-term liabilities

55

59

Total lease liabilities

$

58

$

62

Additional information related to Emera's leases is as follows:

Year ended December 31

For the

2023

2022

Cash paid for amounts included in the measurement of lease liabilities:

 Operating cash flows for operating leases (millions of dollars)

$

8

$

8

Right-of-use assets obtained in exchange for lease obligations:

 Operating leases (millions of dollars)

$

1

$

1

Weighted average remaining lease term (years)

44

44

Weighted average discount rate- operating leases

3.93%

3.98%

Lessee, Future Minimum Lease Payments Under Non-Cancellable Operating Leases

Future minimum lease payments under non-cancellable operating leases for each of the next five years

and in aggregate thereafter are as follows:

millions of dollars

2024

2025

2026

2027

2028

Thereafter

Total

Minimum lease payments

$

6

$

5

$

3

$

3

$

3

$

111

$

131

Less imputed interest

(73)

Total

$

58

Lessor, Direct Finance and Sales-Type Leases

As at

December 31

December 31

millions of dollars 

2023

2022

Total minimum lease payment to be received

$

1,360

$

1,393

Less: amounts representing estimated executory costs

(190)

(205)

Minimum lease payments receivable

$

1,170

$

1,188

Estimated residual value of leased property (unguaranteed)

183

183

Less: Credit loss reserve

(2)

-

Less: unearned finance lease income

(693)

(733)

Net investment in direct finance and sales-type leases

$

658

$

638

Principal due within one year (included in "Receivables and other

current assets")

37

34

Net Investment in direct finance and sales type leases - long-term

$

621

$

604

Lessor, Future Minimum Lease Payments to be Received

As at December 31, 2023, future minimum lease payments to be received for each of the next five years

and in aggregate thereafter were as follows:

millions of dollars

2024

2025

2026

2027

2028

Thereafter

Total

Minimum lease payments to be

received

$

97

$

99

$

98

$

97

$

96

$

873

$

1,360

Less: executory costs

(190)

Total

$

1,170

XML

Property, Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2023

Property, Plant and Equipment [Abstract]

Regulated and Non-Regulated Assets

PP&E consisted of the following regulated and non-regulated assets: 

As at

December 31

December 31

millions of dollars 

Estimated useful life

2023

2022

Generation

3

 to

131

$

13,500

$

13,083

Transmission

10

 to

80

2,835

2,731

Distribution

4

 to

80

7,417

6,978

Gas transmission and distribution

6

 to

92

5,536

5,061

General plant and other

 (1)

2

 to

71

2,985

2,723

Total cost

32,273

30,576

Less: Accumulated depreciation

(1)

(9,994)

(9,574)

22,279

21,002

Construction work in progress

(1)

2,097

1,994

Net book value

$

24,376

$

22,996

(1) SeaCoast owns a

50

% undivided ownership interest in a jointly owned

26

-mile pipeline lateral located in Florida, which went into

service in 2020. At December 31, 2023, SeaCoast’s share of plant in service was $

27

 million USD (2022 – $

27

 million USD), and

accumulated depreciation of $

2

 million USD (2022 – $

1

 million USD). SeaCoast’s undivided ownership interest is financed with its

funds and all operations are accounted for as if such participating interest were a wholly owned facility. SeaCoast’s share of direct

expenses of the jointly owned pipeline is included in "OM&G" in the Consolidated Statements of Income.

XML

Employee Benefit Plans (Tables)

12 Months Ended

Dec. 31, 2023

Employee Benefit Plans [Abstract]

Changes in Benefit Obligation and Plan Assets and Funded Status

For the 

Year ended December 31

millions of dollars

2023

2022

Change in Projected Benefit Obligation

("PBO") and Accumulated Post-

retirement Benefit Obligation ("APBO")

Defined benefit

pension plans

Non-pension

benefit plans

Defined benefit

pension plans

Non-pension

benefit plans

Balance, January 1

$

2,158

$

243

$

2,624

$

318

Service cost

30

3

41

4

Plan participant contributions

6

6

6

6

Interest cost

111

13

80

9

Plan amendments

-

(14)

-

-

Benefits paid 

(147)

(29)

(174)

(31)

Actuarial losses (gains)

146

10

(480)

(79)

Settlements and curtailments

(8)

-

(6)

-

FX translation adjustment

(23)

(5)

67

16

Balance, December 31

$

2,273

$

227

$

2,158

$

243

Change in plan assets

Balance, January 1

$

2,163

$

46

$

2,702

$

51

Employer contributions

42

23

45

24

Plan participant contributions 

6

6

6

6

Benefits paid

(147)

(29)

(174)

(31)

Actual return on assets, net of expenses

262

3

(489)

(7)

Settlements and curtailments

(8)

-

(6)

-

FX translation adjustment

(20)

(1)

79

3

Balance, December 31

$

2,298

$

48

$

2,163

$

46

Funded status, end of year 

$

25

$

(179)

$

5

$

(197)

Plans with PBO/APBO in Excess of Plan Assets and Plans with Accumulated Benefit Obligation ("ABO") in Excess of Plan Assets

millions of dollars

2023

2022

Defined benefit

pension plans

Non-pension

benefit plans

Defined benefit

pension plans

Non-pension

benefit plans

PBO/APBO

$

120

$

205

$

1,006

$

221

FV of plan assets

37

-

914

-

Funded status

$

(83)

$

(205)

$

(92)

$

(221)

millions of dollars

2023

2022

Defined benefit

pension plans

Defined benefit

pension plans

ABO

$

114

$

111

FV of plan assets

37

33

Funded status

$

(77)

$

(78)

Amounts Recognized in Consolidated Balance Sheets

As at

December 31

December 31

millions of dollars

2023

2022

Defined benefit

pension plans

Non-pension

benefit plans

Defined benefit

pension plans

Non-pension

benefit plans

Other current liabilities

$

(5)

$

(18)

$

(13)

$

(20)

Long-term liabilities

(78)

(187)

(80)

(201)

Other long-term assets

108

26

98

24

AOCI, net of tax and regulatory assets

385

20

358

22

Less: Deferred income tax (expense)

recovery in AOCI

(8)

(1)

(7)

(1)

Net amount recognized

$

402

$

(160)

$

356

$

(176)

Amounts Recognized in AOCI and Regulatory Assets

Regulatory assets

Actuarial 

(gains) losses

Past service

(gains) costs

millions of dollars

Defined Benefit Pension Plans

Balance, January 1, 2023

$

336

$

15

$

-

Amortized in current period

(6)

(3)

-

Current year additions

1

41

-

Change in FX rate

(7)

-

-

Balance, December 31, 2023

$

324

$

53

$

-

Non-pension benefits plans

Balance, January 1, 2023

$

31

$

(10)

$

-

Amortized in current period

2

3

-

Current year reductions

(3)

(1)

(3)

Change in FX rate

(1)

-

1

Balance, December 31, 2023

$

29

$

(8)

$

(2)

As at

December

31

December

31

millions of dollars

2023

2022

Defined benefit

pension plans

Non-pension

benefit plans

Defined benefit

pension plans

Non-pension

benefit plans

Actuarial losses (gains)

$

53

(8)

$

15

$

(10)

Past service gains

-

(2)

-

-

Deferred income tax expense

8

1

7

1

AOCI, net of tax

61

(9)

22

(9)

Regulatory assets

324

29

336

31

AOCI, net of tax and regulatory assets

$

385

$

20

$

358

$

22

Net Periodic Benefit Cost

As at

Year ended December 31

millions of dollars

2023

2022

Defined benefit

pension plans

Non-pension

benefit plans

Defined benefit

pension plans

Non-pension

benefit plans

Service cost

$

30

$

3

$

41

$

4

Interest cost

111

13

80

9

Expected return on plan assets

(161)

(2)

(144)

-

Current year amortization of:

 Actuarial losses (gains)

1

(3)

8

-

 Regulatory assets (liability)

6

(2)

21

2

Settlement, curtailments

2

-

2

-

Total

$

(11)

$

9

$

8

$

15

Pension Plan Asset Allocations

Canadian Pension Plans

Asset Class

Target Range at Market

Short-term securities

0%

to

10%

Fixed income

34%

to

49%

Equities:

 Canadian

7%

to

17%

 Non-Canadian

35%

to

59%

Non-Canadian Pension Plans

Asset Class

Target Range at Market

Weighted average

Cash and cash equivalents

0%

to

10%

Fixed income

29%

to

49%

Equities

48%

to

68%

Fair Value of Plan Assets

millions of dollars

NAV

Level 1

Level 2

Total

Percentage

As at

December 31, 2023

Cash and cash equivalents

$

-

$

40

$

-

$

40

2

%

Net in-transits

-

(9)

-

(9)

-

%

Equity securities:

 Canadian equity

-

96

-

96

4

%

 United States equity 

-

141

-

141

6

%

 Other equity

-

112

-

112

5

%

Fixed income securities:

 Government

-

-

172

172

8

%

 Corporate

-

-

90

90

4

%

 Other

-

4

5

9

-

%

Mutual funds

-

50

-

50

2

%

Other

-

6

(1)

5

-

%

Open-ended investments

measured at NAV

 (1)

1,006

-

-

1,006

44

%

Common collective trusts

measured at NAV

(2)

586

-

-

586

25

%

Total 

$

1,592

$

440

$

266

$

2,298

100

%

As at

December 31, 2022

Cash and cash equivalents

$

-

$

70

$

-

$

70

3

%

Net in-transits

-

(70)

-

(70)

(3)

%

Equity securities:

 Canadian equity

-

87

-

87

4

%

 United States equity 

-

233

-

233

11

%

 Other equity

-

186

-

186

8

%

Fixed income securities:

 Government

-

-

104

104

5

%

 Corporate

-

-

83

83

4

%

 Other

-

3

11

14

1

%

Mutual funds

-

68

-

68

3

%

Other

-

-

(3)

(3)

-

%

Open-ended investments

measured at NAV

 (1)

790

-

-

790

36

%

Common collective trusts

measured at NAV

(2)

601

-

-

601

28

%

Total 

$

1,391

$

577

$

195

$

2,163

100

%

(1) Net asset value ("NAV") investments are open-ended registered and non-registered mutual funds, collective investment trusts,

or pooled funds. NAV’s are calculated at least monthly and the funds honour subscription and redemption activity regularly.

(2) The common collective trusts are private funds valued at NAV. The NAVs are calculated based on bid prices of the underlying

securities. Since the prices are not published to external sources, NAV is used as a practical expedient. Certain funds invest

primarily in equity securities of domestic and foreign issuers while others invest in long duration U.S. investment grade fixed

income assets and seeks to increase return through active management of interest rate and credit risks. The funds honour

subscription and redemption activity regularly.

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

2024

$

34

$

19

Expected benefit payments

2024

172

21

2025

163

21

2026

166

21

2027

171

21

2028

173

20

2029 – 2033

890

95

Assumptions Used in Accounting for Defined Benefit Pension and Other Post-Retirement Benefit Plans

Assumptions:

The following table shows the assumptions that have been used in accounting for DB pension and other

post-retirement benefit plans:

2023

2022

(weighted average assumptions)

Defined benefit

pension plans

Non-pension

benefit plans

Defined benefit

pension plans

Non-pension

benefit plans

Benefit obligation – December 31:

Discount rate - past service

4.89

%

4.89

%

5.33

%

5.31

%

Discount rate - future service

4.88

%

4.89

%

5.34

%

5.32

%

Rate of compensation increase

3.87

%

3.85

%

3.62

%

3.61

%

Health care trend - initial (next year)

-

6.04

%

-

5.40

%

 - ultimate 

-

3.76

%

-

3.77

%

 - year ultimate reached

2043

2043

Benefit cost for year ended December 31:

Discount rate - past service

5.33

%

5.31

%

3.05

%

2.81

%

Discount rate - future service

5.34

%

5.32

%

3.18

%

2.92

%

Expected long-term return on plan assets

6.56

%

2.16

%

6.07

%

1.32

%

Rate of compensation increase

3.62

%

3.61

%

3.31

%

3.29

%

Health care trend - initial (current year)

-

5.40

%

-

5.09

%

 - ultimate 

-

3.77

%

-

3.77

%

 - year ultimate reached

2043

2042

Actual assumptions used differ by plan.

XML

Goodwill (Tables)

12 Months Ended

Dec. 31, 2023

Goodwill [Abstract]

Change in Goodwill

22. GOODWILL

The change in goodwill for the year ended December 31 was due to the following:

millions of dollars 

2023

2022

Balance, January 1

$

6,012

$

5,696

Change in FX rate

(141)

389

GBPC impairment charge

-

(73)

Balance, December 31

$

5,871

$

6,012

XML

Short-Term Debt (Tables)

12 Months Ended

Dec. 31, 2023

Short-Term Debt [Abstract]

Short-Term Debt and Related Weighted-Average Interest Rates

millions of dollars 

2023

Weighted

average 

interest rate

2022

Weighted

average 

interest rate

TEC

Advances on revolving credit facilities

$

277

5.68

%

$

1,380

5.00

%

Emera

Non-revolving term facilities

796

6.07

%

796

5.19

%

Bank indebtedness 

9

-

%

-

-

%

TECO Finance 

Advances on revolving credit and term facilities

245

6.54

%

481

5.47

%

PGS

Advances on revolving credit facilities

73

6.36

%

-

-

%

NMGC

Advances on revolving credit facilities

25

6.46

%

59

5.15

%

GBPC

Advances on revolving credit facilities

8

5.54

%

10

5.25

%

Short-term debt

$

1,433

$

2,726

The Company’s total short-term revolving and non-revolving credit facilities, outstanding borrowings and

available capacity as at December 31 were as follows: 

millions of dollars

Maturity

2023

2022

TEC - Unsecured committed revolving credit facility

2026

$

401

$

1,084

TECO Energy/TECO Finance - revolving credit facility

2026

-

542

TECO Finance - Unsecured committed revolving credit facility

2026

529

-

Emera - Unsecured non-revolving term facility

2024

400

400

Emera - Unsecured non-revolving term facility

2024

400

400

PGS - Unsecured revolving credit facility

2028

331

-

TEC - Unsecured revolving facility

2024

265

542

TEC - Unsecured revolving facility

2024

265

-

NMGC - Unsecured revolving credit facility

2026

165

169

Other - Unsecured committed revolving credit facilities

Various

17

18

Total

$

2,773

$

3,155

Less:

Advances under revolving credit and term facilities

1,433

2,731

Letters of credit issued within the credit facilities

3

4

Total advances under available facilities

1,436

2,735

Available capacity under existing agreements

$

1,337

$

420

XML

Other Current Liabilities (Tables)

12 Months Ended

Dec. 31, 2023

Other Current Liabilities

Components of Other Current Liabilities

As at

December 31

December 31

millions of dollars 

2023

2022

Accrued charges

$

172

$

174

Nova Scotia Cap-and-Trade Program provision (note 6)

-

172

Accrued interest on long-term debt

107

97

Pension and post-retirement liabilities (note 21)

23

33

Sales and other taxes payable

11

14

Income tax payable

2

9

Other

112

80

$

427

$

579

XML

Long-Term Debt (Tables)

12 Months Ended

Dec. 31, 2023

Long-term Debt [Abstract]

Summary of Long-Term Debt, Revolving Credit Facilities, Outstanding Borrowings and Available Capacity

Weighted average interest

rate

(1)

millions of dollars

2023

2022

Maturity

2023

2022

Emera 

Bankers acceptances, SOFR loans 

Variable

Variable

2027

$

465

$

403

Unsecured fixed rate notes

4.84%

2.90%

2030

500

500

Fixed to floating subordinated notes

(2)

6.75%

6.75%

2076

1,587

1,625

$

2,552

$

2,528

Emera Finance 

Unsecured senior notes

3.65%

3.65%

2024 - 2046

$

3,637

$

3,725

TEC

(3)

Fixed rate notes and bonds

4.61%

4.15%

2024 - 2051

$

5,654

$

4,341

PGS

Fixed rate notes and bonds

5.63%

3.78%

2028 - 2053

$

1,223

$

772

NMGC

Fixed rate notes and bonds

3.78%

3.11%

2026 - 2051

$

642

$

521

Non-revolving term facility, floating rate

Variable

Variable

2024

30

108

$

672

$

629

NMGI

Fixed rate notes and bonds

3.64%

3.64%

2024

$

198

$

203

NSPI

Discount Notes

(4)

Variable

Variable

2024 - 2027

$

721

$

881

Medium term fixed rate notes

5.13%

5.14%

2025 - 2097

3,165

2,665

$

3,886

$

3,546

EBP

Senior secured credit facility

Variable

Variable

2026

$

246

$

249

ECI

Secured senior notes

Variable

Variable

2027

$

75

$

86

Amortizing fixed rate notes

4.00%

3.97%

2026

79

100

Non-revolving term facility, floating rate

Variable

Variable

2025

29

30

Non-revolving term facility, fixed rate

2.15%

2.05%

2025 - 2027

155

91

Secured fixed rate senior notes

(5)

3.09%

3.06%

2024 - 2029

84

142

$

422

$

449

Adjustments

Fair market value adjustment - TECO Energy acquisition

$

-

$

2

Debt issuance costs

(125)

(126)

Amount due within one year

(676)

(574)

$

(801)

$

(698)

Long-Term Debt

$

17,689

$

15,744

(1) Weighted average interest rate of fixed rate long-term debt.

(2) In 2023, the Company recognized $

109

 million in interest expense (2022 – $

110

 million) related to its fixed to floating

subordinated notes.

(3) A substantial part of TEC’s tangible assets are pledged as collateral to secure its first mortgage bonds. There are currently no

bonds outstanding under TEC’s first mortgage bond indenture.

(4) Discount notes are backed by a revolving credit facility which matures in 2027. Banker’s acceptances are issued under NSPI’s

non-revolving term facility which matures in 2024. NSPI has the intention and unencumbered ability to refinance bankers’

acceptances for a period of greater than one year.

(5) Notes are issued and payable in either USD or BBD.

The Company’s total long-term revolving credit facilities, outstanding borrowings and available capacity as

at December 31 were as follows:

millions of dollars

Maturity

2023

2022

Emera – revolving credit facility

(1)

June 2027

$

900

$

900

TEC - Unsecured committed revolving credit facility

December 2026

657

-

NSPI - revolving credit facility

(1)

December 2027

800

800

NSPI - non-revolving credit facility

July 2024

400

400

Emera - Unsecured non-revolving credit facility

February 2024

400

-

NMGC - Unsecured non-revolving credit facility

March 2024

30

108

ECI – revolving credit facilities

October 2024

10

11

Total

$

3,197

$

2,219

Less:

Borrowings under credit facilities

1,884

1,396

Letters of credit issued inside credit facilities

6

12

Use of available facilities

$

1,890

$

1,408

Available capacity under existing agreements

$

1,307

$

811

(1) Advances on the revolving credit facility can be made by way of overdraft on accounts up to $

50

 million.

As at

Financial Covenant

Requirement

December 31, 2023

Emera

Syndicated credit facilities

Debt to capital ratio

Less than or equal to

0.70

 to 1

0.57

 : 1

Long-Term Debt Maturities

millions of dollars

2024

2025

2026

2027

2028

Thereafter

Total

Emera

$

199

$

-

$

1,587

$

266

$

-

$

500

$

2,552

Emera US Finance LP

397

-

992

-

-

2,248

3,637

TEC

397

-

-

-

-

5,257

5,654

PGS

-

-

-

-

463

760

1,223

NMGC

30

-

93

-

-

549

672

NMGI

198

-

-

-

-

-

198

NSPI

398

125

40

323

-

3,000

3,886

EBP

-

-

246

-

-

-

246

ECI

51

139

89

77

62

4

422

Total

$

1,670

$

264

$

3,047

$

666

$

525

$

12,318

$

18,490

XML

Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2023

Asset Retirement Obligations [Abstract]

Change in Asset Retirement Obligations

The change in ARO for the years ended December 31 is as follows:

millions of dollars

2023

2022

Balance, January 1

$

174

$

174

Accretion included in depreciation expense

9

9

Change in FX rate

(1)

3

Additions

-

1

Accretion deferred to regulatory asset (included in PP&E)

18

1

Liabilities settled

(8)

(1)

Revisions in estimated cash flows

-

(13)

Balance, December 31

$

192

$

174

XML

Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2023

Commitments and Contingencies Disclosure [Abstract]

Summary of Contractual Commitments

millions of dollars

2024

2025

2026

2027

2028

Thereafter

Total

Transportation

(1)

$

696

$

495

$

405

$

388

$

338

$

2,597

$

4,919

Purchased power

(2)

274

249

263

312

312

3,435

4,845

Fuel, gas supply and storage

556

215

62

-

5

-

838

Capital projects

778

111

70

1

-

-

960

Equity investment commitments

(3)

240

-

-

-

-

-

240

Other

154

147

56

46

35

221

659

$

2,698

$

1,217

$

856

$

747

$

690

$

6,253

$

12,461

(1) Purchasing commitments for transportation of fuel and transportation capacity on various pipelines. Includes a commitment of

$

134

 million related to a gas transportation contract between PGS and SeaCoast through 2040.

(2) Annual requirement to purchase electricity production from IPPs or other utilities over varying contract lengths.

(3) Emera has a commitment to make equity contributions to the LIL related to an investment true up in 2024 and sustaining capital

contributions over the life of the partnership. The commercial agreements between Emera and Nalcor require true ups to finalize the

respective investment obligations of the parties in relation the Maritime Link and LIL which is expected to be approximately $

240

million in 2024. In addition, Emera has future commitments to provide sustaining capital to the LIL for routine capital and major

maintenance.

XML

Cumulative Preferred Stock (Tables)

12 Months Ended

Dec. 31, 2023

Cumulative Preferred Stock [Abstract]

Summary of Cumulative Preferred Stock

Authorized:

Unlimited number of First Preferred shares, issuable in series.

Unlimited number of Second Preferred shares, issuable in series.

December 31, 2023

December 31, 2022

Annual Dividend

Redemption

Issued and

Net

Issued and

Net 

Per Share

Price per share

Outstanding

Proceeds

Outstanding

Proceeds

Series A

$

0.5456

$

25.00

4,866,814

$

119

4,866,814

$

119

Series B

Floating

$

25.00

1,133,186

$

28

1,133,186

$

28

Series C

$

1.6085

$

25.00

10,000,000

$

245

10,000,000

$

245

Series E

$

1.1250

$

25.00

5,000,000

$

122

5,000,000

$

122

Series F

$

1.0505

$

25.00

8,000,000

$

195

8,000,000

$

195

Series H

$

1.5810

$

25.00

12,000,000

$

295

12,000,000

$

295

Series J

$

1.0625

$

25.00

8,000,000

$

196

8,000,000

$

196

Series L

$

1.1500

$

26.00

9,000,000

$

222

9,000,000

$

222

Total

58,000,000

$

1,422

58,000,000

$

1,422

Characteristics of the First Preferred Shares:

First Preferred Shares

(1)(2)

Initial Yield 

(%)

Current

Annual

Dividend 

($)

Minimum 

Reset

Dividend

Yield (%)

Earliest Redemption

and/or Conversion

Option Date

Redemption

Value 

($)

Right to

Convert on

a one for

one basis

Fixed rate reset

(3)(4)

 Series A

4.400

0.5456

1.84

August 15, 2025

25.00

Series B

 Series C

 (5)(6)

4.100

1.6085

2.65

August 15, 2028

25.00

Series D

 Series F

4.202

1.0505

2.63

February 15, 2025

25.00

Series G

Minimum rate reset

(3)(4)

 Series B

2.393

Floating

1.84

August 15, 2025

25.00

Series A

 Series H

(5)(7)

4.900

1.5810

4.90

August 15, 2028

25.00

Series I

 Series J

4.250

1.0625

4.25

May 15, 2026

25.00

Series K

Perpetual fixed rate

 Series E

 (8)

4.500

1.1250

25.00

 Series L

(9)

4.600

1.1500

November 15, 2026

26.00

(1) Holders are entitled to receive fixed or floating cumulative cash dividends when declared by the Board of Directors of the

Corporation.

(2) On or after the specified redemption dates, the Corporation has the option to redeem for cash the outstanding First Preferred

Shares, in whole or in part, at the specified per share redemption value plus all accrued and unpaid dividends up to but excluding the

dates fixed for redemption.

(3) On the redemption and/or conversion option date the reset annual dividend per share will be determined by multiplying $

25.00

 per

share by the annual fixed or floating dividend rate, which for Series A, C, F and H is the sum of the five-year Government of Canada

Bond Yield on the applicable reset date, plus the applicable reset dividend yield (Series H annual reset rate must be a minimum of

4.90

 per cent) and for Series B equals the Government of Treasury Bill Rate on the applicable reset date, plus 1.84 per cent.

(4) On each conversion option date, the holders have the option, subject to certain conditions, to convert any or all of their Shares

into an equal number of Cumulative Redeemable First Preferred Shares of a specified series. The Company has the right to redeem 

the outstanding Preferred Shares, Series D, Series G and Series I shares without the consent of the holder every five years thereafter

for cash, in whole or in part at a price of $

25.00

 per share plus all accrued and unpaid dividends up to but excluding the date fixed for

redemption and $

25.50

 per share plus all accrued and unpaid dividends up to but excluding the date fixed for redemption in the case

of redemptions on any other date after August 15, 2028, February 15, 2025 and August 15, 2028, respectively. The reset dividend

yield for Series I equals the Government of Treasury Bill Rate on the applicable reset date, plus

2.54

 per cent.

(5) On July 6, 2023, Emera announced it would not redeem the outstanding Preferred Shares, Series C and Series H on August 15,

2023. On August 4, 2023, Emera announced after having taken into account all conversion notices received from holders, no Series

C Shares were converted into Series D Shares and no Series H Shares were converted into Series I shares. 

(6) The annual fixed dividend per share for Series C Shares was reset from $

1.1802

 to $

1.6085

 for the five-year period from and

including August 15, 2028.

(7) The annual fixed dividend per share for Series H Shares was reset from $

1.2250

 to $

1.5810

 for the five-year period from and

including August 15, 2028.

(8) First Preferred Shares, Series E are redeemable at $25.00 per share.

(9) First Preferred Shares, Series L are redeemable at $

26.00

 on or after November 15, 2026 to November 15, 2027, decreasing

$

0.25

 each year until November 15, 2030 and $

25.00

 per share thereafter.

XML

Non-Controlling Interest in Subsidiaries (Tables)

12 Months Ended

Dec. 31, 2023

Non-Controlling Interest in Subsidiaries [Abstract]

Components of Non-Controlling Interest

29. NON-CONTROLLING INTEREST IN SUBSIDIARIES

As at

December 31

December 31

millions of dollars 

2023

2022

Preferred shares of GBPC 

$

14

$

14

$

14

$

14

Preferred Shares of GBPC

Preferred shares of GBPC:

Authorized:

10,000

 non-voting cumulative redeemable variable perpetual preferred shares.

2023

2022

Issued and outstanding:

number of

shares

millions of

dollars

number of

shares

millions of

dollars

Outstanding as at December 31

10,000

$

14

10,000

$

14

XML

Supplementary Information to Consolidated Statements of Cash Flows (Tables)

12 Months Ended

Dec. 31, 2023

Supplementary Information to Consolidated Statements of Cash Flows [Abstract]

Summary of Supplementary Information to Consolidated Statement of Cash Flows

For the 

Year ended December 31

millions of dollars

2023

2022

Changes in non-cash working capital:

 Inventory

$

(31)

$

(214)

 Receivables and other current assets

(1)

653

(636)

 Accounts payable

(538)

423

 Other current liabilities

(2)

(179)

193

Total non-cash working capital 

$

(95)

$

(234)

(1) Includes $

162

 million related to the January 2023 settlement of NMGC gas hedges (2022 – ($

162

) million). Offsetting regulatory

liability is included in operating cash flow before working capital resulting in no impact to net cash provided by operating activities.

(2) Includes ($

166

) million related to the Nova Scotia Cap-and-Trade program (2022 – $

172

 million). For further detail, refer to note

6. Offsetting regulatory asset (FAM) balance is included in operating cash flow before working capital resulting in no impact to net

cash provided by operating activities.

For the 

Year ended December 31

millions of dollars

2023

2022

Supplemental disclosure of cash paid:

Interest

$

930

$

699

Income taxes

$

43

$

67

Supplemental disclosure of non-cash activities:

Common share dividends reinvested

$

271

$

237

Decrease in accrued capital expenditures

$

(19)

$

(13)

Reclassification of short-term debt to long-term debt

$

657

$

-

Reclassification of long-term debt to short-term debt

$

-

$

500

Supplemental disclosure of operating activities:

Net change in short-term regulatory assets and liabilities

$

123

$

(157)

XML

Stock Based Compensation (Tables)

12 Months Ended

Dec. 31, 2023

Stock-Based Compensation [Abstract]

Weighted Average Fair Values per Stock Option and Assumptions for Options Granted

2023

2022

Weighted average FV per option

$

6.32

$

5.35

Expected term

(1)

5

 years

5

 years

Risk-free interest rate

(2)

3.53

%

1.79

%

Expected dividend yield

(3)

5.05

%

4.55

%

Expected volatility

(4)

20.07

%

18.87

%

(1) The expected term of the option awards is calculated based on historical exercise behaviour and represents the period of time

that the options are expected to be outstanding.

(2) Based on the Bank of Canada five-year government bond yields.

(3) Incorporates current dividend rates and historical dividend increase patterns.

(4) Estimated using the five-year historical volatility.

Summary of Stock Option Information

Total Options

Non-Vested Options

(1)

Number of

Options

 Weighted

average exercise

price per share

Number of

Options

Weighted

average grant

date fair-value

Outstanding as at December 31, 2022

2,853,879

$

50.41

1,348,400

$

4.08

Granted 

483,100

54.64

483,100

6.32

Exercised

(146,475)

43.94

N/A

N/A

Forfeited

(94,900)

56.32

(51,625)

3.61

Vested

N/A

N/A

(526,620)

3.58

Options outstanding December 31, 2023

3,095,604

$

51.20

1,253,255

$

5.17

Options exercisable December 31, 2023

(2)(3)

1,842,349

$

48.39

(1) As at December 31, 2023, there was $

5

 million of unrecognized compensation related to stock options not yet vested which is

expected to be recognized over a weighted average period of approximately

3

 years (2022 – $

4

 million,

3

 years).

(2) As at December 31, 2023, the weighted average remaining term of vested options was

5

 years with an aggregate intrinsic value of

$

8

 million (2022 –

5

 years, $

10

 million).

(3) As at December 31, 2023, the FV of options that vested in the year was $

2

 million (2022 – $

2

 million).

Summary of Activity Related to Employee and Director Deferred Share Units

Employee

DSU

Weighted

Average

Grant Date

FV

Director 

DSU

Weighted

Average

Grant Date

FV

Outstanding as at December 31, 2022

627,223

$

41.55

664,258

$

45.83

Granted including DRIP

85,740

47.66

117,893

49.99

Exercised

N/A

N/A

(53,093)

49.39

Outstanding and exercisable as at December 31, 2023

712,963

$

42.29

729,058

$

46.24

Summary of Activity Related to Employee Performance Share Units

Employee PSU

Weighted Average

Grant Date FV

Aggregate intrinsic value

Outstanding as at December 31, 2022

690,446

$

56.24

$

40

Granted including DRIP

386,261

52.71

Exercised

(323,155)

54.62

Forfeited

(10,187)

55.15

Outstanding as at December 31, 2023

743,365

$

55.13

$

41

Summary of Activity Related to Employee Restricted Share Units

Employee RSU

Weighted Average

Grant Date FV

Aggregate intrinsic value

Outstanding as at December 31, 2022

508,468

$

56.25

$

30

Granted including DRIP

236,537

52.07

Exercised

(171,537)

54.62

Forfeited

(10,827)

54.76

Outstanding as at December 31, 2023

562,641

$

55.01

$

32

XML

Variable Interest Entities (Tables)

12 Months Ended

Dec. 31, 2023

Variable Interest Entities [Abstract]

Summary of Material Unconsolidated Variable Interest Entities

As at

December 31, 2023

December 31, 2022

Maximum

Maximum

millions of dollars

Total

assets

exposure to

loss

Total

assets

 exposure to

loss

Unconsolidated VIEs in which Emera has variable interests

NSPML (equity accounted)

$

489

$

6

$

501

$

6

XML

Summary of Significant Accounting Policies (Nature of Operations) (Narrative) (Details) $ in Billions	12 Months Ended
	Dec. 31, 2023 CAD ($) Customers MW km
NSP Maritime Link Inc. | Equity Method Investee | NSP Maritime Link Inc Project
Nature of operations [Line items]
100% ownership	100.00%
Labrador-Island Link Limited Partnership | Equity Method Investee
Nature of operations [Line items]
Equity Method Investment, Ownership Percentage	31.00%
Maritimes and Northeast Pipeline | Equity Method Investee
Nature of operations [Line items]
Equity Method Investment, Ownership Percentage	12.90%
Maritimes and Northeast Pipeline | Operating | Gas Utilities and Infrastructure
Nature of operations [Line items]
Equity Method Investment, Ownership Percentage	12.90%
Length Of Pipeline | km	1,400
St. Lucia Electricity Services Limited | Equity Method Investee
Nature of operations [Line items]
Equity Method Investment, Ownership Percentage	19.50%
St. Lucia Electricity Services Limited | Operating | Other Electric Utilities
Nature of operations [Line items]
Equity Method Investment, Ownership Percentage	19.50%
Bear Swamp Power Company LLC | Equity Method Investee
Nature of operations [Line items]
Equity Method Investment, Ownership Percentage	50.00%
Tampa Electric | Operating | Florida Electric Utility
Nature of operations [Line items]
Number of Customers	840,000
Nova Scotia Power Inc. | Operating | Canadian Electric Utilities
Nature of operations [Line items]
Number of Customers	549,000
Emera Newfoundland and Labrador Holdings Inc. | Operating | Canadian Electric Utilities
Nature of operations [Line items]
Public Utilities Property Plant And Equipment Generation Capacity | MW	824
Emera Newfoundland and Labrador Holdings Inc. | Operating | Canadian Electric Utilities | NSP Maritime Link Inc Project
Nature of operations [Line items]
100% ownership	100.00%
Emera Newfoundland and Labrador Holdings Inc. | NSP Maritime Link Inc. | Operating | Canadian Electric Utilities
Nature of operations [Line items]
Public Utilities, Equipment, Transmission and Distribution | $	$ 1.8
Length Of Pipeline | km	170
Emera Newfoundland and Labrador Holdings Inc. | Labrador-Island Link Limited Partnership | Operating | Canadian Electric Utilities
Nature of operations [Line items]
Equity Method Investment, Ownership Percentage	31.00%
Public Utilities, Equipment, Transmission and Distribution | $	$ 3.7
Barbados Light and Power Company Limited | Operating | Other Electric Utilities
Nature of operations [Line items]
Number of Customers	134,000
Grand Bahama Power Company Limited | Operating | Other Electric Utilities
Nature of operations [Line items]
Number of Customers	19,000
Peoples Gas System Division | Gas Utilities and Infrastructure
Nature of operations [Line items]
Number of Customers	490,000
New Mexico Gas Company | Gas Utilities and Infrastructure
Nature of operations [Line items]
Number of Customers	540,000
Emera Brunswick Pipeline Company Limited | Gas Utilities and Infrastructure
Nature of operations [Line items]
Length Of Pipeline | km	145
Public Utilities, Property, Plant and Equipment, Distribution, Useful Life	25 years
Emera Brunswick Pipeline Company Limited | Operating | Gas Utilities and Infrastructure
Nature of operations [Line items]
Length Of Pipeline | km	145
Emera Energy | Bear Swamp Power Company LLC | Other
Nature of operations [Line items]
Equity Method Investment, Ownership Percentage	50.00%
Public Utilities Property Plant And Equipment Generation Capacity | MW	660
Brooklyn Power Corporation | Operating | Other
Nature of operations [Line items]
Public Utilities Property Plant And Equipment Generation Capacity | MW	30

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Summary of Significant Accounting Policies (Narrative) (Details)	12 Months Ended
	Dec. 31, 2023 CAD ($)	Dec. 31, 2022 CAD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2022 CAD ($)	Dec. 31, 2021 CAD ($)
Asset Impairment Charges
Impairment charge	$ 0	$ 73,000,000
Goodwill
Goodwill	5,871,000,000			$ 6,012,000,000	$ 5,696,000,000
Goodwill impairment charge	$ 0	73,000,000
Lease, Practical Expedient, Lessor Single Lease Component [true false]	true
Long-Lived Assets
Asset Impairment Charges
Impairment charge	$ 0	0
Equity Method Investments
Asset Impairment Charges
Impairment charge	0	0
Financial Assets
Asset Impairment Charges
Impairment charge	0	0
TECO Energy
Goodwill
Goodwill	5,868,000,000
GBPC
Goodwill
Goodwill
Goodwill impairment charge		$ 73,000,000
NMGC
Goodwill
Goodwill impairment charge	$ 0

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Dispositions (Narrative) (Details)	Mar. 31, 2022
Dolmec [Member] | Disposition
Details of the assets and liabilities classified as held for sale [Line items]
Sale of ownership interest	51.90%

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Segment Information (Reportable Segments) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Segment Reporting Information, For the year ended December 31
Total operating revenues	$ 7,563.0	$ 7,588.0
OM&G	1,879.0	1,596.0
Provincial, state and municipal taxes	433.0	367.0
Depreciation and amortization	1,049.0	952.0
Income from equity investments	146.0	129.0
Other income (expenses), net	158.0	145.0
Interest expense, net	925.0	709.0
GBPC Impairment charge	0.0	73.0
Income tax expense (recovery)	128.0	185.0
Non-controlling interest in subsidiaries	1.0	1.0
Preferred stock dividends	66.0	63.0
Net income (loss) attributable to common shareholders	977.7	945.1
Capital expenditures	2,921.0	2,575.0
Segment Reporting Information, As at December 31
Total assets	39,480.0	39,742.0
Investments subject to significant influence	1,402.0	1,418.0
Goodwill	5,871.0	6,012.0	$ 5,696.0
Regulated | Electric Revenue
Segment Reporting Information, For the year ended December 31
Total operating revenues	5,746.0	5,473.0
Fuel for generation and purchased power	1,881.0	2,171.0
Regulated | Natural gas
Segment Reporting Information, For the year ended December 31
Total operating revenues	1,489.0	1,681.0
Fuel for generation and purchased power	527.0	800.0
Florida Electric Utility
Segment Reporting Information, For the year ended December 31
Total operating revenues	3,548.0	3,280.0
Canadian Electric Utilities
Segment Reporting Information, For the year ended December 31
Total operating revenues	1,671.0	1,675.0
Gas Utilities and Infrastructure
Segment Reporting Information, For the year ended December 31
Total operating revenues	1,510.0	1,697.0
Other Electric Utilities
Segment Reporting Information, For the year ended December 31
Total operating revenues	526.0	518.0
Other
Segment Reporting Information, For the year ended December 31
Total operating revenues	308.0	418.0
Operating
Segment Reporting Information, For the year ended December 31
Total operating revenues	7,563.0	7,588.0
Operating | Florida Electric Utility
Segment Reporting Information, For the year ended December 31
Total operating revenues	3,556.0	3,287.0
OM&G	830.0	625.0
Provincial, state and municipal taxes	289.0	235.0
Depreciation and amortization	571.0	507.0
Income from equity investments	0.0	0.0
Other income (expenses), net	69.0	68.0
Interest expense, net	271.0	185.0
GBPC Impairment charge		0.0
Income tax expense (recovery)	117.0	121.0
Non-controlling interest in subsidiaries	0.0	0.0
Preferred stock dividends	0.0	0.0
Net income (loss) attributable to common shareholders	627.0	596.0
Capital expenditures	1,736.0	1,425.0
Segment Reporting Information, As at December 31
Total assets	21,119.0	21,053.0
Investments subject to significant influence	0.0	0.0
Goodwill	4,628.0	4,739.0
Operating | Florida Electric Utility | Regulated | Electric Revenue
Segment Reporting Information, For the year ended December 31
Fuel for generation and purchased power	920.0	1,086.0
Operating | Florida Electric Utility | Regulated | Natural gas
Segment Reporting Information, For the year ended December 31
Fuel for generation and purchased power	0.0	0.0
Operating | Canadian Electric Utilities
Segment Reporting Information, For the year ended December 31
Total operating revenues	1,671.0	1,675.0
OM&G	384.0	338.0
Provincial, state and municipal taxes	45.0	43.0
Depreciation and amortization	276.0	259.0
Income from equity investments	109.0	87.0
Other income (expenses), net	32.0	24.0
Interest expense, net	170.0	136.0
GBPC Impairment charge		0.0
Income tax expense (recovery)	(9.0)	(8.0)
Non-controlling interest in subsidiaries	0.0	0.0
Preferred stock dividends	0.0	0.0
Net income (loss) attributable to common shareholders	247.0	215.0
Capital expenditures	450.0	507.0
Segment Reporting Information, As at December 31
Total assets	8,634.0	8,223.0
Investments subject to significant influence	1,236.0	1,241.0
Goodwill	0.0	0.0
Operating | Canadian Electric Utilities | Regulated | Electric Revenue
Segment Reporting Information, For the year ended December 31
Fuel for generation and purchased power	699.0	803.0
Operating | Canadian Electric Utilities | Regulated | Natural gas
Segment Reporting Information, For the year ended December 31
Fuel for generation and purchased power	0.0	0.0
Operating | Gas Utilities and Infrastructure
Segment Reporting Information, For the year ended December 31
Total operating revenues	1,524.0	1,704.0
OM&G	405.0	365.0
Provincial, state and municipal taxes	91.0	83.0
Depreciation and amortization	126.0	118.0
Income from equity investments	21.0	21.0
Other income (expenses), net	11.0	13.0
Interest expense, net	129.0	81.0
GBPC Impairment charge		0.0
Income tax expense (recovery)	64.0	70.0
Non-controlling interest in subsidiaries	0.0	0.0
Preferred stock dividends	0.0	0.0
Net income (loss) attributable to common shareholders	214.0	221.0
Capital expenditures	664.0	574.0
Segment Reporting Information, As at December 31
Total assets	7,735.0	7,737.0
Investments subject to significant influence	118.0	128.0
Goodwill	1,240.0	1,270.0
Operating | Gas Utilities and Infrastructure | Regulated | Electric Revenue
Segment Reporting Information, For the year ended December 31
Fuel for generation and purchased power	0.0	0.0
Operating | Gas Utilities and Infrastructure | Regulated | Natural gas
Segment Reporting Information, For the year ended December 31
Fuel for generation and purchased power	527.0	800.0
Operating | Other Electric Utilities
Segment Reporting Information, For the year ended December 31
Total operating revenues	526.0	518.0
OM&G	130.0	123.0
Provincial, state and municipal taxes	3.0	3.0
Depreciation and amortization	68.0	61.0
Income from equity investments	4.0	4.0
Other income (expenses), net	7.0	0.0
Interest expense, net	23.0	19.0
GBPC Impairment charge		73.0
Income tax expense (recovery)	0.0	0.0
Non-controlling interest in subsidiaries	1.0	1.0
Preferred stock dividends	0.0	0.0
Net income (loss) attributable to common shareholders	37.0	(48.0)
Capital expenditures	63.0	63.0
Segment Reporting Information, As at December 31
Total assets	1,311.0	1,337.0
Investments subject to significant influence	48.0	49.0
Goodwill	0.0	0.0
Operating | Other Electric Utilities | Regulated | Electric Revenue
Segment Reporting Information, For the year ended December 31
Fuel for generation and purchased power	275.0	290.0
Operating | Other Electric Utilities | Regulated | Natural gas
Segment Reporting Information, For the year ended December 31
Fuel for generation and purchased power	0.0	0.0
Operating | Other
Segment Reporting Information, For the year ended December 31
Total operating revenues	339.0	440.0
OM&G	151.0	156.0
Provincial, state and municipal taxes	5.0	3.0
Depreciation and amortization	8.0	7.0
Income from equity investments	12.0	17.0
Other income (expenses), net	20.0	23.0
Interest expense, net	332.0	288.0
GBPC Impairment charge		0.0
Income tax expense (recovery)	(44.0)	2.0
Non-controlling interest in subsidiaries	0.0	0.0
Preferred stock dividends	66.0	63.0
Net income (loss) attributable to common shareholders	(147.0)	(39.0)
Capital expenditures	8.0	6.0
Segment Reporting Information, As at December 31
Total assets	1,938.0	2,835.0
Investments subject to significant influence	0.0	0.0
Goodwill	3.0	3.0
Operating | Other | Regulated | Electric Revenue
Segment Reporting Information, For the year ended December 31
Fuel for generation and purchased power	0.0	0.0
Operating | Other | Regulated | Natural gas
Segment Reporting Information, For the year ended December 31
Fuel for generation and purchased power	0.0	0.0
Intersegment Eliminations
Segment Reporting Information, For the year ended December 31
Total operating revenues	(53.0)	(36.0)
OM&G	(21.0)	(11.0)
Provincial, state and municipal taxes	0.0	0.0
Depreciation and amortization	0.0	0.0
Income from equity investments	0.0	0.0
Other income (expenses), net	19.0	17.0
Interest expense, net	0.0	0.0
GBPC Impairment charge		0.0
Income tax expense (recovery)	0.0	0.0
Non-controlling interest in subsidiaries	0.0	0.0
Preferred stock dividends	0.0	0.0
Net income (loss) attributable to common shareholders	0.0	0.0
Capital expenditures	0.0	0.0
Segment Reporting Information, As at December 31
Total assets	(1,257.0)	(1,443.0)
Investments subject to significant influence	0.0	0.0
Goodwill	0.0	0.0
Financing costs	95.0	13.0
Intersegment Eliminations | Regulated | Electric Revenue
Segment Reporting Information, For the year ended December 31
Fuel for generation and purchased power	(13.0)	(8.0)
Intersegment Eliminations | Regulated | Natural gas
Segment Reporting Information, For the year ended December 31
Fuel for generation and purchased power	0.0	0.0
Eliminations
Segment Reporting Information, For the year ended December 31
Total operating revenues	(53.0)	(36.0)
Eliminations | Florida Electric Utility
Segment Reporting Information, For the year ended December 31
Total operating revenues	8.0	7.0
Eliminations | Canadian Electric Utilities
Segment Reporting Information, For the year ended December 31
Total operating revenues	0.0	0.0
Eliminations | Gas Utilities and Infrastructure
Segment Reporting Information, For the year ended December 31
Total operating revenues	14.0	7.0
Eliminations | Other Electric Utilities
Segment Reporting Information, For the year ended December 31
Total operating revenues	0.0	0.0
Eliminations | Other
Segment Reporting Information, For the year ended December 31
Total operating revenues	$ 31.0	$ 22.0

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Segment Information (Geographical) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Revenues from External Customers and Long-Lived Assets [Line Items]
Revenues	$ 7,563	$ 7,588
Property, Plant and Equipment, Net	24,376	22,996
Canada
Revenues from External Customers and Long-Lived Assets [Line Items]
Revenues	1,727	1,725
Property, Plant and Equipment, Net	4,878	4,689
United States
Revenues from External Customers and Long-Lived Assets [Line Items]
Revenues	5,310	5,346
Property, Plant and Equipment, Net	18,588	17,382
Barbados
Revenues from External Customers and Long-Lived Assets [Line Items]
Revenues	389	384
Property, Plant and Equipment, Net	576	583
The Bahamas
Revenues from External Customers and Long-Lived Assets [Line Items]
Revenues	137	122
Property, Plant and Equipment, Net	334	342
Dominica
Revenues from External Customers and Long-Lived Assets [Line Items]
Revenues	$ 0	$ 11

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Segment Information (Narrative) (Details)	12 Months Ended
	Dec. 31, 2023
Segment Information [Abstract]
Segment Reporting, Factors Used to Identify Entity's Reportable Segments	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.

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Revenue (Disaggregation of Revenue by Major Source) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	$ 7,563	$ 7,588
Total operating revenues	7,563	7,588
Florida Electric Utility
Disaggregation of Revenue [Line Items]
Total operating revenues	3,548	3,280
Canadian Electric Utilities
Disaggregation of Revenue [Line Items]
Total operating revenues	1,671	1,675
Other Electric Utilities
Disaggregation of Revenue [Line Items]
Total operating revenues	526	518
Gas Utilities and Infrastructure
Disaggregation of Revenue [Line Items]
Total operating revenues	1,510	1,697
Other
Disaggregation of Revenue [Line Items]
Total operating revenues	308	418
Operating
Disaggregation of Revenue [Line Items]
Total operating revenues	7,563	7,588
Operating | Florida Electric Utility
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	3,556	3,287
Total operating revenues	3,556	3,287
Operating | Canadian Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	1,671	1,675
Total operating revenues	1,671	1,675
Operating | Other Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	526	518
Total operating revenues	526	518
Operating | Gas Utilities and Infrastructure
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	1,524	1,704
Total operating revenues	1,524	1,704
Operating | Other
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	339	440
Total operating revenues	339	440
Eliminations
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	(53)	(36)
Total operating revenues	(53)	(36)
Eliminations | Florida Electric Utility
Disaggregation of Revenue [Line Items]
Total operating revenues	8	7
Eliminations | Canadian Electric Utilities
Disaggregation of Revenue [Line Items]
Total operating revenues	0	0
Eliminations | Other Electric Utilities
Disaggregation of Revenue [Line Items]
Total operating revenues	0	0
Eliminations | Gas Utilities and Infrastructure
Disaggregation of Revenue [Line Items]
Total operating revenues	14	7
Eliminations | Other
Disaggregation of Revenue [Line Items]
Total operating revenues	31	22
Regulated | Other Electric And Regulatory
Disaggregation of Revenue [Line Items]
Total operating revenues	254	335
Non-Regulated
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	328	434
Total operating revenues	328	434
Non-Regulated | Operating | Florida Electric Utility
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Non-Regulated | Operating | Canadian Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Non-Regulated | Operating | Other Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Non-Regulated | Operating | Gas Utilities and Infrastructure
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	21	16
Non-Regulated | Operating | Other
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	339	440
Non-Regulated | Eliminations
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	(32)	(22)
Electric Revenue | Regulated
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	7,235	7,154
Total operating revenues	5,746	5,473
Electric Revenue | Regulated | Operating | Florida Electric Utility
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	3,556	3,287
Electric Revenue | Regulated | Operating | Canadian Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	1,671	1,675
Electric Revenue | Regulated | Operating | Other Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	526	518
Electric Revenue | Regulated | Operating | Gas Utilities and Infrastructure
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	1,503	1,688
Electric Revenue | Regulated | Operating | Other
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Electric Revenue | Regulated | Eliminations
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	(21)	(14)
Electric Revenue | Regulated | Residential
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	4,124	3,617
Electric Revenue | Regulated | Residential | Operating | Florida Electric Utility
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	2,307	1,799
Electric Revenue | Regulated | Residential | Operating | Canadian Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	910	834
Electric Revenue | Regulated | Residential | Operating | Other Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	183	184
Electric Revenue | Regulated | Residential | Operating | Gas Utilities and Infrastructure
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	724	800
Electric Revenue | Regulated | Residential | Operating | Other
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Electric Revenue | Regulated | Residential | Eliminations
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Electric Revenue | Regulated | Commercial
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	2,256	2,039
Electric Revenue | Regulated | Commercial | Operating | Florida Electric Utility
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	1,083	869
Electric Revenue | Regulated | Commercial | Operating | Canadian Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	463	427
Electric Revenue | Regulated | Commercial | Operating | Other Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	285	282
Electric Revenue | Regulated | Commercial | Operating | Gas Utilities and Infrastructure
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	425	461
Electric Revenue | Regulated | Commercial | Operating | Other
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Electric Revenue | Regulated | Commercial | Eliminations
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Electric Revenue | Regulated | Industrial
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	606	691
Electric Revenue | Regulated | Industrial | Operating | Florida Electric Utility
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	274	230
Electric Revenue | Regulated | Industrial | Operating | Canadian Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	219	353
Electric Revenue | Regulated | Industrial | Operating | Other Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	33	32
Electric Revenue | Regulated | Industrial | Operating | Gas Utilities and Infrastructure
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	93	83
Electric Revenue | Regulated | Industrial | Operating | Other
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Electric Revenue | Regulated | Industrial | Eliminations
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	(13)	(7)
Electric Revenue | Regulated | Other Electric
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	443	432
Electric Revenue | Regulated | Other Electric | Operating | Florida Electric Utility
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	395	398
Electric Revenue | Regulated | Other Electric | Operating | Canadian Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	41	28
Electric Revenue | Regulated | Other Electric | Operating | Other Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	7	6
Electric Revenue | Regulated | Other Electric | Operating | Gas Utilities and Infrastructure
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Electric Revenue | Regulated | Other Electric | Operating | Other
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Electric Revenue | Regulated | Other Electric | Eliminations
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Electric Revenue | Regulated | Regulatory Deferrals
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	(510)	(21)
Electric Revenue | Regulated | Regulatory Deferrals | Operating | Florida Electric Utility
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	(522)	(27)
Electric Revenue | Regulated | Regulatory Deferrals | Operating | Canadian Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Electric Revenue | Regulated | Regulatory Deferrals | Operating | Other Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	12	6
Electric Revenue | Regulated | Regulatory Deferrals | Operating | Gas Utilities and Infrastructure
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Electric Revenue | Regulated | Regulatory Deferrals | Operating | Other
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Electric Revenue | Regulated | Regulatory Deferrals | Eliminations
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0
Electric Revenue | Regulated | Other Electric And Regulatory | Operating | Florida Electric Utility
Disaggregation of Revenue [Line Items]
Total operating revenues	19	18
Electric Revenue | Regulated | Other Electric And Regulatory | Operating | Canadian Electric Utilities
Disaggregation of Revenue [Line Items]
Total operating revenues	38	33
Electric Revenue | Regulated | Other Electric And Regulatory | Operating | Other Electric Utilities
Disaggregation of Revenue [Line Items]
Total operating revenues	6	8
Gas Revenue | Regulated
Disaggregation of Revenue [Line Items]
Total operating revenues	1,489	1,681
Gas Revenue | Regulated | Other Electric And Regulatory | Operating | Gas Utilities and Infrastructure
Disaggregation of Revenue [Line Items]
Total operating revenues	199	283
Marketing and trading margin | Non-Regulated
Disaggregation of Revenue [Line Items]
Total operating revenues	96	143
Marketing and trading margin | Non-Regulated | Operating | Florida Electric Utility
Disaggregation of Revenue [Line Items]
Total operating revenues	0	0
Marketing and trading margin | Non-Regulated | Operating | Canadian Electric Utilities
Disaggregation of Revenue [Line Items]
Total operating revenues	0	0
Marketing and trading margin | Non-Regulated | Operating | Other Electric Utilities
Disaggregation of Revenue [Line Items]
Total operating revenues	0	0
Marketing and trading margin | Non-Regulated | Operating | Gas Utilities and Infrastructure
Disaggregation of Revenue [Line Items]
Total operating revenues	0	0
Marketing and trading margin | Non-Regulated | Operating | Other
Disaggregation of Revenue [Line Items]
Total operating revenues	96	143
Marketing and trading margin | Non-Regulated | Eliminations
Disaggregation of Revenue [Line Items]
Total operating revenues	0	0
Energy sales | Non-Regulated | Operating | Florida Electric Utility
Disaggregation of Revenue [Line Items]
Total operating revenues	0	0
Energy sales | Non-Regulated | Operating | Canadian Electric Utilities
Disaggregation of Revenue [Line Items]
Total operating revenues	0	0
Energy sales | Non-Regulated | Operating | Other Electric Utilities
Disaggregation of Revenue [Line Items]
Total operating revenues	0	0
Finance Income | Regulated | Repsol Energy Canada
Disaggregation of Revenue [Line Items]
Revenue which does not represent revenues from contracts with customers	62	61
Finance Income | Regulated | Operating | Florida Electric Utility | Repsol Energy Canada
Disaggregation of Revenue [Line Items]
Revenue which does not represent revenues from contracts with customers	0	0
Finance Income | Regulated | Operating | Canadian Electric Utilities | Repsol Energy Canada
Disaggregation of Revenue [Line Items]
Revenue which does not represent revenues from contracts with customers	0	0
Finance Income | Regulated | Operating | Other Electric Utilities | Repsol Energy Canada
Disaggregation of Revenue [Line Items]
Revenue which does not represent revenues from contracts with customers	0	0
Finance Income | Regulated | Operating | Gas Utilities and Infrastructure | Repsol Energy Canada
Disaggregation of Revenue [Line Items]
Revenue which does not represent revenues from contracts with customers	62	61
Finance Income | Regulated | Operating | Other | Repsol Energy Canada
Disaggregation of Revenue [Line Items]
Revenue which does not represent revenues from contracts with customers	0	0
Finance Income | Regulated | Eliminations | Repsol Energy Canada
Disaggregation of Revenue [Line Items]
Revenue which does not represent revenues from contracts with customers		0
Other revenue | Regulated | Other Electric And Regulatory | Operating | Other
Disaggregation of Revenue [Line Items]
Total operating revenues	0	0
Other revenue | Regulated | Other Electric And Regulatory | Eliminations
Disaggregation of Revenue [Line Items]
Total operating revenues	(8)	(7)
Other revenue | Non-Regulated
Disaggregation of Revenue [Line Items]
Total operating revenues	25	22
Other revenue | Non-Regulated | Operating | Gas Utilities and Infrastructure
Disaggregation of Revenue [Line Items]
Total operating revenues	21	16
Other revenue | Non-Regulated | Operating | Other
Disaggregation of Revenue [Line Items]
Total operating revenues	27	16
Other revenue | Non-Regulated | Eliminations
Disaggregation of Revenue [Line Items]
Total operating revenues	(23)	(10)
Mark-To-Market | Non-Regulated
Disaggregation of Revenue [Line Items]
Revenue which does not represent revenues from contracts with customers	207	269
Mark-To-Market | Non-Regulated | Operating | Florida Electric Utility
Disaggregation of Revenue [Line Items]
Revenue which does not represent revenues from contracts with customers	0	0
Mark-To-Market | Non-Regulated | Operating | Canadian Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue which does not represent revenues from contracts with customers	0	0
Mark-To-Market | Non-Regulated | Operating | Other Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue which does not represent revenues from contracts with customers	0	0
Mark-To-Market | Non-Regulated | Operating | Gas Utilities and Infrastructure
Disaggregation of Revenue [Line Items]
Revenue which does not represent revenues from contracts with customers	0	0
Mark-To-Market | Non-Regulated | Operating | Other
Disaggregation of Revenue [Line Items]
Revenue which does not represent revenues from contracts with customers	216	281
Mark-To-Market | Non-Regulated | Eliminations
Disaggregation of Revenue [Line Items]
Revenue which does not represent revenues from contracts with customers	$ (9)	$ (12)

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Revenue (Remaining Performance Obligations) (Narrative) (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Revenue Remaining Performance Obligation Expected Timing Of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 488	$ 450
Revenue, Remaining Performance Obligation, Expected Timing Of Satisfaction (Year)	2043
SeaCoast Gas Transmission, LLC | PGS
Revenue Remaining Performance Obligation Expected Timing Of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 134
Revenue, Remaining Performance Obligation, Expected Timing Of Satisfaction (Year)	2040

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Regulatory Assets and Liabilities (Regulated Assets) (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Regulatory Assets [Line Items]
Regulatory Assets, Current	$ 339	$ 602
Regulatory Assets, Long-term	2,766	3,018
Total regulatory assets	3,105	3,620
Deferred income tax regulatory assets
Regulatory Assets [Line Items]
Total regulatory assets	1,233	1,166
TEC capital cost recovery for early retired assets
Regulatory Assets [Line Items]
Total regulatory assets	671	674
NSPI FAM
Regulatory Assets [Line Items]
Total regulatory assets	395	307
Pension and post-retirement medical plan
Regulatory Assets [Line Items]
Total regulatory assets	364	369
Cost Recovery Clauses
Regulatory Assets [Line Items]
Total regulatory assets	151	707
Deferrals related to derivative instruments
Regulatory Assets [Line Items]
Total regulatory assets	88	30
Storm cost recovery clauses
Regulatory Assets [Line Items]
Total regulatory assets	52	138
Environmental Remediations
Regulatory Assets [Line Items]
Total regulatory assets	26	27
Stranded Cost Recovery
Regulatory Assets [Line Items]
Total regulatory assets	25	27
NMGC winter event gas cost recovery
Regulatory Assets [Line Items]
Total regulatory assets	0	69
Other
Regulatory Assets [Line Items]
Total regulatory assets	$ 100	$ 106

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Regulatory Assets and Liabilities (Regulated Liabilities) (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	$ 168	$ 495
Regulatory Liability, Long-term	1,604	1,778
Total regulatory liabilities	1,772	2,273
Accumulated reserve - COR
Regulatory Liabilities [Line Items]
Total regulatory liabilities	849	895
Deferred income tax regulatory liabilities
Regulatory Liabilities [Line Items]
Total regulatory liabilities	830	877
Cost Recovery Clauses
Regulatory Liabilities [Line Items]
Total regulatory liabilities	32	70
BLPC Self-insurance fund ("SIF") (note 32)
Regulatory Liabilities [Line Items]
Total regulatory liabilities	29	30
Deferrals related to derivative instruments
Regulatory Liabilities [Line Items]
Total regulatory liabilities	17	230
NMGC gas hedge settlements (note 18)
Regulatory Liabilities [Line Items]
Total regulatory liabilities	0	162
Other
Regulatory Liabilities [Line Items]
Total regulatory liabilities	$ 15	$ 9

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Regulatory Assets and Liabilities - Assets and Liabilities (Narrative) (Details) $ in Millions, $ in Millions	1 Months Ended			12 Months Ended
	Sep. 30, 2022 USD ($)	Feb. 28, 2021 USD ($)	Jan. 31, 2020 USD ($)	Dec. 31, 2025 CAD ($)	Dec. 31, 2024 CAD ($)	Dec. 31, 2023 CAD ($)	Dec. 31, 2023 USD ($)	Dec. 31, 2022 CAD ($)	Jun. 15, 2021 USD ($)
Public Utilities, General Disclosures [Line Items]
Regulatory Assets						$ 3,105		$ 3,620
NMGC winter event gas cost recovery
Public Utilities, General Disclosures [Line Items]
Regulatory Assets						$ 0		$ 69
GBPC | Hurricane | Loss from Catastrophes
Public Utilities, General Disclosures [Line Items]
Storm cost			$ 15
Recovery Period						5 years
GBPC | Steam turbine
Public Utilities, General Disclosures [Line Items]
Public Utilities, Property, Plant and Equipment, Amount of Loss (Recovery) on Plant Abandonment							$ 21
NSPI
Public Utilities, General Disclosures [Line Items]
Storm cost						$ 10
NSPI | Forecast
Public Utilities, General Disclosures [Line Items]
Storm cost				$ 10	$ 10
Tampa Electric
Public Utilities, General Disclosures [Line Items]
Storm cost	$ 119						$ 29
Recovery Period						15 years
NMGC
Public Utilities, General Disclosures [Line Items]
Recovery Period						30 months
Incremental gas cost		$ 108
NMGC | NMGC winter event gas cost recovery
Public Utilities, General Disclosures [Line Items]
Regulatory Assets									$ 108

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Regulatory Assets and Liabilities - Florida Electric Utility (Narrative) (Details) $ in Millions, $ in Millions				1 Months Ended	3 Months Ended	12 Months Ended
	Nov. 17, 2023 USD ($)	Jan. 23, 2023 USD ($)	Jan. 19, 2022 USD ($)	Sep. 30, 2022 USD ($)	Sep. 30, 2023 USD ($)	Dec. 31, 2023 CAD ($)	Dec. 31, 2023 USD ($)	Dec. 31, 2022 CAD ($)	Aug. 16, 2023 USD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)
Public Utilities, General Disclosures [Line Items]
State income tax						11.00%	11.00%	15.00%
Utilities Operating Expense, Depreciation and Amortization						$ 1,049		$ 952
Regulatory Assets						3,105		3,620
Florida Electric Utility | Operating
Public Utilities, General Disclosures [Line Items]
Utilities Operating Expense, Depreciation and Amortization						571		507
Cost Recovery Clauses
Public Utilities, General Disclosures [Line Items]
Regulatory Assets						151		707
Restoration Costs
Public Utilities, General Disclosures [Line Items]
Regulatory Assets						26		27
Storm cost recovery clauses
Public Utilities, General Disclosures [Line Items]
Regulatory Assets						$ 52		$ 138
Tampa Electric
Public Utilities, General Disclosures [Line Items]
Storm Damage Provision				$ 119			$ 29
Recovery Period						15 years
Tampa Electric | Big Bend Modernization Project | Unit 1 components | Florida Electric Utility | Operating
Public Utilities, General Disclosures [Line Items]
Estimated Amount of Investment										$ 876
Public Utilities, Property, Plant and Equipment, Accumulated Depreciation										$ 91
Tampa Electric | Storm cost recovery clauses
Public Utilities, General Disclosures [Line Items]
Storm Damage Provision					$ 35
Regulatory Assets		$ 131							$ 134
Approved reserve level		56
Tampa Electric | Florida Public Service Commission
Public Utilities, General Disclosures [Line Items]
Recovery Period											15 years
Tampa Electric | Florida Public Service Commission | Florida Electric Utility | Operating
Public Utilities, General Disclosures [Line Items]
Public Utilities, Disclosure of Rate Matters						TEC is regulated by the FPSC and is also subject to regulation by the Federal Energy Regulatory Commission. The FPSC sets rates at a level that allows utilities such as TEC to collect total revenues or revenue requirements equal to their cost of providing service, plus an appropriate return on invested capital. Base rates are determined in FPSC rate setting hearings which can occur at the initiative of TEC, the FPSC or other interested parties.	TEC is regulated by the FPSC and is also subject to regulation by the Federal Energy Regulatory Commission. The FPSC sets rates at a level that allows utilities such as TEC to collect total revenues or revenue requirements equal to their cost of providing service, plus an appropriate return on invested capital. Base rates are determined in FPSC rate setting hearings which can occur at the initiative of TEC, the FPSC or other interested parties.
Allowed equity capital structure						54.00%	54.00%
Public Utilities, Approved Rate Increase (Decrease), Amount	$ (22)
Public Utilities, Requested Rate Increase (Decrease), Amount			$ 169
Tampa Electric | Florida Public Service Commission | Additional adjustment for 2026 | Florida Electric Utility | Operating
Public Utilities, General Disclosures [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount							$ (100)
Tampa Electric | Florida Public Service Commission | Additional adjustment for 2027 | Florida Electric Utility | Operating
Public Utilities, General Disclosures [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount							$ (70)
Tampa Electric | Florida Public Service Commission | Cost Recovery Clauses | Florida Electric Utility | Operating
Public Utilities, General Disclosures [Line Items]
Approved regulated return on equity						10.20%	10.20%	10.20%
Public Utilities, Requested Rate Increase (Decrease), Amount		$ 518
Recovery Period		21 months
Tampa Electric | Florida Public Service Commission | Big Bend Modernization Project | Unit 1 components | Florida Electric Utility | Operating
Public Utilities, General Disclosures [Line Items]
Public Utilities, Property, Plant and Equipment, Plant in Service											$ 636
Public Utilities, Property, Plant and Equipment, Accumulated Depreciation											$ 267
Tampa Electric | Florida Public Service Commission | Projected Fuel Costs | Florida Electric Utility | Operating
Public Utilities, General Disclosures [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount		$ (170)
Tampa Electric | Florida Public Service Commission | Range, Minimum | Florida Electric Utility | Operating
Public Utilities, General Disclosures [Line Items]
Approved regulated return on equity						9.25%	9.25%	9.25%
Tampa Electric | Florida Public Service Commission | Range, Minimum | Base rate effective January 2025 | Florida Electric Utility | Operating
Public Utilities, General Disclosures [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount							$ (290)
Tampa Electric | Florida Public Service Commission | Range, Maximum | Florida Electric Utility | Operating
Public Utilities, General Disclosures [Line Items]
Approved regulated return on equity						11.25%	11.25%	11.25%
Tampa Electric | Florida Public Service Commission | Range, Maximum | Base rate effective January 2025 | Florida Electric Utility | Operating
Public Utilities, General Disclosures [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount							$ (320)

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Regulatory Assets and Liabilities - Canada Electric Utilities (Narrative) (Details) $ in Millions					3 Months Ended	12 Months Ended			24 Months Ended
	Jan. 29, 2024 CAD ($)	Dec. 01, 2023 CAD ($)	Oct. 31, 2023 CAD ($)	Aug. 15, 2021	Jun. 30, 2023 CAD ($)	Dec. 31, 2024	Dec. 31, 2023 CAD ($) km	Dec. 31, 2022 CAD ($)	Dec. 31, 2023 CAD ($) km	Dec. 21, 2023 CAD ($)	Mar. 31, 2023 CAD ($)	Feb. 28, 2022 CAD ($)
Public Utilities, General Disclosures [Line Items]
Regulatory Liabilities							$ 1,772	$ 2,273	$ 1,772
Utilities Operating Expense, Depreciation and Amortization							1,049	952
Contractual Obligation, to be Paid, Year One							2,698		2,698
Contractual Obligation, to be Paid, Year Two							1,217		1,217
Regulatory Assets							3,105	3,620	3,105
Non-current assets							11,396	11,850	$ 11,396
Canadian Electric Utilities | Operating
Public Utilities, General Disclosures [Line Items]
Utilities Operating Expense, Depreciation and Amortization							276	259
NSPI
Public Utilities, General Disclosures [Line Items]
Storm cost							$ 10
NSPI | Canadian Electric Utilities
Public Utilities, General Disclosures [Line Items]
Recovery Period							3 years		3 years
NSPI | Canadian Electric Utilities | Operating
Public Utilities, General Disclosures [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amended, Percentage							6.90%
Storm cost							$ 31
Deferred storm rider							$ 21		$ 21
NSPI | Canadian Electric Utilities | Operating | Nova Scotia Cap-and-Trade ("Cap-and-Trade") Program
Public Utilities, General Disclosures [Line Items]
Gas costs								166
Credits purchased from provincial auctions								$ 6
Compliance costs accrued											$ (166)
NSPI | Canadian Electric Utilities | Operating | Subsequent Event [Member]
Public Utilities, General Disclosures [Line Items]
Requested approval for sale of regulatory assets	$ 117
Amortization and financing costs	$ 117
Collection period of amortization and financing costs	10 years
NSPI | Range, Minimum | Canadian Electric Utilities | Operating
Public Utilities, General Disclosures [Line Items]
Approved regulated return on equity							8.75%	8.75%
NSPI | Range, Maximum | Canadian Electric Utilities | Operating
Public Utilities, General Disclosures [Line Items]
Approved regulated return on equity							9.25%	9.25%
Regulated common equity component							40.00%
NSPI | Scenario Plan | Canadian Electric Utilities | Operating
Public Utilities, General Disclosures [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amended, Percentage						6.50%
NSPI | NSPI FAM | Canadian Electric Utilities | Operating
Public Utilities, General Disclosures [Line Items]
Increase to regulatory assets					$ 51
NSPI | UARB | Canadian Electric Utilities | Operating
Public Utilities, General Disclosures [Line Items]
Amount requested to defer operating costs incurred from storm restoration			$ 24
Non-current assets							$ 24		24
NSPI | UARB | Canadian Electric Utilities | Operating | NSP Maritime Link Inc.
Public Utilities, General Disclosures [Line Items]
Holdback payable							$ 4	$ 8	$ 12
Estimate of possible percentage of receiving deliveries							90.00%		90.00%
Monthly holdback amount		$ 4						$ 2
Percent of contracted annual amount							10.00%		10.00%
Emera Newfoundland and Labrador Holdings Inc. | Canadian Electric Utilities | Operating | NSP Maritime Link Inc.
Public Utilities, General Disclosures [Line Items]
Public Utilities, Equipment, Transmission and Distribution							$ 1,800		$ 1,800
Number of pipelines							2
Length Of Pipeline | km							170		170
Regulatory Liabilities												$ 1,800
Costs not recoverable for rate approval												9
Costs not recoverable for rate approval net of tax												$ 7
Holdback payable							$ 4
Contractual Obligation, to be Paid, Year One							$ 164		$ 164	$ 164
Energy Delivery Commitments and Contracts, Term				35 years
Emera Newfoundland and Labrador Holdings Inc. | Range, Minimum | Canadian Electric Utilities | Operating | NSP Maritime Link Inc.
Public Utilities, General Disclosures [Line Items]
Approved regulated return on equity							8.75%
Emera Newfoundland and Labrador Holdings Inc. | Range, Maximum | Canadian Electric Utilities | Operating | NSP Maritime Link Inc.
Public Utilities, General Disclosures [Line Items]
Approved regulated return on equity							9.25%
Equity ratio							30.00%		30.00%

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Regulatory Assets and Liabilities - Gas Utilities and Infrastructure (Narrative) (Details) $ in Millions, $ in Millions				1 Months Ended	12 Months Ended		24 Months Ended
	Nov. 09, 2023 USD ($)	Sep. 14, 2023 USD ($)	May 20, 2022	Feb. 28, 2021 USD ($)	Dec. 31, 2023 CAD ($) km	Dec. 31, 2022 CAD ($)	Dec. 31, 2023 USD ($)
Public Utilities, General Disclosures [Line Items]
Accumulated depreciation					$ 9,994	$ 9,574
Regulatory assets					3,105	3,620
Storm cost recovery clauses
Public Utilities, General Disclosures [Line Items]
Regulatory assets					$ 52	$ 138
Emera Brunswick Pipeline Company Limited | Gas Utilities and Infrastructure
Public Utilities, General Disclosures [Line Items]
Length Of Pipeline | km					145
Emera Brunswick Pipeline Company Limited | Gas Utilities and Infrastructure | Operating
Public Utilities, General Disclosures [Line Items]
Length Of Pipeline | km					145
Public Utilities, Property, Plant and Equipment, Transmission and Distribution, Useful Life					25 years
NMGC
Public Utilities, General Disclosures [Line Items]
Incremental gas cost				$ 108
NMGC | Gas Utilities and Infrastructure | Operating
Public Utilities, General Disclosures [Line Items]
Approved regulated return on equity					9.375%	9.375%
Allowed equity capital structure					52.00%	52.00%
NMGC | New Mexico Public Regulatory | Gas Utilities and Infrastructure | Operating
Public Utilities, General Disclosures [Line Items]
Approved regulated return on equity			10.50%
Public Utilities, Requested Rate Increase (Decrease), Amount		$ 49
PGS | Gas Utilities and Infrastructure | Operating
Public Utilities, General Disclosures [Line Items]
Allowed equity capital structure					54.70%
Accumulated Depreciation, Depletion and Amortization, Property, Plant and Equipment, Period Decrease					$ 20	$ 14	$ 34
PGS | Gas Utilities and Infrastructure | Operating | Scenario Plan
Public Utilities, General Disclosures [Line Items]
Approved regulated return on equity	10.15%
Allowed equity capital structure	54.70%
Phase-in Plan, Amount of Capitalized Costs Recovered	$ 11
Public Utilities, Approved Rate Increase (Decrease), Amount	118
PGS | Gas Utilities and Infrastructure | Operating | Cast Iron/Bare Steel Pipe Replacement | Scenario Plan
Public Utilities, General Disclosures [Line Items]
Phase-in Plan, Amount of Capitalized Costs Recovered	$ 107
PGS | Range, Minimum | Gas Utilities and Infrastructure | Operating
Public Utilities, General Disclosures [Line Items]
Approved regulated return on equity					8.90%
PGS | Range, Minimum | Gas Utilities and Infrastructure | Operating | Scenario Plan
Public Utilities, General Disclosures [Line Items]
Allowed equity capital structure	54.70%
PGS | Range, Maximum | Gas Utilities and Infrastructure | Operating
Public Utilities, General Disclosures [Line Items]
Approved regulated return on equity						11.00%
PGS | Mid Point | Gas Utilities and Infrastructure | Operating
Public Utilities, General Disclosures [Line Items]
Approved regulated return on equity					9.90%
BPLC
Public Utilities, General Disclosures [Line Items]
Approved regulated return on equity					10.00%	10.00%

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Regulatory Assets and Liabilities - Other Electric Utilities (Narrative) (Details) $ in Millions, $ in Millions		1 Months Ended		12 Months Ended
	Apr. 01, 2022 USD ($)	Sep. 30, 2022 USD ($)	Jan. 31, 2022	Dec. 31, 2023 CAD ($)	Dec. 31, 2022 CAD ($)
Public Utilities, General Disclosures [Line Items]
Income tax (expense) recovery				$ (128)	$ (185)
Regulatory liabilities				1,772	2,273
Other Electric Utilities | Operating
Public Utilities, General Disclosures [Line Items]
Income tax (expense) recovery				$ 0	$ 0
Barbados Light and Power Company Limited
Public Utilities, General Disclosures [Line Items]
Approved regulated return on equity				10.00%	10.00%
Barbados Light and Power Company Limited | Other Electric Utilities | Operating
Public Utilities, General Disclosures [Line Items]
Cost sharing ratio				50.00%
Barbados Light and Power Company Limited | Fair Trading Commission | Other Electric Utilities | Operating
Public Utilities, General Disclosures [Line Items]
Approved regulated return on equity		11.75%
Allowed equity capital structure		55.00%
Deferred Tax Liabilities, Regulatory Assets and Liabilities		$ 5.0
Public Utilities, Interim Rate Increase (Decrease), Amount		1.0
Regulatory liabilities		50.0
Accumulated depreciation		$ 16.0
GBPC | GBPA | Other Electric Utilities | Operating
Public Utilities, General Disclosures [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount	$ 3.5
Approved regulated return on equity				8.32%	8.23%
GBPC | GBPA | Other Electric Utilities | Operating | Scenario Plan
Public Utilities, General Disclosures [Line Items]
Approved regulated return on equity			12.84%

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Investments Subject to Significant Influence and Equity Income (Summary of Investments Subject to Significant Influence) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2015
Schedule of Equity Method Investments [Line Items]
Investments subject to significant influence	$ 1,402	$ 1,418
Income (loss) from equity investments and subsidiaries	146	129
Equity Method Investment, Summarized Financial Information [Abstract]
Other long-term liabilities	820	825
Equity Method Investee
Schedule of Equity Method Investments [Line Items]
Investments subject to significant influence	1,402	1,418
Income (loss) from equity investments and subsidiaries	146	129
Equity Method Investee | Emera Inc.
Equity Method Investment, Summarized Financial Information [Abstract]
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity	10
LIL | Equity Method Investee
Schedule of Equity Method Investments [Line Items]
Investments subject to significant influence	747	740
Income (loss) from equity investments and subsidiaries	$ 63	58
Percentage of Ownership	31.00%
LIL | Equity Method Investee | Emera Inc.
Schedule of Equity Method Investments [Line Items]
Percentage of Ownership	31.00%
LIL | Equity Method Investee | Class B units | NSP Maritime Link Inc Project
Schedule of Equity Method Investments [Line Items]
100% ownership	100.00%
LIL | Equity Method Investee | Total Units Issued [Member]
Schedule of Equity Method Investments [Line Items]
Percentage of Ownership	24.50%
NSPML | Equity Method Investee
Schedule of Equity Method Investments [Line Items]
Investments subject to significant influence	$ 489	501
Income (loss) from equity investments and subsidiaries	$ 46	29
NSPML | Equity Method Investee | NSP Maritime Link Inc Project
Schedule of Equity Method Investments [Line Items]
100% ownership	100.00%
M&NP | Equity Method Investee
Schedule of Equity Method Investments [Line Items]
Investments subject to significant influence	$ 118	128
Income (loss) from equity investments and subsidiaries	$ 21	21
Percentage of Ownership	12.90%
M&NP | Equity Method Investee | Emera Inc.
Schedule of Equity Method Investments [Line Items]
Percentage of Ownership	12.90%
Lucelec | Equity Method Investee
Schedule of Equity Method Investments [Line Items]
Investments subject to significant influence	$ 48	49
Income (loss) from equity investments and subsidiaries	$ 4	4
Percentage of Ownership	19.50%
Lucelec | Equity Method Investee | Emera Inc.
Schedule of Equity Method Investments [Line Items]
Percentage of Ownership	19.50%
Bear Swamp
Equity Method Investment, Summarized Financial Information [Abstract]
Other long-term liabilities	$ 81	95	$ 179
Bear Swamp | Equity Method Investee
Schedule of Equity Method Investments [Line Items]
Investments subject to significant influence	0	0
Income (loss) from equity investments and subsidiaries	$ 12	$ 17
Percentage of Ownership	50.00%
Bear Swamp | Equity Method Investee | Emera Inc.
Schedule of Equity Method Investments [Line Items]
Percentage of Ownership	50.00%
Maritime Link And LIL | Plan, subject to approval
Schedule of Equity Method Investments [Line Items]
Percentage of Ownership	49.00%

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Investments Subject to Significant Influence and Equity Income (Summary of Investments Subject to Significant Influence - NSPML) (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Balance Sheets
Current assets	$ 3,708	$ 4,896
Property, plant and equipment	24,376	22,996
Regulatory assets	2,766	3,018
Non-current assets	11,396	11,850
Total assets	39,480	39,742
Current liabilities	4,544	7,287
Non-current liabilities	22,848	21,014
Equity	12,088	11,441	$ 10,150
Total liabilities and equity	39,480	39,742
Variable Interest Entity, Not Primary Beneficiary | NSPML
Balance Sheets
Current assets	21	17
Property, plant and equipment	1,473	1,517
Regulatory assets	272	265
Non-current assets	29	29
Total assets	1,795	1,828
Current liabilities	48	48
Long-term debt	1,109	1,149
Non-current liabilities	149	130
Equity	489	501
Total liabilities and equity	$ 1,795	$ 1,828

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Other Income, Net (Components of Other Expense, Net) (Details) - CAD ($) $ in Millions		12 Months Ended
	Dec. 15, 2022	Dec. 31, 2023	Dec. 31, 2022
Other Income, Net [Abstract]
Interest income		$ 43	$ 25
AFUDC		38	52
Pension non-current service cost recovery		35	24
FX gains (losses)		20	(26)
TECO Guatemala Holdings award	$ 63	0	63
Other		22	7
Other income (expenses), net		$ 158	$ 145

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Interest Expense, Net (Components of Interest Expense, Net) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Interest Expense, Net [Abstract]
Interest on debt	$ 954	$ 727
Allowance for borrowed funds used during construction	(16)	(21)
Other	(13)	3
Interest expense, net	$ 925	$ 709

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Income Taxes (Reconciliation of Effective Income Tax Rate) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Income before provision for income taxes	$ 1,173	$ 1,194
Statutory income tax rate	29.00%	29.00%
Income taxes, at statutory income tax rates	$ 340	$ 346
Deferred income taxes on regulated income recorded as regulatory assets and regulatory liabilities	(72)	(70)
Tax credits	(53)	(18)
Foreign tax rate variance	(36)	(44)
Amortization of deferred income tax regulatory liabilities	(33)	(33)
Tax effect of equity earnings	(15)	(10)
GBPC impairment charge	0	21
Other	(3)	(7)
Income tax expense	$ 128	$ 185
Effective income tax rate	11.00%	15.00%
Regulatory Liabilities	$ 1,772	$ 2,273
Incremental tax benefits payable to customers [Member]
Regulatory Liabilities	$ 30	$ 9

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Income Taxes (Composition of Taxes on Income from Continuing Operations) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Components of Income Tax Expense (Benefit), Continuing Operations [Abstract]
Deferred income taxes	$ 97	$ 152
Income tax expense	128	185
Canada
Components of Income Tax Expense (Benefit), Continuing Operations [Abstract]
Current income taxes	26	25
Deferred income taxes	93	122
Operating loss carry forwards	(93)	(94)
United States
Components of Income Tax Expense (Benefit), Continuing Operations [Abstract]
Current income taxes	5	8
Deferred income taxes	128	252
Investment tax credits	(29)	(7)
Operating loss carry forwards	$ (2)	$ (121)

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Income Taxes (Composition of Income Before Provision for Income Taxes) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Composition of taxes on income from continuing operations [Line items]
Income before provision for income taxes	$ 1,173	$ 1,194
Canada
Composition of taxes on income from continuing operations [Line items]
Income before provision for income taxes	171	173
United States
Composition of taxes on income from continuing operations [Line items]
Income before provision for income taxes	964	1,063
Other
Composition of taxes on income from continuing operations [Line items]
Income before provision for income taxes	$ 38	$ (42)

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Income Taxes (Schedule of Deferred Income Tax Assets and Liabilities) (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Deferred income tax assets:
Tax loss carryforwards	$ 1,195	$ 1,207
Tax credit carryforwards	454	415
Derivative instruments	205	45
Regulatory liabilities	175	264
Other	372	341
Total deferred income tax assets before valuation allowance	2,401	2,272
Valuation allowance	(363)	(312)
Total deferred income tax assets after valuation allowance	2,038	1,960
Deferred income tax (liabilities):
PP&E	(3,223)	(2,981)
Derivative instruments	(235)	(125)
Investments subject to significant influence	(216)	(181)
Regulatory assets	(196)	(310)
Other	(312)	(322)
Total deferred income tax liabilities	(4,182)	(3,919)
Consolidated Balance Sheets presentation:
Long-term deferred income tax assets	208	237
Long-term deferred income tax liabilities	(2,352)	(2,196)
Net deferred income tax liabilities	$ (2,144)	$ (1,959)

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Income Taxes (Net Operating Loss ("NOL"), Capital Loss and Tax Credit Carryforwards and Their Expiration Periods) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2023 CAD ($)
Canada | Capital loss
Composition of taxes on income from continuing operations [Line items]
Gross Tax Carryforwards	$ 73
Subject to Valuation Allowance	(73)
Net Tax Credit Carryforwards	$ 0
Expiration period	Indefinite
Canada | NOL
Composition of taxes on income from continuing operations [Line items]
Gross Tax Carryforwards	$ 2,914
Subject to Valuation Allowance	(1,164)
Net Tax Credit Carryforwards	$ 1,750
Expiration period	2026 - 2043
United States | NOL
Composition of taxes on income from continuing operations [Line items]
Gross Tax Carryforwards	$ 1,360
Subject to Valuation Allowance	(1)
Net Tax Credit Carryforwards	$ 1,359
Expiration period	2036 - Indefinite
United States | Tax credit
Composition of taxes on income from continuing operations [Line items]
Gross Tax Carryforwards	$ 454
Subject to Valuation Allowance	(3)
Net Tax Credit Carryforwards	$ 451
Expiration period	2025 - 2043
State | NOL
Composition of taxes on income from continuing operations [Line items]
Gross Tax Carryforwards	$ 1,003
Subject to Valuation Allowance	(1)
Net Tax Credit Carryforwards	$ 1,002
Expiration period	2026 - Indefinite
Other | NOL
Composition of taxes on income from continuing operations [Line items]
Gross Tax Carryforwards	$ 81
Subject to Valuation Allowance	(28)
Net Tax Credit Carryforwards	$ 53
Expiration period	2024 - 2030

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Income Taxes (Details of Change in Unrecognized Tax Benefits) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Beginning, January 1	$ 33	$ 28
Increases due to tax positions related to current year	5	5
Increases due to tax positions related to a prior year	1	2
Decreases due to tax positions related to a prior year	(2)	(2)
Balance, December 31	$ 37	$ 33

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Income Taxes (Unrecognized tax benefits) (Details) - CAD ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items]
Temporary Differences/Potential change	$ 4,700,000,000	$ 3,800,000,000
Net amount in dispute	126,000,000	126,000,000
Prepaid amount in dispute	55,000,000
Deferred Tax Assets, Allowance	363,000,000	312,000,000
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued [Abstract]
Amount that could affect effective tax rate	37,000,000	33,000,000
Accrued interest	9,000,000	7,000,000
Income Tax Examination, Interest Expense	2,000,000	$ 1,000,000
Accrued penalties	$ 0

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Common Stock (Summary of Issued and Outstanding Common Stock) (Details) - CAD ($) shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Increase (Decrease) In Common Stock Value [Roll Forward]
Beginning Balance	$ 7,762
Issuance of common stock	397	$ 248
Senior management stock options exercised and Employee Share Purchase Plan ("ECSPP")	32	36
Ending Balance	$ 8,462	$ 7,762
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Beginning Balance	269,950	261,070
Issuance of common stock (shares)	8,290	4,070
Issued under Purchase Plans at market rate	5,260	4,210
Options exercised under senior management share option plan	620	600
Ending Balance	284,120	269,950
Common Stock
Increase (Decrease) In Common Stock Value [Roll Forward]
Beginning Balance	$ 7,762	$ 7,242
Issuance of common stock	397	248
Issued under Purchase Plans at market rate	272	238
Senior management stock options exercised and Employee Share Purchase Plan ("ECSPP")	31	34
Ending Balance	$ 8,462	$ 7,762

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Common Stock (Narrative) (Details) - CAD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Debt Instrument [Line Items]
Issuance of common stock (shares)	8,290,000	4,070,000.00
Gross proceeds from Issuance of Common Stock	$ 424	$ 277
Percentage of outstanding stock maximum	10.00%
ATM Program
Debt Instrument [Line Items]
Maximum common stock issued from treasury amount	$ 600
ATM Program | Common Stock
Debt Instrument [Line Items]
Issuance of common stock (shares)	8,287,037	4,072,469
Gross proceeds from Issuance of Common Stock	$ 400	$ 250
Net proceeds from issuance of common stock	$ 397	$ 248
Average price per share, issued	$ 48.27	$ 61.31
Employee Stock Option Plan
Debt Instrument [Line Items]
Common Stock, Capital Shares Reserved for Future Issuance	6,000,000	6,000,000
Share Unit Plans
Debt Instrument [Line Items]
Common Stock, Capital Shares Reserved for Future Issuance	2,000,000	2,700,000
Dividend Reinvestment
Debt Instrument [Line Items]
Common Stock, Capital Shares Reserved for Future Issuance	18,000,000	10,000,000

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Earnings Per Share (Computation of Basic and Diluted Earnings per Share) (Details) - CAD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Numerator
Net income attributable to common shareholders	$ 977.7	$ 945.1
Diluted numerator	$ 977.7	$ 945.1
Denominator
Weighted average shares of common stock outstanding - basic	273.6	265.5
Stock-based compensation	0.2	0.4
Weighted average shares of common stock outstanding- diluted	273.8	265.9
Earnings per common share
Basic	$ 3.57	$ 3.56
Diluted	$ 3.57	$ 3.55

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Accumulated Other Comprehensive Income (Components of Accumulated Other Comprehensive Income) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance	$ 11,441	$ 10,150
Net current period other comprehensive income (loss)	(273)	553
Ending Balance	12,088	11,441
Accumulated Other Comprehensive Income (Loss)
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance	578	25
Other comprehensive income (loss) before reclassifications	(232)	531
Amounts reclassified from accumulated other comprehensive income loss	(41)	22
Net current period other comprehensive income (loss)	(273)	553
Ending Balance	305	578
Unrealized (loss) gain on translation of self-sustaining foreign operations
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance	639	10
Other comprehensive income (loss) before reclassifications	(270)	629
Amounts reclassified from accumulated other comprehensive income loss	0	0
Net current period other comprehensive income (loss)	(270)	629
Ending Balance	369	639
Net change in net investment hedges
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance	(62)	35
Other comprehensive income (loss) before reclassifications	38	(97)
Amounts reclassified from accumulated other comprehensive income loss	0	0
Net current period other comprehensive income (loss)	38	(97)
Ending Balance	(24)	(62)
Losses on derivatives recognized as cash flow hedges
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance	16	18
Other comprehensive income (loss) before reclassifications		0
Amounts reclassified from accumulated other comprehensive income loss	(2)	(2)
Net current period other comprehensive income (loss)	(2)	(2)
Ending Balance	14	16
Net change on available-for-sale investments
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance	(2)	(1)
Other comprehensive income (loss) before reclassifications	0	(1)
Amounts reclassified from accumulated other comprehensive income loss	0	0
Net current period other comprehensive income (loss)	0	(1)
Ending Balance	(2)	(2)
Net change in unrecognized pension and post-retirement benefit costs
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance	(13)	(37)
Other comprehensive income (loss) before reclassifications	0	0
Amounts reclassified from accumulated other comprehensive income loss	(39)	24
Net current period other comprehensive income (loss)	(39)	24
Ending Balance	$ (52)	$ (13)

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Accumulated Other Comprehensive Income (Reclassifications out of Accumulated Other Comprehensive Income (Loss)) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total operating revenues	$ 7,563	$ 7,588
Interest expense, net (note 9)	(925)	(709)
Other income, net (note 8)	158	145
Income tax (expense) recovery	(128)	(185)
Net income	1,045	1,009
Reclassification out of Accumulated Other Comprehensive Income [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Net income	(41)	22
Reclassification out of Accumulated Other Comprehensive Income [Member] | Losses (gain) on derivatives recognized as cash flow hedges
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Income tax (expense) recovery	(1)	(1)
Reclassification out of Accumulated Other Comprehensive Income [Member] | Losses (gain) on derivatives recognized as cash flow hedges | Interest rate hedge
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Interest expense, net (note 9)	(2)	(2)
Reclassification out of Accumulated Other Comprehensive Income [Member] | Net change in unrecognized pension and post-retirement benefit costs
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total before tax	(38)	25
Income tax (expense) recovery	1	1
Net income	(39)	24
Reclassification out of Accumulated Other Comprehensive Income [Member] | Actuarial (gains) losses
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Other income, net (note 8)	0	10
Reclassification out of Accumulated Other Comprehensive Income [Member] | Past service costs (gains)
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Other income, net (note 8)	2	0
Reclassification out of Accumulated Other Comprehensive Income [Member] | Amounts reclassified into obligations
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Pension and post-retirement benefits	$ (40)	$ 15

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Inventory (Components of Inventory) (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Inventory [Abstract]
Fuel	$ 382	$ 404
Materials	408	365
Inventory Total	$ 790	$ 769

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Derivatives Instruments (Derivative Assets and Liabilities) (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
HFT derivatives
Derivative Assets	$ 348	$ 429
Derivative Liabilities	567	1,301
Other derivatives
Other, Derivative Assets	22	5
Other, Derivative Liabilities	7	28
Derivative Assets
Total gross current derivative assets	389	690
Total impact of master netting agreements	(149)	(294)
Derivative Asset, Total	240	396
Derivative Assets, Current	174	296
Derivative Assets, Long-term	66	100
Derivative Liabilities
Total gross current derivative liabilities	653	1,372
Total impact of master netting agreements	(149)	(294)
Derivative Liabilities, Total	504	1,078
Derivative Liabilities, Current	386	888
Derivative Liabilities, Long-term	118	190
Equity derivatives
Other derivatives
Other, Derivative Assets	4	0
Other, Derivative Liabilities	0	5
FX forwards
Other derivatives
Other, Derivative Assets	18	5
Other, Derivative Liabilities	7	23
Power swaps and physical contracts
HFT derivatives
Derivative Assets	29	89
Derivative Liabilities	36	77
Natural gas swaps, futures, forwards, physical contracts
HFT derivatives
Derivative Assets	319	340
Derivative Liabilities	531	1,224
Regulatory deferral
HFT derivatives
Derivative Assets	19	256
Derivative Liabilities	79	43
Derivative Assets
Total impact of master netting agreements	(3)	(18)
Derivative Liabilities
Total impact of master netting agreements	(3)	(18)
Regulatory deferral | Commodity swaps and forwards
Regulatory deferral
Regulatory deferral, Derivative Assets	16	186
Regulatory deferral, Derivative Liabilities	76	42
Regulatory deferral | FX forwards
HFT derivatives
Derivative Assets	3	18
Derivative Liabilities	3	1
Regulatory deferral | Physical natural gas purchases and sales [Member]
HFT derivatives
Derivative Assets	0	52
Derivative Liabilities	0	0
HFT derivatives
Derivative Assets
Total impact of master netting agreements	(146)	(276)
Derivative Liabilities
Total impact of master netting agreements	$ (146)	$ (276)

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Derivatives Instruments (Cash Flow Hedges Recorded in AOCI) (Details) - CAD ($) $ in Millions		12 Months Ended
	May 26, 2021	Dec. 31, 2023	Dec. 31, 2022
Cash Flow Hedges
Realized gain in interest expense, net		$ 2	$ 2
Total gains in net income		2	2
Total unrealized gain in AOCI - effective portion, net of tax		14	$ 16
Unrealized gains currently in AOCI to be reclassified into net income within the next twelve months		$ 2
Cash flow hedges | Treasury lock
Cash Flow Hedges
Derivative gain loss amortization period	10 years
Total unrealized gain in AOCI - effective portion, net of tax	$ 19

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Derivatives Instruments (Changes in Realized and Unrealized Gains (Losses) on Derivatives Receiving Regulatory Deferral) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gain (loss) on derivatives receiving regulatory deferral	$ 666	$ (206)
FX forwards
Derivative Instruments, Gain (Loss) [Line Items]
Realized (gain) loss on derivatives receiving regulatory deferral	17	(24)
Regulatory deferral | Physical natural gas purchases
Derivative Instruments, Gain (Loss) [Line Items]
Total change derivative instruments on derivatives receiving regulatory deferral	(52)	(36)
Regulatory deferral | Physical natural gas purchases | Regulatory Assets
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gain (loss) on derivatives receiving regulatory deferral	0	0
Realized (gain) loss on derivatives receiving regulatory deferral	0	0
Regulatory deferral | Physical natural gas purchases | Regulatory Liabilities
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gain (loss) on derivatives receiving regulatory deferral	(3)	28
Realized (gain) loss on derivatives receiving regulatory deferral	0	0
Regulatory deferral | Physical natural gas purchases | Inventory
Derivative Instruments, Gain (Loss) [Line Items]
Realized (gain) loss on derivatives receiving regulatory deferral	0	0
Regulatory deferral | Physical natural gas purchases | Regulated fuel for generation and purchased
Derivative Instruments, Gain (Loss) [Line Items]
Realized (gain) loss on derivatives receiving regulatory deferral	(49)	(64)
Regulatory deferral | Physical natural gas purchases | Other
Derivative Instruments, Gain (Loss) [Line Items]
Realized (gain) loss on derivatives receiving regulatory deferral	0	0
Regulatory deferral | Commodity swaps and forwards
Derivative Instruments, Gain (Loss) [Line Items]
Total change derivative instruments on derivatives receiving regulatory deferral	(204)	14
Regulatory deferral | Commodity swaps and forwards | Regulatory Assets
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gain (loss) on derivatives receiving regulatory deferral	(109)	(69)
Realized (gain) loss on derivatives receiving regulatory deferral	(5)	48
Regulatory deferral | Commodity swaps and forwards | Regulatory Liabilities
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gain (loss) on derivatives receiving regulatory deferral	(73)	343
Realized (gain) loss on derivatives receiving regulatory deferral	2	(41)
Regulatory deferral | Commodity swaps and forwards | Inventory
Derivative Instruments, Gain (Loss) [Line Items]
Realized (gain) loss on derivatives receiving regulatory deferral	4	(121)
Regulatory deferral | Commodity swaps and forwards | Regulated fuel for generation and purchased
Derivative Instruments, Gain (Loss) [Line Items]
Realized (gain) loss on derivatives receiving regulatory deferral	(9)	(146)
Regulatory deferral | Commodity swaps and forwards | Other
Derivative Instruments, Gain (Loss) [Line Items]
Realized (gain) loss on derivatives receiving regulatory deferral	(14)	0
Regulatory deferral | FX forwards
Derivative Instruments, Gain (Loss) [Line Items]
Total change derivative instruments on derivatives receiving regulatory deferral	(17)	18
Regulatory deferral | FX forwards | Regulatory Assets
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gain (loss) on derivatives receiving regulatory deferral	(3)	1
Realized (gain) loss on derivatives receiving regulatory deferral	0	0
Regulatory deferral | FX forwards | Regulatory Liabilities
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gain (loss) on derivatives receiving regulatory deferral	0	16
Realized (gain) loss on derivatives receiving regulatory deferral	0	0
Regulatory deferral | FX forwards | Inventory
Derivative Instruments, Gain (Loss) [Line Items]
Realized (gain) loss on derivatives receiving regulatory deferral	(10)	1
Regulatory deferral | FX forwards | Regulated fuel for generation and purchased
Derivative Instruments, Gain (Loss) [Line Items]
Realized (gain) loss on derivatives receiving regulatory deferral	(4)	0
Regulatory deferral | FX forwards | Other
Derivative Instruments, Gain (Loss) [Line Items]
Realized (gain) loss on derivatives receiving regulatory deferral	$ 0	$ 0

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Derivatives Instruments (Notional Volumes of Outstanding Derivatives Designated for Regulatory Deferral) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2023 CAD ($) MMBTU MWh t
Commodity swaps and forwards | Coal | 2024
Derivative [Line Items]
Natural Gas (Mmbtu) / Power (MWh) | MWh | t	1
Commodity swaps and forwards | Coal | 2025-2026
Derivative [Line Items]
Natural Gas (Mmbtu) / Power (MWh) | MWh | t	0
Commodity swaps and forwards | Natural gas | 2024
Derivative [Line Items]
Natural Gas (Mmbtu) / Power (MWh) | MWh	16
Commodity swaps and forwards | Natural gas | 2025-2026
Derivative [Line Items]
Natural Gas (Mmbtu) / Power (MWh) | MWh	10
Commodity swaps and forwards | Power | 2024
Derivative [Line Items]
Natural Gas (Mmbtu) / Power (MWh) | MWh | MWh	1
Commodity swaps and forwards | Power | 2025-2026
Derivative [Line Items]
Natural Gas (Mmbtu) / Power (MWh) | MWh | MWh	1
Physical natural gas purchases | Natural gas | 2024
Derivative [Line Items]
Natural Gas (Mmbtu) / Power (MWh) | MWh	7
Physical natural gas purchases | Natural gas | 2025-2026
Derivative [Line Items]
Natural Gas (Mmbtu) / Power (MWh) | MWh	6
Foreign Exchange Swaps and Forward Contracts | 2024
Derivative [Line Items]
Notional volumes of outstanding derivatives designated as cash flow hedges that are expected to settle | $	$ 241
Weighted average rate	1.3155
% of USD requirements	63.00%
Foreign Exchange Swaps and Forward Contracts | 2025-2026
Derivative [Line Items]
Notional volumes of outstanding derivatives designated as cash flow hedges that are expected to settle | $	$ 70
Weighted average rate	1.3197
% of USD requirements	17.00%

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Derivatives Instruments (Realized and Unrealized Gains (Losses) on HFT Derivatives) (Details) - HFT derivatives - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Derivative Instruments, Gain (Loss) [Line Items]
Realized and unrealized gains (losses) with respect to HFT derivatives	$ 1,037	$ 64
Operating revenues | Power | Non-Regulated
Derivative Instruments, Gain (Loss) [Line Items]
Realized and unrealized gains (losses) with respect to HFT derivatives	(6)	17
Operating revenues | Natural gas | Non-Regulated
Derivative Instruments, Gain (Loss) [Line Items]
Realized and unrealized gains (losses) with respect to HFT derivatives	$ 1,043	$ 47

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Derivatives Instruments (Notional Volumes of Outstanding HFT Derivatives) (Details) - HFT derivatives MWh in Millions, MMBTU in Millions	12 Months Ended
	Dec. 31, 2023 MWh MMBTU
Power | Purchases | 2024
Derivative [Line Items]
Notional volumes of outstanding derivatives that are expected to settle | MWh	1
Power | Purchases | 2025
Derivative [Line Items]
Notional volumes of outstanding derivatives that are expected to settle | MWh	0
Power | Purchases | 2026
Derivative [Line Items]
Notional volumes of outstanding derivatives that are expected to settle | MWh	0
Power | Purchases | 2027
Derivative [Line Items]
Notional volumes of outstanding derivatives that are expected to settle | MWh	0
Power | Purchases | 2028 and thereafter
Derivative [Line Items]
Notional volumes of outstanding derivatives that are expected to settle | MWh	0
Power | Sales | 2024
Derivative [Line Items]
Notional volumes of outstanding derivatives that are expected to settle | MWh	1
Power | Sales | 2025
Derivative [Line Items]
Notional volumes of outstanding derivatives that are expected to settle | MWh	0
Power | Sales | 2026
Derivative [Line Items]
Notional volumes of outstanding derivatives that are expected to settle | MWh	0
Power | Sales | 2027
Derivative [Line Items]
Notional volumes of outstanding derivatives that are expected to settle | MWh	0
Power | Sales | 2028 and thereafter
Derivative [Line Items]
Notional volumes of outstanding derivatives that are expected to settle | MWh	0
Natural gas | Purchases | 2024
Derivative [Line Items]
Notional volumes of outstanding derivatives that are expected to settle | MMBTU	296
Natural gas | Purchases | 2025
Derivative [Line Items]
Notional volumes of outstanding derivatives that are expected to settle | MMBTU	80
Natural gas | Purchases | 2026
Derivative [Line Items]
Notional volumes of outstanding derivatives that are expected to settle | MMBTU	50
Natural gas | Purchases | 2027
Derivative [Line Items]
Notional volumes of outstanding derivatives that are expected to settle | MMBTU	38
Natural gas | Purchases | 2028 and thereafter
Derivative [Line Items]
Notional volumes of outstanding derivatives that are expected to settle | MMBTU	30
Natural gas | Sales | 2024
Derivative [Line Items]
Notional volumes of outstanding derivatives that are expected to settle | MMBTU	338
Natural gas | Sales | 2025
Derivative [Line Items]
Notional volumes of outstanding derivatives that are expected to settle | MMBTU	86
Natural gas | Sales | 2026
Derivative [Line Items]
Notional volumes of outstanding derivatives that are expected to settle | MMBTU	16
Natural gas | Sales | 2027
Derivative [Line Items]
Notional volumes of outstanding derivatives that are expected to settle | MMBTU	6
Natural gas | Sales | 2028 and thereafter
Derivative [Line Items]
Notional volumes of outstanding derivatives that are expected to settle | MMBTU	4

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Derivatives Instruments (Realized and Unrealized Gains (Losses) on Other Derivatives) (Details) - CAD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Derivative Instruments, Gain (Loss) [Line Items]
Equity derivative hedges, return of shares	2.9
FX forwards
Derivative Instruments, Gain (Loss) [Line Items]
Realized gains (loss)	$ 17	$ (24)
FX forwards | OM&G
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gain (loss)	0	0
Realized gains (loss)	0	0
FX forwards | Other income, net
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gain (loss)	28	(18)
Realized gains (loss)	(11)	(6)
Equity derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Realized gains (loss)	(9)	(22)
Equity derivatives | OM&G
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gain (loss)	4	(5)
Realized gains (loss)	(13)	(17)
Equity derivatives | Other income, net
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gain (loss)	0	0
Realized gains (loss)	$ 0	$ 0

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Derivatives Instruments (Credit Risk) (Narrative) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2023 CAD ($) Days	Dec. 31, 2022 CAD ($)
Credit Derivatives [Line Items]
Total cash deposits/collateral on hand	$ 101	$ 224
Financial Asset, Past Due [Member]
Credit Derivatives [Line Items]
Financial assets, considered to be past due	142	131
Credit Concentration Risk
Credit Derivatives [Line Items]
Concentration Risk, maximum exposure	1,200	1,900
Total cash deposits/collateral on hand	310	386
Credit Concentration Risk | Receivables, net
Credit Derivatives [Line Items]
Fair Value, Financial assets, considered to be past due	$ 127	$ 114
Average number of days financial asset outstanding | Days	64

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Derivatives Instruments (Summary of Concentration Risk) (Details) - Credit Concentration Risk - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ 1,200,000	$ 1,900,000
Receivables, net | Other accounts receivable
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ 151,000	$ 585,000
% of total exposure	10.00%	25.00%
Receivables, net | Trading group
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ 188,000	$ 507,000
% of total exposure	12.00%	21.00%
Receivables, net | Receivables
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ 1,290,000	$ 1,982,000
% of total exposure	84.00%	83.00%
Receivables, net | Credit rating of A- or above | Trading group
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ 47,000	$ 125,000
% of total exposure	3.00%	5.00%
Receivables, net | Credit rating of BBB- to BBB+ | Trading group
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ 33,000	$ 75,000
% of total exposure	2.00%	3.00%
Receivables, net | Not rated | Trading group
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ 108,000	$ 307,000
% of total exposure	7.00%	13.00%
Derivative Instruments (current and long-term) | Derivatives
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ 240,000	$ 396,000
% of total exposure	16.00%	17.00%
Derivative Instruments (current and long-term) | Receivables and Derivatives
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ 1,530,000	$ 2,378,000
% of total exposure	100.00%	100.00%
Derivative Instruments (current and long-term) | Credit rating of A- or above | Derivatives
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ 138,000	$ 202,000
% of total exposure	9.00%	9.00%
Derivative Instruments (current and long-term) | Credit rating of BBB- to BBB+ | Derivatives
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ 7,000	$ 8,000
% of total exposure	1.00%	0.00%
Derivative Instruments (current and long-term) | Not rated | Derivatives
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ 95,000	$ 186,000
% of total exposure	6.00%	8.00%
Regulated utilities | Receivables, net
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ 951,000	$ 890,000
% of total exposure	62.00%	37.00%
Regulated utilities | Receivables, net | Residential
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ 476,000	$ 455,000
% of total exposure	31.00%	19.00%
Regulated utilities | Receivables, net | Commercial
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ 194,000	$ 192,000
% of total exposure	13.00%	8.00%
Regulated utilities | Receivables, net | Industrial
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ 84,000	$ 121,000
% of total exposure	5.00%	5.00%
Regulated utilities | Receivables, net | Other
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ 103,000	$ 122,000
% of total exposure	7.00%	5.00%
Regulated utilities | Receivables, net | Cash Collateral
Concentration Risk [Line Items]
Concentration Risk, maximum exposure	$ 94,000	$ 0
% of total exposure	6.00%	0.00%

XML

Derivatives Instruments (Cash Collateral Positions) (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Derivative Instruments
Cash collateral provided to others	$ 101	$ 224
Cash collateral received from others	22	112
Total fair value of these derivatives, in a liability position	$ 504	$ 1,078

XML

FV Measurements (Classification of Fair Value of Derivatives) (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Assets
Total assets	$ 240	$ 396
Liabilities
Total liabilities	504	1,078
Level 3
Assets
Total assets	34	90
Liabilities
Total liabilities	365	826
Net assets (liabilities)	(331)	(736)
Level 3 | Regulatory deferral | Physical natural gas purchases
Assets
Total assets		52
Liabilities
Total liabilities		0
Level 3 | HFT derivatives | Power swaps and physical contracts
Assets
Total assets		4
Liabilities
Total liabilities		1
Level 3 | HFT derivatives | Natural gas swaps, futures, forwards and physical contracts
Assets
Total assets	34	34
Liabilities
Total liabilities	365	825
Fair Value, Measurements, Recurring
Assets
Total assets	240	396
Liabilities
Total liabilities	504	1,078
Net assets (liabilities)	(264)	(682)
Fair Value, Measurements, Recurring | Other
Assets
Total assets	22
Liabilities
Total liabilities	7
Fair Value, Measurements, Recurring | FX forwards | Other
Assets
Total assets	18	5
Liabilities
Total liabilities	7	23
Fair Value, Measurements, Recurring | Equity derivatives | Other
Assets
Total assets	4
Liabilities
Total liabilities		5
Fair Value, Measurements, Recurring | Regulatory deferral
Assets
Total assets	16	238
Liabilities
Total liabilities	76	25
Fair Value, Measurements, Recurring | Regulatory deferral | Commodity swaps and forwards
Assets
Total assets	13	168
Liabilities
Total liabilities	73	24
Fair Value, Measurements, Recurring | Regulatory deferral | FX forwards
Assets
Total assets	3	18
Liabilities
Total liabilities	3	1
Fair Value, Measurements, Recurring | Regulatory deferral | Physical natural gas purchases and sales
Assets
Total assets		52
Fair Value, Measurements, Recurring | HFT derivatives
Assets
Total assets	202	153
Liabilities
Total liabilities	421	1,025
Fair Value, Measurements, Recurring | HFT derivatives | Power swaps and physical contracts
Assets
Total assets	18	44
Liabilities
Total liabilities	24	31
Fair Value, Measurements, Recurring | HFT derivatives | Natural gas swaps, futures, forwards, physical contracts
Assets
Total assets	184	109
Fair Value, Measurements, Recurring | HFT derivatives | Natural gas swaps, futures, forwards and physical contracts
Liabilities
Total liabilities	397	994
Fair Value, Measurements, Recurring | Level 1
Assets
Total assets	48	132
Liabilities
Total liabilities	56	73
Net assets (liabilities)	(8)	59
Fair Value, Measurements, Recurring | Level 1 | Other
Assets
Total assets	4
Liabilities
Total liabilities	0
Fair Value, Measurements, Recurring | Level 1 | FX forwards | Other
Assets
Total assets	0	0
Liabilities
Total liabilities	0	0
Fair Value, Measurements, Recurring | Level 1 | Equity derivatives | Other
Assets
Total assets	4
Liabilities
Total liabilities		5
Fair Value, Measurements, Recurring | Level 1 | Regulatory deferral
Assets
Total assets	7	120
Liabilities
Total liabilities	43	15
Fair Value, Measurements, Recurring | Level 1 | Regulatory deferral | Commodity swaps and forwards
Assets
Total assets	7	120
Liabilities
Total liabilities	43	15
Fair Value, Measurements, Recurring | Level 1 | Regulatory deferral | FX forwards
Assets
Total assets	0	0
Liabilities
Total liabilities	0	0
Fair Value, Measurements, Recurring | Level 1 | Regulatory deferral | Physical natural gas purchases and sales
Assets
Total assets		0
Fair Value, Measurements, Recurring | Level 1 | HFT derivatives
Assets
Total assets	37	12
Liabilities
Total liabilities	13	53
Fair Value, Measurements, Recurring | Level 1 | HFT derivatives | Power swaps and physical contracts
Assets
Total assets	(5)	9
Liabilities
Total liabilities	0	2
Fair Value, Measurements, Recurring | Level 1 | HFT derivatives | Natural gas swaps, futures, forwards, physical contracts
Assets
Total assets	42	3
Fair Value, Measurements, Recurring | Level 1 | HFT derivatives | Natural gas swaps, futures, forwards and physical contracts
Liabilities
Total liabilities	13	51
Fair Value, Measurements, Recurring | Level 2
Assets
Total assets	158	174
Liabilities
Total liabilities	83	179
Net assets (liabilities)	75	(5)
Fair Value, Measurements, Recurring | Level 2 | Other
Assets
Total assets	18
Liabilities
Total liabilities	7
Fair Value, Measurements, Recurring | Level 2 | FX forwards | Other
Assets
Total assets	18	5
Liabilities
Total liabilities	7	23
Fair Value, Measurements, Recurring | Level 2 | Equity derivatives | Other
Assets
Total assets	0
Liabilities
Total liabilities		0
Fair Value, Measurements, Recurring | Level 2 | Regulatory deferral
Assets
Total assets	9	66
Liabilities
Total liabilities	33	10
Fair Value, Measurements, Recurring | Level 2 | Regulatory deferral | Commodity swaps and forwards
Assets
Total assets	6	48
Liabilities
Total liabilities	30	9
Fair Value, Measurements, Recurring | Level 2 | Regulatory deferral | FX forwards
Assets
Total assets	3	18
Liabilities
Total liabilities	3	1
Fair Value, Measurements, Recurring | Level 2 | Regulatory deferral | Physical natural gas purchases and sales
Assets
Total assets		0
Fair Value, Measurements, Recurring | Level 2 | HFT derivatives
Assets
Total assets	131	103
Liabilities
Total liabilities	43	146
Fair Value, Measurements, Recurring | Level 2 | HFT derivatives | Power swaps and physical contracts
Assets
Total assets	23	31
Liabilities
Total liabilities	24	28
Fair Value, Measurements, Recurring | Level 2 | HFT derivatives | Natural gas swaps, futures, forwards, physical contracts
Assets
Total assets	108	72
Fair Value, Measurements, Recurring | Level 2 | HFT derivatives | Natural gas swaps, futures, forwards and physical contracts
Liabilities
Total liabilities	19	118
Fair Value, Measurements, Recurring | Level 3
Assets
Total assets	34	90
Liabilities
Total liabilities	365	826
Net assets (liabilities)	(331)	(736)
Fair Value, Measurements, Recurring | Level 3 | Other
Assets
Total assets	0
Liabilities
Total liabilities	0
Fair Value, Measurements, Recurring | Level 3 | FX forwards | Other
Assets
Total assets	0	0
Liabilities
Total liabilities	0	0
Fair Value, Measurements, Recurring | Level 3 | Equity derivatives | Other
Assets
Total assets	0
Liabilities
Total liabilities		0
Fair Value, Measurements, Recurring | Level 3 | Regulatory deferral
Assets
Total assets	0	52
Liabilities
Total liabilities	0	0
Fair Value, Measurements, Recurring | Level 3 | Regulatory deferral | Commodity swaps and forwards
Assets
Total assets	0	0
Liabilities
Total liabilities	0	0
Fair Value, Measurements, Recurring | Level 3 | Regulatory deferral | FX forwards
Assets
Total assets	0	0
Liabilities
Total liabilities	0	0
Fair Value, Measurements, Recurring | Level 3 | Regulatory deferral | Physical natural gas purchases and sales
Assets
Total assets		52
Fair Value, Measurements, Recurring | Level 3 | HFT derivatives
Assets
Total assets	34	38
Liabilities
Total liabilities	365	826
Fair Value, Measurements, Recurring | Level 3 | HFT derivatives | Power swaps and physical contracts
Assets
Total assets	0	4
Liabilities
Total liabilities	0	1
Fair Value, Measurements, Recurring | Level 3 | HFT derivatives | Natural gas swaps, futures, forwards, physical contracts
Assets
Total assets	34	34
Fair Value, Measurements, Recurring | Level 3 | HFT derivatives | Natural gas swaps, futures, forwards and physical contracts
Liabilities
Total liabilities	$ 365	$ 825

XML

FV Measurements (Change in Fair Value of Level 3 Financial Assets) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2023 CAD ($)
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	$ 90
Realized gains included in fuel for generation and purchased power	(49)
Unrealized gains included in regulatory liabilities	(3)
Total realized and unrealized gains (losses) included in non-regulated operating revenues	(4)
Ending Balance	34
Regulatory deferral | Physical natural gas purchases | Energy Related derivative
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	52
Realized gains included in fuel for generation and purchased power	(49)
Unrealized gains included in regulatory liabilities	(3)
Total realized and unrealized gains (losses) included in non-regulated operating revenues	0
Ending Balance	0
Not Designated as Hedging Instrument | Energy Related derivative | Non-regulated operating revenues
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	90
Realized gains included in fuel for generation and purchased power	(49)
HFT derivatives | Energy Related derivative | Non-regulated operating revenues
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	90
Realized gains included in fuel for generation and purchased power	(49)
Unrealized gains included in regulatory liabilities	(3)
Total realized and unrealized gains (losses) included in non-regulated operating revenues	(4)
Ending Balance	34
HFT derivatives | Power | Energy Related derivative
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	4
Realized gains included in fuel for generation and purchased power	0
Unrealized gains included in regulatory liabilities	0
Total realized and unrealized gains (losses) included in non-regulated operating revenues	(4)
Ending Balance	0
HFT derivatives | Natural gas | Energy Related derivative
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	34
Realized gains included in fuel for generation and purchased power	0
Unrealized gains included in regulatory liabilities	0
Total realized and unrealized gains (losses) included in non-regulated operating revenues	0
Ending Balance	$ 34

XML

FV Measurements (Change in Fair Value of Level 3 Financial Liabilities) (Details) - HFT derivatives - Energy Related derivative - Non-regulated operating revenues $ in Millions	12 Months Ended
	Dec. 31, 2023 CAD ($)
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	$ 826
Total realized and unrealized gains included in non-regulated operating revenues	(461)
Ending Balance	365
Power
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	1
Total realized and unrealized gains included in non-regulated operating revenues	(1)
Ending Balance	0
Natural gas
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	825
Total realized and unrealized gains included in non-regulated operating revenues	(460)
Ending Balance	$ 365

XML

FV Measurements (Quantitative Information About Significant Unobservable Inputs Used in Level 3 Measurements) (Details) - CAD ($)	Dec. 31, 2023	Dec. 31, 2022
Assets
Total assets	$ 240,000,000	$ 396,000,000
Liabilities
Total liabilities	504,000,000	1,078,000,000
Fair Value, Measurements, Recurring
Assets
Total assets	240,000,000	396,000,000
Liabilities
Total liabilities	504,000,000	1,078,000,000
Net liability	264,000,000	682,000,000
Regulatory deferral | Fair Value, Measurements, Recurring
Assets
Total assets	16,000,000	238,000,000
Liabilities
Total liabilities	76,000,000	25,000,000
HFT derivatives | Fair Value, Measurements, Recurring
Assets
Total assets	202,000,000	153,000,000
Liabilities
Total liabilities	421,000,000	1,025,000,000
HFT derivatives | Power swaps and physical contracts | Fair Value, Measurements, Recurring
Assets
Total assets	18,000,000	44,000,000
Liabilities
Total liabilities	24,000,000	31,000,000
HFT derivatives | Natural gas swaps, futures, forwards and physical contracts | Fair Value, Measurements, Recurring
Liabilities
Total liabilities	397,000,000	994,000,000
Level 3
Assets
Total assets	34,000,000	90,000,000
Liabilities
Total liabilities	365,000,000	826,000,000
Net liability	331,000,000	736,000,000
Level 3 | Fair Value, Measurements, Recurring
Assets
Total assets	34,000,000	90,000,000
Liabilities
Total liabilities	365,000,000	826,000,000
Net liability	331,000,000	736,000,000
Level 3 | Regulatory deferral | Fair Value, Measurements, Recurring
Assets
Total assets	0	52,000,000
Liabilities
Total liabilities	0	0
Level 3 | Regulatory deferral | Physical natural gas purchases
Assets
Total assets		52,000,000
Liabilities
Total liabilities		$ 0
Level 3 | Regulatory deferral | Range, Minimum | Physical natural gas purchases | Third-party pricing
Liabilities
Derivative, measurement input		5.79
Level 3 | Regulatory deferral | Range, Maximum | Physical natural gas purchases | Third-party pricing
Liabilities
Derivative, measurement input		31.85
Level 3 | Regulatory deferral | Weighted average | Physical natural gas purchases | Third-party pricing
Liabilities
Derivative, measurement input		12.27
Level 3 | HFT derivatives | Fair Value, Measurements, Recurring
Assets
Total assets	34,000,000	$ 38,000,000
Liabilities
Total liabilities	365,000,000	826,000,000
Level 3 | HFT derivatives | Power swaps and physical contracts
Assets
Total assets		4,000,000
Liabilities
Total liabilities		1,000,000
Level 3 | HFT derivatives | Power swaps and physical contracts | Fair Value, Measurements, Recurring
Assets
Total assets	0	4,000,000
Liabilities
Total liabilities	0	1,000,000
Level 3 | HFT derivatives | Natural gas swaps, futures, forwards and physical contracts
Assets
Total assets	34,000,000	34,000,000
Liabilities
Total liabilities	365,000,000	825,000,000
Level 3 | HFT derivatives | Natural gas swaps, futures, forwards and physical contracts | Fair Value, Measurements, Recurring
Liabilities
Total liabilities	$ 365,000,000	$ 825,000,000
Level 3 | HFT derivatives | Range, Minimum | Power swaps and physical contracts | Third-party pricing
Liabilities
Derivative, measurement input		43.24
Level 3 | HFT derivatives | Range, Minimum | Natural gas swaps, futures, forwards and physical contracts | Third-party pricing
Liabilities
Derivative, measurement input	1.27	2.45
Level 3 | HFT derivatives | Range, Maximum | Power swaps and physical contracts | Third-party pricing
Liabilities
Derivative, measurement input		269.10
Level 3 | HFT derivatives | Range, Maximum | Natural gas swaps, futures, forwards and physical contracts | Third-party pricing
Liabilities
Derivative, measurement input	16.25	33.88
Level 3 | HFT derivatives | Weighted average | Power swaps and physical contracts | Third-party pricing
Liabilities
Derivative, measurement input		138.79
Level 3 | HFT derivatives | Weighted average | Natural gas swaps, futures, forwards and physical contracts | Third-party pricing
Liabilities
Derivative, measurement input	4.85	12.01

XML

FV Measurements (Financial Liabilities not Measured at Fair Value on Consolidated Balance Sheets) (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Fair Value Measurement [Domain]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Financial assets and liabilities	$ 16,621	$ 14,670
Fair Value Measurement [Domain] | Level 1
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Financial assets and liabilities	0	0
Fair Value Measurement [Domain] | Level 2
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Financial assets and liabilities	16,363	14,284
Fair Value Measurement [Domain] | Level 3
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Financial assets and liabilities	258	386
Carrying Amount
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Financial assets and liabilities	18,365	16,318
Financial assets and liabilities	$ 16,621	$ 14,670

XML

FV Measurements (Hybrid Notes) (Narrative) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Hybrid Instruments [Line Items]
Hybrid Notes as a hedge of the foreign currency exposure	$ 1,200	$ 1,100
Net investment in United States dollar denominated operations
Hybrid Instruments [Line Items]
Hybrid Notes as a hedge of the foreign currency exposure	1,200
After-tax foreign currency gain (loss)	$ 38	$ (97)

XML

Related Paty Transactions (Narrative) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
NSPML | Regulated
Related Party Transaction [Line Items]
Purchases from Related Party	$ 163	$ 157
M&NP | Non-Regulated
Related Party Transaction [Line Items]
Purchases from Related Party	$ 14	$ 9

XML

Receivables and Other Current Assets (Summary of Receivables and Other Current Assets) (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Receivables and Other Current Assets [Abstract]
Customer accounts receivable - billed	$ 805	$ 1,096
Capitalized transportation capacity	358	781
Customer accounts receivable - unbilled	363	424
Prepaid expenses	105	82
Income taxes receivable	10	9
Allowance for credit losses	(15)	(17)
NMGC gas hedge settlement receivable		162
Other	191	360
Total receivables and other current assets	$ 1,817	$ 2,897

XML

Leases (Narrative) (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2023 CAD ($)	Dec. 31, 2022 CAD ($)	Oct. 31, 2023 USD ($)
Lessee, Operating Leases
Lessee, Operating Lease, Description	The Company has operating leases for buildings, land, telecommunication services, and rail cars. Emera’s leases have remaining lease terms of 1 year to 62 years, some of which include options to extend the leases for up to 65 years. These options are included as part of the lease term when it is considered reasonably certain they will be exercised.
Lease, Expense	$ 127	$ 138
Variable costs for power generation facility finance leases	$ 119	131
Lessee, Operating Lease, Existence of Option to Extend [true false]	true
Lessee, Operating Lease, Option to Extend	The Company has operating leases for buildings, land, telecommunication services, and rail cars. Emera’s leases have remaining lease terms of 1 year to 62 years, some of which include options to extend the leases for up to 65 years. These options are included as part of the lease term when it is considered reasonably certain they will be exercised
Lessee, Lease, Description [Line Items]
Net Investment in Lease	$ 658	$ 638
Renewable Natural Gas Facility [Member]
Lessee, Lease, Description [Line Items]
Lessor, sales-type lease, term of contract			15 years
Lessor Sales Type Lease Assumptions And Judgments Value Of Underlying Asset Amount			$ 35
Brunswick Pipeline Lease [Member]
Lessee, Lease, Description [Line Items]
Lessor, operating lease, term of contract	34 years
Net Investment in Lease	$ 100
Lessor lease option to extend	16 years
Minimum
Lessee, Lease, Description [Line Items]
Lessee, operating lease, renewal term	1 year
Maximum
Lessee, Lease, Description [Line Items]
Lessee, operating lease, renewal term	62 years

XML

Leases (Lessee, Operating Leases and Additional Information) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Assets and Liabilities, Lessee
Right-of-use asset	$ 54	$ 58
Lease liabilities, Current	3	3
Lease liabilities, Long-term	55	59
Total lease liabilities	58	62
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows for operating leases	8	8
Right-of-use assets obtained in exchange for lease obligations: Operating leases	$ 1	$ 1
Weighted average remaining lease term (years)	44 years	44 years
Weighted average discount rate - operating leases	3.93%	3.98%

XML

Leases (Lessee, Future Minimum Lease Payments Under Non-Cancellable Operating Leases) (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Future minimum lease payments under non-cancellable operating leases for each of the next five years and in aggregate thereafter
2024	$ 6
2025	5
2026	3
2027	3
2028	3
Thereafter	111
Minimum lease payments, Total	131
Less imputed interest	(73)
Total	$ 58	$ 62

XML

Leases (Lessor, Direct Finance and Sales-Type Leases) (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Net investment in direct finance and sales-type leases
Total minimum lease payments to be received	$ 1,360	$ 1,393
Less: amounts representing estimated executory costs	(190)	(205)
Minimum lease payments receivable	1,170	1,188
Estimated residual value of leased property (unguaranteed)	183	183
Less: Credit loss reserve	(2)	0
Less: unearned finance lease income	(693)	(733)
Net investment in direct finance and sales-type leases	658	638
Principal due within one year (included in "Receivables and other current assets")	37	34
Net Investment in direct finance leases - long-term	$ 621	$ 604

XML

Leases (Lessor, Future Minimum Lease Payments to be Received) (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Leases [Abstract]
2024	$ 97
2025	99
2026	98
2027	97
2028	96
Thereafter	873
Total minimum lease payments to be received	1,360	$ 1,393
Less: executory costs	(190)	(205)
Minimum lease payments receivable	$ 1,170	$ 1,188

XML

Property, Plant and Equipment (Regulated and Non-Regulated Assets) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Property, Plant and Equipment, Net
Total cost	$ 32,273	$ 30,576
Less: Accumulated depreciation	(9,994)	(9,574)
Total cost less: Accumulated depreciation	22,279	21,002
Construction work in progress	2,097	1,994
Property, Plant and Equipment, Net	24,376	22,996
Generation
Property, Plant and Equipment, Net
Total cost	$ 13,500	13,083
Generation | Range, Minimum
Property, Plant and Equipment [Line Items]
Estimated useful life	3 years
Generation | Range, Maximum
Property, Plant and Equipment [Line Items]
Estimated useful life	131 years
Transmission
Property, Plant and Equipment, Net
Total cost	$ 2,835	2,731
Transmission | Range, Minimum
Property, Plant and Equipment [Line Items]
Estimated useful life	10 years
Transmission | Range, Maximum
Property, Plant and Equipment [Line Items]
Estimated useful life	80 years
Distribution
Property, Plant and Equipment, Net
Total cost	$ 7,417	6,978
Distribution | Range, Minimum
Property, Plant and Equipment [Line Items]
Estimated useful life	4 years
Distribution | Range, Maximum
Property, Plant and Equipment [Line Items]
Estimated useful life	80 years
Gas transmission and distribution
Property, Plant and Equipment, Net
Total cost	$ 5,536	5,061
Gas transmission and distribution | Range, Minimum
Property, Plant and Equipment [Line Items]
Estimated useful life	6 years
Gas transmission and distribution | Range, Maximum
Property, Plant and Equipment [Line Items]
Estimated useful life	92 years
General plant and other
Property, Plant and Equipment, Net
Total cost	$ 2,985	$ 2,723
General plant and other | Range, Minimum
Property, Plant and Equipment [Line Items]
Estimated useful life	2 years
General plant and other | Range, Maximum
Property, Plant and Equipment [Line Items]
Estimated useful life	71 years

XML

Property, Plant and Equipment (Regulated and Non-Regulated Assets) (Narrative) (Details) - Pipeline lateral - SeaCoast Gas Transmission, LLC - General plant and other $ in Millions	12 Months Ended
	Dec. 31, 2023 USD ($) mi	Dec. 31, 2022 USD ($)
Jointly Owned Pipleline lateral
Jointly Owned Utility Plant, Proportionate Ownership Share	50.00%	50.00%
Length of pipeline, in miles | mi	26
Jointly Owned Utility Plant, Gross Ownership Amount of Plant in Service	$ 27	$ 27
Jointly Owned Utility Plant, Ownership Amount of Plant Accumulated Depreciation	$ 2	$ 1

XML

Employee Benefit Plans (Changes in Benefit Obligation and Plan Assets and Funded Status) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Defined benefit pension plans
Change in Projected Benefit Obligation ("PBO") and Accumulated Post-retirement Benefit Obligation ("APBO")
Benefit Obligation, Beginning Balance	$ 2,158	$ 2,624
Service cost	30	41
Plan participant contributions	6	6
Interest cost	111	80
Plan amendments	0	0
Benefits Paid	(147)	(174)
Actuarial losses (gains)	146	(480)
Settlements and curtailments	(8)	(6)
Foreign currency translation adjustment	(23)	67
Benefit Obligation, Ending Balance	2,273	2,158
Change in plan assets
Plan Assets, Beginning Balance	2,163	2,702
Employer contributions	42	45
Plan participant contributions	6	6
Benefits paid	(147)	(174)
Actual return on assets, net of expenses	262	(489)
Settlements and curtailments	(8)	(6)
FX translation adjustment	(20)	79
Plan Assets, Ending Balance	2,298	2,163
Funded Status
Funded status, end of year	25	5
Non-pension Benefit Plans
Change in Projected Benefit Obligation ("PBO") and Accumulated Post-retirement Benefit Obligation ("APBO")
Benefit Obligation, Beginning Balance	243	318
Service cost	3	4
Plan participant contributions	6	6
Interest cost	13	9
Plan amendments	(14)	0
Benefits Paid	(29)	(31)
Actuarial losses (gains)	10	(79)
Settlements and curtailments	0	0
Foreign currency translation adjustment	(5)	16
Benefit Obligation, Ending Balance	227	243
Change in plan assets
Plan Assets, Beginning Balance	46	51
Employer contributions	23	24
Plan participant contributions	6	6
Benefits paid	(29)	(31)
Actual return on assets, net of expenses	3	(7)
Settlements and curtailments	0	0
FX translation adjustment	(1)	3
Plan Assets, Ending Balance	48	46
Funded Status
Funded status, end of year	$ (179)	$ (197)

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Employee Benefit Plans (Plans with PBO/APBO in Excess of Plan Assets) (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Defined benefit pension plans
Plans with PBO/APBO in Excess of Plan Assets
PBO/APBO	$ 120	$ 1,006
FV of plan assets	37	914
Funded Status	(83)	(92)
Non-pension Benefit Plans
Plans with PBO/APBO in Excess of Plan Assets
PBO/APBO	205	221
FV of plan assets	0	0
Funded Status	$ (205)	$ (221)

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Employee Benefit Plans (Plans with Accumulated Benefit Obligation ("ABO") in Excess of Plan Assets) (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Plans with Accumulated Benefit Obligation ("ABO") in Excess of Plan Assets
ABO for the defined benefit pension plans	$ 2,172	$ 2,080
Defined benefit pension plans
Plans with Accumulated Benefit Obligation ("ABO") in Excess of Plan Assets
ABO	114	111
Fair value of plan assets	37	33
Funded Status	$ (77)	$ (78)

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Employee Benefit Plans (Amounts Recognized in Consolidated Balance Sheets) (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Balance Sheet
Other current liabilities	$ (23)	$ (33)
Long-term liabilities	(265)	(281)
Defined benefit pension plans
Balance Sheet
Other current liabilities	(5)	(13)
Long-term liabilities	(78)	(80)
Other long-term assets	108	98
AOCI, net of tax and regulatory assets	385	358
Less: Deferred income tax (expense) recovery in AOCI	(8)	(7)
Net amount recognized	402	356
Non-pension Benefit Plans
Balance Sheet
Other current liabilities	(18)	(20)
Long-term liabilities	(187)	(201)
Other long-term assets	26	24
AOCI, net of tax and regulatory assets	20	22
Less: Deferred income tax (expense) recovery in AOCI	(1)	(1)
Net amount recognized	$ (160)	$ (176)

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Employee Benefit Plans (Amounts Recognized in AOCI and Regulatory Assets) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Change in AOCI and Regulatory Assets
Regulatory assets	$ 3,105	$ 3,620
Defined benefit pension plans
Change in AOCI and Regulatory Assets
Beginning Balance	22
Amortized in current period	1	8
Ending Balance	61	22
Actuarial losses	53	15
Past service gains	0	0
Deferred income tax expense (recovery)	8	7
AOCI, net of tax	61	22
Regulatory assets	324	336
AOCI, net of tax and regulatory assets	385	358
Defined benefit pension plans | Regulatory | Assets
Change in AOCI and Regulatory Assets
Beginning Balance	336
Amortized in current period	(6)
Current year additions (reductions)	1
Change in FX rate	(7)
Ending Balance	324	336
Defined benefit pension plans | Actuarial (gains) losses
Change in AOCI and Regulatory Assets
Beginning Balance	15
Amortized in current period	(3)
Current year additions (reductions)	41
Change in FX rate	0
Ending Balance	53	15
Defined benefit pension plans | Past service costs (gains)
Change in AOCI and Regulatory Assets
Beginning Balance	0
Amortized in current period	0
Current year additions (reductions)	0
Change in FX rate	0
Ending Balance	0	0
Non-pension Benefit Plans
Change in AOCI and Regulatory Assets
Beginning Balance	(9)
Amortized in current period	(3)	0
Ending Balance	(9)	(9)
Actuarial losses	(8)	(10)
Past service gains	(2)	0
Deferred income tax expense (recovery)	1	1
AOCI, net of tax	(9)	(9)
Regulatory assets	29	31
AOCI, net of tax and regulatory assets	20	22
Non-pension Benefit Plans | Regulatory | Assets
Change in AOCI and Regulatory Assets
Beginning Balance	31
Amortized in current period	2
Current year additions (reductions)	(3)
Change in FX rate	(1)
Ending Balance	29	31
Non-pension Benefit Plans | Actuarial (gains) losses
Change in AOCI and Regulatory Assets
Beginning Balance	(10)
Amortized in current period	3
Current year additions (reductions)	(1)
Change in FX rate	0
Ending Balance	(8)	(10)
Non-pension Benefit Plans | Actuarial (gains) losses | Assets
Change in AOCI and Regulatory Assets
Beginning Balance	0
Amortized in current period	0
Current year additions (reductions)	(3)
Change in FX rate	1
Ending Balance	(2)	0
Non-pension Benefit Plans | Past service costs (gains)
Change in AOCI and Regulatory Assets
Beginning Balance	0
Amortized in current period	0
Current year additions (reductions)	(3)
Change in FX rate	1
Ending Balance	$ (2)	$ 0

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Employee Benefit Plans (Net Periodic Benefit Cost) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Defined Benefit Plan Disclosure [Line Items]
Expected return on plan assets	$ (2,577)	$ (2,482)
Defined benefit pension plans
Defined Benefit Plan Disclosure [Line Items]
Service cost	30	41
Interest cost	111	80
Expected return on plan assets	(161)	(144)
Current year amortization of: Actuarial losses	1	8
Regulatory assets (liability)	6	21
Settlement, curtailments	2	2
Net Periodic Benefit Cost, Total	(11)	8
Non-pension Benefit Plans
Defined Benefit Plan Disclosure [Line Items]
Service cost	3	4
Interest cost	13	9
Expected return on plan assets	(2)	0
Current year amortization of: Actuarial losses	(3)	0
Regulatory assets (liability)	(2)	2
Settlement, curtailments	0	0
Net Periodic Benefit Cost, Total	$ 9	$ 15

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Employee Benefit Plans (Pension Plan Asset Allocations) (Details) - Defined benefit pension plans	Dec. 31, 2023
Cash and cash equivalents | Non-Canadian Pension Plans | Range, Minimum
Pension Plan Asset Allocations
Target Range at Market	0.00%
Cash and cash equivalents | Non-Canadian Pension Plans | Range, Maximum
Pension Plan Asset Allocations
Target Range at Market	10.00%
Short-term securities | Canadian Pension Plans | Range, Minimum
Pension Plan Asset Allocations
Target Range at Market	0.00%
Short-term securities | Canadian Pension Plans | Range, Maximum
Pension Plan Asset Allocations
Target Range at Market	10.00%
Fixed income | Canadian Pension Plans | Range, Minimum
Pension Plan Asset Allocations
Target Range at Market	34.00%
Fixed income | Canadian Pension Plans | Range, Maximum
Pension Plan Asset Allocations
Target Range at Market	49.00%
Fixed income | Non-Canadian Pension Plans | Range, Minimum
Pension Plan Asset Allocations
Target Range at Market	29.00%
Fixed income | Non-Canadian Pension Plans | Range, Maximum
Pension Plan Asset Allocations
Target Range at Market	49.00%
Equities: Canadian | Canadian Pension Plans | Range, Minimum
Pension Plan Asset Allocations
Target Range at Market	7.00%
Equities: Canadian | Canadian Pension Plans | Range, Maximum
Pension Plan Asset Allocations
Target Range at Market	17.00%
Equities: Non-Canadian | Canadian Pension Plans | Range, Minimum
Pension Plan Asset Allocations
Target Range at Market	35.00%
Equities: Non-Canadian | Canadian Pension Plans | Range, Maximum
Pension Plan Asset Allocations
Target Range at Market	59.00%
Equities: Non-Canadian | Non-Canadian Pension Plans | Range, Minimum
Pension Plan Asset Allocations
Target Range at Market	48.00%
Equities: Non-Canadian | Non-Canadian Pension Plans | Range, Maximum
Pension Plan Asset Allocations
Target Range at Market	68.00%

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Employee Benefit Plans (Fair Value of Plan Assets) (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Defined benefit pension plans
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	$ 2,298	$ 2,163	$ 2,702
Total
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	$ 2,298	$ 2,163
Percentage	100.00%	100.00%
Total | Cash and cash equivalents
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	$ 40	$ 70
Percentage	2.00%	3.00%
Total | Net in-transits
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	$ (9)	$ (70)
Percentage	0.00%	(3.00%)
Total | Canadian equity
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	$ 96	$ 87
Percentage	4.00%	4.00%
Total | US equity
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	$ 141	$ 233
Percentage	6.00%	11.00%
Total | Other equity
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	$ 112	$ 186
Percentage	5.00%	8.00%
Total | Government
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	$ 172	$ 104
Percentage	8.00%	5.00%
Total | Corporate
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	$ 90	$ 83
Percentage	4.00%	4.00%
Total | Other
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	$ 9	$ 14
Percentage	0.00%	1.00%
Total | Mutual funds
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	$ 50	$ 68
Percentage	2.00%	3.00%
Total | Other
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	$ 5	$ (3)
Percentage	0.00%	0.00%
Total | Open-ended investments measured at NAV
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	$ 1,006	$ 790
Percentage	44.00%	36.00%
Total | Common collective trusts measured at NAV
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	$ 586	$ 601
Percentage	25.00%	28.00%
NAV
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	$ 1,592	$ 1,391
NAV | Cash and cash equivalents
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	0	0
NAV | Net in-transits
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	0	0
NAV | Canadian equity
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	0	0
NAV | US equity
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	0	0
NAV | Other equity
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	0	0
NAV | Government
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	0	0
NAV | Corporate
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	0	0
NAV | Other
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	0	0
NAV | Mutual funds
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	0	0
NAV | Other
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	0	0
NAV | Open-ended investments measured at NAV
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	1,006	790
NAV | Common collective trusts measured at NAV
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	586	601
Level 1
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	440	577
Level 1 | Cash and cash equivalents
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	40	70
Level 1 | Net in-transits
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	(9)	(70)
Level 1 | Canadian equity
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	96	87
Level 1 | US equity
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	141	233
Level 1 | Other equity
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	112	186
Level 1 | Government
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	0	0
Level 1 | Corporate
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	0	0
Level 1 | Other
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	4	3
Level 1 | Mutual funds
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	50	68
Level 1 | Other
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	6	0
Level 1 | Open-ended investments measured at NAV
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	0	0
Level 1 | Common collective trusts measured at NAV
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	0	0
Level 2
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	266	195
Level 2 | Cash and cash equivalents
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	0	0
Level 2 | Net in-transits
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	0	0
Level 2 | Canadian equity
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	0	0
Level 2 | US equity
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	0	0
Level 2 | Other equity
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	0	0
Level 2 | Government
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	172	104
Level 2 | Corporate
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	90	83
Level 2 | Other
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	5	11
Level 2 | Mutual funds
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	0	0
Level 2 | Other
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	(1)	(3)
Level 2 | Open-ended investments measured at NAV
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	0	0
Level 2 | Common collective trusts measured at NAV
Classification of the methodology used by the Company to fair value its investments
Fair Value of Plan Assets	$ 0	$ 0

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Employee Benefit Plans (Expected Cash Flows for Defined Benefit Pension and Other Post-Retirement Benefit Plans) (Details) $ in Millions	Dec. 31, 2023 CAD ($)
Defined benefit pension plans
Expected employer contributions
Expected employer contributions, 2024	$ 34
Expected benefit payments
Expected benefit payments, 2024	172
Expected benefit payments, 2025	163
Expected benefit payments, 2026	166
Expected benefit payments, 2027	171
Expected benefit payments, 2028	173
Expected benefit payments, 2029 - 2033	890
Non-pension Benefit Plans
Expected employer contributions
Expected employer contributions, 2024	19
Expected benefit payments
Expected benefit payments, 2024	21
Expected benefit payments, 2025	21
Expected benefit payments, 2026	21
Expected benefit payments, 2027	21
Expected benefit payments, 2028	20
Expected benefit payments, 2029 - 2033	$ 95

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Employee Benefit Plans (Assumptions Used in Accounting for Defined Benefit Pension and Other Post-Retirement Benefit Plans) (Details)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Defined benefit pension plans
Benefit obligation - December 31:
Discount rate - past service	4.89%	5.33%
Discount rate - future service	4.88%	5.34%
Rate of compensation increase	3.87%	3.62%
Health care trend - initial (next year)	0.00%	0.00%
Health care trend - ultimate	0.00%	0.00%
Benefit cost for year ended December 31:
Discount rate - past service	5.33%	3.05%
Discount rate - future service	5.34%	3.18%
Expected long-term return on plan assets	6.56%	6.07%
Rate of compensation increase	3.62%	3.31%
Health care trend - initial (next year)	0.00%	0.00%
Health care trend - ultimate	0.00%	0.00%
Non-pension Benefit Plans
Benefit obligation - December 31:
Discount rate - past service	4.89%	5.31%
Discount rate - future service	4.89%	5.32%
Rate of compensation increase	3.85%	3.61%
Health care trend - initial (next year)	6.04%	5.40%
Health care trend - ultimate	3.76%	3.77%
Health care trend - year ultimate reached	2043	2043
Benefit cost for year ended December 31:
Discount rate - past service	5.31%	2.81%
Discount rate - future service	5.32%	2.92%
Expected long-term return on plan assets	2.16%	1.32%
Rate of compensation increase	3.61%	3.29%
Health care trend - initial (next year)	5.40%	5.09%
Health care trend - ultimate	3.77%	3.77%
Health care trend - year ultimate reached	2043	2042

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Employee Benefit Plans (Narrative) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Defined-Benefit Plans, information
Defined Benefit Plan, Description	Emera maintains a number of contributory defined-benefit (“DB”) and defined-contribution (“DC”) pension plans, which cover substantially all of its employees. In addition, the Company provides non-pension benefits for its retirees. These plans cover employees in Nova Scotia, New Brunswick, Newfoundland and Labrador, Florida, New Mexico, Barbados, and Grand Bahama Island.
Defined Benefit Plan, Plan Assets, Investment Policy and Strategy, Description	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.
Defined Benefit Plan, Plan Assets, Expected Long-term Rate-of-Return, Description	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.
Defined Benefit Plan, Expected Return on Plan Assets	$ 2,577	$ 2,482
Contribution Amount	$ 45	41
Plan assets recognition period	5 years
Defined benefit pension plans
Defined-Benefit Plans, information
Defined Benefit Plan, Expected Return on Plan Assets	$ 161	144
Non-pension Benefit Plans
Defined-Benefit Plans, information
Defined Benefit Plan, Expected Return on Plan Assets	$ 2	$ 0

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Goodwill (Change in Goodwill) (Details)	12 Months Ended
	Dec. 31, 2023 USD ($)	Dec. 31, 2023 CAD ($)	Dec. 31, 2022 CAD ($)
Goodwill [Roll Forward]
Balance, January 1		$ 6,012,000,000	$ 5,696,000,000
Change in FX rate		(141,000,000)	389,000,000
GBPC impairment charge		0	(73,000,000)
Balance, December 31		5,871,000,000	6,012,000,000
Tampa Electric and PGS
Goodwill [Roll Forward]
GBPC impairment charge	$ 0
NMGC
Goodwill [Roll Forward]
GBPC impairment charge		$ 0
GBPC
Goodwill [Roll Forward]
Balance, January 1
GBPC impairment charge			$ (73,000,000)
Balance, December 31

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Short-Term Debt (Short-Term Debt and Related Weighted-Average Interest Rates) (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Short-term debt and the related weighted-average interest rates
Short-term debt	$ 1,433	$ 2,726
Weighted average interest rate	5.95%	5.01%
Advances on revolving credit and term facilities | TECO Finance
Short-term debt and the related weighted-average interest rates
Short-term debt	$ 245	$ 481
Weighted average interest rate	6.54%	5.47%
Non-revolving term facilities | Emera Inc.
Short-term debt and the related weighted-average interest rates
Short-term debt	$ 796	$ 796
Weighted average interest rate	6.07%	5.19%
Bank indebtedness | Emera Inc.
Short-term debt and the related weighted-average interest rates
Short-term debt	$ 9	$ 0
Weighted average interest rate	0.00%	0.00%
Advances on revolving credit facilities | TEC
Short-term debt and the related weighted-average interest rates
Short-term debt	$ 277	$ 1,380
Weighted average interest rate	5.68%	5.00%
Advances on revolving credit facilities | PGS
Short-term debt and the related weighted-average interest rates
Short-term debt	$ 73	$ 0
Weighted average interest rate	6.36%	0.00%
Advances on revolving credit facilities | NMGC
Short-term debt and the related weighted-average interest rates
Short-term debt	$ 25	$ 59
Weighted average interest rate	6.46%	5.15%
Advances on revolving credit facilities | GBPC
Short-term debt and the related weighted-average interest rates
Short-term debt	$ 8	$ 10
Weighted average interest rate	5.54%	5.25%

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Short-Term Debt (Short-Term Revolving and Non-Revolving Credit Facilities, Outstanding Borrowings and Available Capacity) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity
Total available capacity	$ 2,773	$ 3,155
Total advances under available facilities	1,436	2,735
Available capacity under existing agreements	$ 1,337	420
Revolving credit facility | TEC
Short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity
Maturity	2026
Total available capacity	$ 401	1,084
Revolving credit facility | TECO Energy/TECO Finance
Short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity
Maturity	2026
Total available capacity	$ 0	542
Revolving credit facility | TECO Finance
Short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity
Maturity	2026
Total available capacity	$ 529	0
Revolving credit facility | PGS
Short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity
Maturity	2028
Total available capacity	$ 331	0
Revolving credit facility | NMGC
Short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity
Maturity	2026
Total available capacity	$ 165	169
Revolving credit facility II | TEC
Short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity
Maturity	2024
Total available capacity	$ 265	542
Revolving credit facility III | TEC
Short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity
Maturity	2024
Total available capacity	$ 265	0
Revolving credit facility III | Other
Short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity
Total available capacity	$ 17	18
Term credit facility | TEC
Short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity
Maturity	2024
Non-revolving term loan | Emera Inc.
Short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity
Maturity	2024
Total available capacity	$ 400	400
Non-revolving term loan II | Emera Inc.
Short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity
Maturity	2024
Total available capacity	$ 400	400
Advances under revolving credit and term facilities
Short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity
Total advances under available facilities	1,433	2,731
Letters of credit issued within the credit facilities
Short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity
Total advances under available facilities	$ 3	$ 4

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Short-Term Debt (Narrative) (Details) $ in Millions, $ in Millions	Dec. 16, 2023 CAD ($)	Dec. 15, 2023	Dec. 01, 2023 USD ($)	Nov. 24, 2023 USD ($)	Jun. 30, 2023 CAD ($)	Jun. 29, 2023	Apr. 03, 2023 USD ($)	Mar. 01, 2023 USD ($)	Dec. 31, 2023 CAD ($)	Dec. 31, 2022 CAD ($)
Line of Credit Facility [Line Items]
Weighted average interest rate									5.95%	5.01%
Line of Credit Facility, Maximum Borrowing Capacity									$ 2,773	$ 3,155
Revolving credit facility | TEC
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity									401	1,084
Revolving credit facility | NMGC
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity									165	169
Revolving credit facility | TECO Energy/TECO Finance
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity									0	542
Revolving credit facility | TECO Finance
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity									529	0
Revolving credit facility | Peoples Gas System [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity									331	0
Revolving credit facility | Peoples Gas System [Member] | Gas Utilities and Infrastructure
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity			$ 250
Line of Credit Facility, Expiration Date			Dec. 01, 2028
Available increase in borrowing capacity			$ 100
Revolving credit facility II | TEC
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity									265	542
Revolving credit facility II | TEC | Florida Electric Utility [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity							$ 200
Line of Credit Facility, Expiration Date							Apr. 01, 2024
Debt term							364 days
Revolving credit facility III | TEC
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity									$ 265	$ 0
Revolving credit facility III | TEC | Florida Electric Utility [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity								$ 200
Line of Credit Facility, Expiration Date								Feb. 28, 2024
Debt term								364 days
Non-revolving term facilities | TEC | Florida Electric Utility [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity				$ 400
Line of Credit Facility, Expiration Date				Dec. 13, 2023
Non-revolving term facilities | Emera Inc.
Line of Credit Facility [Line Items]
Weighted average interest rate									6.07%	5.19%
Line of Credit Facility, Maximum Borrowing Capacity									$ 400	$ 400
Non-revolving term facilities | Emera Inc. | Other Segments [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 400
Debt Instrument, Maturity Date	Dec. 16, 2024	Dec. 16, 2023
Non-revolving term loan II | Emera Inc.
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity									$ 400	$ 400
Non-revolving term loan II | Emera Inc. | Other Segments [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity					$ 400
Debt Instrument, Maturity Date					Aug. 02, 2024	Aug. 02, 2023

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Other Current Liabilities (Components of Other Current Liabilities) (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Other Current Liabilities
Accrued charges	$ 172	$ 174
Nova Scotia Cap-and-Trade Program provision	0	172
Accrued interest on long-term debt	107	97
Pension and post-retirement liabilities	23	33
Sales and other taxes payable	11	14
Income taxes payable	2	9
Other	112	80
Other current liabilities, Total	$ 427	$ 579

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Long-Term Debt (Summary of Long-Term Debt, Revolving Credit Facilities, Outstanding Borrowings and Available Capacity) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Debt Instrument [Line Items]
Debt issuance costs	$ (125)	$ (126)
Amount due within one year	(676)	(574)
Long Term Debt, Adjustments	(801)	(698)
Long-Term Debt	17,689	15,744
Interest expense	109	110
Emera
Debt Instrument [Line Items]
Long-term debt	2,552	2,528
NMGC
Debt Instrument [Line Items]
Long-term debt	672	629
NSPI
Debt Instrument [Line Items]
Long-term debt	3,886	3,546
ECI
Debt Instrument [Line Items]
Long-term debt	422	449
TECO Energy
Debt Instrument [Line Items]
Fair market value adjustment	$ 0	$ 2
Bankers acceptances | SOFR loans | Emera
Debt Instrument [Line Items]
Interest Rate Terms	Variable	Variable
Maturity	2027
Long-term debt	$ 465	$ 403
Unsecured fixed rate notes | Emera
Debt Instrument [Line Items]
Weighted average interest rate	4.84%	2.90%
Maturity	2030
Long-term debt	$ 500	$ 500
Unsecured fixed rate notes | Emera Finance
Debt Instrument [Line Items]
Maturity	2024 - 2046
Fixed to floating subordinated notes | Emera
Debt Instrument [Line Items]
Weighted average interest rate	6.75%	6.75%
Maturity	2076
Long-term debt	$ 1,587	$ 1,625
Unsecured senior notes | Emera Finance
Debt Instrument [Line Items]
Weighted average interest rate	3.65%	3.65%
Long-term debt	$ 3,637	$ 3,725
Fixed rate notes and bonds | TEC
Debt Instrument [Line Items]
Weighted average interest rate	4.61%	4.15%
Maturity	2024 - 2051
Long-term debt	$ 5,654	$ 4,341
Fixed rate notes and bonds | PGS
Debt Instrument [Line Items]
Weighted average interest rate	5.63%	3.78%
Maturity	2028 - 2053
Long-term debt	$ 1,223	$ 772
Fixed rate notes and bonds | NMGC
Debt Instrument [Line Items]
Weighted average interest rate	3.78%	3.11%
Maturity	2026 - 2051
Long-term debt	$ 642	$ 521
Fixed rate notes and bonds | NMGI
Debt Instrument [Line Items]
Weighted average interest rate	3.64%	3.64%
Maturity	2024
Long-term debt	$ 198	$ 203
Discount notes | NSPI
Debt Instrument [Line Items]
Interest Rate Terms	Variable	Variable
Maturity	2024 - 2027
Long-term debt	$ 721	$ 881
Medium term fixed rate notes | NSPI
Debt Instrument [Line Items]
Weighted average interest rate	5.13%	5.14%
Maturity	2025 - 2097
Long-term debt	$ 3,165	$ 2,665
Senior secured credit facility | EBP
Debt Instrument [Line Items]
Interest Rate Terms	Variable	Variable
Maturity	2026
Long-term debt	$ 246	$ 249
Amortizing fixed rate notes | ECI
Debt Instrument [Line Items]
Weighted average interest rate	4.00%	3.97%
Maturity	2026
Long-term debt	$ 79	$ 100
Secured senior notes | ECI
Debt Instrument [Line Items]
Interest Rate Terms	Variable	Variable
Maturity	2027
Long-term debt	$ 75	$ 86
Secured fixed rate senior notes | ECI
Debt Instrument [Line Items]
Weighted average interest rate	3.09%	3.06%
Maturity	2024 - 2029
Long-term debt	$ 84	$ 142
Non-revolving term facility, floating rate | NMGC
Debt Instrument [Line Items]
Interest Rate Terms	Variable	Variable
Maturity	2024
Long-term debt	$ 30	$ 108
Non-revolving term facility, floating rate | ECI
Debt Instrument [Line Items]
Interest Rate Terms	Variable	Variable
Maturity	2025
Long-term debt	$ 29	$ 30
Non-revolving term facility, fixed rate | ECI
Debt Instrument [Line Items]
Weighted average interest rate	2.15%	2.05%
Maturity	2025 - 2027
Long-term debt	$ 155	$ 91

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Long-Term Debt (Revolving Credit Facilities, Outstanding Borrowings and Available Capacity) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Debt Instrument [Line Items]
Available capacity under existing agreements	$ 2,773	$ 3,155
Use of available facilities	1,890	1,408
Available capacity under existing agreements	1,337	420
Revolving credit facility
Debt Instrument [Line Items]
Available capacity under existing agreements	3,197	2,219
Available capacity under existing agreements	1,307	811
Advances on the revolving credit facility	50
Revolving credit facility | Emera
Debt Instrument [Line Items]
Available capacity under existing agreements	$ 900	900
Maturity	June 2027
Revolving credit facility | TEC
Debt Instrument [Line Items]
Available capacity under existing agreements	$ 657	0
Maturity	December 2026
Revolving credit facility | NSPI
Debt Instrument [Line Items]
Available capacity under existing agreements	$ 800	800
Maturity	December 2027
Revolving credit facility | ECI
Debt Instrument [Line Items]
Available capacity under existing agreements	$ 10	11
Maturity	October 2024
Non-revolving credit facility | Emera
Debt Instrument [Line Items]
Available capacity under existing agreements	$ 400	0
Maturity	February 2024
Non-revolving credit facility | NSPI
Debt Instrument [Line Items]
Available capacity under existing agreements	$ 400	400
Maturity	July 2024
Non-revolving credit facility | NMGC
Debt Instrument [Line Items]
Available capacity under existing agreements	$ 30	108
Maturity	March 2024
Borrowings under credit facilities
Debt Instrument [Line Items]
Use of available facilities	$ 1,884	1,396
Letters of credit issued within the credit facilities
Debt Instrument [Line Items]
Use of available facilities	$ 6	$ 12

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Long-Term Debt (Significant Covenants) (Details)	Dec. 31, 2023
Maximum
Debt Instrument [Line Items]
Debt to capital ratio	0.70
Syndicated credit facilities
Debt Instrument [Line Items]
Debt to capital ratio	0.57

XML

Long-Term Debt (Long-Term Debt Maturities) (Details) $ in Millions	Dec. 31, 2023 CAD ($)
Subsidiaries
Debt Instrument [Line Items]
2024	$ 1,670
2025	264
2026	3,047
2027	666
2028	525
Thereafter	12,318
Total, long-term debt maturities, including capital lease obligations	18,490
Emera
Debt Instrument [Line Items]
2024	199
2025	0
2026	1,587
2027	266
2028	0
Thereafter	500
Total, long-term debt maturities, including capital lease obligations	2,552
Emera US Finance LP
Debt Instrument [Line Items]
2024	397
2025	0
2026	992
2027	0
2028	0
Thereafter	2,248
Total, long-term debt maturities, including capital lease obligations	3,637
Tampa Electric
Debt Instrument [Line Items]
2024	397
2025	0
2026	0
2027	0
2028	0
Thereafter	5,257
Total, long-term debt maturities, including capital lease obligations	5,654
PGS
Debt Instrument [Line Items]
2024	0
2025	0
2026	0
2027	0
2028	463
Thereafter	760
Total, long-term debt maturities, including capital lease obligations	1,223
NMGC
Debt Instrument [Line Items]
2024	30
2025	0
2026	93
2027	0
2028	0
Thereafter	549
Total, long-term debt maturities, including capital lease obligations	672
NMGI
Debt Instrument [Line Items]
2024	198
2025	0
2026	0
2027	0
2028	0
Thereafter	0
Total, long-term debt maturities, including capital lease obligations	198
NSPI
Debt Instrument [Line Items]
2024	398
2025	125
2026	40
2027	323
2028	0
Thereafter	3,000
Total, long-term debt maturities, including capital lease obligations	3,886
EBP
Debt Instrument [Line Items]
2024	0
2025	0
2026	246
2027	0
2028	0
Thereafter	0
Total, long-term debt maturities, including capital lease obligations	246
ECI
Debt Instrument [Line Items]
2024	51
2025	139
2026	89
2027	77
2028	62
Thereafter	4
Total, long-term debt maturities, including capital lease obligations	$ 422

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Long-Term Debt (Narrative) (Details) $ in Millions, $ in Millions									12 Months Ended
	Feb. 16, 2024	Jan. 30, 2024 USD ($)	Dec. 19, 2023 USD ($)	Oct. 19, 2023 USD ($)	Aug. 18, 2023 CAD ($)	May 24, 2023 USD ($)	May 02, 2023 CAD ($)	Mar. 24, 2023 CAD ($)	Dec. 31, 2023 CAD ($)	Dec. 31, 2022 CAD ($)
Debt Instrument [Line Items]
Available capacity under existing agreements									$ 2,773	$ 3,155
Repayment of long-term debt									$ 151	$ 367
Senior unsecured bonds due March 1, 2029 | TEC | Subsequent event | Florida Electric Utility [Member]
Debt Instrument [Line Items]
Debt instrument, face amount		$ 500
Maturity date		Mar. 01, 2029
Stated interest rate		4.90%
5-year credit facility | TEC | Subsequent event | Florida Electric Utility [Member]
Debt Instrument [Line Items]
Repayment of long-term debt		$ 497
Debt term		5 years
Unsecured notes due November 15, 2032 and March 24, 2053 | NSPI | Canadian Electric Utilities
Debt Instrument [Line Items]
Debt instrument, face amount								$ 500
Unsecured notes due November 15, 2032 | NSPI | Canadian Electric Utilities
Debt Instrument [Line Items]
Debt instrument, face amount								$ 300
Maturity date								Nov. 15, 2032
Stated interest rate								4.95%
Unsecured notes due March 24, 2053 | NSPI | Canadian Electric Utilities
Debt Instrument [Line Items]
Debt instrument, face amount								$ 200
Maturity date								Mar. 24, 2053
Stated interest rate								5.36%
Senior notes due December 19, 2028, December 19, 2033 and December 19, 2053 | PGS | Gas Utilities and Infrastructure [Member]
Debt Instrument [Line Items]
Debt instrument, face amount			$ 925
Senior notes due December 19, 2028 | PGS | Gas Utilities and Infrastructure [Member]
Debt Instrument [Line Items]
Debt instrument, face amount			$ 350
Maturity date			Dec. 19, 2028
Stated interest rate			5.42%
Senior notes due December 19, 2033 | PGS | Gas Utilities and Infrastructure [Member]
Debt Instrument [Line Items]
Debt instrument, face amount			$ 350
Maturity date			Dec. 19, 2033
Stated interest rate			5.63%
Senior notes due December 19, 2053 | PGS | Gas Utilities and Infrastructure [Member]
Debt Instrument [Line Items]
Debt instrument, face amount			$ 225
Maturity date			Dec. 19, 2053
Stated interest rate			5.94%
Senior unsecured notes due October 19, 2033 | NMGC | Gas Utilities and Infrastructure [Member]
Debt Instrument [Line Items]
Debt instrument, face amount				$ 100
Maturity date				Oct. 19, 2033
Stated interest rate				6.36%
Non-revolving term loan due May 24, 2028 | GBPC | Other Electric Utilities [Member]
Debt Instrument [Line Items]
Debt instrument, face amount						$ 28
Maturity date						May 24, 2028
Stated interest rate						4.00%
Non-revolving term facility due February 19, 2025 | Emera
Debt Instrument [Line Items]
Debt instrument, face amount					$ 400
Maturity date					Feb. 19, 2024
Non-revolving term facility due February 19, 2025 | Emera | Subsequent event
Debt Instrument [Line Items]
Maturity date	Feb. 19, 2025
Senior unsecured notes due May 2, 2030 | Emera
Debt Instrument [Line Items]
Debt instrument, face amount							$ 500
Maturity date							May 02, 2030
Stated interest rate							4.84%

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Asset Retirement Obligation (Change in Asset Retirement Obligations) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Change in ARO
Balance, January 1	$ 174	$ 174
Accretion included in depreciation expense	9	9
Change in FX rate	(1)	3
Additions	0	1
Accretion deferred to regulatory asset (included in PP&E)	18	1
Liabilities settled	(8)	(1)
Revisions in estimated cash flows	0	(13)
Balance, December 31	$ 192	$ 174

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Commitments and Contingencies (Summary of Contractual Commitments) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2023 CAD ($) MW	Dec. 31, 2022 CAD ($)
Recorded Unconditional Purchase Obligation [Line Items]
2024	$ 2,698
2025	1,217
2026	856
2027	747
2028	690
Thereafter	6,253
Contractual Commitments	12,461
Other commitments
Commitment	1,772	$ 2,273
Revenue, Remaining Performance Obligation, Amount	$ 488	$ 450
Nalcor Energy
Other commitments
Long-term Purchase Commitment, Period	50 years
Nalcor Energy | Equity contributions true ups
Recorded Unconditional Purchase Obligation [Line Items]
Contractual Commitments	$ 240
SeaCoast Gas Transmission, LLC | PGS
Other commitments
Revenue, Remaining Performance Obligation, Amount	$ 134
Maritime Link Project
Other commitments
Long-term Purchase Commitment, Period	38 years
Maritime Link Project | NSPML
Other commitments
Approved base rate	$ 1,800
Maritime Link Project | NSPI
Other commitments
Commitment	$ 164
LIL
Other commitments
Capacity of electricity transmission project (MW) | MW	700
Transportation
Recorded Unconditional Purchase Obligation [Line Items]
2024	$ 696
2025	495
2026	405
2027	388
2028	338
Thereafter	2,597
Contractual Commitments	4,919
Purchased power
Recorded Unconditional Purchase Obligation [Line Items]
2024	274
2025	249
2026	263
2027	312
2028	312
Thereafter	3,435
Contractual Commitments	4,845
Fuel, gas supply and storage
Recorded Unconditional Purchase Obligation [Line Items]
2024	556
2025	215
2026	62
2027	0
2028	5
Thereafter	0
Contractual Commitments	838
Capital projects
Recorded Unconditional Purchase Obligation [Line Items]
2024	778
2025	111
2026	70
2027	1
2028	0
Thereafter	0
Contractual Commitments	960
Equity Method Investments
Recorded Unconditional Purchase Obligation [Line Items]
2024	240
2025	0
2026	0
2027	0
2028	0
Thereafter	0
Contractual Commitments	240
Other Commitment [Member]
Recorded Unconditional Purchase Obligation [Line Items]
2024	154
2025	147
2026	56
2027	46
2028	35
Thereafter	221
Contractual Commitments	$ 659

XML

Commitments and Contingencies (Legal Proceedings) (Narrative) (Details) - Dec. 31, 2023 $ in Millions, $ in Millions	CAD ($)	USD ($)
Prime Rate [Member] | Tampa Electric
Loss Contingencies [Line Items]
Loss Contingency, Estimate of Possible Loss	$ 15	$ 11

XML

Commitments and Contingencies (Guarantees and Letters of Credit) (Narrative) (Details) $ in Millions, $ in Millions	Dec. 31, 2023 USD ($)	Dec. 31, 2023 CAD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2022 CAD ($)
Nova Scotia Power Inc. [Member]
Guarantor Obligations [Line Items]
Guaranty Liabilities	$ 104		$ 119
Letters of Credit Outstanding, Amount		$ 56		$ 63
TECO Energy
Guarantor Obligations [Line Items]
Letters of Credit Outstanding, Amount	13
Guarantor Obligations, Maximum Exposure, Undiscounted	13
TECO Energy | SeaCoast Gas Transmission, LLC
Guarantor Obligations [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	45
ECI
Guarantor Obligations [Line Items]
Guaranty Liabilities	66
Payment Guarantee | SeaCoast Gas Transmission, LLC
Guarantor Obligations [Line Items]
Letters of Credit Outstanding, Amount	27
Surety Bonds
Guarantor Obligations [Line Items]
Letters of Credit Outstanding, Amount	$ 103		$ 145

XML

Commitments and Contingencies (Collaborative Arrangements) (Narrative) (Details) - Jointly Owned Electricity Generation Plant - NSPI - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Collaborative Arrangement and Arrangement Other than Collaborative [Line Items]
Regulated fuel for generation and purchased power	$ 8	$ 12
Operating, maintenance and general (OM&G)	$ 3	$ 3

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Cumulative Preferred Stock (Summary of Cumulative Preferred Stock Authorized) (Details) - CAD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Class of Stock [Line Items]
Issued and Outstanding	58,000,000	58,000,000
Net Proceeds	$ 1,422	$ 1,422
Series A Preferred Stock
Class of Stock [Line Items]
Annual Dividend Per Share	$ 0.5456
Preferred Stock, Redemption Price Per Share	$ 25.00
Issued and Outstanding	4,866,814	4,866,814
Net Proceeds	$ 119	$ 119
Series B Preferred Stock
Class of Stock [Line Items]
Preferred Stock, Redemption Price Per Share	$ 25.00
Issued and Outstanding	1,133,186	1,133,186
Net Proceeds	$ 28	$ 28
Preferred Stock Dividend Payment Rate Variable	Floating
Series C Preferred Stock
Class of Stock [Line Items]
Annual Dividend Per Share	$ 1.6085
Preferred Stock, Redemption Price Per Share	$ 25.00
Issued and Outstanding	10,000,000	10,000,000
Net Proceeds	$ 245	$ 245
Series E Preferred Stock
Class of Stock [Line Items]
Annual Dividend Per Share	$ 1.1250
Preferred Stock, Redemption Price Per Share	$ 25.00
Issued and Outstanding	5,000,000	5,000,000
Net Proceeds	$ 122	$ 122
Series F Preferred Stock
Class of Stock [Line Items]
Annual Dividend Per Share	$ 1.0505
Preferred Stock, Redemption Price Per Share	$ 25.00
Issued and Outstanding	8,000,000	8,000,000
Net Proceeds	$ 195	$ 195
Series H Preferred Stock
Class of Stock [Line Items]
Annual Dividend Per Share	$ 1.5810
Preferred Stock, Redemption Price Per Share	$ 25.00
Issued and Outstanding	12,000,000	12,000,000
Net Proceeds	$ 295	$ 295
Series J Preferred Stock
Class of Stock [Line Items]
Annual Dividend Per Share	$ 1.0625
Preferred Stock, Redemption Price Per Share	$ 25.00
Issued and Outstanding	8,000,000	8,000,000
Net Proceeds	$ 196	$ 196
Series L Preferred Stock
Class of Stock [Line Items]
Annual Dividend Per Share	$ 1.1500
Preferred Stock, Redemption Price Per Share	$ 26.00
Issued and Outstanding	9,000,000	9,000,000
Net Proceeds	$ 222	$ 222

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Cumulative Preferred Stock (Characteristics of the First Preferred Shares) (Details) - 12 months ended Dec. 31, 2023 - $ / shares	Total	Total
Series A Preferred Stock
Class of Stock [Line Items]
Initial Yield	4.40%
Current Annual Dividend		$ 0.5456
Earliest Redemption and/or Conversion Option Date	August 15, 2025	August 15, 2025
Redemption Value	$ 25.00	$ 25.00
Preferred Stock, Conversion Basis	Right to Convert on a one for one basis	Right to Convert on a one for one basis
Conversion of Stock, Type of Stock Converted	Series B	Series B
Series A Preferred Stock | Minimum
Class of Stock [Line Items]
Initial Yield	1.84%
Series C Preferred Stock
Class of Stock [Line Items]
Initial Yield	4.10%
Current Annual Dividend		$ 1.6085
Earliest Redemption and/or Conversion Option Date	August 15, 2028	August 15, 2028
Redemption Value	$ 25.00	$ 25.00
Preferred Stock, Conversion Basis	Right to Convert on a one for one basis	Right to Convert on a one for one basis
Conversion of Stock, Type of Stock Converted	Series D	Series D
Series C Preferred Stock | Minimum
Class of Stock [Line Items]
Initial Yield	2.65%
Series C Preferred Stock | Prior To August 15, 2028
Class of Stock [Line Items]
Current Annual Dividend	$ 1.1802
Series F Preferred Stock
Class of Stock [Line Items]
Initial Yield	4.202%
Current Annual Dividend		$ 1.0505
Earliest Redemption and/or Conversion Option Date	February 15, 2025	February 15, 2025
Redemption Value	$ 25.00	$ 25.00
Preferred Stock, Conversion Basis	Right to Convert on a one for one basis	Right to Convert on a one for one basis
Conversion of Stock, Type of Stock Converted	Series G	Series G
Series F Preferred Stock | Minimum
Class of Stock [Line Items]
Initial Yield	2.63%
Series B Preferred Stock
Class of Stock [Line Items]
Initial Yield	2.393%
Earliest Redemption and/or Conversion Option Date	August 15, 2025	August 15, 2025
Redemption Value	$ 25.00	$ 25.00
Preferred Stock, Conversion Basis	Right to Convert on a one for one basis	Right to Convert on a one for one basis
Conversion of Stock, Type of Stock Converted	Series A	Series A
Series B Preferred Stock | Minimum
Class of Stock [Line Items]
Initial Yield	1.84%
Series H Preferred Stock
Class of Stock [Line Items]
Initial Yield	4.90%
Current Annual Dividend		$ 1.5810
Earliest Redemption and/or Conversion Option Date	August 15, 2028	August 15, 2028
Redemption Value	$ 25.00	$ 25.00
Preferred Stock, Conversion Basis	Right to Convert on a one for one basis	Right to Convert on a one for one basis
Conversion of Stock, Type of Stock Converted	Series I	Series I
Series H Preferred Stock | Minimum
Class of Stock [Line Items]
Initial Yield	4.90%
Series H Preferred Stock | Prior To August 15, 2028
Class of Stock [Line Items]
Current Annual Dividend	$ 1.2250
Series J Preferred Stock
Class of Stock [Line Items]
Initial Yield	4.25%
Current Annual Dividend		$ 1.0625
Earliest Redemption and/or Conversion Option Date	May 15, 2026	May 15, 2026
Redemption Value	$ 25.00	$ 25.00
Right to Convert on a one for one basis	Series K	Series K
Series J Preferred Stock | Minimum
Class of Stock [Line Items]
Initial Yield	4.25%
Series E Preferred Stock
Class of Stock [Line Items]
Initial Yield	4.50%
Current Annual Dividend		$ 1.1250
Redemption Value	$ 25.00	25.00
Series L Preferred Stock
Class of Stock [Line Items]
Initial Yield	4.60%
Current Annual Dividend		$ 1.1500
Earliest Redemption and/or Conversion Option Date	November 15, 2026	November 15, 2026
Redemption Value	$ 26.00	$ 26.00
Series L Preferred Stock | On Or After November 15, 2026 to November 15, 2027
Class of Stock [Line Items]
Redemption Value	26.00	26.00
Series L Preferred Stock | After November 15, 2027 To November 15, 2030
Class of Stock [Line Items]
Preferred Stock, Redemption Price, Annual Decrease	0.25	0.25
Series L Preferred Stock | After November 15, 2030
Class of Stock [Line Items]
Redemption Value	25.00	25.00
Series D Preferred Stock
Class of Stock [Line Items]
Redemption Value	25.00	25.00
Series D Preferred Stock | After August 15, 2028
Class of Stock [Line Items]
Redemption Value	25.50	25.50
Series G Preferred Stock
Class of Stock [Line Items]
Redemption Value	25	25
Series G Preferred Stock | After February 15, 2025
Class of Stock [Line Items]
Redemption Value	$ 25.5	25.5
Series I Preferred Stock
Class of Stock [Line Items]
Initial Yield	2.54%
Redemption Value	$ 25	25
Series I Preferred Stock | After August 15, 2028
Class of Stock [Line Items]
Redemption Value	$ 25.5	$ 25.5

XML

Cumulative Preferred Stock (Narrative) (Details)	12 Months Ended
	Dec. 31, 2023
First Preferred Shares
Class of Stock [Line Items]
Preferred Stock Dividend Preference Or Restrictions	First Preferred Shares are neither redeemable at the option of the shareholder nor have a mandatory redemption date. They are classified as equity and the associated dividends are deducted on the Consolidated Statements of Income before arriving at “Net income attributable to common shareholders” and shown on the Consolidated Statement of Changes in Equity as a deduction from retained earnings. The First Preferred Shares of each series rank on a parity with the First Preferred Shares of every other series and are entitled to a preference over the Second Preferred Shares, the Common Shares, and any other shares ranking junior to the First Preferred Shares with respect to the payment of dividends and the distribution of the remaining property and assets or return of capital of the Company in the liquidation, dissolution or wind-up, whether voluntary or involuntary. In the event the Company fails to pay, in aggregate, eight quarterly dividends on any series of the First Preferred Shares, the holders of the First Preferred Shares, for only so long as the dividends remain in arrears, will be entitled to attend any meeting of shareholders of the Company at which directors are to be elected and to vote for the election of two directors out of the total number of directors elected at any such meeting.

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Non-Controlling Interest in Subsidiaries (Components of Non-Controlling Interest) (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Noncontrolling Interest [Line Items]
Stockholders' Equity Attributable to Noncontrolling Interest	$ 14	$ 14
GBPC
Noncontrolling Interest [Line Items]
Noncontrolling Interest, Amount Represented by Preferred Stock	$ 14	$ 14

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Non-Controlling Interest in Subsidiaries (Preferred Shares of GBPC) (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Noncontrolling Interest [Line Items]
Number of shares issued and outstanding	58,000,000	58,000,000
Non-voting Cumulative Redeemable Variable Perpetual Preferred Shares | GBPC
Noncontrolling Interest [Line Items]
Preferred Stock, Shares Authorized	10,000
Number of shares issued and outstanding	10,000	10,000
Outstanding as at December 31	$ 14	$ 14

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Non-Controlling Interest in Subsidiaries (Narrative) (Details) - GBPC	12 Months Ended
	Dec. 31, 2023 $ / shares
Noncontrolling Interest [Line Items]
Preferred Stock, Dividend Payment Terms	6.0 per cent per annum fixed cumulative preferential dividend to be paid semi-annually
Preferred Stock, Redemption Terms	The preferred shares are redeemable by GBPC after June 17, 2021
Non-voting Cumulative Redeemable Variable Perpetual Preferred Shares
Noncontrolling Interest [Line Items]
Preferred Stock, Redemption Price Per Share	$ 1,000
Non-voting Cumulative Redeemable Variable Perpetual Preferred Shares | USD preferred shares
Noncontrolling Interest [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	6.00%

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Supplementary Information to Consolidated Statements of Cash Flows (Summary of Supplementary Information to Consolidated Statement of Cash Flows) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Changes in non-cash working capital
Inventory	$ (31)	$ (214)
Receivables and other current assets	653	(636)
Accounts payable	(538)	423
Other current liabilities	(179)	193
Total non-cash working capital	(95)	(234)
Supplemental disclosure of cash paid:
Interest	930	699
Income Taxes	43	67
Supplemental disclosure of non-cash activities:
Common share dividends reinvested	271	237
Reclassification of short-term debt to long-term debt	657	0
Reclassification of long-term debt to short-term debt	0	500
Decrease in accrued capital expenditures	(19)	(13)
Supplemental disclosure of operating activities:
Net change in short-term regulatory assets and liabilities	123	(157)
January 2023 Settlement Of NMGC Gas Hedges [Member]
Changes in non-cash working capital
Receivables and other current assets	162	(162)
Nova Scotia Cap-And-Trade Program [Member]
Changes in non-cash working capital
Other current liabilities	$ (166)	$ 172

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Stock-Based Compensation (Employee Common Share Purchase Plan and Common Shareholders Dividend Reinvestment and Share Purchase Plan) (Narrative) (Details) shares in Millions	12 Months Ended
	Dec. 31, 2023 CAD ($) shares	Dec. 31, 2023 USD ($) shares	Dec. 31, 2022 CAD ($)
Employee Common Share Purchase Plan
Employee Stock Ownership Plan (ESOP) Disclosures [Line Items]
Employee Common Share Purchase Plan, Description	Eligible employees may participate in the ECSPP. As of December 31, 2023, the plan allows employees to make cash contributions of a minimum of $25 to a maximum of $20,000 CAD or $15,000 USD per year for the purpose of purchasing common shares of Emera. The Company also contributes 20 per cent of the employees’ contributions to the plan. The plan allows reinvestment of dividends for all participants except where prohibited by law.	Eligible employees may participate in the ECSPP. As of December 31, 2023, the plan allows employees to make cash contributions of a minimum of $25 to a maximum of $20,000 CAD or $15,000 USD per year for the purpose of purchasing common shares of Emera. The Company also contributes 20 per cent of the employees’ contributions to the plan. The plan allows reinvestment of dividends for all participants except where prohibited by law.
Defined Contribution Plan, Minimum Annual Contributions Per Employee, Amount	$ 25
Defined Contribution Plan, Maximum Annual Contributions Per Employee, Amount	$ 20,000	$ 15,000
Defined Contribution Plan, Employer Matching Contribution, Percent of Match	20.00%	20.00%
Compensation cost for shares issued	$ 3,000,000		$ 3,000,000
Dividend Reinvestment Plan
Employee Stock Ownership Plan (ESOP) Disclosures [Line Items]
Employee Common Share Purchase Plan, Description	The Company also has a Common Shareholders DRIP, which provides an opportunity for shareholders residing in Canada to reinvest dividends and purchase common shares. This plan provides for a discount of up to 5 per cent from the average market price of Emera’s common shares for common shares purchased in connection with the reinvestment of cash dividends. The discount was 2 per cent in 2023.	The Company also has a Common Shareholders DRIP, which provides an opportunity for shareholders residing in Canada to reinvest dividends and purchase common shares. This plan provides for a discount of up to 5 per cent from the average market price of Emera’s common shares for common shares purchased in connection with the reinvestment of cash dividends. The discount was 2 per cent in 2023.
Maximum aggregate number of common shares reserved for issuance | shares	7	7
Discount from Market Price, Purchase Date			2.00%
Dividend Reinvestment Plan | Maximum
Employee Stock Ownership Plan (ESOP) Disclosures [Line Items]
Discount from Market Price, Purchase Date	5.00%	5.00%

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Stock-Based Compensation (Narrative) (Details) $ / shares in Units, $ in Thousands, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2023 CAD ($) $ / shares shares	Dec. 31, 2022 CAD ($) $ / shares shares	Dec. 31, 2022 USD ($)	Dec. 31, 2021
Stock option plan, Additional information
Percentage of outstanding stock maximum	10.00%
Dividend Reinvestment Plan
Stock option plan, Additional information
Maximum aggregate number of common shares reserved for issuance | shares	7.0
Share Unit Plans
Maximum aggregate number of common shares reserved for issuance | shares	7.0
DSU Plan
Share Unit Plans
Cash payments made during the year	$ 3,000	$ 8,000
Employee Stock Option Plan
Stock option plan, Additional information
Maximum term	10 years
Maximum aggregate number of common shares reserved for issuance | shares	6.0	6.0
Terms of award	P10Y
Share Unit Plans
Maximum aggregate number of common shares reserved for issuance | shares	6.0	6.0
Share Unit Plans
Stock option plan, Additional information
Maximum aggregate number of common shares reserved for issuance | shares	2.0	2.7
Share Unit Plans
Maximum aggregate number of common shares reserved for issuance | shares	2.0	2.7
First Anniversary | DSU Plan | Executive and senior management
Stock option plan, Additional information
Vesting rights, percentage	25.00%
First Anniversary | DSU Plan | Executive and senior management | Minimum
Stock option plan, Additional information
Vesting rights, percentage	50.00%
Vesting period after date of retirement | Employee Stock Option Plan
Stock option plan, Additional information
Vesting period				27 months
Vesting period after termination without just cause or death | Employee Stock Option Plan
Stock option plan, Additional information
Vesting period		6 months	6 months	6 months
Vesting period after termination for just cause or resignation | Employee Stock Option Plan
Stock option plan, Additional information
Vesting period		60 days	60 days	60 days
Stock Option Plan
Stock option plan, Additional information
Share-based payment award, description	The Company has a stock option plan that grants options to senior management of the Company for a maximum term of 10 years. The option price of the stock options is the closing price of the Company’s common shares on the Toronto Stock Exchange on the last business day on which such shares were traded before the date on which the option is granted. The maximum aggregate number of shares issuable under this plan is 14.7 million shares. As at December 31, 2023, Emera was in compliance with this requirement. Stock options granted in 2021 and prior vest in 25 per cent increments on the first, second, third and fourth anniversaries of the date of the grant. Stock options granted in 2022 and thereafter vest in 20 per cent increments on the first, second, third, fourth and fifth anniversaries of the date of the grant. If an option is not exercised within 10 years, it expires and the optionee loses all rights thereunder. The holder of the option has no rights as a shareholder until the option is exercised and shares have been issued. The total number of stocks to be optioned to any optionee shall not exceed five per cent of the issued and outstanding common stocks on the date the option is granted.
Maximum aggregate number of common shares reserved for issuance | shares	14.7
Vesting rights	The holder of the option has no rights as a shareholder until the option is exercised and shares have been issued.
Percentage of outstanding stock maximum	5.00%
Policy for issuing shares upon exercise	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.
Cash received for options exercised	$ 6,000	$ 9,000
Total intrinsic value of options exercised	$ 2,000	$ 4,000
Exercise price range, lower range limit | $ / shares	$ 32.35	$ 32.35
Exercise price range, upper range limit | $ / shares	$ 60.03	$ 60.03
Fair value assumptions, method used	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.
Share Unit Plans
Compensation cost recognized for employee and director	$ 2,000	$ 2,000
Maximum aggregate number of common shares reserved for issuance | shares	14.7
Stock Option Plan, Granted 2021 | First Anniversary
Stock option plan, Additional information
Vesting rights, percentage				25.00%
Stock Option Plan, Granted 2021 | Second Anniversary
Stock option plan, Additional information
Vesting rights, percentage				25.00%
Stock Option Plan, Granted 2021 | Third Anniversary
Stock option plan, Additional information
Vesting rights, percentage				25.00%
Stock Option Plan, Granted 2021 | Fourth Anniversary
Stock option plan, Additional information
Vesting rights, percentage				25.00%
Stock Option Plan, Granted 2022 | First Anniversary
Stock option plan, Additional information
Vesting rights, percentage		20.00%	20.00%
Stock Option Plan, Granted 2022 | Second Anniversary
Stock option plan, Additional information
Vesting rights, percentage		20.00%	20.00%
Stock Option Plan, Granted 2022 | Third Anniversary
Stock option plan, Additional information
Vesting rights, percentage		20.00%	20.00%
Stock Option Plan, Granted 2022 | Fourth Anniversary
Stock option plan, Additional information
Vesting rights, percentage		20.00%	20.00%
Stock Option Plan, Granted 2022 | Fifth Anniversary
Stock option plan, Additional information
Vesting rights, percentage		20.00%	20.00%
Share Unit Plans | Share Unit Plans
Stock option plan, Additional information
Share-based payment award, description	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
Share Unit Plans
Compensation cost recognized for employee and director	$ 2,000	$ 6,000
Tax expense related to compensation costs for share units realized	1,000	2,000
Deferred Share Unit Plans | Employee
Share Unit Plans
Share Unit Plans: Aggregate intrinsic value	36,000	33,000
Deferred Share Unit Plans | Director
Share Unit Plans
Share Unit Plans: Aggregate intrinsic value	$ 37,000	34,000
Deferred Share Unit Plans | Share Unit Plans | DSU Plan
Share Unit Plans
Deferred share unit plan, description	When short-term incentive awards are determined, the amount elected is converted to DSUs, which have a value equal to the market price of an Emera common share. When a dividend is paid on Emera’s common shares, each participant’s DSU account is allocated additional DSUs equal in value to the dividends paid on an equivalent number of Emera common shares. Following termination of employment or retirement, and by December 15 of the calendar year after termination or retirement, the value of the DSUs credited to the participant’s account is calculated by multiplying the number of DSUs in the participant’s account by the average of Emera’s stock closing price for the fifty trading days prior to a given calculation date. Payments are made in cash. In addition, special DSU awards may be made from time to time by the Management Resources and Compensation Committee (“MRCC”), to selected executives and senior management to recognize singular achievements or by achieving certain corporate objectives.
Deferred Share Unit Plans | Share Unit Plans | DSU Plan | Executive and senior management
Share Unit Plans
Deferred share unit plan, description	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.
Deferred Share Unit Plans | Share Unit Plans | DSU Plan | Director
Share Unit Plans
Deferred share unit plan, description	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.
Performance Share Unit Plan
Stock option plan, Additional information
Award service period	3 years
Share Unit Plans
Tax expense related to compensation costs for share units realized	$ 3,000	5,000
Cash payments made during the year	19,000	24,000
Performance Share Unit Plan | Employee
Share Unit Plans
Share Unit Plans: Aggregate intrinsic value	$ 41,000	40,000
Performance Share Unit Plan | Share Unit Plans
Stock option plan, Additional information
Share-based payment award, description	Under the PSU plan, certain executive and senior employees are eligible for long-term incentives payable through the plan. PSUs are granted annually for three-year overlapping performance cycles, resulting in a cash payment. PSUs are granted based on the average of Emera’s stock closing price for the fifty trading days prior to the effective grant date. Dividend equivalents are awarded and paid in the form of additional PSUs. The PSU value varies according to the Emera common share market price and corporate performance. PSUs vest at the end of the three-year cycle and the payouts will be calculated and approved by the MRCC early in the following year. The value of the payout considers actual service over the performance cycle and may be pro-rated in certain departure scenarios. In the case of retirement, as defined in the PSU plan, grants may continue to vest in full and payout in normal course post-retirement.
Compensation cost recognized for stock options	$ 11,000	18,000
Restricted Share Unit Plan
Stock option plan, Additional information
Award service period	3 years
Share Unit Plans
Tax expense related to compensation costs for share units realized	$ 3,000		$ 2
Share Unit Plans: Aggregate intrinsic value	32,000
Cash payments made during the year	$ 10,000
Restricted Share Unit Plan | Employee
Share Unit Plans
Share Unit Plans: Aggregate intrinsic value		30,000
Restricted Share Unit Plan | Share Unit Plans
Stock option plan, Additional information
Share-based payment award, description	Under the RSU plan, certain executive and senior employees are eligible for long-term incentives payable through the plan. RSUs are granted annually for three-year overlapping performance cycles, resulting in a cash payment. RSUs are granted based on the average of Emera’s stock closing price for the fifty trading days prior to the effective grant date. Dividend equivalents are awarded and paid in the form of additional RSUs. The RSU value varies according to the Emera common share market price. RSUs vest at the end of the three-year cycle and the payouts will be calculated and approved by the MRCC early in the following year. The value of the payout considers actual service over the performance cycle and may be pro-rated in certain departure scenarios. In the case of retirement, as defined in the RSU plan, grants may continue to vest in full and payout in normal course post-retirement.
Compensation cost recognized for stock options	$ 10,000	$ 9,000

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Stock-Based Compensation (Weighted Average Fair Values per Stock Option and Assumptions for Options Granted) (Details) - $ / shares	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Stock-Based Compensation [Abstract]
Weighted average FV per option	$ 6.32	$ 5.35
Expected term	5 years	5 years
Risk-free interest rate	3.53%	1.79%
Expected dividend yield	5.05%	4.55%
Expected volatility	20.07%	18.87%

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Stock-Based Compensation (Summary of Stock Option Information) (Details) - CAD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Total Options, Number of Options
Total Options: Number of Options, Exercised	(620,000)	(600,000)
Non-Vested Options: Weighted average exercise price per share
Non-Vested Options: Weighted average exercise price per share, Granted	$ 6.32	$ 5.35
Stock option plan, Additional information
Non-Vested options: Unrecognized compensation	$ 5	$ 4
Non-vested options: Weighted average recognition period	3 years	3 years
Vested Options: Weighted average remaining term	5 years	5 years
Vested Options: Aggregate intrinsic value	$ 8	$ 10
Vested Options: Fair value	$ 2	$ 2
Employee Stock Option Plan
Total Options, Number of Options
Total Options: Number of Options, Outstanding, Beginning Balance	2,853,879
Granted	483,100
Total Options: Number of Options, Exercised	(146,475)
Total Options: Number of Options, Forfeited	(94,900)
Total Options: Number of Options, Outstanding, Ending Balance	3,095,604	2,853,879
Total Options: Number of Options, Options exercisable	1,842,349
Total Options, Weighted average exercise price per share
Total Options: Weighted average exercise price per share, Outstanding, Beginning Balance	$ 50.41
Total Options: Weighted average exercise price per share, Granted	54.64
Total Options: Weighted average exercise price per share, Exercised	43.94
Total Options: Weighted average exercise price per share, Forfeited	56.32
Total Options: Weighted average exercise price per share, Outstanding, Ending Balance	51.20	$ 50.41
Total Options: Weighted average exercise price per share, Options exercisable	$ 48.39
Non-Vested Options, Number of Options
Non-Vested Options: Number of Options, Outstanding, Beginning Balance	1,348,400
Granted	483,100
Non-Vested Options: Number of Options, Vested	526,620
Non-Vested Options: Number of options, Forfeited	(51,625)
Non-Vested Options: Number of Options, Ending Balance	1,253,255	1,348,400
Non-Vested Options: Weighted average exercise price per share
Non-Vested Options: Weighted average exercise price per share, Outstanding, Beginning Balance	$ 4.08
Non-Vested Options: Weighted average exercise price per share, Granted	6.32
Non-Vested Options: Weighted average exercise price per share, Vested	3.58
Non-Vested Options: Weighted average exercise price per share, Forfeited	3.61
Non-Vested Options: Weighted average exercise price per share, Outstanding, Ending Balance	$ 5.17	$ 4.08

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Stock-Based Compensation (Summary of Activity Related to Employee and Director Deferred Share Units) (Details) - DSU Plan - Deferred Share Unit Plans	12 Months Ended
	Dec. 31, 2023 $ / shares shares
Employee
Share Unit Plans: Units
Share Unit Plans: Outstanding, Beginning Balance | shares	627,223
Share Unit Plans: Granted including DRIP | shares	85,740
Share Unit Plans: Outstanding and exercisable, Ending Balance | shares	712,963
Share Unit Plans: Weighted Average Grant Date Fair Value
Share Unit Plans: Weighted Average Grant Date Fair Value: Outstanding, Beginning Balance | $ / shares	$ 41.55
Share Unit Plans: Weighted Average Grant Date Fair Value: Granted including DRIP | $ / shares	47.66
Share Unit Plans: Weighted Average Grant Date Fair Value: Outstanding and exercisable, Ending Balance | $ / shares	$ 42.29
Director
Share Unit Plans: Units
Share Unit Plans: Outstanding, Beginning Balance | shares	664,258
Share Unit Plans: Granted including DRIP | shares	117,893
Share Unit Plans: Exercised | shares	(53,093)
Share Unit Plans: Outstanding and exercisable, Ending Balance | shares	729,058
Share Unit Plans: Weighted Average Grant Date Fair Value
Share Unit Plans: Weighted Average Grant Date Fair Value: Outstanding, Beginning Balance | $ / shares	$ 45.83
Share Unit Plans: Weighted Average Grant Date Fair Value: Granted including DRIP | $ / shares	49.99
Share Unit Plans: Weighted Average Grant Date Fair Value: Exercised | $ / shares	49.39
Share Unit Plans: Weighted Average Grant Date Fair Value: Outstanding and exercisable, Ending Balance | $ / shares	$ 46.24

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Stock-Based Compensation (Summary of Activity Related to Employee Performance Share Units) (Details) - Performance Share Unit Plan - Employee - CAD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Share Unit Plans: Units
Share Unit Plans: Outstanding, Beginning Balance	690,446
Share Unit Plans: Granted including DRIP	386,261
Share Unit Plans: Exercised	(323,155)
Share Unit Plans: Forfeited	(10,187)
Share Unit Plans: Outstanding and exercisable, Ending Balance	743,365
Share Unit Plans: Weighted Average Grant Date Fair Value
Share Unit Plans: Weighted Average Grant Date Fair Value: Outstanding, Beginning Balance	$ 56.24
Share Unit Plans: Weighted Average Grant Date Fair Value: Granted including DRIP	52.71
Share Unit Plans: Weighted Average Grant Date Fair Value: Exercised	54.62
Share Unit Plans: Weighted Average Grant Date Fair Value: Forfeited	55.15
Share Unit Plans: Weighted Average Grant Date Fair Value: Outstanding and exercisable, Ending Balance	$ 55.13
Share Unit Plans: Aggregate intrinsic value
Share Unit Plans: Aggregate intrinsic value	$ 41.0	$ 40.0

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Stock-Based Compensation (Summary of Activity Related to Employee Restricted Share Units) (Details) - Restricted Share Unit Plan - CAD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Share Unit Plans: Aggregate intrinsic value
Share Unit Plans: Aggregate intrinsic value	$ 32
Employee
Share Unit Plans: Units
Share Unit Plans: Outstanding, Beginning Balance	508,468
Share Unit Plans: Granted including DRIP	236,537
Share Unit Plans: Exercised	(171,537)
Share Unit Plans: Forfeited	(10,827)
Share Unit Plans: Outstanding and exercisable, Ending Balance	562,641
Share Unit Plans: Weighted Average Grant Date Fair Value
Share Unit Plans: Weighted Average Grant Date Fair Value: Outstanding, Beginning Balance	$ 56.25
Share Unit Plans: Weighted Average Grant Date Fair Value: Granted including DRIP	52.07
Share Unit Plans: Weighted Average Grant Date Fair Value: Exercised	54.62
Share Unit Plans: Weighted Average Grant Date Fair Value: Forfeited	54.76
Share Unit Plans: Weighted Average Grant Date Fair Value: Outstanding and exercisable, Ending Balance	$ 55.01
Share Unit Plans: Aggregate intrinsic value
Share Unit Plans: Aggregate intrinsic value		$ 30

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Variable Interest Entities (Summary of Material Unconsolidated Variable Interest Entities) (Details) - NSPML - NSPML - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Variable Interest Entity [Line Items]
Equity Method Investment, Underlying Equity in Net Assets	$ 489	$ 501
Maximum exposure to loss	$ 6	$ 6