40-F - EMA - Equibles

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, 2024

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, 2024:

295,935,686

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

☐

☒

Indicate by check mark whether the

registrant has submitted electronically 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

☒

☐

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

use

the

extended

transition

period

for

complying

with

any

new

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

check

mark

whether

the

registrant

has

filed

report

and

attestation

its

management’s

assessment

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.

☐

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).

☐

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, 2024,

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,

2024 and concluded that the Registrant's internal control over financial

reporting is effective as at

December 31, 2024.

(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,

2024

, 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 Carla M. Tully.

The Board has determined

that Paula Y.

Gold-Williams, Kent M. Harvey,

B. Lynn Loewen, Ian E. Robertson and

Carla M. Tully 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

Carla

M. Tully is included in their biographical information

contained in the Registrant’s Annual Information

Form for the

fiscal year ended December 31, 2024, 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 January 1, 2025 (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 January 27, 2025 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

2024

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 21, 2025 for the

year ended December 31, 2024, filed as Exhibit 99.2 hereto (the “MD&A”) and with

respect to clause (a) the

information provided at note 28 (“D. Guarantees and Letters of Credit”) and

note 33 (“Variable

Interest Entities”),

and with respect to clause (b) note 28 (“A. Commitments”) and note

26 (“Long-Term Debt”),

to the Audited

Consolidated Financial Statements as at and for the years ended December 31, 2024

and December 31, 2023, 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.

Disclosure Regarding Foreign Jurisdictions that

Prevent Inspections.

Not applicable.

Recovery of Erroneously Awarded

Compensation

. Not applicable.

EXHIBIT INDEX

Exhibit

Number

Description

99.1

2024 Annual Information Form dated February 21, 2025 for the fiscal year ended

December 31,

2024

99.2

Management’s Discussion and Analysis

dated February 21, 2025 for the year ended December

31, 2024

99.3

Audited Consolidated Financial Statements as at and for the years ended

December 31, 2024 and

December 31, 2023

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 and effective on January

1, 2025) (incorporated by reference

to Emera Incorporated’s Form 6-K,

furnished to the Commission on January 27, 2025)

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 21

day of February, 2025.

EMERA

INCORPORATED

By:

/s/ Scott C. Balfour

Name:

Scott C. Balfour

Title:

President & Chief

Executive Officer

EX-99.1

Exhibit 99.1

LOGO

Emera Incorporated

Annual Information Form

For the year ended December 31, 2024

February 21, 2025

ANNUAL INFORMATION FORM

For the year ended December 31, 2024

Dated: February 21, 2025

TABLE OF CONTENTS

PRESENTATION OF INFORMATION	4
CAUTIONARY NOTE REGARDING FORWARD-LOOKING INFORMATION	4
CORPORATE STRUCTURE	5
Name and Incorporation	5
Intercorporate Relationships	6
INTRODUCTION	6
DESCRIPTION OF THE BUSINESS	7
Business Segments	7
Florida Electric Utility	7
Canadian Electric Utilities	10
Gas Utilities and Infrastructure	13
Other Electric Utilities	16
Other	17
GENERAL DEVELOPMENT OF THE BUSINESS	18
Florida Electric Utility	18
Canadian Electric Utilities	20
Gas Utilities and Infrastructure	24
Other Electric Utilities	25
Other	27
Financing Activity	28
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	32
MARKET FOR SECURITIES	33
Trading Price and Volume	33
ATM Program	33
DIRECTORS AND OFFICERS	33
Directors	33
Officers	36
AUDIT COMMITTEE	37
Audit and Non-Audit Services Pre-Approval Process	39
Auditors’ Fees	39
Emera Incorporated – 202 4 Annual Information Form	2
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CERTAIN PROCEEDINGS	39
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CONFLICTS OF INTEREST	40
LEGAL PROCEEDINGS AND REGULATORY ACTIONS	40
NO INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS	40
MATERIAL CONTRACTS	40
TRANSFER AGENT AND REGISTRAR	40
EXPERTS	41
ADDITIONAL INFORMATION	41
APPENDIX “A” – DEFINITIONS OF CERTAIN TERMS	42
APPENDIX “B” – SUMMARY OF TERMS AND CONDITIONS OF AUTHORIZED SERIES OF FIRSTPREFERRED SHARES	46
APPENDIX “C” – MONTHLY TRADING VOLUME AND HIGH AND LOW PRICE FOR EMERA’SSECURITIES IN 2024	49
APPENDIX “D” – EMERA INCORPORATED AUDIT COMMITTEE CHARTER	50
Emera Incorporated – 202 4 Annual Information Form	3
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PRESENTATION OF INFORMATION

Unless otherwise noted, the information contained in this AIF is given at or for the year ended December 31, 2024. All financial information is expressed CAD, rounded to the nearest million, and is presented in accordance with USGAAP, unless otherwise stated. Emera uses adjusted net income as a financial performance measure, which is not a defined financial measure under 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 under Emera’s profile 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, the expected timing and outcome of the pending sale of NMGC, 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 – 202 4 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.

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; change in law risk; operating and maintenance risks; changes in economic conditions; commodity price and availability risk; liquidity and capital markets risk; changes in credit ratings; future dividend growth, rate base growth, and adjusted earnings per common share (“EPS”) 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; climate change risk; 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 – 202 4 Annual Information Form	5

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, 2024.

Subsidiaries	Percentage Ownership (%)	Jurisdiction
Tampa Electric Company	100	Florida
Nova Scotia Power	100	Nova Scotia
Peoples Gas System	100	Florida

INTRODUCTION

Emera (TSX: EMA) is a North American provider of energy services owning and operating a portfolio of cost-of-service, rate-regulated electric and gas utilities. Its largest operations are in Florida, with additional operations in Atlantic Canada, New Mexico and the Caribbean. Emera is headquartered in Halifax, Nova Scotia.

Emera’s business strategy is centered on continued investment in its regulated utilities, combined with a focus on operational excellence and efficiency, to safely and reliably deliver energy to its 2.6 million customers. Effective execution of these priorities supports predictable and growing earnings, cash flow and dividends for shareholders.

Earnings opportunities in regulated utilities are a function of the magnitude of net investment in the utility (known as “rate base”), the amount of equity in the capital structure and the targeted ROE, all as established and approved through regulation. Earnings are also affected by sales volumes and operating expenses. In 2024, Emera’s regulated cost-of-service utilities in Florida accounted for 65 per cent of average consolidated rate base, with Atlantic Canada comprising 27 per cent, the Caribbean and New Mexico at 4 per cent each.

Emera’s capital investment plan is forecasted to be approximately $20 billion from 2025 through 2029 and is focused on delivering value for customers through prudent investments in reliability and system resiliency, infrastructure modernization, expansion to address customer growth, integration of renewables, and technological innovations to deliver better customer experiences. It is anticipated that approximately 80 per cent of this capital investment plan will be made in Emera’s Florida utilities, necessitated by customer growth and system requirements at both TEC and PGS.

Emera’s capital investment plan will be funded primarily through internally generated cash flows, debt raised at the operating company level consistent with regulated capital structures, equity issuances, and the anticipated sale of NMGC. Generally, Emera’s equity requirements are expected to be funded through the issuance of preferred equity, and the issuance of common equity through Emera’s DRIP and its ATM Program. Maintaining investment-grade credit ratings is a core strategic priority of the Company.

Emera has increased dividends per common share paid for 18 consecutive years and has provided forward annual dividend growth guidance of one to two per cent. Emera’s anticipates adjusted EPS average growth of five to seven per cent through 2027 which will support reduction in the ratio of dividend payout to adjusted net income. For further information on the non-GAAP ratios “Adjusted EPS” and “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.

Emera Incorporated – 202 4 Annual Information Form	6

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 an equity interest in NSPML (100 per cent);<br>
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•	Gas Utilities and Infrastructure, which includes PGS, NMGC, Emera Brunswick Pipeline Company, SeaCoast and<br>an equity interest in M&NP (12.9 per cent);
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•	Other Electric Utilities, which includes ECI, a holding company with regulated electric utilities which<br>include BLPC, GBPC and an equity interest in Lucelec (19.5 per cent); and
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•	Other, **** which includes Emera Energy, corporate holding, financing companies and certain other<br>investments.
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Emera and its subsidiaries had 7,605 employees as at December 31, 2024, approximately 30 per cent of whom are unionized.

Operations by Segment

FloridaElectric Utility

The Florida Electric Utility segment 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 $13 billion USD of assets, approximately 855,000 customers and 2,587 employees as at December 31, 2024.

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.

Beginning in 2025, TEC’s approved regulated ROE range is 9.50 per cent to 11.50 per cent (2024 - 9.25 per cent to 11.25 per cent), based on an allowed equity capital structure of 54 per cent (2024 – 54 per cent). An ROE of 10.50 per cent (2024 - 10.20 per cent) is used for the calculation of the return on investments for clauses.

For further details on TEC’s regulatory environment, base rates and recovery mechanisms, refer to Note 7, Regulatory Assets and Liabilities, in the Audited Financial Statements, which are hereby incorporated by reference, a copy of which is available electronically under Emera’s profile on SEDAR+ at www.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	2024	2023	2024	2023
Residential	59.7	64.9	48.8	49.0
Commercial	27.1	30.4	30.8	30.7
Industrial	6.4	7.7	9.6	9.9
Other ^(1)^	6.8	(3.0)	10.8	10.4
Total	100.0	100.0	100.0	100.0
(1)	Other includes regulatory deferrals related to clauses, sales to public authorities, and off-system sales to other utilities.
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Emera Incorporated – 202 4 Annual Information Form	7
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Energy Sources and Generation

As at December 31, 2024, TEC owns 6,620 MW of generating capacity, of which 73 per cent is natural gas fired, 20 per cent is solar and 7 per cent is coal. TEC also owns 2,192 kilometres of transmission facilities and 20,693 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 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 toConsolidated Net Income and Consolidated Adjusted Net Income

Florida Electric Utility’s contribution to consolidated net income was $468 million USD in 2024 (2023 – $466 million USD). Florida Electric Utility’s contribution to consolidated adjusted net income was $470 million in 2024 (2023 - $466 million). For a reconciliation of Florida Electric Utility’s adjusted net income to consolidated net income, refer to the “Non-GAAP Financial Measures and Ratios” and “Financial Highlights – Florida Electric Utility” 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 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 2024, capital investments, including AFUDC, in the Florida Electric Utility segment were $1.4 billion USD (2023 – $1.3 billion USD). In 2025, capital investment is expected to be approximately $1.7 billion USD, including AFUDC. Capital projects include solar investments, grid modernization, storm hardening investments, building resilience and energy storage.

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.

Carbon Reductions and GHG

TEC has historically supported voluntary efforts to reduce carbon emissions and has taken significant steps to reduce overall emissions at TEC’s facilities. Since 2000, TEC has reduced its system-wide emissions of CO2 by more than 50 per cent, bringing emissions to below 1990 levels, where they continue to remain. Since 2005, TEC has continued to optimize its existing coal units to operate on natural gas, during which time the number of retail customers and retail energy sales have risen. TEC has also substantially reduced CO2 emissions by significantly expanding the use of solar power, repowering Big Bend Unit 1 steam turbine,

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and retiring Big Bend Unit 2 and Unit 3. The Big Bend Unit 1 modernization project is capable of producing 1,090 megawatts of power and will continue to lead to lower system-wide emissions.

On April 24, 2024, the EPA issued its final power plant rules for electric generating units, including (i) new GHG standards; and (ii) Mercury and Air Toxics Standards (“MATS”). The new MATS will not have a material impact on TEC. The new GHG standard applies only to existing coal-fired and new natural gas electric generating units and will therefore have limited impact on TEC generating units. Big Bend Unit 4 is the only unit affected. As written, the rule would require Big Bend Unit 4 to retire in 2039 without major enhancements to the unit, instead of the current planned retirement date of 2040.

CCR Recycling and Regulation

TEC produces ash and other by-products, collectively known as coal combustion residuals (“CCRs”) at Big Bend Power Station. Greater than 90 per cent of all CCRs produced at this facility are marketed to customers for beneficial use in commercial and industrial products. The EPA’s final CCR rule became effective on October 19, 2015 and regulates CCRs as non-hazardous solid waste. In 2016 and 2017, the FPSC approved Environmental Cost Recovery for capital and O&M expenses associated with various projects proposed as part of TEC’s CCR compliance program. Subsequently, a closure by removal and liner retrofit project for the West Slag Dewatering Pond was completed in 2020 and closure by removal of all CCRs from the Economizer Ash and Pyrite Ponds was completed in October 2021. The final project required for compliance with the CCR Rule at Big Bend is the North Gypsum Stackout Area Drainage Improvements Project, which is scheduled for completion in 2025. FDEP has revised the existing state solid waste regulation to incorporate Florida CCR permit requirements for regulated units and these new requirements will operate in lieu of the Federal permitting program. However, TEC is largely exempt from the state permitting requirements because it completed its mandatory closure projects prior to the state rule’s passage. On May 18, 2023, the EPA proposed new rules requiring identification and regulation of Legacy CCR Management Units. TEC is a member of the Utility Solid Waste Activities Group, who filed comments on behalf of its members in July 2023 contesting many of the proposed rule’s provisions.

The new CCR rule finalized in April 2024 covers any landfill or impoundment in existence at an inactive power facility but not receiving CCRs as of 2015, any CCR placed into the environment for beneficial uses, or CCR units (landfills and impoundments) previously closed under state programs. TEC is currently evaluating the impact of the new CCR rule at Unit 4 of the Big Bend Power Station and will likely require site evaluations beginning in 2025 to determine the presence or absence of CCR management units. If found, additional evaluations would be required in 2026 and based on those findings, modifications to the site groundwater monitoring could be required beginning in 2027 to determine the need for additional corrective action.

TEC expects that the costs to comply with the new environmental regulations would be eligible for recovery. If approved as prudent, the costs would be reflected in customers’ bills, recovered through either the environmental cost recovery clause or base rates.

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 United States”. TEC has two ongoing projects (one for Bayside and one for Big Bend) that require compliance with the rule. Compliance includes the completion of the biological, technical, and financial study elements required by the rule. These study elements have been completed and submitted for Bayside and were used by the Florida Department of Environmental Protection (“FDEP”) to determine the necessity of cooling water system retrofits. 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. TEC is negotiating an alternative schedule for Big Bend (as allowed by the rule) but completed a portion of the compliance requirements with the Big Bend modernization project with the installation of fish-friendly modified traveling screens and a fish return on modernized Unit 1. The remainder of the compliance

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requirements are to be determined and completed at a later date. The full impact of the new regulations on TEC will depend on the study elements performed as part of the rules’ implementation, and the actual requirements established by FDEP.

The final EPA rule for existing steam electric effluent limit guidelines (“ELGs”) became effective January 4, 2016 and establishes limits for certain wastewater discharges. The new ELGs will not have a material impact on TEC. Big Bend completed construction of a deep injection well system in December 2023 for disposal of various types of wastewater. This change will be made to the final National Pollutant Discharge Elimination System (“NPDES”) permit, anticipated in 2025. Since Polk Power Station also uses a deep injection well rather than discharging it to surface water, the effluent limitations will no longer apply to either power station. The referenced wastewater at each power station will be regulated under the Underground Injection Control program rather than the NPDES program.

EPA Waters of the US

In 2023, the EPA and Department of the Army issued a final rule amending the definition of “waters of the United States”. The final rule is expected to have environmental permitting implications for new Tampa Electric solar sites and permitting renewals for existing facilities requiring approved jurisdictional determinations.

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.

Superfund and FormerManufactured 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 28, 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.

CanadianElectric Utilities

The Canadian Electric Utilities segment includes NSPI and NSPML. 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. NSPML is a 100 per cent equity interest in the Maritime Link Project (“Maritime Link”), a transmission project between the island of Newfoundland and Nova Scotia.

On June 4, 2024, Emera completed the sale of its LIL equity interest. For further information, refer to the “Significant Items Affecting Earnings” and “Other Developments” sections of Emera’s MD&A, which is incorporated herein by reference, a copy of which is available electronically under Emera’s profile on SEDAR+ at www.sedarplus.ca.

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NSPI

NSPI is the primary electricity supplier in Nova Scotia, providing electricity generation, transmission and distribution services to approximately 557,000 customers with $7.1 billion in assets and 2,344 employees, as at December 31, 2024.

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 of approved rate base.

For further details on NSPI’s regulatory environment and recovery mechanisms, refer to Note 7, Regulatory Assets and Liabilities, in the Audited Financial Statements, which are hereby incorporated by reference, a copy of which is available electronically under Emera’s profile on SEDAR+ at www.sedarplus.ca.

Market and Sales

NSPI Revenue and Electricity Sales Volumes by Customer Class
	Electric Revenues (%)		GWh Electric Sales Volumes (%)
For the year ended December 31	2024	2023	2024	2023
Residential	55.0	55.7	48.2	47.8
Commercial	27.5	28.4	28.8	29.2
Industrial	15.2	13.4	21.0	20.7
Other	2.3	2.5	2.0	2.3
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 (“petcoke”) and 2 per cent is biomass-fueled generation. In addition, NSPI has contracts to purchase renewable energy from IPPs, and COMFIT participants, which own 533 MW of capacity. NSPI also has rights to 153 MW of Maritime Link capacity, representing NLH’s NS Block delivery obligations, as discussed below.

NLH 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, NLH 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 NLH through the Energy Access Agreement. The Energy Access Agreement enables NSPI to access a market-priced bid from NLH 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

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stations and other key facilities through the Supervisory Control and Data Acquisition system, a software application 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 NLH, 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 andDistribution

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.

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. NLH’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.

Contribution to Consolidated Net Income

Canadian Electric Utilities’ contribution to consolidated net income was $232 million in 2024 (2023 – $247 million).

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 2024 were $487 million (2023 – $451 million), including AFUDC. In 2025, NSPI expects to invest $480 million, including AFUDC, primarily in capital projects to support power system reliability and reliable service for customers.

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NSPML

NSPML does not anticipate any significant capital investment in 2025.

Environmental Considerations

NSPI is subject to environmental laws and regulations set by both the Government of Canada and 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 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 2024 Annual Information Form, a copy of which is available electronically under NSPI’s profile on SEDAR+ at www.sedarplus.ca.

Gas Utilities and Infrastructure

The Gas Utilities and Infrastructure segment 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 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	2024	2023	2024	2023
Residential	46.7	50.3	13.1	13.2
Commercial	32.5	29.5	26.3	26.8
Industrial	6.2	6.5	51.7	51.5
Other	14.6	13.7	8.9	8.5
Total	100.0	100.0	100.0	100.0
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PGS

As at December 31, 2024, PGS serves approximately 508,000 customers with $3.1 billion USD in assets and 814 employees. The PGS system includes approximately 25,240 kilometres of natural gas mains and 14,530 kilometres of service lines. Natural gas throughput (the amount of gas delivered to its customers, including transportation-only service) was 2 billion therms in 2024.

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

The approved ROE range for PGS is 9.15 per cent to 11.15 per cent, based on an allowed equity capital structure of 54.7 per cent. An ROE of 10.15 per cent is used for the calculation of return on investments recovered through cost recovery clauses.

For further details on PGS’ regulatory environment and recovery mechanisms, refer to Note 7, Regulatory Assets and Liabilities, in the Audited Financial Statements, which are hereby incorporated by reference, a copy of which is available electronically under Emera’s profile on SEDAR+ at www.sedarplus.ca.

NMGC

As at December 31, 2024, NMGC serves approximately 550,000 customers with $1.5 billion USD in assets and 750 employees. NMGC’s system includes 2,405 km of transmission lines and 17,810 km of distribution lines. Annual natural gas throughput was 1 billion therms in 2024.

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 7, Regulatory Matters, 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.

On August 5, 2024, Emera announced an agreement to sell NMGC. The transaction is expected to close in late 2025, subject to certain approvals, including approval by the NMPRC. For more information on the pending transaction, refer to the “General Development of the Business – Gas Utilities and Infrastructure” section below and the “Other Developments” section 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.

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.

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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.

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 and Consolidated Adjusted Net Income

Gas Utilities and Infrastructure’s contribution to consolidated net income was $188 million USD in 2024 (2023 – $158 million USD). Gas Utilities and Infrastructure’s contribution to consolidated adjusted net income was $194 million USD in 2024 (2023 – $158 million USD). For a reconciliation of Gas Utilities and Infrastructure’s adjusted net income to consolidated net income, refer to the “Non-GAAP Financial Measures and Ratios” and “Financial Highlights – Gas Utilities and Infrastructure” 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

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 PGS in 2024 were $323 million USD (2023 – $495 million USD in the Gas Utilities and Infrastructure segment). In 2025, capital investment at PGS is expected to be approximately $360 million USD, including AFUDC. PGS will make investments to maintain the reliability of its system 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 28, 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.

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Other Electric Utilities

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

Market and Sales

Other Electric Utilities operating revenues for 2024 were $413 million USD (2023 – $390 million USD) and electric sales volumes for 2024 were 1,307 GWh (2023 – 1,260 GWh).

BLPC

As at December 31, 2024, BLPC serves approximately 135,000 customers with $538 million USD of assets and a workforce of 432 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 3,989 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.

For further information and developments regarding BLPC, refer to the “General Development of the Business – Other Electric Utilities” section below.

GBPC

As at December 31, 2024, GBPC serves approximately 19,500 customers, with $340 million USD of assets and a workforce of 206 employees. GBPC owns 98 MW of oil-fired generation, approximately 90 kilometres of transmission facilities and 994 kilometers of distribution facilities.

GBPC has historically been 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 further information and developments regarding GBPC, refer to the “General Development of the Business – Other Electric Utilities” section below.

For further details on GBPC’s regulatory environment and recovery mechanisms, refer to Note 7, Regulatory Assets and Liabilities, in the Audited Financial Statements, which is hereby incorporated by reference, a copy of which is available electronically under Emera’s profile on SEDAR+ at www.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

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economy of operations. The generation and transmission system control centres are linked to their generating stations and other key parts of their systems by the “Supervisory Control and Data Acquisition” systems, with fibre optic, voice and data communications networks.

Transmission and Distribution

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

Contribution to Consolidated Net Income and Adjusted Net Income

Other Electric Utilities’ contribution to consolidated net income was $35 million USD in 2024 (2023 – $28 million USD). Other Electric Utilities’ contribution to consolidated adjusted net income was $35 million USD in 2024 (2023 – $26 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.

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 2024 were $59 million USD (2023 – $47 million USD). In 2025, capital investment is expected to be approximately $140 million USD, including AFUDC, 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 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 Corporate; Emera Energy Services (EES), physical energy marketing and trading business; a 50 per cent joint venture interest in Bear Swamp, a 660 MW pumped storage hydroelectric facility in northwestern Massachusetts; and Block Energy. In Q4 2024, Block Energy initiated the process to wind-up operations.

Corporate items included 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.

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Emera Energy

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

Earnings from EES are generally dependent on market conditions. In particular, volatility in natural gas and electricity markets, which can be influenced by weather, local supply constraints and other supply and demand factors, can provide higher levels of margin opportunity. The business is seasonal, with Q1 and Q4 usually providing the greatest opportunity for earnings. EES is generally expected to deliver annual adjusted net income 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 $686 million in 2024 (2023 – loss of $147 million). Other’s contribution to consolidated adjusted net income was a loss of $342 million in 2024 (2023 – loss of $314 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 2025, capital investment in the Other segment is not expected to be significant.

GENERAL DEVELOPMENT OF THE BUSINESS

Three YearHistory and Changes Expected in 2025

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 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 pursuant to the terms of a settlement agreement reached and approved in 2021. Effective July 1, 2022, the mid-point ROE was 10.20 per cent, and the range was 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.

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On April 2, 2024, TEC filed a rate case with the FPSC for new base rates. On December 3, 2024, the FPSC rendered a decision which includes annual base rate increases of $185 million USD in 2025 and adjustments of $87 million USD and $9 million USD in 2026 and 2027, respectively. The rates include recovery of solar generation projects, energy storage capacity, a more resilient and modernized energy control center, and other resiliency and reliability projects. The allowed equity in the capital structure will continue to be 54 per cent from investor sources of capital and the allowed regulatory ROE range is 9.50 per cent to 11.50 per cent with a 10.50 per cent midpoint. On February 3, 2025, the FPSC issued the final order approving the decision, effective January 1, 2025. On February 18, 2025, a motion for reconsideration on certain aspects of the rate case order was filed with the FPSC. TEC will respond to this motion in February 2025. TEC expects the FPSC to reach a final decision on the motion in Q2 2025.

Fuel Recovery

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.

On April 2, 2024, TEC requested a mid-course adjustment to its fuel and capacity charges, reflecting a $138 million USD reduction over 12 months, from June 2024 through May 2025. The requested reduction was due to a decrease in actual and projected 2024 natural gas prices since TEC submitted its projected 2024 costs in the fall of 2023. On May 7, 2024, the FPSC approved the mid-course adjustment.

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 retired the Unit 1 components that would not be used in the modernized plant Big Bend Unit 2 and Big Bend Unit 3 in 2020, 2021 and 2023, respectively.

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. 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. The remaining balance of $29 million USD as of December 31, 2023, was collected over 12 months in 2024.

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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.

On September 26, 2024, Hurricane Helene passed 100 miles west of Tampa and made landfall approximately 200 miles north of Tampa, in Taylor County, as a Category 4 hurricane. TEC’s service territory was impacted by the tropical storm force winds and storm surge which resulted in a peak number of customers out of 100,000. As of December 31, 2024, TEC deferred $49 million USD to the storm reserve for future recovery.

On October 9, 2024, Hurricane Milton made landfall approximately 50 miles south of Tampa, near Sarasota, and was the worst weather event to impact the area in over 100 years. The Category 3 hurricane had a significant impact on TEC’s service territory which resulted in a peak number of customers out of 600,000. As of December 31, 2024, TEC deferred $340 million USD to the storm reserve for future recovery.

As at December 31, 2024, total restoration costs charged to the storm reserve account have exceeded the storm reserve balance and therefore $377 million USD has been deferred as a regulatory asset for future recovery. On February 4. 2025, the FPSC approved TEC’s petition filed on December 27, 2024 for the recovery of $466 million USD for costs associated with Hurricane Idalia, Hurricane Debby, Hurricane Helene and Hurricane Milton and the associated interest to replenish the storm reserve over an 18-month recovery period beginning in March 2025. The amount of cost-recovery is subject to a true-up mechanism with the FPSC.

Storm Protection Cost Recovery Clauseand 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. The current approved plan addressed the years 2023, 2024 and 2025 and was approved by the FPSC on October 4, 2022.

For more information, refer to the “Regulatory Environments and Updates – Florida Electric Utility” section of Note 7, Regulatory Assets and Liabilities, in the Audited Financial Statements, which is hereby incorporated by reference, a copy of which is available electronically under Emera’s profile on SEDAR+ at www.sedarplus.ca

Canadian Electric Utilities

NSPI

General Rate Application and Settlement Agreement

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. On March 27, 2023 the UARB issued a final order approving the electricity rates effective on February 2, 2023.

The settlement agreement established a storm rider for each of 2023, 2024 and 2025, which gives NSPI the ability to apply to the UARB for deferral and recovery of expenses if major storm restoration expense exceeds approximately $10 million in any given year. The storm rider was effective as of February 2, 2023, 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 costs, with recovery beginning in the year after the application. On December 2, 2024, the UARB approved the recovery of $24 million of major storm restoration and

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incremental financing costs deferred to NSPI’s storm rider in 2023 to be recovered over a 12-month period beginning on January 1, 2025.

The settlement agreement also established a DSM rider, allowing NSPI to recover costs associated with DSM programs developed and delivered by EfficiencyOne, a third-party entity that currently holds the franchise for the provision of energy efficiency and conservation in the Province, regulated by the UARB.]. The DSM rider was effective as of February 2, 2023, the GRA decision date. Differences between DSM program costs and amounts recovered from customers through electricity rates are deferred to a DSM regulatory asset or liability and recovered from or returned to customers in subsequent periods.

Fuel Recovery

On April 17, 2024, the UARB approved the sale of $117 million of the FAM regulatory asset to Invest Nova Scotia, a provincial Crown corporation. On April 30, 2024, the transaction closed and the $117 million was remitted to NSPI, which resulted in a corresponding decrease of the FAM regulatory asset. NSPI is collecting the amortization and financing costs related to the $117 million from customers on behalf of Invest Nova Scotia over a 10-year period which began in Q2 2024 and is remitting those amounts to Invest Nova Scotia quarterly.

On September 24, 2024, the Government of Canada finalized an agreement with NSPI, NSPML and the Province on terms and conditions for a federal loan guarantee (“FLG”) of $500 million in debt to be issued by NSPML to help Nova Scotia customers manage unrecovered costs of the replacement energy that was required during the several years of delay in the Muskrat Falls hydroelectricity project. On September 25, 2024, NSPI and NSPML filed applications with the UARB related to the FLG. On November 29, 2024, the UARB approved NSPML’s application to issue the debt, transfer the proceeds to NSPI as a refund of a portion of previous NSPML assessment payments, and to increase its annual assessment charge to NSPI to recover the refund and related financing costs over a 28-year period. On December 16, 2024, the net proceeds of the NSPML debt issuance were transferred to NSPI and applied against the FAM regulatory asset balance. On February 18, 2025, the UARB approved NSPI’s application to increase 2025 fuel rates to service the incremental NSPML debt.

Hurricane Fiona

On June 27, 2024, the UARB approved the deferred recognition of $25 million in incremental operating costs incurred during the Hurricane Fiona storm restoration efforts in September 2022. Following UARB approval, the $25 million was reclassified to “Regulatory assets” from “Other long-term assets”. The UARB also directed NSPI to reclassify $10 million of undepreciated costs related to assets retired because of Hurricane Fiona to “Regulatory assets” from “PP&E” on the Consolidated Balance Sheets. NSPI began amortizing both of these regulatory assets over a 10-year period beginning July 1, 2024.

Regulatory Matters – General

For more information, refer to the “Regulatory Environments and Updates – Canadian Electric Utilities – NSPI” section of Note 7, Regulatory Assets and Liabilities, in the Audited Financial Statements, which is hereby incorporated by reference, a copy of which is available electronically under Emera’s profile on SEDAR+ at www.sedarplus.ca.

Battery Energy Storage System (“BESS”) Project

On June 13, 2024, the UARB approved $238 million of capital investment, including AFUDC, for the BESS Project. The project is comprised of three 50 MW, four-hour battery facilities. Two facilities are anticipated to be in-service in late 2025 and the third facility in 2026.

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Environmental Legislation and Regulations

Nova Scotia Energy Reform Act

On April 5, 2024, the Province enacted Bill 404 - Energy Reform (2024) Act. This legislation implements certain recommendations made by the Clean Electricity Solutions Task Force, which was established by the Province to advise the provincial government on Nova Scotia’s transition away from coal to more renewable sources of energy. The legislation enacted the Energy and Regulatory Board Act, which established the Nova Scotia Energy Board (“NSEB”). The NSEB is a new board which will regulate energy and utility entities in Nova Scotia, with a mandate of increased focus on meeting energy transition demands. The legislation also enacts the More Access to Energy Act, which provides for the establishment of and phased transition to the Nova Scotia Independent Energy System Operator (“NSIESO”). The Province previously had announced that the NSEISO’s responsibilities will include managing the operations of the electricity system, the connection of renewable energy projects to the grid and system planning and procuring new energy sources. NSPI is fully engaged in supporting the Province on these initiatives.

CleanElectricity Regulations (“CER”)

On December 17, 2024, Environment and Climate Change Canada released a finalized version of the CER. The CER establish performance standards to further limit GHG emissions from fossil fuel generated electricity starting in 2035 and help facilitate the Government of Canada’s intention of achieving a net-zero electricity grid by 2050. Compliance with the finalized version of the CER is not anticipated to require significant capital investment incremental to achieve the 2030 targets as NSPI’s planned capital investment during this period is driven by the Province’s goals to transition off coal and reach 80 per cent renewable electricity sales by 2030.

Nova Scotia Renewable Electricity Regulations (“RER”)

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 2024 and 2023, with 42 per cent and 43 per cent, respectively, of NSPI’s electric sales coming from renewable sources. NSPI’s 2024 renewable sales are subject to an annual compliance filing.

Due to the delay of NSPI receiving energy from the NS Block, the Province had 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, through a proceeding with the UARB, of the $10 million penalty levied on NSPI by the Province for non-compliance with the RER compliance period ending in 2022. The hearing for the matter is currently scheduled for June 2025.

Carbon Pricing Regulations

NSPI is a mandatory participant in Nova Scotia’s output-based pricing system (“OBPS”) carbon pricing program, which was effective January 1, 2023. Nova Scotia’s OBPS implements GHG emissions performance standards for large industrial GHG emitters that vary by fuel type. GHG emissions in excess of the prescribed intensity standards are subject to a carbon price that starts at $65 per tonne in 2023 and increases by $15 per tonne annually, reaching $170 per tonne by 2030. NSPI’s regulatory framework

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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. NSPI received granted emissions allowances and was permitted to purchase up to five per cent of the credits available at provincial auctions. Any remaining allowance shortfall required the purchase of reserve credits directly from the Province. Lower than forecast Muskrat Falls energy received during the compliance period resulted in the increased deployment of higher carbon-emitting generation sources. 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 Amendments

In April 2023, the Province enacted amendments to the Electricity Act which will allow the Province to issue requests for proposals for energy-storage in Nova Scotia, similar to the existing procurement process for renewable energy. In addition, the amendments to the Electricity Act allow the Governor in Council to approve unique or innovative energy storage projects that provide benefits to the electric system and reduce costs for customers.

In November 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. In 2024, the UARB approved the BESS project. For further details refer to “Regulatory Matters – General” section above.

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.

NSPML

Maritime Link Project

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 from NSPI for the recovery of costs associated with the Maritime Link in 2022. This was subject to a holdback of up to $2 million per month, beginning April 2022, release of which was contingent on receiving in that month at least 90 per cent of NS Block deliveries, including supplemental Energy deliveries.

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In December 2022, NSPML received UARB approval to collect up to $164 million from NSPI for the recovery of costs associated with the Maritime Link in 2023, subject to a monthly holdback of up to $2 million, which increased 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”. The UARB also confirmed that the holdback mechanism would cease once 90 per cent of NS Block deliveries were 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 UARB 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.

On September 25, 2024, NSPI and NSPML filed applications with the UARB related to the FLG. On December 16, 2024, the net proceeds of the NSPML debt issuance were transferred to NSPI and applied against the FAM regulatory asset balance as a refund of a portion of previous NSPML assessment payments. For further details, refer to the “Fuel Recovery” section above.

On November 29, 2024, NSPML received approval from the UARB to collect up to $197 million in 2025 from NSPI; which includes $158 million for the recovery of costs associated with the Maritime Link, and $39 million associated with the additional FLG debt and financing costs discussed in the “NSPI” section above. Payments from NSPI are subject to a holdback of up to $4 million per month. There was no holdback recorded for the year ended December 31, 2024. NSPML expects to file an application to terminate the holdback mechanism in early 2025.

LIL

Sale of LIL Equity Interest

On June 4, 2024, Emera completed the sale of its 31.1 per cent LIL equity interest for a total transaction value of $1.2 billion, including cash proceeds of $957 million and $235 million for assuming Emera’s contractual obligation to fund the remaining initial capital investment, which represents additional LIL equity interest for the acquirer. For more information, see the “Other Developments” 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.

Gas Utilities and Infrastructure

General -Sale of NMGC

On August 5, 2024, Emera entered into an agreement to sell its indirect wholly owned subsidiary NMGC for a total enterprise value of approximately $1.3 billion USD, consisting of cash proceeds and the transfer of debt and customary closing adjustments. The transaction is currently expected to close in October 2025, subject to certain approvals, including approval by the NMPRC. As a result of the pending sale, NMGC’s assets and liabilities are classified as held for sale as of Q3 2024. For more information on the pending transaction, refer to the “Other Developments” 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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PGS

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.

On January 30, 2025, PGS notified the FPSC of its intent to seek a base rate increase effective January 2026, reflecting a revenue requirement of approximately $90 to $110 million USD and subsequent year adjustment for 2027 of approximately $25 to $40 million USD. PGS’ proposed rates support on-going growth in Florida and a continued commitment to delivering safe and reliable service to PGS customers. The filing range amounts are estimates until PGS files its detailed case in March 2025. The FPSC is scheduled to hear the case in Q3 2025 with a decision expected by the end of 2025.

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. On March 1, 2024, NMGC filed with the NMPRC a settlement with the support of all parties in the case for an increase of $30 million USD in annual base revenues and maintaining NMGC’s ROE at 9.375 per cent. The rates reflect the recovery of increased operating costs and capital investments in pipeline projects and related infrastructure, as well as a new customer information and billing system. NMGC also agreed to withdraw, and to not reassert in a future rate case application, its request for a regulatory asset for costs associated with its 2022 application for a certificate of public convenience and necessity for a liquefied natural gas storage facility in New Mexico. The NMPRC approved the rate case settlement on July 25, 2024. New rates became effective October 1, 2024.

For more information, refer to the “Regulatory Environments and Updates – Gas Utilities and Infrastructure” section of Note 7, Regulatory Assets and Liabilities, in the Audited Financial Statements, which is hereby incorporated by reference, a copy of which is available electronically under Emera’s profile on SEDAR+ at www.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 totalling approximately $71 million USD. On March 7, 2023, BLPC filed a Motion for Review and

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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. The appeal is currently scheduled to be heard in 2025.

Clean Energy Transition Rider (“CETR”)

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 CETR (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 CETR. On May 6, 2024, the FTC approved the recovery of a 15 MW battery storage system through the CETR.

Tax Legislation

On May 24, 2024, the Government of Barbados signed the Income Tax (Amendment and Validation) Act into law. The legislation, effective January 1, 2024, implemented a corporate income tax rate of 9 per cent, requiring BLPC to remeasure its deferred income tax liabilities. On July 18, 2024, BLPC requested the deferred recovery of the $5 million USD remeasurement. BLPC is seeking amortization of the costs over a period to be approved by the FTC during a future rate setting process.

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.

On August 1, 2024, as required by the GBPA Operating Protocol and Regulatory Framework Agreement, GBPC filed a rate plan proposal. Review of the rate application is expected to be completed in 2025.

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 and 2024 the fuel pass through charge was adjusted monthly, in-line with actual fuel costs.

StormRestoration Costs – Hurricane Matthew

Restoration costs associated with Hurricane Matthew in 2016 were recovered through an approved fuel charge, approved in 2016 by the GBPA. 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. As of November 2024, the Hurricane Matthew regulatory asset has been fully recovered.

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For more information, refer to the “Regulatory Environments and Updates – Other Electric Utilities” section of Note 7, Regulatory Assets and Liabilities, in the Audited Financial Statements, which is hereby incorporated by reference, a copy of which is available electronically under Emera’s profile on SEDAR+ at www.sedarplus.ca.

Electricity Act, 2024

On June 1, 2024, the Electricity Act, 2024 took effect. The legislation purports to remove the jurisdiction of the GBPA over GBPC and to have the Utilities Regulation and Competition Authority, another Bahamian regulator, regulate GBPC. The GBPA has opposed the legislated removal of its regulatory authority over GBPC, citing conflict with the Hawksbill Creek Agreement, the 1955 agreement with the Bahamian government that provided for the development and administration of the Freeport area. Management expects the matter of regulatory jurisdiction over GBPC to be the subject of legal proceedings, however, does not foresee that the legislation or the outcome of such proceedings will have a material impact to Emera.

Other

Canadian Tax Legislation Changes

On June 20, 2024, Bill C-59, an Act to implement certain provisions of the fall economic statement tabled in Parliament on November 21, 2023, and certain provisions of the budget tabled in Parliament on March 28, 2023, was enacted. Bill C-59 includes the EIFEL regime, which is effective January 1, 2024. EIFEL applies to limit a company’s net interest and financing expense deduction to no more than 30 per cent of EBITDA for tax purposes. Any denied interest and financing expenses under the EIFEL regime can be carried forward indefinitely. During 2024, the Company incurred $185 million of interest and financing expenses in connection with a specific financing structure. The interest and financing expenses related to the financing structure as well as $88 million of other interest and financing expenses are expected to be denied under the EIFEL regime. It was determined that the Company is more likely than not to realize the tax benefit of the denied interest and financing expenses in future periods and therefore a $79 million deferred income tax asset was recorded as at December 31, 2024.

USGAAP – Exemptive Relief

On January 28, 2021, the International Accounting Standards Board (“IASB”) published an Exposure Draft: Regulatory Assets and RegulatoryLiabilities, 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.

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Financing Activity

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, approximately 5.12 million common shares were issued under the ATM Program at an average price of $51.52 per share for gross proceeds of $264 million ($261 million, net of after-tax issuance costs) and an aggregate gross sales limit of $336 million remained available for issuance under the ATM Program.

During 2025, up to and including February 21, 2025, 187,600 common shares were issued under the ATM Program and an aggregate gross sales limit of $326 million remains available for issuance under the ATM Program.

Preferred Share Issuances

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 August 15, 2023.

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 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 on August 15, 2023.

On January 8, 2025, Emera announced it would not redeem the 8 million outstanding Series F First Preferred Shares. The holders of the Series F First Preferred Shares had the right, at their option, to convert all or any of their Series F First Preferred Shares, on a one-for-one basis, into Series G First Preferred Shares on February 15, 2025 or to continue to hold their Series F First Preferred Shares. On February 6, 2025, Emera announced after having taken into account all conversion notices received from holders, no

Emera Incorporated – 202 4 Annual Information Form	28

Series F First Preferred Shares would be converted into Series G First Preferred Shares on February 15, 2025.

Senior Notes

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.

Subordinated Notes

On June 18, 2024, EUSHI Finance, Inc., completed an issuance of $500 million USD fixed-to-fixed reset rate junior subordinated notes (the “Subordinated Notes”). The notes initially bear interest at a rate of 7.625 per cent, and will reset on December 15, 2029, and every five years thereafter, to a rate per annum equal to the five-year U.S. treasury rate plus 3.136 per cent. The notes mature on December 15, 2054. EUSHI Finance, Inc., at its option, may redeem the notes, in whole or in part, 90 days prior to the first interest reset date, and any semi-annual interest payment date thereafter, at a redemption price equal to the principal amount.

Proceeds from the $500 million USD note issuance discussed above were used to repay an Emera US Finance LP $300 million USD senior note upon maturity in June 2024, and to repay a New Mexico Gas Intermediate, Inc. $150 million USD fixed rate note upon maturity in July 2024. The remaining proceeds were used for general corporate purposes.

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 28, 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, 2024, 295,935,686 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.

Emera Incorporated – 202 4 Annual Information Form	29

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

On the liquidation, dissolution or winding-up of Emera, holders of common shares are entitled to participate rateably in any distribution of assets of Emera, subject to the rights of holders of first preferred shares and second preferred shares, if any, who are entitled to receive the assets of the Company on such a distribution in priority to the holders of the common shares.

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

Emera First Preferred Shares

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

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

The first preferred shares of each series are not redeemable at the option of their holders. For a summary of the terms and conditions of the Company’s authorized First Preferred Shares as of December 31, 2024, 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, 2024, 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

Emera Incorporated – 202 4 Annual Information Form	30

Board may require shareholders to furnish statutory declarations as to matters relevant to enforcement of the restrictions.

CREDIT RATINGS

Emera has the following credit ratings by the Rating Agencies:

	Moody’s	S&P	Fitch
Corporate	Baa3	BBB	BBB
Outlook	Negative	Stable ^(1)^	Negative
Senior unsecured debt program	Baa3	BBB-	BBB
Hybrid Notes	Ba2	BB+	BB+
First Preferred Shares	N/A	P-3 (high)	BB+
(1)	On January 22, 2025, S&P revised its outlook on Emera to stable from negative with no change to<br>existing ratings.
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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.

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Fitch

Fitch’s credit ratings are on a long-term debt scale that ranges from AAA to D, representing the range from highest to lowest quality of such rated securities. The rating of BBB obtained from Fitch in respect of the senior unsecured debt is the fourth highest of nine available rating categories and indicates that the issuer has adequate capacity to meet its financial commitments. The rating of BB from Fitch in respect of the Hybrid Notes is characterized as having elevated default risk however business or financial flexibility exists that support servicing the financial commitments. The BB rating from Fitch is the fifth highest of nine available ratings categories and the addition of either a “(+)” or a “(-)” designation after a rating indicates the relative standing within a particular category. In each case, however, adverse economic conditions or changing circumstances are more likely to lead to weakened capacity of the obligor to meet its financial commitments on the obligation.

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

For further information on the credit ratings of Emera and its subsidiaries, 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.

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 June 28, 2024 Emera adjusted its annual dividend growth rate to one to two per cent.

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 2024.

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
Common Shares^(1), (2), (3)^	2.8775	2.7875	$2.6775
Series A First Preferred Shares^(4)^	0.5456	0.5456	$0.5456
Series B First Preferred Shares	1.6966	1.5583	$0.6869
Series C First Preferred Shares^(5)^	1.6085	1.2873	$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)^	1.5810	1.3140	$1.2250
Series J First Preferred Shares^(8)^	1.0625	1.0625	$1.0625
Series L First Preferred Shares^(9)^	1.1500	1.1500	$1.1500

All values are in US Dollars.

(1)	On September 22, 2022, Emera approved an increase in the annual common share dividend rate from $2.65 to<br>$2.76. The first payment was effective November 15, 2022.
Emera Incorporated – 202 4 Annual Information Form	32
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(2)	On September 20, 2023, Emera approved an increase in the annual common share dividend rate from $2.76 to<br>$2.87. The first payment was effective November 15, 2023.
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(3)	On September 18, 2024, Emera approved an increase in the annual common share dividend rate from $2.87 to<br>$2.90. The first payment was effective November 15, 2024.
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(4)	The Series A First Preferred Shares annual dividend rate was reset from $0.6388 to $0.5456 for the five year<br>period commencing August 15, 2020 and ending on (and inclusive of) August 14, 2025.
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(5)	The Series C First Preferred Shares annual dividend rate was reset from $1.18024 to $1.60852 for the five year<br>period commencing August 15, 2023 and ending on (and inclusive of) August 14, 2028.
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(6)	The Series F First Preferred Shares annual dividend rate was reset from $1.0505 to $1.43724 for the five year<br>period commencing February 15, 2025 and ending on (and inclusive of) February 14, 2030.
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(7)	The Series H First Preferred Shares annual dividend rate was reset from $1.2250 to $1.5810 for the five year<br>period commencing August 15, 2023 and ending on (and inclusive of) August 14, 2028.
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(8)	The Series J First Preferred Shares with an annual dividend rate of $1.0625 (per share) were issued<br>April 6, 2021.
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(9)	The Series L First Preferred Shares with an annual dividend rate of $1.150 (per share) were issued<br>September 24, 2021.
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Pursuant to the Income Tax Act (Canada) and corresponding provincial legislation, all dividends paid on Emera’s common shares and first preferred shares qualify as eligible dividends.

MARKET FOR SECURITIES

Trading Price and Volume

Emera’s common shares, Series A First Preferred Shares, Series B First Preferred Shares, Series C First Preferred Shares, Series E First Preferred Shares, Series F First Preferred Shares, Series H First Preferred Shares, Series J First Preferred Shares and Series L First Preferred Shares are listed and posted for trading on the TSX under the symbols “EMA”, “EMA.PR.A”, “EMA.PR.B”, “EMA.PR.C”, “EMA.PR.E”, “EMA.PR.F”, “EMA.PR.H”, “EMA.PR.J” and “EMA.PR.L”, respectively. The Barbados DRs are listed on the BSE under the symbol EMABDR. The Bahamas DRs are listed on the BISX under the symbol EMAB. The trading volume and high and low price for Emera’s securities for each month of 2024 are set out In Appendix “C” of this AIF.

ATM Program

On November 18, 2024, Emera increased the size of the ATM Program to allow the Company to issue up to $1 billion 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 increased by an amendment dated November 18, 2024 to its prospectus supplement dated November 14, 2023 and an amendment dated November 13, 2024 to its 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. For more information on the ATM Program, refer to “General Development of the Business – Financing Activity – ATM Program” section above.

DIRECTORS AND OFFICERS

Directors

The following information is provided for each Director of Emera as at December 31, 2024:

Name, Residence, Principal Occupations During the Past Five Years	DirectorSince ^(2)^	Committees ^(3)^
M. Jacqueline Sheppard (Chair), Calgary, Alberta, Canada<br><br><br>Chair of the Board since May 2014.^(1)^Director of Suncor Energy Inc., a Canadian<br>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.^^Former Executive Vice President, Corporate and Legal of Talisman Energy Inc. Founder and former Lead Director of	2009	(4)
Emera Incorporated – 202 4 Annual Information Form	33
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Name, Residence, Principal Occupations During the Past Five Years	DirectorSince ^(2)^	Committees ^(3)^
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Black Swan Energy Inc., an Alberta upstream<br>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<br>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.
Scott C. Balfour, Halifax, Nova Scotia, Canada<br><br><br>A Director and President and Chief Executive Officer of Emera since March 2018. Mr. Balfour is a Director of many Emera<br>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<br>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<br>Ontario Energy Association.	2018	(5)
James V, Bertram Calgary, Alberta, Canada<br><br><br>Chair of the Board, Keyera Corporation. Formerly President, and Chief Executive Officer of Keyera from 1998 until 2015, when he<br>became Executive Chair. Director of Methanex Corporation, the world’s largest producer and supplier of methanol to major international markets.	2018	Chair of HSEC<br> <br>and Member of<br><br><br>MRCC
Henry E. Demone, Lunenburg, Nova Scotia, Canada<br><br><br>Former Chair of High Liner Foods, the leading North American processor and marketer of value-added frozen seafood. Mr. Demone<br>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. Former Director of Saputo Inc. from June<br>2012 to September 2024.	2014	Chair of MRCC<br> <br>and Member of<br><br><br>NCGC
Paula Y. Gold-Williams, San Antonio, Texas, U.S.<br><br><br>Former President and CEO of CPS Energy, a fully integrated electric and natural gas municipal utility based in San Antonio, Texas.<br>Currently serves as the Co-Chair of the Keystone Policy Center. Energy Pillar Co-Chair of Dentons’ Global Smart Cities & Communities Initiatives and Think<br>Tank. A Director of ReNew Energy Global Plc, a renewable energy company based in India. Member of the Nasdaq’s Center for Board Excellence.	2022	Member of AC<br> <br>and HSEC
Kent M. Harvey, New York, New York, U.S.<br><br><br>Former Chief Financial Officer for PG&E Corporation, an energy-based holding company, and the parent of Pacific Gas and Electric<br>Company, one of the largest combined natural gas and electric energy companies in the United States.	2017	Chair of AC and Member of HSEC
B. Lynn Loewen, FCPA, FCA, Montreal, Quebec,Canada<br> <br>Member of the Board of Directors of National Bank of Canada, a Canadian Chartered Bank, Chair of its Audit Committee<br>and member of its Risk Management and Technology Committees. Member of the Board of Directors of Kinaxis Inc., a Canadian company that has been revolutionizing supply chain management for more than three decades. She is a Member of Kinaxis’<br>Audit Committee. Chancellor of Mount Allison University, Chair of its Nominating and Governance Committee and a member of the Executive Committee since 2018. She is the former President of Minogue Medical Inc., a Canadian supplier of innovative<br>medical technologies, supplies and equipment Former member of the Board of Directors of Gildan Activewear Inc. a Canadian apparel manufacture, from April 2024 to May 2024 and former member of the Board of Directors of Xplore Inc., a Canadian<br>broadband service provider, and a member of its Audit Committee from 2021 to 2023.	2013	Member of AC, HSEC and RSC
Brian J. Porter, Toronto, Ontario, Canada<br><br><br>Former President and CEO of The Bank of Nova Scotia, operating as Scotiabank, a global bank operating in Canada and the Americas,<br>from November 2013 until his	2024^(6)^	Member of AC and RSC
Emera Incorporated – 202 4 Annual Information Form	34
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Name, Residence, Principal Occupations During the Past Five Years	DirectorSince ^(2)^	Committees ^(3)^
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retirement in January 2023. Chair of the<br>Board of Governors of Huron University College at Western University, Chair of the Building Ontario Fund and Chair of the Atlantic Salmon Federation (Canada). Director of Fairfax Financial Holdings Ltd. Previously served as Chair of the University<br>Health Network Board of Trustees.
Ian E. Robertson, Oakville, Ontario,Canada<br> <br>A principal of the Northern Genesis Capital Group, an investment group focused on identifying and investing in energy<br>transition businesses. 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<br>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<br> <br>and RSC
Karen H. Sheriff, Picton, Ontario,Canada<br> <br>Ms. Sheriff is past President and CEO of Q9 Networks Inc., and prior to that, President and CEO of Bell Aliant,<br>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 is a former member of the Board of Directors of CPP Investments and WestJet Airlines<br>Ltd.	2021	Chair of NCGC<br> <br>and Member of MRCC and RSC
Jochen E. Tilk, Toronto, Ontario,Canada<br> <br>Former Executive Chair of Nutrien Ltd., a Canadian global supplier of agricultural products and services based in<br>Saskatoon, Saskatchewan. Former President and Chief Executive Officer of Potash Corporation of Saskatchewan. Mr. Tilk is Chair of the Board of AngloGold Ashanti Limited, a publicly listed international gold mining company, based in London, U.K.<br>He is also Chair of the Princess Margaret Cancer Foundation, a not-for-profit organization.	2018	Chair of RSC<br> <br>and Member of MRCC and NCGC
Carla M. Tully, Arlington, Virginia,U.S.<br> <br>Former Chief Executive Officer and Co-Founder of Earthrise Energy, PBC, an<br>energy transition company. Currently, serves on the boards of the Nikola Corporation, Pattern Energy and the Citizens for Responsible Energy Solutions Forum. She is also a Senior Advisor for the Canadian Pension Plan Investment Board (CPPIB) and an<br>advisor to several energy transition startups.	2024^(7)^	Member of<br> <br>NCGC and AC
(1)	It was announced by the Company on November 14, 2024 that Karen Sheriff would succeed Jackie Sheppard as<br>next chair of Board of Directors, effective February 21, 2025.
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(2)	Denotes the year the individual became a Director of Emera. Directors are elected for a one year term which<br>expires at the termination of Emera’s annual general meeting.
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(3)	Board Committees as of December 31, 2024: Audit Committee (AC), Health, Safety and Environment Committee<br>(HSEC), Management Resources and Compensation Committee (MRCC), Nominating and Corporate Governance Committee (NCGC), and Risk and Sustainability Committee (RSC).
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(4)	Ms. Sheppard is not a member of any committee but attends all committee meetings as Chair of the Board.<br>
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(5)	Mr. Balfour is not a member of any committee as he is the President and Chief Executive Officer of the<br>Company but attends all committee meetings.
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(6)	Effective March 6, 2024, Brian J. Porter became a Director of Emera.
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(7)	Effective June 26, 2024, Carla M. Tully became a Director of Emera.
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Emera Incorporated – 202 4 Annual Information Form	35
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Officers

The Officers of Emera as at December 31, 2024 were as follows:

Name and Residence	Principal Occupations During the Past Five Years
Scott C. Balfour<br><br><br>President and Chief Executive Officer<br> <br>Halifax, Nova Scotia, Canada	A Director and **** President and Chief Executive Officer of Emera since March 2018.^(1)^
Gregory W. Blunden, FCPA<br><br><br>Chief Financial Officer<br> <br>Halifax, Nova Scotia, Canada	Chief Financial Officer of Emera since March 2016.
Archibald Collins<br><br><br>President and Chief Executive Officer,<br> <br>Tampa Electric Company ^(2)^<br> <br>Tampa, Florida, U.S.	President and CEO of Tampa Electric since May 2021. Prior to this, has served as President and Chief Operating Officer of Emera Caribbean, President and<br>CEO of Grand Bahama Power, Executive Vice President Commercial Operations with Emera Energy, and Chief Operating Officer of Tampa Electric.
Karen E. Hutt<br><br><br>Executive Vice-President,<br> <br>Business Development and Strategy<br><br><br>Halifax, Nova Scotia, Canada	Executive Vice-President, Business Development and Strategy of Emera since October 2019. Previously, President and Chief Executive Officer of NSPI since<br>August 2016.
R. Michael Roberts<br><br><br>Chief Human Resources Officer<br> <br>Halifax, Nova Scotia, Canada	Chief Human Resources Officer of Emera and NSPI since December 2014. Director of EBPC since March 2024.
Daniel P. Muldoon<br><br><br>Executive Vice-President Project<br> <br>Development and Operations Support<br><br><br>Halifax, Nova Scotia, Canada	Executive Vice-President Project Development and Operations Support of Emera. Chair of the Boards of EBPC, Emera Technologies LLC and NMGC and Block<br>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<br><br><br>Executive Vice-President and General Counsel<br> <br>Halifax, Nova Scotia, Canada	Executive Vice-President and General Counsel of Emera since July 2022. Prior to this, General Counsel of Emera since November 2017. Prior to joining<br>Emera, Senior Partner and head of the power and climate change practice groups at Bennett Jones LLP in Toronto.
Brian C. Curry<br><br><br>Corporate Secretary<br> <br>Halifax, Nova Scotia, Canada	Corporate Secretary of Emera since November 2023 and prior to that Associate Corporate Secretary, Emera. Former Senior Director Regulatory and Corporate<br>Secretary, NSPI from February 2021 to February 2023, Senior Regulatory Counsel and Corporate Secretary, NSPI from January 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<br>table.
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(2)	Mr. Collins is included in Emera’s list of Officers in his capacity as the President and CEO of Tampa<br>Electric Company, which comprises the Florida Electric Utility segment, a principal business unit of Emera.
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As at December 31, 2024, the Directors and Officers, in total, beneficially owned or controlled, directly or indirectly, 239,479 common shares or less than 1 per cent of the issued and outstanding common shares of Emera.

Emera Incorporated – 202 4 Annual Information Form	36

AUDIT COMMITTEE

The Audit Committee of Emera is composed of the following six members, all of whom are independent Directors: Kent M. Harvey (Chair), Paula Gold-Williams, B. Lynn Loewen, Brian J. Porter, Ian E. Robertson and Carla M. Tully. 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. She was Co-Chair of the Keystone Policy Center, having been a member of both the Policy Center and its Energy Board since 2016. She serves as an Energy Pillar Co-Chair of Dentons’ Global Smart Cities & Communities Initiatives and Think Tank. She is also a member of the board of directors of ReNew Energy Global Plc, a renewable energy company based in India. She is also a member of the Nasdaq’s Center for Board Excellence, a community of like-minded board members, leaders, and innovators committed to advancing corporate governance best practices and effectiveness. Previously, Ms. Gold-Williams held other board positions, including serving on the United States’ Secretary of Energy’s Advisory Board; being a 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, President of Expertech Network Installation Inc., a Canadian network infrastructure service provider. Ms. Loewen also held key positions with Bell Canada Enterprises, as Vice President of Finance Operations from 2005 to 2008, and as Vice President of Financial Controls from 2003 to 2005. Earlier in her career, she was with Air Canada Jazz where she held positions of increasing responsibility, including Chief Financial Officer and Vice President of Corporate Services. Ms. Loewen is a member of the Board of Directors of National Bank of Canada, serving as Chair of the Audit Committee and as a member of the Risk Management and Technology Committees. She is also a member of the Board of Directors of Kinaxis Inc., a Canadian company that has been revolutionizing supply chain management for more than three decades. She serves on Kinaxis’ Audit Committee. Chancellor of Mount

Emera Incorporated – 202 4 Annual Information Form	37

Allison University, Chair of its Nominating and Governance Committee and a member of its Executive Committee since 2018. A member of its Board of Regents from 1998 to 2008, serving as Chair from 2007–2008. Ms. Loewen was a member of the Board of Directors of Gildan Activewear Inc., a Canadian apparel manufacturer from April 2024 to May 2024. 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 from 2001 to 2007, where she served on the Audit and Conflicts Committee from 2003 to 2007 and as Audit and Conflicts Committee Chair from 2006 to 2007. She was also Chair of its Governance Committee from 2003 to 2006. She holds a Bachelor of Commerce from Mount Allison University. Fellow of the Chartered Professional Accountants and has received the Directors Designation from the Institute of Corporate Directors.

Brian J. Porter

He joined the Emera Board on March 6, 2024. Mr. Porter was the President and CEO of The Bank of Nova Scotia, operating as Scotiabank, a global bank operating in Canada and the Americas, from November 2013 until his retirement in January 2023. Mr. Porter is Chair of the Board of Governors of Huron University College, Chair of the Building Ontario Fund and Chair of the Atlantic Salmon Federation (Canada). He is a Director of Fairfax Financial Holdings Ltd. He previously served as Chair of the University Health Network Board of Trustees. Mr. Porter received a Bachelor of Commerce from Dalhousie University, and was awarded an Honorary Doctor of Laws from Dalhousie University in 2008 and from Ryerson University in 2018. He is a graduate of the Advanced Management Program of the Harvard Business School. Mr. Porter has extensive experience in banking and capital markets and led one of Canada’s largest chartered banks through a period of significant growth and expansion.

Ian E. Robertson

He is a principal of the Northern Genesis Capital Group, an investment group focused on identifying and investing in energy transition businesses. 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., and 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.

Carla M. Tully

She joined the Emera Board of Directors in June 2024. She is the former Chief Executive Officer and Co-Founder of Earthrise Energy, PBC, an energy transition company she co-developed from concept and grew to a successful 1.7 gigawatts (GW) independent power producer, with an additional 2.0 GW of renewable energy under development. She previously served as Executive Vice President and Managing Director of Renewable Energy at MAP Energy, a $2.4 billion energy investment firm where she scaled the company’s renewable energy development business and raised its first all-renewable energy fund. At The AES Corporation, a global Fortune 500 utility and energy generation company, Ms. Tully held key senior leadership roles, including President of AES UK and Ireland. Currently, Ms. Tully serves on the boards of the Nikola Corporation, Pattern Energy and the Citizens for Responsible Energy Solutions Forum. She is also a Senior Advisor for the Canadian Pension Plan Investment Board (CPPIB) and an advisor to several energy transition startups. She holds a Master of Business Administration from Columbia Business School,

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a Master of Arts in Law and Diplomacy from the Fletcher School at Tufts University, and a bachelor’s degree in international relations and economics from the University of Southern California.

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.

Auditors’ Fees

The aggregate fees billed by Ernst & Young LLP, the Company’s external auditors, during the fiscal years ended December 31, 2024 and 2023 respectively, were as follows:

Service Fee	2024 ()
Audit Fees
Audit-Related Fees ^(1)^
Tax Fees ^(2)^
All Other Fees
Total

All values are in US Dollars.

(1)	Audit-related fees for Emera relate to fees associated with agreed upon procedures over rate-case filings and<br>the audit of pension plans.
(2)	Tax fees for Emera relate to tax compliance services and general tax consulting advice on various matters.<br>
---	---

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<br>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,<br>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<br>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)	with the exception of Ms. Tully as set forth below, are, as at the date of this AIF, or have been within ten<br>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<br>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<br>relating to bankruptcy or insolvency, or become subject to or instituted any
---	---
Emera Incorporated – 202 4 Annual Information Form	39
---	---
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<br>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<br>investor making an investment decision.
---	---

As of the date of this AIF, Carla M. Tully is a director of Nikola Corporation (“Nikola”). On February 19, 2025, Nikola announced that it and certain of its subsidiaries had filed voluntary petitions under Chapter 11 of the Bankruptcy Code in the United States Bankruptcy Court for the District of Delaware and that Nikola had also filed a motion seeking authorization to pursue an auction and sale process under Section 363 of the U.S. Bankruptcy Code.

CONFLICTS OFINTEREST

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

LEGAL PROCEEDINGS AND REGULATORY ACTIONS

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

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

NO INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

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

MATERIAL CONTRACTS

Emera did not enter into any material contracts outside the ordinary course of business during the year ended December 31, 2024, nor has it entered into any material contracts outside the ordinary course of business prior to the year ended December 31, 2024 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.

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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 under Emera’s profile 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.

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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 InformationForm” means this 2024 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, 2024 and December 31, 2023, 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;

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“EfficiencyOne” mean a federally incorporated not-for-profit third-party entity that currently holds the franchise for the provision of energy efficiency and conservation in the Province, which is deemed to be a utility under the Public Utilities Act and regulated by the UARB.

“EIFEL” means excessive interest and financing expenses limitation;

“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;

“Emera US Finance LP” means a wholly owned indirect financing limited partnership of Emera, formed under the laws of the State of Delaware;

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

“EUSHI Finance, Inc.” means a wholly owned indirect financing subsidiary of Emera, incorporated under the laws of the State of Delaware;

“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 BondYield” 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;

“GHG” means greenhouse gas;

“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);

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“Labrador-Island Transmission Link Project” or “LIL” means an electricity transmission project in Newfoundland and Labrador developed by NLH (formerly, Nalcor Energy), which enables the transmission of the Muskrat Falls energy between Labrador and the island of Newfoundland;

“LNG” means liquefied natural gas;

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

“MaritimeLink” 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, 2024, 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;

“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;

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

“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;

“NSEB” means Nova Scotia Energy Board;

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

“NSPI” or “NovaScotia 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;

“O&M expenses” means operations and maintenance expenses;

“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;

“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 indirect subsidiary of Emera 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

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provincial government of Nova Scotia, and “provincial” refers to Nova Scotia;

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

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

“RENAC” means Repsol Energy North America Canada Partnership;

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

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

“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 indirect subsidiary of Emera;

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

“SEDAR+” means the System for Electronic Document Analysis and Retrieval+ of the Canadian Securities Administrators, at www.sedarplus.ca;

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

“Series A First PreferredShares” 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;

“SO 2” means sulphur dioxide;

“SoBRA” means solar base rate adjustment;

“ Subordinated Notes ” means the $500 million USD 7.625% Fixed-to-Fixed Reset Rate Junior Subordinated Notes due 2054;

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

“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.

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APPENDIX “B” – Summary of Terms and Conditions of Authorized Series ofFirst

Preferred Shares

As of December 31, 2024, the following series of First Preferred Shares have been authorized:

Series A, B, C, D, E, F, G, H, I, J, K and L FirstPreferred 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 – 202 4 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 are 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 FirstPreferred Shares	Initial Redemption /Interest Reset Date	Subsequent Redemption /Conversion / Interest<br> <br>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, 2024, 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 – 202 4 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 – 202 4 Annual Information Form	48

APPENDIX “C” - MONTHLY TRADING VOLUME AND HIGH AND LOW PRICE FOR

EMERA’S SECURITIES IN 2024


		BarbadosBBD^(1)^		Bahamas<br> <br>BSD ^(2)^		A		B		C		E		F		H		J		L
December
High ()	56.20		20.06		8.52		16.85		16.94		23.56		19.00		21.43		24.50		22.74		19.19
Low ()	52.71		18.41		8.52		16.00		16.01		22.66		18.31		19.95		23.17		21.80		18.34
Volume	23,295,397		82		15,247		45,696		24,662		74,824		41,102		90,137		143,287		185,594		138,818
November
High ()	53.75		20.00		9.43		16.00		16.99		23.01		18.78		20.37		23.47		22.28		18.85
Low ()	49.46		17.57		9.43		15.26		16.55		21.87		18.01		19.28		22.55		20.65		18.58
Volume	32,478,281		54		953		101,485		51,304		169,123		35,600		205,903		387,791		56,328		60,962
October
High ()	54.19		23.00		9.79		16.52		17.19		23.00		19.40		19.91		23.71		21.45		19.53
Low ()	49.06		17.93		8.98		15.03		16.02		22.30		18.69		19.06		23.15		20.95		18.66
Volume	34,184,085		1,280		0		66,359		22,322		115,923		38,135		300,184		97,443		110,039		140,356
September
High ()	53.83		23.00		9.50		15.40		17.00		22.94		19.46		19.59		23.75		21.60		19.60
Low ()	50.64		18.56		9.50		14.95		15.25		22.04		18.95		18.93		22.81		20.95		19.05
Volume	21,527,984		32		913		92,918		28,520		143,633		28,147		31,230		148,702		65,786		82,297
August
High ()	50.91		23.00		9.06		15.26		16.88		22.92		19.07		19.39		23.90		22.15		19.38
Low ()	48.53		17.43		9.06		14.40		16.40		21.52		18.35		18.07		23.05		19.92		18.70
Volume	26,567,189		25		365		28,208		10,062		160,812		31,014		262,878		182,558		89,727		31,289
July
High ()	50.56		18.31		8.55		15.75		17.75		22.43		18.60		19.39		24.01		22.80		19.00
Low ()	44.13		16.11		8.55		15.00		16.49		21.55		17.37		18.57		23.00		20.30		17.79
Volume	29,603,191		0		1,826		20,749		35,993		169,967		62,491		147,804		243,084		133,891		73,003
June
High ()	48.19		23.00		8.80		15.35		17.10		21.80		17.70		19.93		23.24		21.14		18.01
Low ()	44.40		16.06		8.10		14.24		16.25		20.23		17.06		17.53		21.85		20.01		17.26
Volume	20,606,470		5		0		49,361		64,972		144,182		43,696		169,210		118,740		93,825		95,191
May
High ()	50.69		23.00		9.29		15.50		17.40		21.77		17.84		19.80		23.30		21.49		18.10
Low ()	46.07		16.75		8.37		14.85		16.76		21.20		16.81		18.55		21.00		20.27		17.32
Volume	28,099,615		35		0		356,028		52,925		504,710		17,355		202,799		108,480		82,250		31,871
April
High ()	47.99		23.00		8.52		15.11		17.74		21.74		17.44		18.85		22.46		20.49		17.95
Low ()	45.56		16.62		8.24		14.37		16.38		21.00		16.75		18.51		20.90		19.94		16.96
Volume	37,216,196		49		6,106		174,528		42,988		78,041		32,482		339,208		191,149		49,423		160,921
March
High ()	49.14		23.00		9.12		14.60		16.44		21.55		17.65		18.89		22.27		20.32		17.98
Low ()	47.04		17.12		8.66		14.15		16.05		20.90		16.89		18.22		21.15		19.26		17.30
Volume	16,223,256		16		0		90,523		14,951		62,190		18,200		54,278		55,243		97,184		33,448
February
High ()	48.83		18.09		9.60		14.55		17.08		22.00		17.96		19.39		22.49		21.32		17.82
Low ()	46.23		17.05		9.60		13.97		16.25		20.99		17.10		18.40		21.24		20.02		17.21
Volume	23,857,187		0		150		10,410		14,510		59,971		35,530		166,299		54,054		55,580		56,528
January
High ()	51.81		23.00		9.68		15.18		17.00		22.00		17.98		19.90		22.49		21.02		17.95
Low ()	47.41		17.63		8.85		13.49		15.00		20.25		16.79		17.09		21.40		18.00		16.95
Volume	25,400,512		235		0		220,670		45,357		108,412		40,908		319,541		119,158		92,010		124,913

All values are in US Dollars.

(1)	The Barbados DRs trade on the BSE. During those months in 2024 when the Volume Traded was zero (0), the table<br>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 2024 when the Volume Traded was zero (0), the table<br>above indicates the high and low trading prices of the Bahamas DRs relative to those of Emera’s common shares on the TSX.
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Emera Incorporated – 202 4 Annual Information Form	49
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February 2025
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APPENDIX “D” - EMERA INCORPORATED AUDIT COMMITTEE CHARTER

PART I

MANDATE ANDRESPONSIBILITIES

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 financialstatements and financial reporting; and
---	---
-	any other duties set out in this Charter or delegated to the Committee by the Board.
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1.	Financial Reporting
---	---
(a)	The Committee shall be responsible for reviewing, assessing the completeness and clarity of the disclosures in,<br>and recommending to the Board for approval:
---	---
(i)	the audited annual financial statements of Emera, all related Management’s Discussion and Analysis, and<br>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<br>releases.
---	---
(b)	The Board may delegate the approval of the quarterly financial statements, all related Management’s<br>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<br>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<br>preparing or issuing the auditor’s report or performing other audit, review, or attest services for Emera, and the compensation of such external auditors.
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(b)	Once appointed, the external auditor shall report directly to the Committee, and the Committee shall oversee<br>the work of the external auditor concerning the preparation or
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Emera Incorporated – 202 4 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<br>concerning financial reporting.
---	---
(d)	At least annually, the Committee shall obtain and review a report by the external auditors describing:<br>(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<br>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<br>the auditors’ independence).
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(e)	The Committee shall annually evaluate the auditors’, including the lead audit partner’s,<br>qualifications, performance, professional skepticism and independence.
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(f)	The Committee shall determine that the external audit firm has a process in place to address the rotation of<br>the lead audit partner and other audit partners serving the account as required under prescribed independence rules.
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(g)	Every five (5) years, the Committee shall perform a comprehensive review of the performance of the<br>external auditors over multiple years to provide further insight on the audit firm, its independence and application of professional standards.
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(h)	The Committee will review differences that were noted or proposed by the external auditors, but that were<br>considered immaterial or insignificant; and any “management” or “internal control” letter issued, or proposed to be issued.
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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<br>regulation, the Committee may delegate the pre-approval of non-audit services to a member of the Committee or a sub-committee<br>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<br>the audit, including the general approach, scope, areas subject to significant risk of material misstatement, estimated fees and other terms of engagement.
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Emera Incorporated – 202 4 Annual Information Form	51
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(b)	The Committee shall discuss with the external auditor any issues that arise with Management or the internal<br>auditors during the course of the audit and the adequacy of Management’s responses in addressing audit-related deficiencies.
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(c)	The Committee shall regularly review with the external auditors any audit problems or difficulties encountered<br>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<br>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<br>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<br>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<br>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;
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(c)	disagreements between Management and the external auditor or the internal auditors regarding the application of<br>any accounting principles or practices;
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(d)	any material change to Emera’s auditing and accounting principles and practices as recommended by<br>Management, the external auditor or the internal auditors or which may result from proposed changes to applicable generally accepted accounting principles;
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(e)	the effect of regulatory and accounting initiatives on Emera’s financial statements and other financial<br>disclosures;
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(f)	any reserves, accruals, provisions, estimates or Management programs and policies, including factors that<br>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;
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(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;
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Emera Incorporated – 202 4 Annual Information Form	52
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(h)	any legal matter, claim or contingency that could have a significant impact on the financial statements,<br>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<br>financial statements;
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(i)	the treatment for financial reporting purposes of any significant transactions which are not a normal part of<br>Emera’s operations.
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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<br>process of Emera, including the Chief Financial Officer.
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(b)	The Committee may request for review, and shall receive when requested, material tax policies and tax planning<br>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.
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(c)	The Committee shall meet at least annually with Management to review and discuss Emera’s major financial<br>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.
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(d)	The Committee may review any investments or transactions that the Committee wishes to review, or which the<br>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<br>recommendations concerning such subsidiaries.
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(f)	The Committee may request for review, and shall receive when requested, all related party transactions required<br>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.
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Emera Incorporated – 202 4 Annual Information Form	53
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9.	Internal Controls
---	---

The Committee shall oversee:

(a)	the adequacy and effectiveness of the Company’s internal accounting and financial controls and the<br>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.<br>
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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<br>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<br>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,<br>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.
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(e)	Discuss with Emera’s Chief Legal Officer at least annually any legal matters that may have a material<br>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.
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10.	Internal Auditor
---	---
(a)	The lead internal auditor shall report directly to the Committee. The Committee shall approve the appointment,<br>removal and replacement of the lead internal auditor. The Committee shall approve the remuneration of the lead internal auditor on appointment.
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(b)	The Committee shall review and approve the internal audit plan, including activities, organizational structure,<br>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<br>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,<br>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.
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Emera Incorporated – 202 4 Annual Information Form	54
---	---
(d)	The Committee shall obtain from the internal auditor and review summaries of the significant reports to<br>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<br>accounts.
---	---
(f)	The Committee may communicate with the internal auditor with respect to their reports and recommendations, the<br>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 annually, approve the internal audit charter. The internal auditor shall confirm<br>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, at least annually, review the independence of the internal audit function and shall make<br>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<br>independent assessor or assessment team, of the internal audit function in conformance with Global Internal Audit 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<br>non-compliance with legal and regulatory requirements;
(b)	Annually receive and review a report on executive officers’ compliance with the Company’s Code of<br>Conduct;
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(c)	Annually provide feedback on the performance of the Chief Financial Officer;
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Emera Incorporated – 202 4 Annual Information Form	55
---	---
(d)	Review actions taken by the Company to identify and manage risks related to the Audit Committee mandate,<br>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<br>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<br>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.<br>
---	---
(b)	The Board shall appoint members to the Committee who are financially literate, as required by applicable<br>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<br>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<br>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<br>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<br>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<br>members of the Committee promptly following their election.
---	---
Emera Incorporated – 202 4 Annual Information Form	56
---	---
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<br>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,<br>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<br>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<br>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<br>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 – 202 4 Annual Information Form	58

EX-99.2

exhibit992p1i0

Exhibit 99.2

Management’s Discussion & Analysis

As at February 21, 2025

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, 2024 relative to the same periods in 2023

and selected financial information for 2022; and its financial position as at December 31, 2024 relative to

December 31, 2023. 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, 2024.

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, 2024, Emera’s rate-regulated subsidiaries and investments

include:

Rate-Regulated Subsidiary or Equity Investment

Accounting Policies Approved/Examined By

Subsidiary

Tampa Electric Company (“TEC”)

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”)

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

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

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.

TABLE

OF CONTENTS

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

Introduction and Strategic Overview………….……

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

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

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

Consolidated Financial Highlights………………

Consolidated Income Statement Highlights……

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

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

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

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

Other Electric Utilities ……………………………

Other……………………………………………….

Consolidated Balance Sheet Highlights…………..

Other Developments…………………………………

Financial Highlights……………………………..…..

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

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

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

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

Other…………………………………………….….

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

Consolidated Cash Flow Highlights…..…………

Working Capital……………………………………

Contractual Obligations…………………………..

Forecasted Consolidated Capital Investments…

Debt Management………………………………..

Credit Ratings……………………………………..

Guaranteed Debt………………………………….

Outstanding Stock Data………………………….

Pension Funding……………………………………..

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

Dividend Payout Ratio……………………………….

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

Enterprise Risk and Risk Management……………

Risk Management including Financial

Instruments…………………………………………

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

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

Changes in Accounting Policies and Practices…...

Future Accounting Pronouncements……………

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

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,

the expected timing and outcome of the pending sale of NMGC, 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.

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; change in law risk; operating and maintenance risks; changes in economic conditions;

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

dividend growth, rate base growth, and adjusted earnings per common share (“EPS”) 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;

climate change risk; 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

Emera (TSX: EMA) is a North American provider of energy services, owning and operating a portfolio of

cost-of-service, rate-regulated electric and gas utilities. Its largest operations are in Florida, with additional

operations in Atlantic Canada, New Mexico, and the Caribbean. Emera is headquartered in Halifax, Nova

Scotia.

Emera’s business strategy is centered on continued investment in its regulated utilities, combined with a

focus on operational excellence and efficiency, to safely and reliably deliver energy to its 2.6 million

customers. Effective execution of these priorities supports predictable and growing earnings, cash flow

and dividends for shareholders.

Earnings opportunities in regulated utilities are a function of the magnitude of net investment in the utility

(known as “rate base”), the amount of equity in the capital structure, and the targeted return on that equity

(“ROE”), all as established and approved through regulation. Earnings are also affected by sales volumes

and operating expenses. In 2024, Emera’s regulated cost-of-service utilities in Florida accounted for 65

per cent of average consolidated rate base, with Atlantic Canada comprising 27 per cent, and the

Caribbean and New Mexico at 4 per cent each.

Emera’s capital investment plan is forecasted to be approximately $20 billion from 2025 through 2029 and

is focused on delivering value for customers through prudent investments in reliability and system

resiliency, infrastructure modernization,

expansion to address customer growth, integration of

renewables, and technological innovations to deliver better customer experiences. It is anticipated that

approximately 80 per cent of this capital investment will be made in Emera’s Florida utilities, necessitated

by customer growth and system requirements at both TEC and PGS.

As at

millions of dollars

2025

2026

2027

2028

2029

Total

Capital investment plan

3,420

3,990

4,050

4,380

4,590

20,430

Average consolidated rate base

US operations

21,520

23,340

25,140

27,050

29,400

Canadian operations

7,630

8,000

8,370

8,590

8,870

Total

29,150

31,340

33,510

35,640

38,270

*Capital investment plan and average consolidated rate base exclude NMGC. Refer to “Other Developments” for more information

on the pending sale of NMGC

Emera’s capital investment plan will be funded primarily through internally generated cash flows, debt

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

the anticipated sale of NMGC. Generally, Emera’s equity requirements 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 its at-the-market program (“ATM program”). Maintaining investment-grade

credit ratings is a core strategic priority of the Company.

Emera has increased dividends per common share paid for 18 consecutive years and has provided

forward annual dividend growth guidance of one to two per cent. Emera’s anticipates adjusted EPS

average growth of five to seven per cent through 2027 which will support reduction in the ratio of dividend

payout to adjusted net income. For further information on the non-GAAP ratios “Adjusted EPS” and

“Dividend Payout Ratio of Adjusted Net Income”, refer to the “Non-GAAP Financial Measures and Ratios”

section.

NON-GAAP FINANCIAL MEASURES AND RATIOS

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

are calculated by adjusting certain GAAP measures for specific items. They may not be comparable to

similar measures presented by other entities. These measures and ratios are discussed and reconciled

below.

Adjusted Net Income, Adjusted 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 items below from net income attributable to common shareholders. Management

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

investors to better understand and evaluate the business.

Emera calculates adjusted net income for the Florida Electric Utility, Canadian Electric Utilities, Gas

Utilities and Infrastructure, Other Electric Utilities, and Other segments. Reconciliation to the nearest

GAAP measure is included in each segment. For more information refer to the Financial Highlights

section for each of Florida Electric Utility, Gas Utilities and Infrastructure, Other Electric Utilities, and

Other.

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, refer to the “Dividend Payout Ratio” section.

Adjusting item impacting all periods:

Mark-to-market (“MTM”) Adjustments:

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.

Adjusting items impacting 2024:

Gain on Sale of Emera’s Indirect Minority Interest in the LIL (“Gain on sale of LIL”):

In Q2 2024, Emera recognized a $107 million gain, after tax and transaction costs, on the sale of LIL. In

Q4 2024, Emera recognized a $22 million tax benefit related to the reversal of a prior year valuation

allowance. A portion of the taxable capital gain on sale of LIL was offset by prior year loss carryforwards,

of which the tax benefit was subject to a valuation allowance as at December 31, 2023.

For further

details refer to the “Significant Items Affecting Earnings” and “Other Developments” sections.

Financing Structure Wind-Up:

In Q4 2024, Emera recognized a $58 million tax benefit related to denied interest and financing expenses

and the wind-up of a specific financing structure. For further details refer to the “Significant Items Affecting

Earnings” and “Other Developments” sections.

Charges Related to Wind-Down Costs and Certain Asset Impairments:

In Q4 2024, the Company recognized $26 million, after-tax, in wind-down costs and certain asset

impairments, primarily at Block Energy LLC (“Block Energy”). For further details, refer to the “Significant

Items Affecting Earnings” section.

Charges Related to the Pending Sale of NMGC:

On August 5, 2024, Emera entered into an agreement to sell NMGC. In Q3 2024, the Company

recognized $206 million in non-cash goodwill and other impairment charges, after-tax, and an additional

loss of $19 million in estimated transaction costs, after-tax, related to the pending sale. For further details,

refer to the “Significant Items Affecting Earnings” and “Other Developments” sections.

Adjusting items impacting 2022:

GBPC Impairment Charge:

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.

NSPML Unrecoverable Costs:

In Q1 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.

Reconciliation of Net Income Attributable to Common Shareholders to Adjusted Net Income:

Three months ended

Year ended

For the

December 31

millions of dollars (except per share amounts)

2024

2023

2024

2023

2022

Net income attributable to common shareholders

154

289

494

978

945

Gain on sale of LIL, after-tax

(1)

129

Financing structure wind-up

Charges related to wind-down costs and certain asset

impairments, after-tax

(2)

(26)

Charges related to the pending sale of NMGC, after-tax

(3)(4)

(225)

MTM (loss) gain, after-tax

(5)

(146)

114

(291)

169

175

GBPC impairment charge

(73)

NSPML unrecoverable costs

(7)

Adjusted net income

246

175

849

809

850

EPS – basic

0.52

1.04

1.71

3.57

3.56

Adjusted EPS – basic

0.84

0.63

2.94

2.96

3.20

(1) Includes an income tax recovery of $22 million for the three months ended December 31, 2024 and net of income tax

expense of

$53 million for the year ended December 31, 2024 (2023 – nil).

(2) Net of income tax recovery of $6 million for the three months and year ended December 31, 2024 (2023 – nil).

(3) Represents (i) $206 million in non-cash goodwill and other impairment charges, after-tax and (ii) $19 million

in transaction costs,

after-tax for the year ended December 31, 2024 (2023 – nil).

(4) Net of income tax recovery of $21 million for the year ended December 31, 2024 (2023 – nil).

(5) Net of income tax recovery of $57 million for the three months ended December 31, 2024 (2023 – $44 million

expense) and $117

million recovery for the year ended December 31, 2024 (2023 – $68 million expense) (2022 – $73 million expense).

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.

Adjusted EBITDA represents EBITDA excluding the income effect of the gain on sale of LIL, charges

related to wind-down costs and certain asset impairments, charges related to the pending sale of NMGC,

MTM adjustments, the 2022 GBPC impairment charge, and the 2022 NSPML unrecoverable costs.

Reconciliation of Net Income to EBITDA and Adjusted EBITDA:

Three months ended

Year ended

For the

December 31

millions of dollars

2024

2023

2024

2023

2022

Net income

(1)

173

307

568

1,045

1,009

Interest expense, net

248

241

973

925

709

Income tax (recovery) expense

(199)

(159)

128

185

Depreciation and amortization

296

264

1,162

1,049

952

EBITDA

518

863

2,544

3,147

2,855

Gain on sale of LIL, excluding income tax

182

Charges related to wind-down costs and certain asset

impairments, excluding income tax

(32)

Charges related to the pending sale of NMGC,

excluding income tax

(246)

MTM (loss) gain, excluding income tax

(203)

158

(408)

237

248

GBPC impairment charge

(73)

NSPML unrecoverable costs

(7)

Adjusted EBITDA

753

705

3,048

2,910

2,687

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

CONSOLIDATED

FINANCIAL REVIEW

Significant Items Affecting Earnings

The items detailed below have had a significant impact on Net Income Attributable to Common

Shareholders but have been excluded from Adjusted Net Income as described in the section entitled

“Non-GAAP Financial Measures and Ratios”.

Financing Structure Wind-Up

During 2024, the Company incurred $185 million of interest and financing expenses in connection with a

specific financing structure. The current and future interest and financing expenses are expected to be

denied under the recently enacted Excessive Interest and Financing Expenses Limitation (“EIFEL”)

legislation and, as a result, the financing structure has been wound up. It was determined that Emera is

more likely than not to realize the benefit of the current denied interest and financing expenses in future

periods and therefore a $54 million deferred income tax asset and related income tax benefit ($0.19 per

common share) was recorded during Q4 2024. In addition, Emera recognized a $4 million income tax

benefit ($0.01 per common share) related to the reversal of a deferred income tax liability on the wind-up

of the financing structure. The total tax benefit of $58 million was recorded in “Income Tax (Recovery)

Expense” on the Consolidated Statements of Income and included in the Other segment. For further

details on the EIFEL legislation, refer to the “Other Developments” section.

Charges Related to Wind-Down Costs and Certain Asset Impairments

In Q4 2024, Emera recognized $32 million ($26 million after-tax, or $0.09 per common share) in wind-

down costs and certain asset impairments, primarily at Block Energy. These were recorded in “Other

Income, net” and “Impairment Charges” on the Consolidated Statements of Income and included mainly

in the Other segment.

Gain on Sale of LIL

On June 4, 2024, Emera completed the sale of its LIL equity interest. A gain on sale of $182 million after

transaction costs ($107 million, after tax and transaction costs, or $0.37 per common share), was

recognized in “Other Income, net” on the Consolidated Statements of Income in Q2 2024 and included in

the Other segment. In Q4 2024, Emera recognized a $22 million ($0.08 per common share) tax benefit

related to the reversal of a prior year valuation allowance. A portion of the taxable capital gain on the sale

of the LIL equity interest was offset by prior year loss carryforwards, of which the tax benefit had been

subject to a valuation allowance as at December 31, 2023. This tax benefit was recorded in “Income Tax

(Recovery) Expense” on the Consolidated Statements of Income in Q4 2024 and included in the Other

segment. For further details on the transaction, refer to the “Other Developments” section.

Charges Related to the Pending Sale of NMGC

In Q3 2024, Emera recognized non-cash goodwill and other impairment charges of $221 million ($206

after-tax, or $0.72 per common share) related to the NMGC reporting unit. These charges were recorded

in “Impairment charges” on the Consolidated Statements of Income and included in the Other and Gas

Utilities and Infrastructure segments, respectively. For further details on the pending sale of NMGC, refer

to the “Other Developments” section. For further details on the non-cash goodwill impairment charge,

refer to note 23 in the consolidated financial statements.

Additionally, in Q3 2024, Emera recorded a loss of $25 million ($19 million after-tax, or $0.06 per common

share) in estimated transaction costs related to the pending sale of NMGC. These transaction costs were

recorded in “Other Income, net” on the Consolidated Statement of Income and included in the Other

segment. For further details, refer to the “Other Developments” section.

Earnings Impact of MTM Loss, After-Tax

Quarter-to-date the 2023 MTM gain, after-tax, of $114 million decreased $260 million to a $146 million

MTM loss, after-tax, for the same period in 2024. For the year ended, the 2023 MTM gain, after-tax, of

$169 million decreased $460 million to a $291 million MTM loss, after-tax, for the same period in 2024.

These decreases were primarily due to changes in existing positions, partially offset by lower amortization

of gas transportation at Emera Energy Services (“EES”).

Consolidated Financial Highlights

For the

Three months ended

Year ended

millions of dollars

December 31

Adjusted net income

2024

2023

2024

2023

2022

Florida Electric Utility

120

115

644

627

596

Canadian Electric Utilities

232

247

222

Gas Utilities and Infrastructure

267

214

221

Other Electric Utilities

Other

(59)

(71)

(342)

(314)

(218)

Adjusted net income

246

175

849

809

850

Gain on sale of LIL, after-tax

129

Financing structure wind-up

Charges related to wind-down costs and

certain asset impairments, after-tax

(26)

Charges related to the pending sale of NMGC, after-tax

(225)

MTM (loss) gain, after-tax

(146)

114

(291)

169

175

GBPC impairment charge

(73)

NSPML unrecoverable costs

(7)

Net income attributable to common shareholders

154

289

494

978

945

The following table highlights significant changes in adjusted net income from 2023 to 2024:

For the

Three months ended

Year ended

millions of dollars

December 31

Adjusted net income – 2023

175

809

Operating Unit Performance

Increased earnings at NSPI due to increased income tax recovery,

partially offset by higher operating, maintenance and general expenses

(“OM&G”) due primarily to a lower storm cost deferral

Increased earnings quarter-over-quarter at Other Electric Utilities

primarily due to the timing of recovery of fuel costs and lower OM&G.

Year-over-year increased primarily due to higher sales volumes, partially

offset by higher OM&G

Increased earnings quarter-over-quarter at NMGC due to higher

revenue from new base rates, partially offset by higher income tax

expense. Decreased earnings year-over-year due to lower asset

optimization revenue, partially offset by higher revenue from new base

rates

(4)

Increased earnings at PGS due to higher revenue from new base rates

and customer growth, partially offset by increased interest expense,

depreciation, OM&G, and income tax expense

Increased earnings at TEC due to higher revenues from customer

growth and new base rates, and the impact of a weaker CAD, partially

offset by higher OM&G, and depreciation. Year-over-year increased

earnings also due to lower income tax expense and lower interest

expense, partially offset by unfavourable weather

Decreased earnings year-over-year at EES due to favourable hedging

opportunities in Q1 2023 and less favourable market conditions in 2024

(3)

(16)

Decreased earnings at Bear Swamp primarily due to the recognition of

investment tax credits in 2023

(13)

(20)

Decreased income from equity investments due to the sale of LIL equity

interest

(16)

(32)

Corporate

Decreased deferred income tax asset valuation allowance due to

utilization of tax loss carryforwards

Increased income tax recovery due to increased loss before provision

for income taxes

Increased interest expense due to the impact of a weaker CAD on USD

interest expense, increased total Corporate debt and increased interest

rates

(9)

(38)

Increased OM&G quarter-over-quarter primarily due to the timing

difference in the valuation of long-term incentive expense and related

hedges

(16)

(1)

Other Variances

(1)

(15)

Adjusted net income – 2024

246

849

For the

Year ended December 31

millions of dollars

2024

2023

2022

Operating cash flow before changes in working capital

2,194

2,336

1,147

Change in working capital

452

(95)

(234)

Operating cash flow

2,646

2,241

913

Investing cash flow

(2,218)

(2,917)

(2,569)

Financing cash flow

(818)

939

1,555

For further discussion of cash flow, refer to the "Consolidated Cash Flow Highlights" section.

As at

December 31

millions of dollars

2024

2023

2022

Total assets

42,951

39,480

39,742

Total long-term

debt (including current portion)

(1)

18,407

18,365

16,318

(1) On August 5, 2024, Emera announced an agreement to sell NMGC. As at December 31, 2024, NMGC's assets and liabilities

were classified as held for sale and are excluded from this table. For further details, refer to the 'Other Developments' section

and

note 4 in the consolidated financial statements.

Consolidated Income Statement Highlights

For the

Three months ended

Year ended

millions of dollars

December 31

(except per share amounts)

2024

2023

Variance

2024

2023

Variance

2022

Operating revenues

1,763

1,972

(209)

7,200

7,563

(363)

7,588

Operating expenses

1,524

1,467

(57)

6,120

5,769

(351)

5,959

Income from operations

239

505

(266)

1,080

1,794

(714)

1,629

Other (expense) income, net

(29)

(80)

203

158

145

Interest expense, net

248

241

(7)

973

925

(48)

709

Income tax (recovery) expense

(199)

250

(159)

128

287

185

Net income attributable to

common shareholders

154

289

(135)

494

978

(484)

945

Adjusted net income

246

175

849

809

850

Weighted average shares of

common stock outstanding

(in millions)

294.1

277.7

16.4

289.1

273.6

15.5

265.5

EPS – basic

0.52

1.04

(0.52)

1.71

3.57

(1.86)

3.56

EPS – diluted

0.52

1.04

(0.52)

1.71

3.57

(1.86)

3.55

Adjusted EPS – basic

0.84

0.63

0.21

2.94

2.96

(0.02)

3.20

Adjusted EBITDA

753

705

3,048

2,910

138

2,687

Dividends per common share

declared

0.7250

0.7175

0.0075

2.8775

2.7875

0.0900

2.6775

Dividends per first preferred shares declared:

Series A

0.5456

Series B

1.6966

1.5583

0.1383

0.6869

Series C

1.6085

1.2873

0.3212

1.1802

Series E

1.1250

Series F

1.0505

Series H

1.5810

1.3140

0.2670

1.2250

Series J

1.0625

Series L

1.1500

Operating Revenues

For Q4 2024, operating revenues decreased $209 million compared to Q4 2023 and, excluding

decreased MTM gain of $291 million, increased $82 million. For the year ended December 31, 2024,

operating revenues decreased $363 million compared to 2023 and, excluding decreased MTM gain of

$559 million, increased $196 million. The increases were due to new rates at PGS, NSPI, TEC and

NMGC; the impact of a weaker CAD; and increased customer growth at TEC and PGS. The increases

were partially offset by lower fuel recovery clause and storm surcharge revenue (offset in OM&G) at TEC;

and lower fuel revenue at NMGC. Year-over-year increase was also due to a change in the fuel cost

recovery methodology for an industrial customer in 2023 at NSPI (offset in fuel for generation and

purchased power).

Operating Expenses

For Q4 2024, operating expenses increased $57 million compared to Q4 2023, and, excluding charges

related to wind-down costs and certain asset impairments of $4 million, increased $53 million. For the

year ended December 31, 2024, operating expenses increased $351 million compared to 2023, and

excluding the goodwill and other impairment charges primarily related to the pending sale of NMGC of

$225 million, increased $126 million due to higher depreciation at TEC and PGS; the impact of a weaker

CAD; higher OM&G due to timing of deferred clause recoveries at PGS and TEC; lower storm cost

deferral and higher demand side management program costs at NSPI; and higher labour costs at PGS.

This was partially offset by lower natural gas prices at NMGC, PGS and TEC and lower storm cost

recognition at TEC (offset in revenue). Year-over-year increase was also due to a change in fuel cost

recovery for an industrial customer in 2023 at NSPI (offset in revenue).

Other Income, Net

For Q4 2024, other income, net decreased $80 million compared to Q4 2024 due to charges related to

wind-down costs and certain asset impairments and higher FX losses.

For the year ended December 31, 2024, other income, net increased $45 million compared to the same

period in 2023 due to the gain on sale of LIL, after transaction costs, partially offset by higher FX losses,

charges related wind-down costs and certain asset impairments, transaction costs related to the pending

sale of NMGC, and lower interest income.

Interest Expense, Net

For Q4 2024, interest expense, net increased $7 million and for the year ended December 31,2024,

increased $48 million compared to the same periods in 2023 due to the impact of a weaker CAD on USD

interest expense, increased borrowings to support ongoing operations and higher interest rates.

Income Tax (Recovery) Expense

For Q4 2024, income tax recovery increased $250 million compared to Q4 2023 due to decreased

income before provision for income taxes, decreased deferred income tax asset valuation allowance and

recognition of tax benefits associated with denied interest and financing expenses.

For the year ended December 31, 2024, income tax recovery increased $287 million compared to 2023

due to decreased income before provision for income taxes (excluding the gain on sale of LIL and

charges related to the pending sale of NMGC), decreased deferred income tax asset valuation allowance

and recognition of tax benefits associated with denied interest and financing expenses. This increased

recovery was partially offset by the net tax impact of the gain on sale of LIL and charges related to the

pending sale of NMGC.

Net Income and Adjusted Net Income

For Q4 2024, net income attributable to common shareholders compared to Q4 2023, was favourably

impacted by the $58 million tax benefit related to a specific financing structure and its wind-up and the

$22 million valuation allowance reversal related to the gain on sale of LIL, and unfavourably impacted by

the $26 million charges related to wind-down costs and certain asset impairments, and the $260 million

decrease in MTM gains. Excluding these impacts, adjusted net income increased $71 million, primarily

due to increased earnings at NSPI, Other Electric Utilities, NMGC, PGS, and TEC, and increased

Corporate income tax recovery. This was partially offset by lower equity earnings from LIL; increased

Corporate OM&G due to timing of long-term incentive expenses and related hedges; increased Corporate

interest expense; and decreased earnings at Emera Energy.

For the year ended December 31, 2024, net income attributable to common shareholders,

compared to

the same period in 2023, was favourably impacted by the $129 million gain on sale of LIL, and the $58

million tax benefit related to a specific financing structure and its wind-up and unfavourably impacted by

the $26 million in charges related to wind-down costs and certain asset impairments, $225 million in

charges related to the pending sale of NMGC, and the $460 million decrease in MTM gains. Excluding

these changes, adjusted net income increased $40 million. The increase was primarily due to increased

earnings at PGS, NSPI, TEC, and Other Electric Utilities, and increased Corporate income tax recovery.

This was partially offset by increased Corporate interest expense; lower equity earnings from LIL; and

decreased earnings at Emera Energy.

EPS – Basic and Adjusted EPS – Basic

For Q4 2024, EPS – basic was lower than in Q4 2023 due to the impact of decreased earnings, as

discussed above, and an increase in weighted average shares outstanding. Adjusted EPS – basic was

higher in Q4 2024, compared to Q4 2023, due to increased adjusted earnings as discussed above,

partially offset by an increase in weighted average shares outstanding.

For the year ended December 31, 2024, EPS – basic was lower than in 2023 due to the impact of an

increase in weighted average shares outstanding and decreased earnings, as discussed above. Adjusted

EPS – basic was lower in 2024, compared to 2023, due to the impact of an increase in weighted average

shares outstanding, partially offset by increased adjusted earnings, as discussed above.

Effect of Foreign Currency Translation

Emera operates in the United States (“US”), Canada 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

on net income attributable to common shareholders for 2024 and 2023 are as follows:

Three months ended

Year ended

December 31

2024

2023

2024

2023

Weighted average CAD/USD

1.37

1.36

1.35

Period end CAD/USD exchange rate

1.44

1.32

1.44

1.32

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

millions of USD

2024

2023

2024

2023

Florida Electric Utility

(1)

470

466

Gas Utilities and Infrastructure

(2)(3)

178

142

Other Electric Utilities

Other segment

(4)(5)

(33)

(18)

(131)

(95)

Total

(1)(3)(5)

123

111

552

539

(1) Excludes $2 million USD, after-tax, in other impairment charges for the three months and year ended December 31, 2024.

(2) Includes USD net income from PGS, NMGC, SeaCoast and M&NP.

(3) Excludes $6 million USD, after-tax, in other impairment charges associated with the pending sale of NMGC for the year ended

December 31, 2024.

(4) Includes Emera Energy's USD adjusted net income from EES, Bear Swamp and interest expense on Emera Inc.'s USD

denominated debt.

(5) Excludes $84 million USD in MTM losses, after-tax, for the three months ended December 31, 2024 (2023 – $73 million

USD

MTM gain, after-tax) and $189 million in USD MTM losses, after-tax, for the year ended December 31, 2024 (2023 – $116

million

USD MTM gain, after-tax).

Weakening of the CAD increased adjusted net income by $2 million in Q4 2024 and $5 million for the

year ended December 31, 2024, compared to the same periods in 2023. 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.

The translation impact of a weaker CAD on USD earnings was more than offset by the realized and

unrealized losses on FX hedges used to mitigate translation risk of USD earnings, resulting in a $29

million decrease to net income in Q4 2024 and $35 million decrease to net income for the year ended

December 31, 2024, compared to the same periods in 2023.

BUSINESS OVERVIEW AND OUTLOOK

Florida Electric Utility

The Florida Electric Utility segment 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 $13 billion USD of assets and approximately 855,000 customers at December 31, 2024.

TEC owns 6,620 megawatts (“MW”) of generating capacity, of which 73 per cent is natural gas fired, 20

per cent is solar and 7 per cent is coal. TEC also owns 2,192 kilometres of transmission facilities and

20,693 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.

Beginning in 2025, TEC’s approved regulated ROE range is 9.50 per cent to 11.50 per cent (2024 – 9.25

per cent to 11.25 per cent) based on an allowed equity capital structure of 54 per cent (2024 – 54 per

cent). An ROE of 10.50 per cent (2024 – 10.20 per cent) is used for the calculation of the return on

investments for clauses.

TEC anticipates earning within its ROE range in 2025. As a result of new base rates effective January 1,

2025, TEC's 2025 USD earnings are expected to be higher than in 2024. Normalizing 2024 for weather,

TEC’s sales volumes in 2025 are projected to be higher than in 2024 due to customer growth. TEC

expects customer growth rates in 2025 to be comparable to 2024, reflective of the expected economic

growth in Florida.

On April 2, 2024, TEC filed a rate case with the FPSC for new base rates. On December 3, 2024, the

FPSC rendered a decision which includes annual base rate increases of $185 million USD in 2025 and

adjustments of $87 million USD and $9 million USD in 2026 and 2027, respectively. The rates include

recovery of solar generation projects, energy storage capacity, a more resilient and modernized energy

control center, and other resiliency and reliability projects. The allowed equity in the capital structure will

continue to be 54 per cent from investor sources of capital and the allowed regulatory ROE range is 9.50

per cent to 11.50 per cent with a 10.50 per cent midpoint. On February 3, 2025, the FPSC issued the final

order approving the decision, effective January 1, 2025. On February 18, 2025, a motion for

reconsideration on certain aspects of the rate case order was filed with the FPSC. TEC will respond to

this motion in February 2025. TEC expects the FPSC to reach a final decision on the motion in Q2 2025.

On September 26, 2024, Hurricane Helene passed 100 miles west of Tampa and made landfall

approximately 200 miles north of Tampa, in Taylor

County, as a Category 4 hurricane. TEC’s service

territory was impacted by the tropical storm force winds and storm surge which resulted in a peak number

of customers out of 100,000. As of December 31, 2024, TEC deferred $49 million USD to the storm

reserve for future recovery.

On October 9, 2024, Hurricane Milton made landfall approximately 50 miles south of Tampa, near

Sarasota, and was the worst weather event to impact the area in over 100 years. The Category 3

hurricane had a significant impact on TEC’s service territory which resulted in a peak number of

customers out of 600,000. As of December 31, 2024, TEC deferred $340 million USD to the storm

reserve for future recovery.

As at December 31, 2024, total restoration costs charged to the storm reserve account have exceeded

the storm reserve balance (for additional details on the storm reserve, refer to note 7 in Emera’s

consolidated financial statements) and therefore $377 million USD has been deferred as a regulatory

asset for future recovery. On February 4, 2025, the FPSC approved TEC’s petition filed on December 27,

2024 for the recovery of $466 million USD for costs associated with Hurricane Idalia, Hurricane Debby,

Hurricane Helene and Hurricane Milton and the associated interest to replenish the storm reserve over an

18-month recovery period beginning in March 2025. The amount of cost-recovery is subject to a true-up

mechanism with the FPSC.

On April 2, 2024, TEC requested a mid-course adjustment to its fuel and capacity charges, reflecting a

$138 million USD reduction over 12 months, from June 2024 through May 2025. The requested reduction

was due to a decrease in actual and projected 2024 natural gas prices since TEC submitted its projected

2024 costs in the fall of 2023. On May 7, 2024, the FPSC approved the mid-course adjustment.

In 2025, capital investment in the Florida Electric Utility segment is expected to be $1.7 billion USD (2024

– $1.4 billion USD), including allowance for funds used during construction (“AFUDC”). Capital projects

include solar investments,

grid modernization, storm hardening investments, building resilience and

energy storage.

Canadian Electric Utilities

The Canadian Electric Utilities segment includes NSPI and NSPML. 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. NSPML is a 100 per cent equity interest in the

Maritime Link Project (“Maritime Link”), a transmission project between the island of Newfoundland and

Nova Scotia.

On June 4, 2024, Emera completed the sale of its LIL equity interest. For further information, refer to the

“Significant Items Affecting Earnings” and “Other Developments” sections.

NSPI

With $7.1 billion of assets and approximately 557,000 customers at December 31, 2024, 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

533 MW of capacity. NSPI also has rights to 153 MW of Maritime Link capacity,

representing

Newfoundland and Labrador Hydro’s (“NLH”) Nova Scotia Block (“NS Block”) delivery obligations,

discussed below. NSPI owns approximately 5,000 kilometres of transmission facilities and 28,000

kilometres of distribution facilities.

NLH 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, NLH 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 NLH through the Energy

Access Agreement. The Energy Access Agreement enables NSPI to access a market-priced bid from

NLH 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 anticipates earning below its allowed ROE range in 2025. NSPI expects earnings in 2025 to be

consistent with 2024. Sales volumes are expected to be higher in 2025 than 2024.

On September 24, 2024, the Government of Canada finalized an agreement with NSPI, NSPML and the

Province of Nova Scotia (the “Province”) on terms and conditions for a federal loan guarantee (“FLG”) of

$500 million in debt to be issued by NSPML to help Nova Scotia customers manage unrecovered costs of

the replacement energy that was required during the several years of delay in the Muskrat Falls

hydroelectricity project. On September 25, 2024, NSPI and NSPML filed applications with the UARB

related to the FLG. On November 29, 2024, the UARB approved NSPML’s application to issue the debt,

transfer the proceeds to NSPI as a refund of a portion of previous NSPML assessment payments

(“NSPML Refund”), and to increase its annual assessment charge to NSPI to recover the refund and

related financing costs over a 28-year period. On December 16, 2024, the net proceeds of the NSPML

debt issuance were transferred to NSPI and applied against the FAM regulatory asset balance. On

February 18, 2025, the UARB approved NSPI's application to increase 2025 fuel rates to service the

incremental NSPML debt

On December 2, 2024, the UARB approved the recovery of $24 million of major storm restoration and

incremental financing costs deferred to NSPI’s storm rider in 2023 to be recovered over a 12-month

period beginning on January 1, 2025.

On June 27, 2024, the UARB approved the deferred recognition of $25 million in incremental operating

costs incurred during the Hurricane Fiona storm restoration efforts in September 2022. Following UARB

approval, the $25 million was reclassified to “Regulatory assets” from “Other long-term assets”. The

UARB also directed NSPI to reclassify $10 million of undepreciated costs related to assets retired

because of Hurricane Fiona to “Regulatory assets” from “PP&E” on the Consolidated Balance Sheets.

NSPI began amortizing both of these regulatory assets over a 10-year period beginning July 1, 2024.

On June 13, 2024, the UARB approved $238 million of capital investment, including AFUDC, for the

Battery Energy Storage System Project. The project is comprised of three 50 MW, four-hour battery

facilities. Two facilities are anticipated to be in-service in late 2025 and the third facility in 2026.

On April 17, 2024, the UARB approved the sale of $117 million of the FAM

regulatory asset to Invest

Nova Scotia, a provincial Crown corporation. On April 30, 2024, the transaction closed and the $117

million was remitted to NSPI, which resulted in a corresponding decrease of the FAM regulatory asset.

NSPI is collecting the amortization and financing costs related to the $117 million from customers on

behalf of Invest Nova Scotia over a 10-year period, which began in Q2 2024, and is remitting those

amounts to Invest Nova Scotia quarterly.

In 2025, capital investment, including AFUDC, is expected to be $480 million (2024 – $487 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. 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 Regulations (“CER”):

On December 17, 2024, Environment and Climate Change Canada released a finalized version of the

CER. The CER establish performance standards to further limit greenhouse gas (“GHG”) emissions from

fossil fuel-generated electricity starting in 2035 and help facilitate the Government of Canada’s intention

of achieving a net-zero electricity grid by 2050. Compliance with the finalized version of the CER is not

anticipated to require significant capital investment incremental to achieve the 2030 targets as NSPI’s

planned capital investment during this period is driven by the Province’s goals to transition off coal and

reach 80 per cent renewable electricity sales by 2030.

Nova Scotia Energy Reform Act:

On April 5, 2024, the Province enacted Bill 404 - Energy Reform (2024) Act. The legislation enacted the

Energy and Regulatory Board Act, which established the Nova Scotia Energy Board (“NSEB”). The NSEB

is a new board which will regulate energy and utility entities in Nova Scotia, with a mandate of increased

focus on meeting energy transition demands. The legislation also enacts the More Access to Energy Act,

which provides for the establishment of and phased transition to the Nova Scotia Independent Energy

System Operator. NSPI is fully engaged in supporting the Province on these initiatives.

RER:

On May 26, 2023, NSPI initiated an appeal, through a proceeding with the UARB, of the $10 million

penalty levied on NSPI by the Province for non-compliance with the RER compliance period ending in

The hearing for the matter is currently scheduled for June 2025.

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.

Equity earnings from NSPML in 2025 are expected to consistent with 2024. The NSPML investment is

recorded as “Investments subject to significant influence” on Emera’s Consolidated Balance Sheets.

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. NLH’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 September 24, 2024, the Government of Canada finalized an agreement with NSPI, NSPML, and the

Province on terms and conditions for a FLG of $500 million in debt to be issued by NSPML. For further

information, refer to the NSPI section above.

On November 29, 2024, NSPML received approval from the UARB to collect up to $197 million in 2025

from NSPI; which includes $158 million for the recovery of costs associated with the Maritime Link, and

$39 million associated with the additional FLG debt and financing costs discussed in the NSPI section

above. Payments from NSPI are subject to a holdback of up to $4 million per month. There was no

holdback recorded for the year ended December 31, 2024. NSPML expects to file an application to

terminate the holdback mechanism in early 2025.

NSPML does not anticipate any significant capital investment in 2025.

Gas Utilities and Infrastructure

The Gas Utilities and Infrastructure segment 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 US.

On August 5, 2024, Emera announced an agreement to sell NMGC. The transaction is expected to close

in late 2025, subject to certain approvals, including approval by the NMPRC. As a result of the pending

sale, NMGC’s assets and liabilities were classified as held for sale as of Q3 2024. For more information

on the pending transaction, refer to the “Other Developments” section.

PGS

With $3.1 billion USD of assets and approximately 508,000 customers, the PGS system includes 25,240

kilometres of natural gas mains and 14,530 kilometres of service lines. Natural gas throughput (the

amount of gas delivered to its customers, including transportation-only service) was 2 billion therms in

2024.

The approved ROE range for PGS is 9.15 per cent to 11.15 per cent based on an allowed equity capital

structure of 54.7 per cent. An ROE of 10.15 per cent is used for the calculation of return on investments

for clauses.

PGS anticipates earning near the bottom of its allowed ROE range in 2025 as a result of the continued

investments across Florida to maintain reliability and service new customers. Capital investments are

expected to outpace revenue growth. USD earnings for 2025 are expected to be consistent with 2024

primarily due to higher operating costs and depreciation driven by ongoing capital investments to support

customer demand and system needs.

On January 30, 2025, PGS notified the FPSC of its intent to seek a base rate increase effective January

2026, reflecting a revenue requirement of approximately $90 to $110 million USD and subsequent year

adjustment for 2027 of approximately $25 to $40 million USD. PGS' proposed rates support on-going

growth in Florida and a continued commitment to delivering safe and reliable service to PGS customers.

The filing range amounts are estimates until PGS files its detailed case in March 2025. The FPSC is

scheduled to hear the case in Q3 2025 with a decision expected by the end of 2025.

In 2025, capital investment, including AFUDC, is expected to be approximately $360 million USD (2024 –

$323 million USD). PGS will make investments to maintain the reliability of their systems and support

customer growth.

NMGC

With $1.5 billion USD of assets and approximately 550,000 customers, NMGC’s system includes

approximately 2,405 kilometres of transmission pipelines and 17,810 kilometres of distribution pipelines.

Annual natural gas throughput was approximately 1 billion therms in 2024.

The approved ROE for NMGC is 9.375 per cent, on an allowed equity capital structure of 52 per cent.

NMGC’s USD earnings contributions to Emera in 2025 are expected to be lower than in 2024 as a result

of the pending sale of NMGC that is currently expected to close in October 2025.

On September 14, 2023, NMGC filed a rate case with the NMPRC for new base rates. On March 1, 2024,

NMGC filed with the NMPRC a settlement with the support of all parties in the case for an increase of $30

million USD in annual base revenues and maintaining NMGC’s ROE at 9.375 per cent. The rates reflect

the recovery of increased operating costs and capital investments in pipeline projects and related

infrastructure, as well as a new customer information and billing system. NMGC also agreed to withdraw,

and to not reassert in a future rate case application, its request for a regulatory asset for costs associated

with its 2022 application for a certificate of public convenience and necessity for a liquefied natural gas

storage facility in New Mexico. The NMPRC approved the rate case settlement on July 25, 2024. New

rates became effective October 1, 2024.

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.

Other Electric Utilities’ USD earnings in 2025 are expected to be consistent with the prior year.

In 2025, capital investment in the Other Electric Utilities segment is expected to be approximately $140

million USD, including AFUDC (2024 – $59 million USD), primarily in more efficient and cleaner sources

of generation, including renewables and battery storage.

BLPC

With $538 million USD of assets and approximately 135,000 customers, BLPC owns 243 MW of

generating capacity, of which 96 per cent is oil-fired and 4 per cent is solar. BLPC owns approximately

188 kilometres of transmission facilities and 3,989 kilometres of distribution facilities. BLPC’s approved

regulated return on rate base is 10 per cent.

On May 24, 2024, the Government of Barbados signed the Income Tax (Amendment and Validation)

Act

into law. The legislation, effective January 1, 2024, implemented a corporate income tax rate of 9 per

cent, requiring BLPC to remeasure its deferred income tax liabilities. On July 18, 2024, BLPC requested

the deferred recovery of the $5 million USD remeasurement. BLPC is seeking amortization of the costs

over a period to be approved by the FTC during a future rate setting process.

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 totalling approximately $71 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. The appeal is

currently scheduled to be heard in 2025.

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.

GBPC

With $340 million USD of assets and approximately 19,500 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 is 8.52 per cent.

On August 1, 2024, as required by the GBPA Operating Protocol and Regulatory Framework Agreement,

GBPC filed a rate plan proposal. Review of the rate application is expected to be completed in 2025

On June 1, 2024, the Electricity Act, 2024 took effect. The legislation purports to remove the jurisdiction of

the GBPA over GBPC and to have the Utilities Regulation and Competition Authority, another Bahamian

regulator, regulate GBPC. The GBPA

has opposed the legislated removal of its regulatory authority over

GBPC, citing conflict with the Hawksbill Creek Agreement, the 1955 agreement with the Bahamian

government that provided for the development and administration of the Freeport area. Management

expects the matter of regulatory jurisdiction over GBPC to be the subject of legal proceedings, however,

does not foresee that the legislation or the outcome of such proceedings will have a material impact to

Emera.

Other

The Other segment includes 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 Corporate; Emera Energy Services (EES), a physical

energy marketing and trading business; a 50 per cent joint venture interest in Bear Swamp, a 660 MW

pumped storage hydroelectric facility in northwestern Massachusetts; and Block Energy. In Q4 2024,

Block Energy initiated the process to wind-up operations.

Corporate items included are certain corporate-wide functions including executive management, strategic

planning, treasury services, legal, financial reporting, tax planning, corporate business development,

corporate governance, investor relations, risk management, insurance, acquisition and disposition related

costs, gains or losses on select assets sales, and corporate human resource activities. It includes interest

revenue on intercompany financings and interest expense on corporate debt in both Canada and the US.

It also includes costs associated with corporate activities that are not directly allocated to the operations

of Emera’s subsidiaries and investments.

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 of $15 to $30 million USD.

The adjusted net loss from the Other segment is expected to be lower in 2025 than 2024, due primarily to

the wind-up of Block Energy in 2024.

The Other segment does not anticipate any significant capital investment in 2025.

CONSOLIDATED

BALANCE SHEET HIGHLIGHTS

Significant changes in the Consolidated Balance Sheets between December 31, 2023 and December 31,

2024 include:

Increase

(Decrease)

Total

due to

Other

Increase

held for sale

Increase

millions of dollars

(Decrease)

classification (1)

(Decrease)

Explanation of Other Increase (Decrease)

Assets

Cash and cash equivalents

(371)

(8)

(363)

Decreased due to investment in PP&E, net

repayments on committed credit facilities at

Corporate and NSPI, repayment of short-term

debt at TEC, retirement of long-term debt at

Emera, TEC and New Mexico Gas

Intermediate, Inc (“NMGI”), and dividends paid

on Emera common stock. These were partially

offset by cash from operations, proceeds from

debt issuances at TEC and EUSHI Finance,

Inc. (“EUSHI Finance”), proceeds received on

the sale of the LIL equity interest and proceeds

from common shares issued

Derivative instruments

(current and long-term)

(74)

(1)

(73)

Decreased due to reversal of 2023 contracts at

EES, partially offset by higher commodity prices

at NSPI

Regulatory assets (current

and long-term)

322

(34)

356

Increased due to higher storm costs recovery

clause assets at TEC and NSPI, the effect of

FX translation of Emera’s non-Canadian

affiliates, and reclassification of early retired

plant from PP&E to a regulatory asset at TEC.

These were partially offset by decreased FAM

balance at NSPI due to the NSPML refund, and

decreased fuel clause recovery balance at TEC

due to higher over-recoveries

Receivables and other assets

(current and long-term)

(150)

220

Increased due to higher cash collateral

positions on derivative instruments and

increased trade receivables as a result of

higher commodity prices at EES, and the effect

of FX translation of Emera's non-Canadian

affiliates. These were partially offset by lower

gas transportation assets at EES and lower

trade receivables at TEC

Assets held for sale (current

and long-term), net of

liabilities

973

PP&E, net of accumulated

depreciation and amortization

1,792

(1,828)

3,620

Increased due to capital additions in excess of

depreciation and the effect of FX translation of

Emera's non-Canadian affiliates, partially offset

by a reclassification of early retired plant to TEC

capital cost recovery regulatory asset

Investments subject to

significant influence

(748)

Decreased primarily due to sale of LIL equity

interest

Goodwill

(13)

(303)

290

Increased due to the effect of FX translation of

Emera's non-Canadian affiliates, partially offset

by the non-cash impairment charge recognized

primarily related to NMGC

(1) On August 5, 2024, Emera announced the sale of NMGC. As at December 31, 2024 NMGC's assets and liabilities were

classified as held for sale. For further details, refer to the 'Other Developments' section and note 3 in the consolidated financial

statements.

Increase

(Decrease)

Total

due to

Other

Increase

held for sale

Increase

millions of dollars

(Decrease)

classification (1)

(Decrease)

Explanation of Other Increase (Decrease)

Liabilities and Equity

Short-term debt and long-

term debt (including current

portion)

(742)

751

Increased due the effect of FX translation of

Emera's non-Canadian affiliates, proceeds from

long-term debt issuance at TEC, and issuance

of junior subordinated notes at EUSHI Finance.

These were partially offset by repayment of

Emera’s committed credit facilities using the LIL

transaction proceeds, repayment of short-term

debt at TEC and NSPI, and retirement of long-

term debt at Corporate, TEC, and NMGI

Accounts payable

538

(131)

669

Increased due to storm cost payable at TEC,

the effect of FX translation of Emera’s non-

Canadian affiliates, and increased commodity

prices at EES

Deferred income tax

liabilities, net of deferred

income tax assets

(205)

(167)

(38)

No significant change after removing impact of

held for sale classification

Derivative instruments

(current and long-term)

113

(1)

114

Increased due to new contracts in 2024 and

changes in existing positions at EES, higher FX

forward liability at Corporate due to changes in

the FX hedges, partially offset by higher

commodity prices and settlements of derivative

instruments at NSPI

Regulatory liabilities (current

and long-term)

108

(284)

392

Increased due to effect of FX translation of

Emera’s non-Canadian affiliates and

recognition of fuel cost recovery liabilities at

TEC and NSPI due to over-recovery of fuel

costs

Other liabilities (current and

long-term)

152

(34)

186

Increased due the effect of FX translation of

Emera's non-Canadian affiliates and higher

accrued interest on long-term debt at NSPI

Common stock

580

Increased due to shares issued

Accumulated other

comprehensive income

956

Increased due to the effect of FX translation of

Emera's non-Canadian affiliates

Retained earnings

(335)

Decreased due to dividends paid in excess of

net income

(1) On August 5, 2024, Emera announced the sale of NMGC. As at December 31, 2024 NMGC's assets and liabilities were

classified as held for sale. For further details, refer to the 'Other Developments' section and note 3 in the consolidated financial

statements.

OTHER DEVELOPMENTS

Canadian Tax Legislation

Changes

On June 20, 2024, Bill C-59, an Act to implement certain provisions of the fall economic statement tabled

in Parliament on November 21, 2023, and certain provisions of the budget tabled in Parliament on March

28, 2023, was enacted.

Bill C-59 includes the EIFEL regime, which is effective January 1, 2024. EIFEL

applies to limit a company’s net interest and financing expense deduction to no more than 30 per cent of

EBITDA for tax purposes. Any denied interest and financing expenses under the EIFEL regime can be

carried forward indefinitely. During 2024, the Company incurred $185 million of interest and financing

expenses in connection with a specific financing structure. The interest and financing expenses related to

the financing structure as well as $88 million of other interest and financing expenses are expected to be

denied under the EIFEL regime. It was determined that the Company is more likely than not to realize the

tax benefit of the denied interest and financing expenses in future periods and therefore a $79 million

deferred income tax asset has been recorded as at December 31, 2024

Pending Sale of NMGC

On August 5, 2024, Emera entered into an agreement to sell its indirect wholly owned subsidiary NMGC

for a total enterprise value of approximately $1.3 billion USD, consisting of cash proceeds and the

transfer of debt and customary closing adjustments. The transaction is expected to close in late 2025,

subject to certain approvals, including approval by the NMPRC. As a result of the pending sale, NMGC’s

assets and liabilities are classified as held for sale.

As the transaction proceeds will be lower than the carrying amount of the assets and liabilities being sold,

Emera assessed the NMGC reporting unit for goodwill impairment by comparing the FV of expected

transaction proceeds to the carrying value of net assets, including goodwill of $366 million USD (“NMGC

carrying amount”). The goodwill of the reporting unit was determined to be impaired and a non-cash

goodwill impairment charge of $210 million ($198 million, after-tax) or $155 million USD ($146 million

USD, after-tax) was recorded in “Impairment Charges” on the Consolidated Statements of Income in Q3

2024.

Following the goodwill impairment assessment, the held for sale assets and liabilities were measured at

the lower of their carrying amount or fair value less costs to sell. The measurement resulted in an

additional loss for the estimated future transaction costs of $16 million ($12 million after-tax), in addition to

incurred transaction costs of $9 million ($7 million after-tax) recorded in “Other Income, net” on the

Consolidated Statements of Income in Q3 2024.

The Company will continue to record depreciation on the NMGC assets through the transaction closing

date, as the depreciation continues to be reflected in customer rates and will be reflected in the carryover

basis of the assets when sold. Depreciation and amortization of $26 million ($19 million USD) was

recorded on these assets from August 5, 2024, the date they were classified as held for sale, through

December 31, 2024.

Increase in Common Dividend

On September 18, 2024, the Emera Board of Directors approved an increase in the annual common

share dividend rate to $2.90 from $2.87 per common share. The first payment was effective November

15, 2024.

Sale of LIL Equity Interest

On June 4, 2024, Emera completed the sale of its 31.1 per cent LIL equity interest for a total transaction

value of $1.2 billion, including cash proceeds of $957 million and $235 million for assuming Emera’s

contractual obligation to fund the remaining initial capital investment, which represents additional LIL

equity interest for the acquirer. Cash proceeds from the sale in the amount of $30 million is held in escrow

pending finalization of certain agreements with the LIL general partner. The escrow proceeds receivable

is held at FV and included in the gain on sale, after transaction costs. As of December 31, 2024, the

estimated FV of the escrow proceeds receivable is $25 million. In Q2 2024, a gain on sale, after tax and

transaction costs, of $107 million, was included in the Other segment (the gain on sale, net of transaction

costs of $182 million was recognized in “Other Income, net” on the Consolidated Statements of Income).

In Q4 2024, Emera recognized a $22 million tax benefit due to the reversal of a prior year valuation

allowance related to loss carryforwards applied against a portion of the taxable capital gain on the sale of

LIL. This tax benefit was recorded in “Income Tax (Recovery) Expense” on the Consolidated Statements

of Income in Q4 2024 and included in the Other segment. Proceeds from the sale were used to reduce

corporate debt and fund investment in the Company’s regulated utility businesses.

Appointments

Board of Directors

Effective February 21, 2025, Karen Sheriff was appointed Chair of the Emera Board of Directors,

succeeding Jackie Sheppard. Ms. Sheriff joined the Emera Board of Directors in February 2021 and since

that time has served as a member of the Management Resources and Compensation Committee, the

Risk and Sustainability Committee as well as Chair of the Nominating and Corporate Governance

Committee.

Effective June 26, 2024, Carla Tully joined the Emera Board of Directors. Ms. Tully is the former Chief

Executive Officer and Co-Founder of Earthrise Energy, PBC, an energy transition company.

She also

previously served as Executive Vice President and Managing Director of Renewable Energy at MAP

Energy and held various senior leadership roles with AES Corporation.

Effective March 6, 2024, Brian J. Porter joined the Emera Board of Directors. Mr. Porter is the former

President and Chief Executive Officer of The Bank of Nova Scotia (Scotiabank), a global bank operating

in Canada and the Americas.

FINANCIAL HIGHLIGHTS

Florida Electric Utility

Three months ended

Year ended

For the

December 31

millions of USD (except as indicated)

2024

2023

2024

2023

Operating revenues – regulated electric

582

613

2,526

2,637

Regulated fuel for generation and purchased power

151

162

622

682

Contribution to consolidated adjusted net income

470

466

Contribution to consolidated adjusted net income - CAD

120

115

644

627

Charges related to wind-down costs and certain asset

impairments, after-tax

(1)

(2)

Contribution to consolidated net income

468

466

Contribution to consolidated net income – CAD

117

115

641

627

Average fuel costs in dollars per MWh

(1) Net of income tax recovery of $1 million for the three months and year ended December 31, 2024.

The impact of the change in the FX rate increased CAD earnings and adjusted earnings for the three

months and year ended December 31, 2024, by $3 million and $10 million, respectively.

Net Income

Highlights of net income changes are summarized in the following table:

For the

Three months ended

Year ended

millions of USD

December 31

Contribution to consolidated net income – 2023

466

Decreased operating revenues primarily due to decreased fuel

recovery clause revenue, lower storm surcharge revenue (offset in

OM&G), and the unfavourable load impact of Hurricane Milton, partially

offset by customer growth and new base rates. Revenues were also

impacted by favourable weather of $10 million quarter-over-quarter,

and unfavourable weather of $10 million year-over-year

(31)

(111)

Decreased fuel for generation and purchased power due to lower

natural gas prices

Decreased OM&G due to lower storm cost recognition (offset in

revenue), partially offset by the timing of deferred clause recoveries

and higher solar operations, labour, and software maintenance costs

Increased depreciation and amortization due to additions to facilities

and generation projects placed in service

(9)

(32)

Decreased interest expense year-over-year due to lower borrowings

Decreased state and municipal taxes due to lower retail sales tax,

partially offset by higher property taxes

Decreased income tax expense year-over-year due to increased

production tax credits related to solar facilities

Other

(1)

Contribution to consolidated net income – 2024

468

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"))

2024

2023

2024

2023

Residential

1,507

1,711

10,269

10,307

Commercial

686

803

6,481

6,462

Industrial

162

203

2,019

2,082

Other

(1)

171

(80)

2,276

2,194

Total

2,526

2,637

21,045

(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)

2024

2023

Natural gas

18,027

17,843

Solar

2,250

1,748

Purchased power

1,569

1,443

Coal

744

Total

21,878

21,778

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 7 in

the consolidated financial statements.

Canadian Electric Utilities

On June 4, 2024, Emera completed the sale of its LIL equity interest. For further details on the

transaction, refer to the “Other Developments” section.

Three months ended

Year ended

For the

December 31

millions of dollars (except as indicated)

2024

2023

2024

2023

Operating revenues – regulated electric

479

439

1,855

1,671

Regulated fuel for generation and purchased power

(1)

(216)

234

509

777

Contribution to consolidated net income

232

247

Average fuel costs in dollars per MWh

(2)

(73)

(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) 2024 Average fuel costs include the $486 million NSPML Refund which decreased average fuel costs

by $164 per MWh and $43

per MWh for the three months and year ended December 31, 2024, respectively.

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 which decreased average fuel

costs by $15 per MWh. For more information the NSPML Refund and the Nova Scotia Cap-and-Trade

Program provision reversal,

refer to note 7 in the consolidated financial statements.

Canadian Electric Utilities' contribution to consolidated net income is summarized in the following table:

Three months ended

Year ended

For the

December 31

millions of dollars

2024

2023

2024

2023

NSPI

160

141

Equity investment in NSPML

Equity investment in LIL

Contribution to consolidated net income

232

247

Net Income

Highlights of net income changes are summarized in the following table:

For the

Three months ended

Year ended

millions of dollars

December 31

Contribution to consolidated net income – 2023

247

Increased operating revenues at NSPI due to new rates. Year-over-year

also due to changes in fuel cost recovery methodology for an industrial

customer in 2023

(1)

184

Decreased regulated fuel for generation and purchased power at NSPI

due to the NSPML Refund

(1)

and decreased commodity prices, partially

offset by change in generation mix and increased sales volumes. Year-

over-year decrease was partially offset by the reversal of the Nova

Scotia Cap-and-Trade Program provision

(1)

in 2023

450

268

Increased FAM deferral at NSPI primarily due to the NSPML Refund

(1)

Year-over-year increase also due to changes in the fuel cost recovery

methodology for an industrial customer in 2023 and under-recovery of

fuel costs in 2023, partially offset by the reversal of the Nova Scotia

Cap-and-Trade Program provision

(1)

in 2023

(484)

(428)

Increased OM&G due to a lower storm cost deferral, and higher demand

side management program costs at NSPI

(8)

(24)

Decreased income from equity investments due to the sale of LIL

(16)

(34)

Increased income tax recovery at NSPI due to the utilization of tax loss

carryforwards offset to a regulatory deferred income tax liability, partially

offset by decreased tax deductions in excess of accounting depreciation

related to property, plant and equipment

Other

(13)

Contribution to consolidated net income – 2024

232

(1) For more information on the changes in fuel cost recovery methodology for an industrial customer in 2023, the $486 million

NSPML Refund, and the $166 million reversal of the Nova Scotia Cap-and-Trade Program provision,

refer to note 7 in the

consolidated financial statements.

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)

2024

2023

2024

2023

Residential

997

910

5,096

4,986

Commercial

499

463

3,046

3,053

Industrial

276

219

2,217

2,164

Other

222

239

Total

1,813

1,633

10,581

10,442

Regulated Fuel for Generation and Purchased Power

Annual production volumes are summarized in the following table:

Production Volumes (GWh)

2024

2023

Coal

3,347

3,086

Natural gas

2,317

1,946

Purchased power

620

881

Petcoke

374

553

Oil

132

145

Total non-renewables

6,790

6,611

Purchased power - IPP,

COMFIT and imports

3,464

3,251

Wind, hydro and solar

932

1,149

Biomass

140

128

Total renewables

4,536

4,528

Total production volumes

11,326

11,139

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 Output-Based Pricing System, availability of renewable generation, availability of energy from the

NS Block, plant performance, and compliance with environmental regulations.

Regulatory Environment - NSPI

NSPI is a public utility as defined in the Public Utilities Act and is subject to regulation under the Public

Utilities Act by the UARB. The Public Utilities Act gives the UARB supervisory powers over NSPI’s

operations and expenditures. Electricity rates for NSPI’s customers are subject to UARB approval. NSPI

is not subject to a general annual rate review process, but rather participates in hearings held from time to

time at NSPI’s or the UARB’s request. For further details on NSPI’s regulatory environment and recovery

mechanisms, refer to note 7 in the consolidated financial statements.

Gas Utilities and Infrastructure

On August 5, 2024, Emera announced an agreement to sell NMGC. The transaction is expected to close

in late 2025, subject to certain approvals, including regulatory approval by the NMPRC. For more

information on the pending transaction, refer to the “Other Developments” section.

Three months ended

Year ended

For the

December 31

millions of USD (except as indicated)

2024

2023

2024

2023

Operating revenues – regulated gas

(1)

317

290

1,160

1,114

Operating revenues – non-regulated

Total operating revenue

320

293

1,175

1,129

Regulated cost of natural gas

289

391

Contribution to consolidated adjusted net income

194

158

Contribution to consolidated adjusted net income – CAD

267

214

Charges related to the pending sale of NMGC, after-tax

(2)

(6)

Contribution to consolidated net income

188

158

Contribution to consolidated net income – CAD

259

214

(1) Operating revenues – regulated gas includes $12 million of finance income from Brunswick Pipeline (2023 – $11

million) for the

three months ended December 31, 2024 and $46 million (2023 – $46 million) for the year ended December 31 2024;

however, it is

excluded from the gas revenues and cost of natural gas analysis below.

(2) Includes an other impairment charge, net of income tax recovery of nil and $2 million for the three months and the year ended

December 31, 2024, respectively.

Gas Utilities and Infrastructure's contribution to consolidated adjusted net income is summarized in the

following table:

Three months ended

Year ended

For the

December 31

millions of USD

2024

2023

2024

2023

PGS

120

NMGC

Other

Contribution to consolidated adjusted net income

194

158

Impact of the change in the FX rate increased CAD earnings and adjusted earnings for the three months

and year ended December 31, 2024, by $3 million and $4 million respectively.

Net Income

Highlights of net income changes are summarized in the following table:

For the

Three months ended

Year ended

millions of USD

December 31

Contribution to consolidated net income – 2023

158

Increased gas revenues due to new base rates at PGS and NMGC,

and customer growth at PGS, partially offset by lower fuel revenues at

NMGC

Decreased asset optimization revenues at NMGC

(8)

Decreased cost of natural gas due to lower natural gas prices primarily

at NMGC

102

Increased OM&G primarily due to the timing of deferred clause

recoveries and higher labour cost at PGS

(5)

(31)

Increased depreciation primarily due to asset growth at PGS and the

effect of reversal of accumulated depreciation in 2023 as a result of the

2021 rate case settlement at PGS

(13)

(39)

Increased interest expense, net year-over-year, primarily due to higher

interest rates and increased borrowings to support ongoing operations

and capital investments primarily at PGS

(15)

Increased income tax expense primarily due to increased income

before provision for income taxes at PGS. Quarter-over-quarter

increase also due to increased income before provision for income

taxes at NMGC

(13)

(21)

Charges related to the pending sale of NMGC, after-tax

(6)

Other

(6)

Contribution to consolidated net income – 2024

188

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)

(millions of Therms)

2024

2023

2024

2023

Residential

520

537

410

414

Commercial

362

315

824

839

Industrial

(1)

1,620

1,615

Other

(2)

163

147

278

266

Total

(3)

1,114

1,068

3,132

3,134

(1) Industrial gas revenue includes sales to power generation customers.

(2) Other gas revenue includes off-system sales to other utilities and various other items.

(3) Total gas revenue

excludes $46 million of finance income from Brunswick Pipeline (2023 – $46 million).

Regulated Cost of Natural Gas

PGS and NMGC purchase gas from various suppliers depending on the needs of their customers. In

Florida, gas is delivered to the PGS distribution system through interstate pipelines on which PGS has

firm transportation capacity for delivery by PGS to its customers. NMGC’s natural gas is transported on

major interstate pipelines and NMGC’s intrastate transmission and distribution system for delivery to

customers.

In Florida, natural gas service is unbundled for non-residential customers and residential customers who

use more than 1,999 therms annually and elect the option. In New Mexico, NMGC is required, if

requested, to provide transportation-only services for all customer classes. The commodity portion of

bundled sales is included in operating revenues, at the cost of the gas on a pass-through basis, therefore

no net earnings effect when a customer shifts to transportation-only sales.

Annual gas sales by type are summarized in the following table:

Gas Volumes by Type

(millions of Therms)

2024

2023

Transportation

2,434

2,461

System supply

698

673

Total

3,132

3,134

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’s and NMGC’s regulatory environment and recovery mechanisms, refer to

note 7 in the consolidated financial statements.

Other Electric Utilities

Three months ended

Year ended

For the

December 31

millions of USD (except as indicated)

2024

2023

2024

2023

Operating revenues – regulated electric

107

104

413

390

Regulated fuel for generation and purchased power

215

204

Contribution to consolidated adjusted net income

Contribution to consolidated adjusted net income – CAD

Equity securities MTM (loss) gain

(1)

Contribution to consolidated net income

– CAD

Electric sales volumes (GWh)

323

1,307

1,260

Electric production volumes (GWh)

347

345

1,403

1,362

Average fuel cost in dollars per MWh

159

165

153

150

The impact of the change in the FX rate increased CAD earnings and adjusted earnings by $1 million for

the three months and year ended December 31, 2024.

Other Electric Utilities' contribution to consolidated adjusted net income is summarized in the following

table:

Three months ended

Year ended

For the

December 31

millions of USD

2024

2023

2024

2023

BLPC

GBPC

Other

(1)

(3)

Contribution to consolidated adjusted net income

Net Income

Highlights of net income changes are summarized in the following table:

For the

Three months ended

Year ended

millions of USD

December 31

Contribution to consolidated net income – 2023

Increased operating revenues quarter-over-quarter due to the timing of

recovery of fuels costs. Year-over-year increased primarily due to

higher sales volumes.

Increased fuel for generation and purchased power year-over-year due

to higher sales volumes at BLPC.

(11)

Increased OM&G, year-over-year due to higher insurance premiums

and increased generation maintenance costs at GBPC and BLPC.

(8)

Other

Contribution to consolidated net income – 2024

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

7 in the consolidated financial statements.

Other

Three months ended

Year ended

For the

December 31

millions of dollars

2024

2023

2024

2023

Marketing and trading margin

(1) (2)

Other non-regulated operating revenue

Total operating revenues – non-regulated

109

123

Contribution to consolidated adjusted net (loss) income

(59)

(71)

(342)

(314)

Gain on sale of LIL, after-tax (3)(4)

129

Financing structure wind-up

Charges related to wind-down costs and certain asset

impairments, after-tax

(5)

(23)

Charges related to the pending sale of NMGC, after-tax (6)

(217)

MTM (loss) gain, after-tax

(7)

(144)

112

(291)

167

Contribution to consolidated net (loss) income

(146)

(686)

(147)

(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 loss, pre-tax of $159 million in Q4 2024 (2023 – $131 million gain) and a MTM

loss, pre-tax of $357 million for the year ended December 31, 2024 (2023 – $216 million gain).

(3) On June 4, 2024, Emera completed the sale of its LIL equity interest. For further details on the transaction, refer to the

“Significant Items Affecting Earnings” and “Other Developments” sections.

(4) Includes an income tax recovery of $22 million for the three months ended December 31, 2024 and net income tax expense

$53 million for the year ended December 31, 2024 (2023 – nil).

(5) Primarily relates to Block Energy, net of income

tax recovery of $6 million for the year ended December 31, 2024 (2023 – nil).

(6) Includes a goodwill impairment charge of $210 million ($198 million after-tax) and transaction costs of $25 million ($19 million

after-tax) for the year ended December 31, 2024 (2023 – nil).

(7) Net of income tax recovery of $57 million for the three months ended December 31, 2024 (2023 – $44 million

expense) and

$117 million recovery for the year ended December

31, 2024 (2023 – $68 million expense).

Other's contribution to consolidated adjusted net (loss) income is summarized in the following table:

Three months ended

Year ended

For the

December 31

millions of dollars

2024

2023

2024

2023

Emera Energy:

EES

Other

(2)

Corporate – see breakdown of adjusted contribution below

(73)

(91)

(360)

(356)

Block Energy

(4)

(13)

(18)

Other

(1)

(4)

Contribution to consolidated adjusted net (loss) income

(59)

(71)

(342)

(314)

Net Income

Highlights of net income changes are summarized in the following table:

For the

Three months ended

Year ended

millions of dollars

December 31

Contribution to consolidated net (loss) income – 2023

(147)

Decreased marketing and trading margin year-over-year due to

favourable hedging opportunities in Q1 2023 and less favourable

market conditions in 2024, specifically lower natural gas prices and

volatility

(19)

Increased OM&G quarter-over-quarter primarily due to the timing

difference in the valuation of long-term incentive expense and related

hedges

(18)

(2)

Increased interest expense due to the impact of a weaker CAD on USD

interest expense, increased total debt and increased interest rates

(9)

(38)

Corporate FX losses on the translation of USD short-term debt

balances

(5)

(9)

Decreased deferred income tax asset valuation allowance due to the

utilization of tax loss carryforwards

Increased income tax recovery due to increased loss before provision

for income taxes, partially offset by the recognition of investment tax

credits related to Bear Swamp facility upgrades in 2023

Gain on sale of LIL, after-tax

129

Financing structure wind-up

Charges related to wind-down costs and certain asset impairments,

after-tax

(23)

Charges related to the pending sale of NMGC, after-tax

(217)

The 2023 MTM gain, after-tax, decreased to a loss for the same

periods in 2024 due to changes in existing positions, partially offset by

lower amortization of gas transportation assets at EES

(254)

(457)

Other

(4)

Contribution to consolidated net (loss) income – 2024

(146)

(686)

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 US Southeast, Gulf Coast and Midwest, and

Central Canadian and Alberta 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 $16 million in Q4 2024, compared to $19

million in Q4 2023; and $30 million ($21 million USD) for the year ended December 31, 2024, compared

to $46 million ($33 million USD) for the same period in 2023. Market conditions in 2024 were less

favourable compared to 2023 due to lower natural gas prices and volatility.

MTM Adjustments

Emera Energy’s “Marketing and trading margin”, “Non-regulated fuel for generation and purchased

power”, “Income from equity investments” and “Income tax (recovery) expense” are affected by MTM

adjustments. Variance explanations of the MTM changes for this quarter and for the year are explained in

the table above.

Emera Energy has a number of asset management agreements (“AMA”) with counterparties, including

local gas distribution utilities, power utilities and natural gas producers in North America. The AMAs

involve Emera Energy buying or selling gas for a specific term, and the corresponding release of the

counterparties’ gas transportation/storage capacity to Emera Energy. MTM adjustments on these AMAs

arise on the price differential between the point where gas is sourced and where it is delivered. At

inception, the MTM adjustment is offset fully by the value of the corresponding gas transportation asset,

which is amortized over the term of the AMA contract.

Subsequent changes in gas price differentials, to the extent they are not offset by the accounting

amortization of the gas transportation asset, will result in MTM gains or losses recorded in income. MTM

adjustments may be substantial during the term of the contract, especially in the winter months of a

contract when delivered volumes and market pricing are usually at peak levels. As a contract is realized,

and volumes reduce, MTM volatility is expected to decrease. Ultimately, the gas transportation asset and

the MTM adjustment reduce to zero at the end of the contract term. As the business grows, and AMA

volumes increase, MTM volatility resulting in gains and losses may also increase.

Emera Corporate has FX forwards to manage the cash flow risk of forecasted USD cash inflows.

Fluctuations in the FX rate result in MTM gains or losses are recorded in “Other income, net” on the

Consolidated Statements of Income.

Corporate

Corporate's adjusted loss is summarized in the following table:

Three months ended

Year ended

For the

December 31

millions of dollars

2024

2023

2024

2023

Operating expenses

(1)

(23)

(7)

(74)

(73)

Interest expense

(97)

(88)

(367)

(329)

Income tax recovery

170

111

Preferred dividends

(19)

(18)

(73)

(66)

Other

(2)(3)

(10)

(3)

(16)

Corporate adjusted net loss

(4)(5)(6)(7)

(73)

(91)

(360)

(356)

(1) Operating expenses include OM&G and depreciation.

(2) Other includes realized 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 $5 million ($4 million after-tax) for the three months ended December 31, 2024

(2023 – $4

million net loss, pre-tax and $3 million loss, after-tax) and a $12 million net loss, pre-tax ($9 million after-tax) for the year

ended

December 31, 2024 (2023 – $11 million

net loss, pre-tax and $8 million loss after-tax) on FX hedges, as discussed above.

(4) Excludes a MTM loss, after-tax of $25 million for the three months ended December 31, 2024 (2023 – $15 million gain, after-tax)

and a MTM loss, after-tax of $31 million for the year ended December 31, 2024 (2023 – $20 million gain, after-tax).

(5) Excludes a gain on sale of LIL, after-tax, of $107 million for the year ended December 31, 2024 (2023 – nil).

(6) Excludes certain charges related to the pending sale of NMGC of $234 million ($217 million after-tax) for the year ended

December 31, 2024 (2023 – nil).

(7) Excludes the tax recovery of $58 million related to a specific financing structure and its wind-up and $22 million

on reversal of a

prior year valuation allowance related to the sale of LIL for the three months and year ended December 31, 2024 (2023

– nil).

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 and storm 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 that they 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 $20 billion capital investment plan over the 2025 through 2029 period and

supports ongoing growth. Capital investments at Emera’s regulated utilities are subject to regulatory

approval.

Emera currently has a strong liquidity position and ability to service debt obligations as they come due to

meet any near-term capital investment requirements as currently planned. Emera plans to use cash from

operations, debt raised at the utilities, Corporate equity, and proceeds from the pending sale of NMGC 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, Corporate 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 total committed credit facilities with varying maturities that cumulatively provide $2.3 billion

CAD and $1.6 billion USD of credit, with approximately $1.1 billion CAD and $593 million USD undrawn

and available at December 31, 2024. The Company was holding a cash balance of $204 million, which

includes $8 million classified as assets held for sale, related to the pending sale of NMGC, at December

31, 2024. For further discussion, refer to the “Debt Management” section below.

Consolidated Cash Flow Highlights

Significant changes in the Consolidated Statements of Cash Flows between the years ended December

31, 2024 and 2023 include:

millions of dollars

2024

2023

$ Change

Cash, cash equivalents and restricted cash, beginning of period

588

332

256

Provided by (used in):

Operating cash flow before changes in working capital

2,194

2,336

(142)

Change in working capital

452

(95)

547

Operating activities

2,646

2,241

405

Investing activities

(2,218)

(2,917)

699

Financing activities

(818)

939

(1,757)

Effect of exchange rate changes on cash, cash equivalents, restricted cash, and

cash associated with assets held for sale

(7)

Cash, cash equivalents, restricted cash, and cash associated with assets held

for sale, end of period

221

588

(367)

Cash Flow from Operating Activities

Net cash provided by operating activities increased

$405 million to $2,646 million for the year ended

December 31, 2024, compared to $2,241 million in 2023.

Cash from operations before changes in working capital decreased

$142 million for the year ended

December 31, 2024. This decrease was due to increased storm cost recovery regulatory asset related to

Hurricane Helene and Hurricane Milton at TEC, lower fuel clause recoveries at TEC, and the reversal of

the Nova Scotia Cap-and-Trade Program provision in Q1 2023 at NSPI. These were partially offset by the

NSPML Refund, favourable change in regulatory liabilities due to the 2023 gas hedge settlements at

NMGC, increased electric revenue at NSPI, proceeds from the FAM asset sale to Invest Nova Scotia at

NSPI, and increased earnings and the recovery of the conservation clause expense at PGS.

Changes in working capital increased operating cash flows by $547 million for the year ended December

31, 2024. This increase was due to increased accounts payable at TEC due to Hurricane Helene and

Hurricane Milton storm cost accruals, favourable changes in cash collateral positions at NSPI, lower

accounts receivable at TEC, reversal of the Nova Scotia Cap-and-Trade Program provision in Q1 2023 at

NSPI, favourable changes in fuel inventory at NSPI and TEC, and favourable changes in accounts

payable at NSPI, NMGC, and PGS. These were partially offset by unfavourable changes in cash

collateral positions at EES, unfavourable changes in accounts receivable at NMGC due to the receipt of

the 2023 gas hedge settlement, unfavourable changes in natural gas inventory at EES, and unfavourable

changes in accounts receivable at NSPI.

Cash Flow used in Investing Activities

Net cash used in investing activities decreased $699 million to $2,218 million for the year ended

December 31, 2024, compared to $2,917 million in 2023. The decrease was primarily due to the

proceeds of $927 million received on the sale of Emera’s LIL equity interest, partially offset by higher

capital investment in 2024.

Capital expenditures for the year ended December 31, 2024, including AFUDC, were $3,206 million

compared to $2,976 million in 2023. Details of 2024 capital spending by segment are shown below:

●

$1,998 million – Florida Electric Utility (2023 – $1,771 million);

●

$494 million – Canadian Electric Utilities (2023 – $461 million);

●

$626 million – Gas Utilities and Infrastructure (2023 – $673 million);

●

$81 million – Other Electric Utilities (2023 – $63 million); and

●

$7 million – Other (2023 – $8 million).

Cash Flow from Financing Activities

Net cash used in financing activities decreased $1,757 million to $818 million for the year ended

December 31, 2024, compared to net cash provided by financing activities of $939 million in 2023. This

decrease was due to lower issuance of long-term debt at PGS, NSPI, and NMGC, higher repayment of

Emera's committed credit facilities using the LIL transaction proceeds, retirement of long-term debt at

Emera, TEC and NMGC, and higher net repayments under committed credit facilities at NSPI. These

were partially offset by proceeds from the fixed-to-fixed reset rate junior subordinated notes issuance by

EUSHI Finance Inc., lower short-term debt repayments at TEC, and issuance of long-term debt at TEC.

Working Capital

As at December 31, 2024, Emera’s cash and cash equivalents were $196 million (2023 – $567 million)

and Emera’s investment in non-cash working capital was $224 million (2023 – $831 million). Of the cash

and cash equivalents held at December 31, 2024, $185 million was held by Emera’s foreign subsidiaries

(2023 – $482 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, 2024, contractual commitments for each of the next five years and in aggregate

thereafter consisted of the following:

millions of dollars

2025

2026

2027

2028

2029

Thereafter

Total

Long-term debt principal

(1)

234

3,279

120

651

1,764

13,192

19,240

Interest payment obligations

(2)(3)

884

799

712

705

636

8,210

11,946

Purchased power

(4)

307

277

368

369

4,487

6,176

Transportation

(5)(6)

742

545

544

454

412

3,228

5,925

Capital projects

604

287

915

Fuel, gas supply and storage

(7)

591

711

Pension and post-retirement

obligations

(8)

224

500

Asset retirement obligations

422

436

Other

160

264

717

3,562

5,409

1,938

2,316

3,314

30,027

46,566

As detailed below, contractual obligations at December 31, 2024 includes

those related to NMGC. On completion of the sale of

NMGC, all remaining future contractual obligations will be transferred to the buyer.

For further details on the pending transaction,

refer to the "Other Developments" section.

(1) Includes $696 million related to NMGC (2026: $100 million, and $576 million thereafter).

(2) 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,

2024, including any expected

required payment under associated swap agreements.

(3) Includes $353 million related to NMGC (2025: $26 million, 2026: $26 million, 2027: $23 million, 2028: $23 million,

2029: $23

million, and $232 million thereafter).

(4) Annual requirement to purchase electricity from IPPs or other utilities over varying contract lengths.

(5) Purchasing commitments for transportation of fuel and transportation capacity on various pipelines.

Includes a commitment of

$135 million related to a gas transportation contract between PGS and SeaCoast through 2040.

(6) Includes $86 million related to NMGC (2025: $30 million, 2026: $24 million, 2027: $16 million, 2028: $12 million,

and 2029: $4

million).

(7) Includes $177 million related to NMGC (2025: $109 million, 2026: $52 million, 2027: $13 million, and 2028: $3 million).

(8) Includes the estimated contractual obligation, which is calculated as the current legislatively required contributions

to the

registered funded pension plans, 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.

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 November 2024, the UARB approved the collection of up to

$197 million from NSPI for the recovery of Maritime Link costs in 2025. The timing and amounts payable

to NSPML for the remainder of the 38-year commitment period are subject to UARB approval.

Emera has committed to obtain certain transmission rights in New Brunswick during summer periods

(April through October, inclusive) for NLH's use, if requested, 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 2025 forecasted consolidated capital investments, including AFUDC, are as follows:

millions of dollars

Florida

Electric

Utility

Canadian

Electric

Utilities

Gas Utilities

and

Infrastructure

Other

Electric

Utilities

Other

Total

Generation

358

117

507

New renewable generation

567

648

Electric transmission

169

188

410

Electric distribution

614

140

754

Gas transmission and distribution

481

Facilities, equipment, vehicles, and other

547

620

2,255

485

486

189

3,420

Debt Management

In addition to funds generated from operations, Emera and its subsidiaries have, in aggregate, access to

unsecured committed syndicated revolving and non-revolving bank lines of credit in either CAD or USD

per the table below.

Undrawn

Credit

and

millions of dollars in currency as noted below

Maturity

Facilities

Utilized

Available

In CAD:

Emera – committed revolving credit facility

June 2029

1,300

792

508

NSPI – committed revolving credit facility

June 2029

800

189

611

Emera – non-revolving facility

February 2026

200

In USD:

TEC – committed revolving credit facility

December 2028

800

637

163

TECO Finance – committed revolving credit facility

December 2028

400

184

216

PGS – revolving facility

December 2028

250

138

112

NMGC – revolving credit facility

December 2026

125

Other – committed revolving credit facilities

Various

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, 2024.

Emera’s significant covenant is listed below:

As at

Financial Covenant

Requirement

December 31, 2024

Emera

Syndicated credit facilities

Debt to capital ratio

Less than or equal to 0.70 to 1

0.55 : 1

Recent significant financing activity for Emera and its subsidiaries are discussed below by segment:

Florida Electric Utilities

On July 12, 2024, TEC repaid a $300 million USD note upon maturity. This note was repaid with

proceeds from commercial paper.

On April 1, 2024, TEC amended its $800 million USD unsecured committed revolving credit facility to

extend the maturity date from December 17, 2026 to December 1, 2028. There were no other changes in

commercial terms from the prior agreement.

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.

Canadian Electric Utilities

On June 24, 2024, NSPI amended its unsecured non-revolving credit facility to extend the maturity date

from July 15, 2024 to June 24, 2025 and reduce the facility from $400 million to $300 million. On

December 16, 2024, NSPI repaid the $300 million unsecured non-revolving credit facility using the net

proceeds from the NSPML debt issuance transferred to NSPI as approved by the UARB. For more

information on the FLG, refer to the “Business Overview and Outlook – Canadian Electric Utilities”

section.

On June 24, 2024, NSPI amended its unsecured committed revolving credit facility to extend the maturity

date from December 16, 2027 to June 24, 2029. There were no other material changes in commercial

terms from the prior agreement.

On June 13, 2024, NSPI entered a non-revolving credit facility to finance the Battery Energy Storage

Project. NSPI can request funds under the facility quarterly for amounts related to incurred project costs

up to the total commitment of the lessor of $120 million and 45.06 per cent of the total eligible project

costs over the term of the agreement. The facility will be available until 6 months after completion of the

project, not to exceed May 21, 2027, and matures 20 years following the end of the period. As at

December 31, 2024, NSPI had utilized $19 million from the facility, which bears interest at 2.51 per cent.

Gas Utilities and Infrastructure

On December 10, 2024, Brunswick Pipeline amended its non-revolving loan agreement. The maturity

date was extended to December 2028 and now includes annual principal repayments.

On July 30, 2024, NMGI repaid its $150 million USD fixed rate notes upon maturity.

Other Electric Utilities

On May 2, 2024, BLPC amended its $92 million Barbadian dollar ($46 million USD) loan facility to extend

the maturity date from February 19, 2025 to July 19, 2028. There were no other material changes in

commercial terms from the prior agreement.

Other

On June 24, 2024, Emera amended its unsecured committed revolving credit facility increasing the facility

from $900 million to $1,300 million. Emera also extended the maturity date from June 24, 2027 to June

24, 2029. There were no other material changes in commercial terms from the prior agreement.

On June 24, 2024, Emera repaid its $400 million unsecured non-revolving credit facility set to mature in

August 2024.

On June 18, 2024, EUSHI Finance completed an issuance of $500 million USD fixed-to-fixed reset rate

junior subordinated notes. The notes initially bear interest at a rate of 7.625 per cent, and will reset on

December 15, 2029, and every five years thereafter, to a rate per annum equal to the five-year U.S.

treasury rate plus 3.136 per cent. The notes mature on December 15, 2054. EUSHI Finance, at its option,

may redeem the notes, in whole or in part, 90 days prior to the first interest reset date, and any semi-

annual interest payment date thereafter, at a redemption price equal to the principal amount.

Proceeds from the $500 million USD note issuance discussed above were used to repay an Emera US

Finance LP $300 million USD senior note upon maturity in June 2024, and to repay an NMGI $150 million

USD fixed rate notes upon maturity in July 2024. The remaining proceeds were used for general

corporate purposes.

On June 17, 2024, Emera repaid $200 million on the December 2024 unsecured non-revolving facility,

decreasing the facility from $400 million to $200 million. In December 2024, Emera repaid the $200

million upon maturity.

On April 1, 2024, TECO Finance amended its $400 million USD unsecured committed revolving credit

facility to extend the maturity date from December 17, 2026 to December 1, 2028. There were no other

changes in commercial terms from the prior agreement.

On February 16, 2024, Emera amended its $400 million unsecured non-revolving facility to extend the

maturity date from February 19, 2024 to February 19, 2025. There were no other changes in commercial

terms from the prior agreement. On July 19, 2024, Emera reduced the amount of the facility from $400

million to $200 million. On February 20, 2025, Emera extended the agreement for an additional year to

February 2026 with no other changes in terms. This facility was classified as long-term debt at December

31, 2024.

Credit Ratings

Emera and its subsidiaries have been assigned the following senior unsecured debt ratings:

Fitch

S&P

Moody's

DBRS

Emera

(1)

BBB (Negative)

BBB- (Stable)

Baa3 (Negative)

N/A

TEC

(1)

A (Negative)

BBB+ (Stable)

A3 (Negative)

N/A

PGS

A (Negative)

N/A

NMGC

(2)

BBB+ (Stable)

N/A

NSPI

(1)

N/A

BBB- (Stable)

N/A

BBB (high)(stable)

(1) On January 22, 2025, Standard and Poor’s (“S&P") revised its outlook on Emera and its subsidiaries to stable from negative with

no change to existing ratings.

(2) On May 30, 2024, Fitch Ratings (“Fitch”) revised NMGC’s outlook to stable from negative.

Guaranteed Debt

As of December 31, 2024, the Company had $2.95 billion USD (2023 – $2.75 billion USD) senior

unsecured notes and junior subordinated notes (collectively referred to as the "US Notes”) outstanding.

The US Notes are fully and unconditionally guaranteed, on a joint and several basis, and in the case of

the fixed-to-fixed reset rate junior subordinated notes due 2054 only, on a joint, several and subordinated

basis, by Emera and Emera US Holdings Inc. (“EUSHI”) (in such capacity, the “Guarantor Subsidiaries”).

Emera owns, directly or indirectly, all of the limited and general partnership interests in Emera US

Finance LP.

EUSHI Finance is owned indirectly by Emera through EUSHI.

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, EUSHI, Emera US Finance LP and EUSHI Finance (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

2024

2023

Loss from operations

(279)

(62)

Net gains

(1)

442

394

(1) Includes $1,352 million (2023 – $962 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

2024

2023

Current assets

(1)

391

272

Goodwill

5,858

5,871

Other assets

(2)

6,474

6,263

Total assets

(3)

12,723

12,406

Current liabilities

(4)

611

1,264

Long-term liabilities

(5)

13,129

11,956

Total liabilities

13,740

13,220

(1) Includes $217 million (2023 – $178 million) in amounts due from non-guarantor subsidiaries.

(2) Includes $5,937 million (2023 – $5,906 million) in amounts due from non-guarantor subsidiaries.

(3) Excludes investments in non-guarantor subsidiaries. Consolidated Emera total assets are $42,951 million

(2023 – $39,480 million).

(4) Includes $184 million (2023 – $167 million) due to non-guarantor subsidiaries.

(5) Includes $5,980 million (2023 – $5,854 million) due to non-guarantor subsidiaries.

Outstanding Stock Data

Common Stock

millions of

Issued and outstanding:

dollars

Balance, December 31, 2023

284.12

8,462

Issuance of common stock under ATM program

(1)

5.12

261

Issued under the DRIP,

net of discounts

6.10

291

Senior management stock options exercised and Employee Share Purchase Plan

0.60

Balance, December 31, 2024

295.94

9,042

(1) For the year ended December 31, 2024, a total of 5,117,273

common shares were issued under Emera's ATM program

at an

average price of $51.52 per share for gross proceeds of $264 million ($261 million, net of after-tax issuance costs). As at

December 31, 2024, an aggregate gross sales limit of $336 million remained available for issuance under the ATM

program.

As at February 14, 2025, the amount of issued and outstanding common shares was 297.7 million.

If all outstanding stock options were converted as at February 14, 2025, an additional 3.8 million common

shares would be issued and outstanding.

ATM Equity Program

On November 18, 2024, Emera increased the size of the ATM Program to allow the Company to issue up

to $1 billion 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 increased by an amendment dated November 18,

2024 to its prospectus supplement dated November 14, 2023 and an amendment dated November 13,

2024 to its short form base shelf prospectus dated October 3, 2023.

Preferred Stock

As at February 19, 2025, 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 January 8, 2025, Emera announced that it would not redeem the outstanding Series F preferred

shares on February 15, 2025. During the conversion period between January 15, 2025 and January 31,

2025, subject to certain conditions, the holders of Series F shares had the right, at their option, to convert

all or any of their Series F shares, on a one-for-one basis into Cumulative Floating Rate First Preferred

Shares, Series G on February 15, 2025.

On January 16, 2025, Emera announced that the annual fixed dividend per share for Series F shares will

be reset from $1.0505 to $1.4372 for the five-year period from and including February 15, 2025.

On February 6, 2025, Emera announced after having taken into account all conversion notices received

from holders none of the Series F preferred shares were converted to Series G preferred shares.

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 multi-year period. Expected cash flow

for DB pension plans is $41 million in 2025 (2024 – $36 million). All pension plan contributions are tax

deductible and will be funded with cash from operations.

Emera’s DB pension plans employ a long-term strategic approach with respect to asset allocation, real

return and risk. The underlying objective is to earn an appropriate return, given the Company’s goal of

preserving capital with an acceptable level of risk for the pension fund investments.

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 $56 million for 2025 (2024 –

$51 million).

Defined Benefit Pension Plan Summary

in millions of dollars

Plans by region

TECO Holdings

NSPI

Caribbean

Total

Assets as at December 31, 2024

987

1,495

2,493

Accounting obligation at December 31, 2024

970

1,380

2,367

Accounting expense (income) during fiscal 2024

(11)

(3)

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,

2024 totalled $200 million (2023 – $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 were not included within the Consolidated Balance Sheets as at

December 31, 2024:

TECO Holdings, Inc. (“TECO Holdings”) has 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. The counterparty has the right to require TECO Holdings to provide replacement credit

support either in the form of a substitute guarantee from an affiliate with an investment grade credit rating

or a letter of credit or cash deposit of $27 million USD.

TECO Holdings has 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. The

counterparty has the right to require TECO Holdings to provide replacement credit support in the form of

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 has 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 guarantees on behalf of its subsidiary, NS Power Energy Marketing Incorporated, in the amount

of $104 million USD (2023 – $104 million USD) with terms of varying lengths.

The Company has standby letters of credit and surety bonds in the amount of $105 million USD

(December 31, 2023 – $103 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, 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 2025. The amount committed

as at December 31, 2024 was $58 million (December 31, 2023 – $56 million).

Emera has provided an indemnity to a counterparty in relation to certain future tax amounts that could

arise from specific future changes in Canadian federal law, subject to certain conditions and limitations.

No such changes in law have been proposed at this time. A reasonable estimate of the potential amount

of future payments that could result from future claims under this indemnity cannot be calculated, but the

risk of having to make any significant payments under this indemnity is considered to be remote.

DIVIDEND PAYOUT

RATIO

Emera has provided annual dividend growth guidance of one to two per cent per year. On September 18,

2024, the Board approved an increase in the annual common share dividend rate to $2.9000 from

$2.8700 per common share. The first quarterly dividend payment at the increased rate was paid on

November 15, 2024.

Emera’s common share dividends paid in 2024 were $2.8775 ($0.7175 in Q1, Q2, and Q3 and $0.7250 in

Q4) per common share and for 2023 were $2.7875 ($0.6900 in Q1, Q2, and Q3 and $0.7175 in Q4) per

common share. This represents a dividend payout ratio of net income of 168 per cent in 2024 (2023 – 78

per cent) and a dividend payout ratio of adjusted net income of 98 per cent in 2024 (2023 – 94 per cent).

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 a recovery of $324 million for the year ended December 31, 2024 (2023 –

$163 million expense). 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 –

NSPML” 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 $

million for the year ended December 31, 2024 (2023

– $14 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, 2024 and at December 31, 2023.

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 risks are appropriately identified, assessed,

monitored and subject to appropriate controls. The Board has a Risk and Sustainability Committee

(“RSC”) 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.

The significant business risks to Emera are described below, many of which are beyond the Company’s

control, and could have a material adverse effect on Emera or its subsidiaries, or their business

operations, liquidity or access to or cost of capital, financial position, prospects, and/or results of

operations (herein considered a “Material Adverse Effect”). The nature of risk is such that no such list is

comprehensive, and the actual effect of any of the risks discussed could be materially different from what

is described below. Additionally,

other risks not presently known may arise, risks not currently considered

material may become material in the future, or two or more risks which are not themselves material, could

together be material.

Regulatory and Political Risk

The Company’s rate-regulated subsidiaries and certain investments are subject to complex legislative

and regulatory frameworks that cover material aspects of their businesses. These frameworks influence

key factors such as rates and cost structures, revenue requirements, allowed ROEs, capital structures,

rate base and capital investments, and the recovery of purchased electricity and fuel costs and other

costs. Regulators also review the prudency of costs and make other decisions that can impact customer

rates and the reliability of service. Emera’s cost-of-service utilities must obtain regulatory approvals for

material aspects of their businesses, including changing or adding rates and/or riders. Such approvals

often require public hearing proceedings involving numerous stakeholders, and there is no assurance in

the outcomes or impact of any regulatory process or decision.

If Emera is unable to recover in a timely manner a material amount of costs or a return on invested capital

through regulatory mechanisms or otherwise, is disallowed the recovery of certain costs, is subject to

regulatory penalties, is not permitted to make certain capital investments, or is not permitted to invest in or

divest certain utility assets, it could result in a Material Adverse Effect, including valuation impairments.

Regulatory lag, the time between the incurrence of costs and the granting of the rates to recover those

costs by regulators, may also result in a Material Adverse Effect.

Aspects of the acquisition, ownership, operations, siting, planning, construction, and decommissioning of

electric generation, storage, transmission and distribution facilities and natural gas transportation and

distribution systems are also subject to regulatory processes and approvals of regulators, government

departments and agencies, and other third parties. The failure to obtain, maintain, and renew such

approvals or significant changes in the terms and conditions thereof could have a Material Adverse Effect.

The regulatory framework, process and regulatory decisions may also be adversely affected by changes

in government, shifts in government or public policy, legislative changes, regulatory decisions, geopolitical

changes, changes in the economic environment, or other factors. Government interference in the

regulatory process or regulatory decisions can undermine regulatory stability, predictability,

and

independence. Any such changes could have a Material Adverse Effect.

Change in Law Risk

The Company is also exposed to changes in the political environment and leadership, changes in law or

regulations, changes to governmental policies, trade disputes, and the imposition of tariffs, any of which

may impact the Company’s businesses, the markets for energy and inputs thereto, or general economic

conditions, and which may result in a Material Adverse Effect. This may include initiatives regarding

deregulation or restructuring of the energy industry, which may result in increased competition, and

increased or unrecovered costs. State and local policies in some US 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.

Emera cannot predict future legislative, policy, or regulatory changes, whether caused by economic,

political or other factors, or the resulting operating or compliance costs or other impacts. It may be difficult

for Emera to respond in an effective and timely manner to such future legislative, policy or regulatory

changes.

Environmental Legislation

Emera is subject to extensive regulation by federal, provincial, state, regional and local authorities

regarding environmental matters, primarily related to its utility operations. This includes laws, regulations

and policies relating to GHG emissions, renewable energy standards, climate change, air quality, water

quality and usage, waste management, wastewater discharges, soil quality, aquatic and terrestrial

habitats, hazardous waste, health, endangered species, and wildlife mortality.

In some jurisdictions where Emera operates, government legislation and policy has included timelines for

mandated shutdowns of coal-fired generating facilities, has required a certain percentage of electricity be

generated from renewables, carbon pricing, emissions limits and cap and trade mechanisms. Over the

medium and long terms, these 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.

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 and

reductions in GHG emissions, as well as the goal to phase out coal-fired electricity generation by 2030.

The Government of Canada has also enacted regulations imposing emissions standards on coal-fired

generation that would effectively require the decommissioning of such facilities. While Nova Scotia is

exempted from such regulations through 2029, there is no guarantee that such exemption will continue

into the future. Failure to meet such goals by 2030 or comply with applicable legislation or regulation

could result in a Material Adverse Effect.

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 and could result in a Material Adverse

Effect.

These and new or revised environmental laws, regulations, policies, or interpretations of those laws,

regulations or policies could result in a Material Adverse Effect by, among other things, preventing or

delaying the development of energy infrastructure projects, restricting the use or output of certain

facilities, requiring the early retirement of certain generation facilities that could result in stranded costs,

limiting the availability or use of certain fuels required for the production of electricity, requiring additional

pollution control equipment, curtailing sales of natural gas to new customers, which could reduce future

customer growth in Emera’s natural gas businesses, changing the nature and timing of capital

investments, requiring significant capital investments, imposing operating or other costs associated with

compliance including carbon taxes or emissions allowances, or by limiting or eliminating certain

operations or rendering such operations uneconomical.

Impacts could be more significant in the future as

the result of new or revised laws or requirements or stricter or more expansive application of existing

environmental laws, regulations and policies. Failure to recover environmental costs in a timely manner

through rates may also result in a Material Adverse Effect.

In addition to imposing continuing compliance obligations, there are permit requirements, laws and

regulations authorizing the imposition of penalties for non-compliance, exposing Emera to legal or

regulatory proceedings, disputes, civil fines, injunctive relief, criminal penalties and other sanctions, which

could result in a Material Adverse Effect.

Weather Risk

A Material Adverse Effect may arise from weather seasonal variations impacting energy consumption, as

well as severe weather events, changing air temperatures, wildfires and other severe weather conditions

that are expected to become more frequent and intense as a result of climate change. Refer to “Climate

Change Risk”.

The temperature, seasonal variations, and other weather conditions significantly influence the availability

and demand for electricity and natural gas by customers, the price of energy commodities, such as fuel

used by the Company’s utilities, and the production of electricity at power generation facilities. For

example, NSPI could see lower sales in winter months if temperatures are warmer than expected.

Severe weather events or conditions such as hurricanes, floods, storm surge, tornadoes, droughts, fires,

extreme temperatures, snow or ice storms, and other natural disasters create a risk of physical damage to

the Company’s assets and a risk of extended service outages or fuel supply disruptions.

For example,

high winds can cause widespread damage to transmission and distribution infrastructure, solar

generation, and wind-powered generation. 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.

Severe weather events or conditions could reduce revenues and require the Company to incur additional

costs, such as repair and replacement costs, costs of replacement power and fuel, increased insurance

costs, and the need to access additional financing sources. These could result in a Material Adverse

Effect if not resolved or mitigated in a timely and efficient manner through insurance or regulatory cost

recovery. 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 after the fact through the establishment of regulatory assets. Recovery is not assured, is subject to

prudency review, and may be subject to delay resulting in increased debt and debt servicing costs.

Severe weather events or other catastrophic natural disasters could also result in long-term reductions in

demand for electricity or natural gas or the slowing of customer growth in one or more of the Company’s

service territories, which could have a Material Adverse Effect. The impact of extreme weather events

would be amplified if the same events affect multiple utilities in the Company’s portfolio.

High winds and lack of precipitation also increase the risk of wildfires resulting from the Company’s

infrastructure or for which the Company may otherwise have responsibility. 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 or if recovery is delayed, they could result in a Material Adverse Effect. Resulting

costs could include fire suppression costs, regeneration, timber value, increased insurance costs and

costs arising from damages and losses incurred by third parties.

The Company purchases power from third-party owned hydroelectricity sources and 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.

Climate Change Risk

Physical Risk:

Climate change may negatively impact the Company’s operations as a result of increased frequency and

intensity of weather events and related physical risks, any of which could result in a Material Adverse

Effect (for more information refer to “Weather Risk” and “System Operating and Maintenance Risks”). An

increase in physical risk associated with climate change can also adversely impact the cost and

availability of insurance, insurance deductibles and self-retention, as well as credit ratings, which could

affect credit risk spreads on new long-term debt and credit facilities, as well as their availability (refer to

“Liquidity and Capital Markets Risk”).

Transition Risk:

As government policy and the economy transition toward decarbonization in many jurisdictions, the

Company is exposed to risks arising from policy, legal, technology,

and market changes, which could

result in a Material Adverse Effect. The energy transition will require the Company to address changes to

environmental policies, laws and regulations which are being proposed and adopted in many jurisdictions

in response to concerns regarding the effects or impacts of climate change (refer to “Environmental

Legislation”). The pace of such new initiatives is expected to accelerate in some jurisdictions.

The Company will be required to manage the impacts of these changes on customer demand and rates,

while integrating increased amounts of intermittent renewable energy sources and new technologies,

implementing and making the investments required to meet new resiliency and security standards, and

adapting the Company’s infrastructure and generating capacity to meet changing customer demands and

usage patterns. The energy transition and the ability of the Company to achieve mandated climate related

targets and goals will require significant capital investment, effective engagement with policymakers,

regulators and stakeholders, and depend upon many factors which are outside of the Company’s direct

control. 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.

Given concerns regarding carbon-emitting generation, assets and businesses may, over time, become

difficult or uneconomic to insure in commercial insurance markets. Some 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 less insurance capacity, more restrictive coverage

and increased premiums. The Company could also face litigation or regulatory action related to

environmental harms from GHG emissions or failure to substantiate certain environmental claims.

The failure to effectively respond to climate change transition risks could adversely affect the Company’s

ability to deliver safe, reliable, and cost-effective service, the Company’s reputation with stakeholders, its

ability to operate and grow, and the Company’s access to, and cost of, capital, each of which could result

in a Material Adverse Effect.

Cybersecurity Risk

Emera is exposed to potential risks related to cyberattacks, data breaches, cyber-extortion, and

unauthorized access that could result in a Material Adverse Effect. 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 energy infrastructure, 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, by increasing the sophistication, magnitude, and frequency of cyberattacks.

Cyberattacks can reach the Company’s assets and information via their interfaces with third parties or the

public internet and gain access to critical and non-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, links in e-mails or other communications, or social engineering. The methods used by

attackers are continuously evolving and can be difficult to predict and detect and may become more

sophisticated, frequent, severe, and difficult to stop to the extent that attackers are able to leverage

evolving artificial intelligence models or tools.

Despite security measures in place, the Company’s systems, assets and information could experience

security breaches that could cause system failures, disrupt energy supply and delivery, business

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, compromise billing and customer-facing information, such as outage maps, disrupt internal

control and financial processes, or result in the release, loss, corruption, destruction, and/or misuse of

critical, sensitive, confidential or proprietary information, intellectual property, or personal information of

customers or employees. These breaches could also delay delivery or result in contamination or

degradation of hydrocarbon products the Company transports, stores or distributes.

Cyberattacks or unauthorized access may cause lost revenues, costs, losses, regulatory penalties and

third-party damages all, or some of which may not be recoverable through insurance, legal, regulatory

cost recovery or other processes. 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. This could result in a Material Adverse Effect and there is no assurance that

cyberattacks or other security breaches can be adequately addressed in a timely manner.

The Company seeks to manage these risks by aligning to a common set of cybersecurity standards and

policies derived, in part, on the National Institute of Standards and Technology’s Cyber Security

Framework, periodic security testing, program maturity objectives, cybersecurity incident readiness

program, and employee communication and training. With respect to certain of its assets, the Company is

required to comply with rules and standards relating to cybersecurity and IT including, but not limited to,

those mandated by bodies such as the North American Electric Reliability Corporation, Northeast Power

Coordinating Council, and the United States Department of Homeland Security. The status of key

elements of the Company’s cybersecurity program is reported to the RSC. The Board oversees risk and

mitigation plans in relation to cybersecurity risks and receives a quarterly update in a risk dashboard at

each regularly scheduled Board meeting.

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, data centers, and battery storage. Government policies promoting energy

efficiency, 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 and result in a Material

Adverse Effect.

Foreign Exchange Risk

The Company is exposed to foreign currency exchange rate changes. Emera operates internationally,

with a significant 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.

Emera manages currency risks through matching US denominated debt to finance its US operations and

may use foreign currency derivative instruments to hedge specific transactions and earnings exposure.

The Company may enter FX forward and swap contracts to limit exposure on certain foreign currency

transactions such as fuel purchases, revenue streams and capital expenditures, and on net income

earned outside of Canada. The regulatory framework for the Company’s rate-regulated subsidiaries

permits the recovery of prudently incurred costs, including FX.

The Company does not utilize derivative financial instruments for foreign currency trading or speculative

purposes or to hedge the value of its investments in foreign subsidiaries. Exchange gains and losses on

net investments in foreign subsidiaries do not impact net income as they are reported in Accumulated

Other Comprehensive Income (Loss) ("AOCI”).

Liquidity and Capital Markets Risk

Liquidity risk relates to Emera’s ability to ensure sufficient funds are available to meet its financial

obligations. 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

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.

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 have a Material Adverse Effect. 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.

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 Markets 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.

Public Health Crisis Risk

An outbreak of infectious disease, a pandemic or other public health threats, or a fear of any of the

foregoing, could result in a Material Adverse Effect to Emera and its subsidiaries. This could include

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 investments, capital market activities, and counterparty risk; which could result in a

Material Adverse Effect.

Health and Safety

The Company’s operations inherently involve risk to the health and safety of employees, contractors and

members of the public. Personal injury or loss of life resulting from failure to implement or observe

appropriate health and safety procedures or comply with health and safety laws and regulations could

result in adverse operational, reputational, legal, regulatory, or financial impacts, any of which could have

a Material Adverse Effect.

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 that could result in a Material Adverse Effect 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.

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.

There is no assurance that management strategies will be effective, and significant counterparty defaults

could result in a Material Adverse Effect.

Supply Chain Risk

Emera’s ability to meet customer energy requirements, respond to storm-related disruptions and execute

on the capital investment 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, increase the cost,

or result in shortages of certain materials, fuel, equipment and other resources that are critical to the

Company’s operations. These disruptions may be further exacerbated by inflationary pressures, labour

shortages, more frequent and severe weather events, government incentives increasing demand for

clean energy projects, changes in carbon-related costs, policies and regulations, and the impact of

international conflicts. In addition, global supply chains and the financial condition and results of the

business could be Materially Adversely Affected by the imposition of custom duties or other tariffs, or an

increase in trade restrictions in the future. 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 and could have a Material Adverse Effect.

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. 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 a Material Adverse Effect.

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.

Regulated Utilities:

The Company’s utility fuel supply is exposed to broader global market 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, tariffs, trade sanctions or embargos.

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, any of which could result in a Material Adverse Effect.

Emera Energy Marketing and Trading:

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, imposition of tariffs, 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.

Future Employee Benefit Plan Performance and Funding Risk

Emera subsidiaries have both defined benefit and defined contribution employee pension plans that cover

employees and retirees. All defined benefit plans are closed to new entrants, except for the TECO

Holdings 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. The three 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 have a Material

Adverse Effect.

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 have a

Material Adverse Effect.

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 a Material Adverse Effect.

IT Risk

Emera relies on various IT systems to manage operations, including increasing reliance on IT solutions

operated by third parties, such as software as a service and third-party cloud hosting. 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.

Income Tax Risk

The computation of the Company’s provision for income taxes is impacted by changes in tax legislation in

Canada, the US and the Caribbean and any such changes could have a Material Adverse Effect. 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.

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, human error, damage to facilities, 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. Electric utility and natural gas transmission

and distribution pipeline operation interruption could negatively affect customer and public confidence,

and public safety and have a Material Adverse Effect.

Insurance, warranties, or recovery through regulatory mechanisms may not cover any or all these losses,

which could have a Material Adverse Effect.

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. A significant portion of Emera’s electric utilities’

transmission and distribution assets and its gas utilities’ distribution assets are not insured, as is

customary in the industry, as the cost of coverage is prohibitive. 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 will be covered by insurance.

The occurrence of significant uninsured claims, claims in excess of the insurance coverage limits, or

claims that fall within a significant self-insured retention could have a Material Adverse Effect, if regulatory

recovery is not available.

RISK MANAGEMENT INCLUDING FINANCIAL

INSTRUMENTS

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 and PGS have no derivatives related to hedging.

Derivatives that do not meet any of the above criteria are designated as HFT, with changes in FV

normally recorded in net income of the period. The Company has not elected to designate any derivatives

to be included in the HFT category where another accounting treatment would apply.

Derivative Assets and Liabilities Recognized on the Balance Sheet

As at

December 31

millions of dollars

2024

2023

Regulatory Deferral:

Derivative instrument assets

(1)

Derivative instrument liabilities

(2)

(40)

(76)

Regulatory assets

(1)

Regulatory liabilities

(2)

(44)

(17)

Net asset

HFT Derivatives:

Derivative instrument assets

(1)

122

202

Derivatives instruments liabilities

(2)

(542)

(421)

Net liability

(420)

(219)

Other Derivatives:

Derivative instrument assets

(1)

Derivatives instruments liabilities

(2)

(36)

(7)

Net asset (liability)

(36)

(1) Current, other and assets held for sale.

(2) Current, long-term and liabilities associated with assets held for sale.

Realized and Unrealized Gains (Losses) Recognized in Net Income

For the

Year ended December 31

millions of dollars

2024

2023

Regulatory Deferral:

Regulated fuel for generation and purchased power

(1)

(44)

HFT Derivatives:

Non-regulated operating revenues

207

1,037

Other Derivatives:

OM&G

(9)

Other income, net

(56)

Net gains (losses)

(42)

Total net gains

121

1,107

(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

“Regulated fuel for generation and purchased power” when the hedged item is consumed.

As of December 31, 2024, the unrealized gain in AOCI was $12 million, after-tax (December 31, 2023 –

$14 million, after-tax). For the year ended December 31, 2024, unrealized gains of $2 million (2023 – $2

million) have been reclassified from AOCI into interest expense.

DISCLOSURE AND INTERNAL CONTROLS

Management is responsible for establishing and maintaining adequate disclosure controls and

procedures (“DC&P”) and internal control over financial reporting (“ICFR”), as defined in National

Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings (“NI 52-109”). The

Company’s internal control framework is based on 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, 2024 to

provide reasonable assurance regarding the reliability of financial reporting in accordance with USGAAP.

Management recognizes the inherent limitations in internal control systems, no matter how well designed.

Control systems determined to be appropriately designed can only provide reasonable assurance with

respect to the reliability of financial reporting and may not prevent or detect all misstatements.

There were no changes in the Company’s ICFR, during the year ended December 31, 2024, 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, 2024, the Company had recorded $3,427 million (2023 – $3,105 million) of regulatory

assets and $1,880 million (2023 – $1,772 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, 2024, the balance of the Accumulated reserve – COR

within regulatory liabilities was $733 million (2023 – $849 million).

Pension and Other Post-Retirement Employee Benefits

The Company provides post-retirement benefits to employees, including defined benefit pension plans.

The cost of providing these benefits is dependent upon many factors that result from actual plan

experience and assumptions of future expectations.

The accounting related to employee post-retirement benefits is a critical accounting estimate. Changes in

the estimated benefit obligation, affected by employee demographics - including age, compensation

levels, employment periods, contribution levels and earnings - could have a material impact on reported

assets, liabilities, accumulated other comprehensive income and results of operations. Changes in key

actuarial assumptions, including anticipated rates of return on plan assets and discount rates used in

determining the accrued benefit obligation and benefit costs, could change annual funding requirements.

This could have a significant impact on the Company’s annual earnings and cash requirements.

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 8.2 years (8.4 years for 2024 benefit cost) for Canadian plans and a

weighted average of 11.6 years for US 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:

2024

2023

Discount rate for

benefit cost

purposes

Expected

return on

plan assets

Discount rate for

benefit cost

purposes

Expected

return on

plan assets

TECO Holdings Group Retirement Plan

5.27%

7.05%

5.55%

7.05%

TECO Holdings Group Supplemental

Executive Retirement Plan

(1)

5.15%

N/A

5.45%/5.31%

N/A

TECO Holdings Group Benefit

Restoration Plan (1)

5.18%

N/A

5.48/5.30/5.49%

N/A

TECO Holdings Post-retirement Health

and Welfare Plan

5.28%

N/A

5.53%/6.14%

N/A

NMGC Retiree Medical Plan

5.28%

4.25%

5.55%

2.50%

NSPI

4.63%, 4.62%

6.00%

5.17%, 5.19%

6.25%

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 $56 million in 2024 (2023 – $43 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 2024 benefit cost of $0.5

million and $3.0 million, respectively (2023 – $0.5 million and $2.5 million).

Unbilled Revenue

Electric and gas revenues are billed on a systematic basis over a one or two-month period for NSPI and a

one-month period for other Emera utilities. At the end of each month, the Company must make an

estimate of energy delivered to customers since the date their meter was last read and determine related

revenues earned but not yet billed. The unbilled revenue is estimated based on several factors, including

current month’s generation, estimated customer usage by class, weather, line losses, inter-period

changes to customer classes and applicable customer rates. Based on the extent of estimates included in

determination of unbilled revenue, actual results may differ from the estimate. At December 31, 2024,

unbilled revenues totalled $342 million (2023 – $363 million) on total regulated operating revenues of

$7,447 million (2023 – $7,235 million).

PP&E

PP&E represents 61 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 $1,135 million for the year ended December 31, 2024 (2023 – $1,019 million).

Goodwill Impairment Assessments

Goodwill is calculated as the excess of the purchase price of an acquired entity over the estimated FV of

identifiable assets acquired, and liabilities assumed at the acquisition date.

Goodwill is subject to assessment for impairment at the reporting unit level annually, or if an event or

change in circumstances indicates that the FV of a reporting unit may be below its carrying value.

Application of the goodwill impairment test requires management judgment on significant assumptions

and estimates. When assessing goodwill for impairment, the Company has the option of first performing a

qualitative assessment to determine whether a quantitative assessment is necessary. In performing a

qualitative assessment, management considers, among other factors, macroeconomic conditions,

industry and market considerations and overall financial performance.

If the Company performs a qualitative assessment and determines it is more likely than not that its FV is

less than its carrying amount, or if the Company chooses to bypass the qualitative assessment, a

quantitative test is performed. The quantitative test compares the FV of the reporting unit to its carrying

amount, including goodwill. If the carrying amount of the reporting unit exceeds its FV, an impairment loss

is recorded. Significant assumptions used in estimating the FV of a reporting unit include discount and

growth rates, rate case assumptions including future cost of capital, valuation of the reporting units' net

operating loss (“NOL”), and projected operating and capital cash flows. Adverse changes in these

assumptions could result in a future material impairment of the goodwill assigned to Emera’s reporting

units.

As of December 31, 2024, Emera’s goodwill represents the excess of the acquisition purchase price for

TECO Energy, Inc. (TEC, PGS and NMGC reporting units) over the FV assigned to identifiable assets

acquired and liabilities assumed. In Q3 2024, Emera entered into an agreement to sell NMGC. As a

result, a quantitative goodwill impairment assessment was performed on the NMGC reporting unit and the

Company recorded a goodwill impairment charge of $210 million ($198 million, after-tax) or $155 million

USD ($146 million USD, after-tax). The reduced NMGC goodwill balance of $303 million is included in the

NMGC disposal unit classified as held for sale. For further details, refer to note 23 in the consolidated

financial statements.

In Q4 2024, a qualitative assessment was performed for TEC, given the significant excess of FV over

carrying amounts calculated during the last quantitative test in Q4 2023. Management concluded it was

more likely than not that the FV of this reporting unit exceeded its carrying amount, including goodwill. As

such, no quantitative testing was required. Given the length of time passed since the last quantitative

impairment test for the PGS reporting unit, Emera elected to bypass a qualitative assessment and

performed a quantitative impairment assessment in Q4 2024 using a combination of the income and

market approach. This assessment estimated that the FV of the PGS reporting unit exceeded its carrying

amount, including goodwill, and as a result no impairment charges were recognized.

As of December 31, 2024, the Company had goodwill with a total carrying amount of $5,858 million

(December 31, 2023 – $5,871 million). The change in the carrying value of goodwill from 2023 to 2024

was primarily a result of the impairment of the goodwill assigned to the NMGC reporting unit and NMGC

goodwill included in disposal units classified as held for sale, partially offset by the effect of the FX

translation of Emera’s foreign affiliates.

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.

In 2024, impairment charges of $19 million ($14 million after-tax) were recognized on certain assets, $8

million of which was included in “Other income, net” with $11 million included in “Impairment Charges” on

the Consolidated Income Statement. No impairment charges related to long-lived assets were recognized

in 2023.

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, 2024, AROs recorded on the balance sheet were $217 million (2023 – $192 million).

The Company estimates the undiscounted amount of cash flow required to settle the obligations is

approximately $453 million (2023 – $426 million), which will be incurred between 2025 and 2061. The

majority of these costs will be incurred between 2028 and 2050.

Financial Instruments

The Company is required to determine the FV of all derivatives except those that qualify for the NPNS

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

The new USGAAP accounting policy that is applicable to, and adopted by the Company in 2024, is

described as follows:

Improvements to Reportable Segment Disclosures

The Company adopted Accounting Standard Update (“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 was effective for annual reporting periods beginning

after December 15, 2023, and for interim periods beginning after December 15, 2024. Adoption of the

standard resulted in additional qualitative disclosures provided in note 5.

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.

Disaggregation of Income Statement Expenses

In November 2024, the FASB issued ASU 2024-03, Income Statement Reporting–Comprehensive

Income–Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement

Expenses. The standard update improves the disclosures about a public business entity’s expenses by

requiring more detailed information about the types of expenses (including purchases of inventory,

employee compensation, depreciation and amortization) included within income statement expense

captions. The guidance will be effective for annual reporting periods beginning after December 15, 2026,

and interim reporting periods beginning after December 15, 2027. Early adoption is permitted. The

standard updates are to be applied prospectively with the option for retrospective application. The

Company is currently evaluating the impact of adoption of the standard update on its consolidated

financial statements disclosures.

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. 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 disclosures.

SUMMARY OF QUARTERLY

RESULTS

For the quarter ended

millions of dollars

(except per share amounts)

2024

2023

Operating revenues

1,763

1,802

1,617

2,018

1,972

1,740

1,418

2,433

Net income attributable to common

shareholders

154

129

207

289

101

560

EPS – basic

0.52

0.01

0.45

0.73

1.04

0.37

0.10

2.07

EPS – diluted

0.52

0.01

0.45

0.73

1.04

0.37

0.10

2.07

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. Quarter-over-quarter variances are discussed further

below.

Q4 2024 compared to Q4 2023

For explanation of variances, refer to the “Consolidated Income Statement Highlights” section.

Q3 2024 compared to Q3 2023

Q3 2024 net income attributable to common shareholders decreased by $97 million and EPS – basic and

diluted decreased by $0.36 compared to Q3 2023. The decreases were primarily due to charges related

to the pending sale of NMGC; decreased earnings at Emera Energy; lower equity earnings from LIL;

lower Corporate income tax recovery due to decreased losses before provision for income taxes;

increased Corporate interest expense due to increased interest rates and increased total debt; and

increased Corporate preferred share dividends. These changes were partially offset by decreased MTM

losses; increased earnings at TEC, PGS, NSPI and NMGC; and lower Corporate OM&G due to the timing

difference in the valuation of long-term incentive expense and related hedges. The change in EPS was

also impacted by an increase in weighted average shares outstanding.

Q2 2024 compared to Q2 2023

Q2 2024 net income attributable to common shareholders increased by $101 million and EPS – basic and

diluted increased by $0.35 compared to Q2 2023. The increases were primarily due to the gain on sale of

LIL, after transaction costs; increased earnings at PGS and TEC; increased Corporate income tax

recovery due to increased losses before provision for income taxes; and decreased MTM losses. These

changes were partially offset by decreased earnings at NMGC and NSPI; higher Corporate interest

expense due to increased interest rates and increased total average debt; and FX losses on the

translation of USD short-term debt balances in Corporate. The change in EPS was also impacted by an

increase in weighted average shares outstanding.

Q1 2024 compared to Q1 2023

Q1 2024 net income attributable to common shareholders decreased by $353 million and EPS – basic

and diluted decreased by $1.34 compared to Q1 2023. The decreases were primarily due to increased

MTM losses; lower earnings at TEC, NMGC, NSPI and EES; increased Corporate OM&G due to the

timing difference in the valuation of long-term incentive expense and related hedges; and increased

Corporate interest expense due to increased total debt. These changes were partially offset by higher

earnings at PGS and NSPML; and higher income tax recovery at Corporate. The change in EPS was also

impacted by an increase in weighted average shares outstanding.

EX-99.3

Exhibit 99.3

EMERA INCORPORATED

Consolidated

Financial Statements

December 31,

2024

and 2023

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 21, 2025

“Scott Balfour”

“Gregory Blunden”

President and Chief Executive Officer

Chief Financial Officer

Report of Independent Registered Public Accounting Firm

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, 2024 and 2023, 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, 2024 and 2023, and the consolidated results

of its operations and its consolidated cash

flows for each of the two years in the period ended December

31, 2024, 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.

Accounting for the effects of rate regulation

Description

of the Matter

As disclosed in note 7 of the consolidated financial statements,

the Company has $3.4

billion in regulatory assets and $1.9 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 $270 million

and liabilities of $690 million,

disclosed in note 16 to the consolidated financial statements,

are measured at FV.

The

Company recognized $207 million in realized and unrealized

gains during the year with

respect to HFT derivatives.

Auditing the Company’s valuation of HFT derivatives

is complex and highly judgmental

due to the complexity of the contract terms and valuation models,

and the significant

estimation required in determining the 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 17 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 21, 2025

Emera Incorporated

Consolidated Statements of Income

For the

Year ended December 31

millions of dollars (except per share amounts)

2024

2023

Operating revenues

Regulated electric

5,872

5,746

Regulated gas

1,575

1,489

Non-regulated

(247)

328

Total

operating revenues (note 6)

7,200

7,563

Operating expenses

Regulated fuel for generation and purchased power

1,992

1,881

Regulated cost of natural gas

396

527

Operating, maintenance and general expenses ("OM&G")

1,918

1,879

Provincial, state, and municipal taxes

427

433

Depreciation and amortization

1,162

1,049

Impairment charges (note 23)

225

Total

operating expenses

6,120

5,769

Income from operations

1,080

1,794

Income from equity investments (note 8)

146

Other income, net (note 9)

203

158

Interest expense, net (note 10)

973

925

Income before provision for income taxes

409

1,173

Income tax (recovery) expense (note 11)

(159)

128

Net income

568

1,045

Non-controlling interest in subsidiaries ("NCI")

Preferred stock dividends

Net income attributable to common shareholders

494

978

Weighted average shares of common stock outstanding (in millions) (note 13)

Basic

289

274

Diluted

289

274

Earnings per common share (note 13)

Basic

1.71

3.57

Diluted

1.71

3.57

Dividends per common share declared

2.8775

2.7875

The accompanying notes are an integral part of these consolidated financial statements.

Emera Incorporated

Consolidated Statements of Comprehensive Income

For the

Year ended December 31

millions of dollars

2024

2023

Net income

568

1,045

Other comprehensive income (loss) ("OCI"), net of tax

Foreign currency translation adjustment

(1)

1,027

(270)

Unrealized (losses) gains on net investment hedges

(2)

(139)

Cash flow hedges – reclassification adjustment for gains included in income

(2)

Unrealized gains on available-for-sale investment

Net change in unrecognized pension and post-retirement benefit obligation

(3)

(39)

OCI

(4)

956

(273)

Comprehensive income

1,524

772

Comprehensive income attributable to NCI

Comprehensive Income of Emera Incorporated

1,523

771

The accompanying notes are an integral part of these consolidated financial statements.

1) Net of tax expense of $

million for the year ended December 31, 2024 (2023

– $

million recovery).

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, 2024 (2023 – $

million expense).

4) Net of tax expense of $

million for the year ended December 31, 2024 (2023

– $

million recovery).

Emera Incorporated

Consolidated Balance Sheets

As at

December 31

millions of dollars

2024

2023

Assets

Current assets

Cash and cash equivalents

196

567

Restricted cash

Inventory (note 15)

781

790

Derivative instruments (notes 16 and 17)

115

174

Regulatory assets (note 7)

595

339

Receivables and other current assets (note 19)

1,811

1,817

Assets held for sale (note 4)

173

3,688

3,708

Property, plant and equipment ("PP&E"),

net of accumulated depreciation

and amortization of $

10,442

and $

9,994

, respectively (note 21)

26,168

24,376

Other assets

Deferred income taxes (note 11)

392

208

Derivative instruments (notes 16 and 17)

Regulatory assets (note 7)

2,832

2,766

Net investment in direct finance and sales type leases (note 20)

610

621

Investments subject to significant influence (note 8)

654

1,402

Goodwill (note 23)

5,858

5,871

Other long-term assets (note 33)

538

462

Assets held for sale (note 4)

2,160

13,095

11,396

Total assets

42,951

39,480

The accompanying notes are an integral part of these consolidated financial statements.

Emera Incorporated

Consolidated Balance Sheets – Continued

As at

December 31

millions of dollars

2024

2023

Liabilities and Equity

Current liabilities

Short-term debt (note 24)

1,400

1,433

Current portion of long-term debt (note 26)

234

676

Accounts payable

1,992

1,454

Derivative instruments (notes 16 and 17)

526

386

Regulatory liabilities (note 7)

262

168

Other current liabilities (note 25)

489

427

Liabilities associated with assets held for sale (note 4)

212

5,115

4,544

Long-term liabilities

Long-term debt (note 26)

18,173

17,689

Deferred income taxes (note 11)

2,331

2,352

Derivative instruments (notes 16 and 17)

118

Regulatory liabilities (note 7)

1,618

1,604

Pension and post-retirement liabilities (note 22)

274

265

Other long-term liabilities (note 8 and 27)

910

820

Liabilities associated with assets held for sale (note 4)

1,148

24,545

22,848

Equity

Common stock (note 12)

9,042

8,462

Cumulative preferred stock (note 29)

1,422

Contributed surplus

Accumulated other comprehensive income ("AOCI') (note 14)

1,261

305

Retained earnings

1,468

1,803

Total

Emera Incorporated equity

13,277

12,074

NCI (note 30)

Total

equity

13,291

12,088

Total liabilities and equity

42,951

39,480

Commitments and contingencies

(note 28)

nil

The accompanying notes are an integral part of these consolidated financial statements.

Approved on behalf of the Board of Directors

“Karen Sheriff”

“Scott Balfour”

Chair of the Board

President and Chief Executive Officer

Emera Incorporated

Consolidated Statements of Cash Flows

For the

Year ended December 31

millions of dollars

2024

2023

Operating activities

Net income

568

1,045

Adjustments to reconcile net income to net cash provided by operating activities:

Depreciation and amortization

1,165

1,060

Income from equity investments, net of dividends

(8)

(22)

Allowance for funds used during construction ("AFUDC") – equity

(53)

(38)

Deferred income taxes, net

(191)

Net change in pension and post-retirement liabilities

(46)

(68)

NSPI fuel adjustment mechanism ("FAM")

451

(88)

Net change in fair value ("FV") of derivative instruments

228

(666)

Net change in regulatory assets and liabilities

(226)

554

Net change in capitalized transportation capacity

175

434

Goodwill impairment charge

214

Gain on sale of LIL, excluding transaction costs

(191)

Other operating activities, net

108

Changes in non-cash working capital (note 31)

452

(95)

Net cash provided by operating activities

2,646

2,241

Investing activities

Additions to PP&E

(3,151)

(2,937)

Proceeds from disposal of investment subject to significant influence

927

Other investing activities

Net cash used in investing activities

(2,218)

(2,917)

Financing activities

Change in short-term debt, net

(66)

Proceeds from short-term debt with maturities greater than 90 days

548

Repayment of short-term debt with maturities greater than 90 days

(1,086)

Proceeds from long-term debt, net of issuance costs

1,361

1,932

Retirement of long-term debt

(1,086)

(151)

Net repayments under committed credit facilities

(825)

(96)

Issuance of common stock, net of issuance costs

284

424

Dividends on common stock

(538)

(488)

Dividends on preferred stock

(73)

(66)

Other financing activities

(12)

Net cash (used in) provided by financing activities

(818)

939

Effect of exchange rate changes on cash, cash equivalents, restricted cash and

cash associated with assets held for sale

(7)

Net (decrease) increase in cash, cash equivalents, restricted cash and cash

associated with assets held for sale

(367)

256

Cash, cash equivalents, and restricted cash, beginning of year

588

332

Cash, cash equivalents, restricted cash, and cash associated with assets held for

sale, end of year

221

588

Cash, cash equivalents, restricted cash and cash associated with assets held

for sale consists of:

Cash

191

559

Short-term investments

Restricted cash

Assets held for sale

Cash, cash equivalents, restricted cash and cash associated with assets held for

sale

221

588

Supplementary Information to Consolidated Statements of Cash Flows (note 31)

The accompanying notes are an integral part of these consolidated financial statements.

Emera Incorporated

Consolidated Statements of Changes in Equity

Common

Preferred

Contributed

Retained

Total

Stock

Surplus

AOCI

Earnings

NCI

Equity

millions of dollars

Balance, December 31, 2023

8,462

1,422

305

1,803

12,088

Net income of Emera Inc.

567

568

Other comprehensive income, net of

tax expense of $

million

956

Dividends declared on preferred stock

(note 29)

(73)

Dividends declared on common stock

2.8775

/share)

(829)

Issued under the at-the-market

program ("ATM"), net of after-tax

issuance costs

261

Issued under the Dividend

Reinvestment Program ("DRIP"), net of

discount

291

Senior management stock options

exercised and Employee Common

Share Purchase Plan ("ECSPP")

Other

(1)

Balance, December 31, 2024

9,042

1,422

1,261

1,468

13,291

Balance, December 31, 2022

7,762

1,422

578

1,584

11,441

Net income of Emera Inc.

1,044

1,045

Other comprehensive loss, net of tax

recovery of $

million

(273)

Dividends declared on preferred stock

(note 29)

(66)

Dividends declared on common stock

2.7875

/share)

(759)

Issued under the ATM, net of after-tax

issuance costs

397

Issued under the DRIP, net of discount

272

Senior management stock options

exercised and ECSPP

Other

(1)

Balance, December 31, 2023

8,462

1,422

305

1,803

12,088

The accompanying notes are an integral part of these consolidated financial statements.

Emera Incorporated

Notes to the Consolidated Financial Statements

As at December 31, 2024 and 2023

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Operations

Emera Incorporated (“Emera” or the “Company”) is an

energy and services company that invests in

electricity generation, transmission and distribution, and

gas transmission and distribution.

At December 31, 2024, Emera’s reportable segments

include the following:

●

Florida Electric Utility,

which consists of Tampa

Electric (“TEC”), a vertically integrated regulated

electric utility, serving

approximately

855,000

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

557,000

customers; and

●

100

per cent equity interest in NSP Maritime Link Inc. (“NSPML”),

which developed the

Maritime Link Project, a $

1.8

billion, including AFUDC, transmission project between the

island of Newfoundland and Nova Scotia.

On June 4, 2024, Emera completed the sale of its

31.1

per cent indirect minority equity interest in the

Labrador Island Link Partnership (“LIL”), which was previously

included in the Canadian Electric

Utilities segment. For further details, refer to note 4.

●

Gas Utilities and Infrastructure, which includes:

●

Peoples Gas System Inc. (“PGS”), a regulated gas distribution

utility, serving

approximately

508,000

customers across Florida;

●

New Mexico Gas Company,

Inc. (“NMGC”), a regulated gas distribution utility,

serving

approximately

550,000

customers in New Mexico. On August 5, 2024,

Emera announced an

agreement to sell NMGC. The transaction is expected to

close in late 2025, subject to certain

approvals, including approval by the New Mexico Public

Regulation Commission (“NMPRC”).

For further details, refer to note 4.

●

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 (“US”) border under a

-year firm service agreement with Repsol Energy

North

America Canada Partnership (“Repsol Energy Canada”),

which expires in 2034;

●

SeaCoast Gas Transmission, LLC (“SeaCoast”),

a regulated intrastate natural gas

transmission company offering services in Florida;

and

●

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 US.

●

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

135,000

customers;

●

Grand Bahama Power Company Limited (“GBPC”), a vertically

integrated regulated electric

utility on Grand Bahama Island, serving approximately

19,500

customers; and

●

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 segment includes investments in

energy-related non-regulated companies that 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. This

includes:

●

Emera Energy, which

consists of:

●

Emera Energy Services (“EES”), a physical energy business

that purchases and sells

natural gas and electricity and provides related energy

asset management services;

●

Brooklyn Power Corporation (“Brooklyn Energy”), a

MW biomass co-generation

electricity facility in Brooklyn, Nova Scotia; and

●

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”), EUSHI Finance, Inc.

and TECO Finance, Inc.

(“TECO Finance”), financing subsidiaries of Emera;

●

Emera US Holdings Inc., a wholly owned holding company

for certain of Emera’s assets

located in the US; 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.

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 33.

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 7.

Foreign Currency Translation

Monetary assets and liabilities denominated in foreign

currencies are converted to CAD at the rates of

exchange prevailing at the balance sheet date. The resulting differences

between the translation at the

original transaction date and the balance sheet date are

included in income.

Assets and liabilities of foreign operations whose functional

currency is not the Canadian dollar are

translated using exchange rates in effect at the balance

sheet date and the results of operations at the

average exchange rate in effect for the period. The

resulting exchange gains and losses on the assets

and liabilities are deferred on the balance sheet in AOCI.

The Company designates certain USD denominated debt

held in CAD functional currency companies as

hedges of net investments in USD denominated foreign

operations. The change in the carrying amount of

these investments, measured at exchange rates in effect

at the balance sheet date, is recorded in 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

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

value, including goodwill (“carrying amount”). 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 comparable industries, or in the case

of the NMGC quantitative assessment in 2024,

transactions involving the reporting unit. 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, 2024, Emera’s goodwill represented

the excess of the acquisition purchase price for

TECO Energy, Inc.

(TEC, PGS and NMGC reporting units) over the FV

assigned to identifiable assets

acquired and liabilities assumed. In Q3 2024, Emera entered

into an agreement to sell NMGC. As a

result, a quantitative goodwill impairment assessment

was performed on the NMGC reporting unit and the

Company recorded a goodwill impairment charge of $

210

million ($

198

million, after-tax) or $

155

million

USD ($

146

million USD, after-tax). The reduced NMGC goodwill

balance of $

303

million is included in the

NMGC disposal unit classified as held for sale. For further

details, refer to note 23.

In Q4 2024, a qualitative assessment was performed for

TEC given the significant excess of FV over

carrying amounts calculated during the last quantitative test

in Q4 2023. Management concluded it was

more likely than not that the FV of this reporting unit exceeded

its carrying amount, including goodwill. As

such, no quantitative testing was required. Given the length

of time passed since the last quantitative

impairment test for the PGS reporting unit, Emera elected

to bypass a qualitative assessment and

performed a quantitative impairment assessment in Q4

2024 using a combination of the income and

market approach. This assessment estimated that the

FV of the PGS reporting unit exceeded its carrying

amount, including goodwill, and as a result, no impairment

charges were recognized.

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, NSPML 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, NSPML 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 11.

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 and PGS

have no derivatives related to hedging.

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 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

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 “OM&G” 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.

In 2024, impairment charges of $

million ($

million after-tax) were recognized on certain assets,

million of which was included in Other income, net with $

million included in Impairment charges on the

Consolidated Income Statement.

impairment charges related to long-lived assets were recognized

2023.

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.

impairment of equity method investments was required

in either 2024 or 2023.

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.

impairment of financial assets was required in either

2024 or 2023.

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 “PP&E” 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 or regulatory assets. 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 22.

Government Grants

The Company accounts for government grants by applying

a grant accounting model by analogy to

International Accounting Standards (“IAS”) 20, Accounting

for Government Grants and Disclosure of

Government Assistance. A grant relating to an asset is

reflected in the determination of the carrying

amount of the asset. A grant relating to income is presented

as a deduction from the related expense it is

intended to compensate.

In 2024, the Company received an aggregate of $

million (2023 – $

million) of government grants from

various Canadian and US government agencies towards

capital projects included in

PP&E

. The capital

projects receiving grants primarily relate to the Company’s

decarbonization and environmental

compliance initiatives. Further details on significant grant programs

utilized in 2024 and 2023 are noted

below.

Natural Resources Canada (“NRCan”) Smart Renewables

& Electrification Pathways (“SREP”):

On March 27, 2024, NSPI was approved for a grant under the

NRCan SREPs to fund the construction of

three

50 MW battery storage systems in Nova Scotia.

NSPI can make claims under the grant for

per

cent of eligible project costs to a maximum $

109

million. Eligible costs can be incurred until March

31,

For the year-end December 31, 2024, NSPI received

million (2023 –

nil

) in funding under the

grant, which has been recorded as a reduction to the carrying

amount of the project in

PP&E

CHANGE IN ACCOUNTING POLICY

The new USGAAP accounting policy that is applicable

to, and adopted by the Company in 2024, is

described as follows:

Improvements to Reportable Segment Disclosures

The Company adopted Accounting Standard Update (“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 was

effective for annual reporting periods beginning

after December 15, 2023, and for interim periods beginning

after December 15, 2024. Adoption of the

standard resulted in additional qualitative disclosures provided

in note 5.

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.

Disaggregation of Income Statement Expenses

In November 2024, the FASB

issued ASU 2024-03, Income Statement Reporting–Comprehensive

Income–Expense Disaggregation Disclosures (Subtopic

220-40): Disaggregation of Income Statement

Expenses. The standard update improves the disclosures about

a public business entity’s expenses by

requiring more detailed information about the types of

expenses (including purchases of inventory,

employee compensation, depreciation and amortization)

included within income statement expense

captions. The guidance will be effective for annual

reporting periods beginning after December 15, 2026,

and interim reporting periods beginning after December

15, 2027. Early adoption is permitted. The

standard updates are to be applied prospectively with the option

for retrospective application. The

Company is currently evaluating the impact of adoption

of the standard update on its consolidated

financial statements disclosures.

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. 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 disclosures.

DISPOSITIONS

Pending Sale of NMGC

On August 5, 2024, Emera entered into an agreement

to sell its indirect wholly owned subsidiary NMGC

for a total enterprise value of approximately $

1.3

billion USD, consisting of cash proceeds and the

transfer of debt and customary closing adjustments. The

transaction is expected to close in late 2025,

subject to certain approvals, including approval by the

NMPRC. As a result of the pending sale, NMGC’s

assets and liabilities are classified as held for sale.

As the transaction proceeds will be lower than the carrying amount

of the assets and liabilities being sold,

Emera assessed the NMGC reporting unit for goodwill impairment

by comparing the FV of expected

transaction proceeds to the carrying value of net assets,

including goodwill of $

366

million USD (“NMGC

carrying amount”). The goodwill of the reporting unit was

determined to be impaired and a non-cash

goodwill impairment charge of $

210

million ($

198

million, after-tax) or $

155

million USD ($

146

million

USD, after-tax) was recorded in “Impairment Charges” on the Consolidated

Statements of Income in Q3

2024.

Following the goodwill impairment assessment, the held for

sale assets and liabilities were measured at

the lower of their carrying amount or fair value less costs

to sell. The measurement resulted in an

additional loss for the estimated future transaction costs

of $

million ($

million after-tax), in addition to

incurred transaction costs of $

million ($

million after-tax) recorded in “Other Income, net” on the

Consolidated Statements of Income in Q3 2024.

The Company will continue to record depreciation on the NMGC

assets through the transaction closing

date, as the depreciation continues to be reflected in

customer rates and will be reflected in the carryover

basis of the assets when sold. Depreciation and amortization

of $

million ($

million USD) was

recorded on these assets from August 5, 2024, the date

they were classified as held for sale, through

December 31, 2024.

Details of the assets and liabilities classified as held for

sale are as follows:

As at

December 31

millions of dollars

2024

Cash and cash equivalents

Inventory

Derivative instruments

Regulatory assets

Receivables and other current assets

127

Current assets held for sale

173

PP&E

1,828

Regulatory assets

Goodwill

303

Other long-term assets

Long-term assets held for sale

2,160

Total assets held for sale

2,333

Short-term debt

Derivative instruments

Regulatory liabilities

Accounts payable and other current liabilities

155

Current liabilities associated with assets held for sale

212

Long-term debt

696

Deferred income taxes

167

Regulatory liabilities

274

Other long-term liabilities

Long-term liabilities associated with assets held for sale

1,148

Total liabilities associated with assets held for sale

1,360

Sale of LIL Equity Interest

On June 4, 2024, Emera completed the sale of its

31.1

per cent indirect minority equity interest in the LIL

for a total transaction value of $

1.2

billion, including cash proceeds of $

957

million and $

235

million for

assuming Emera’s contractual obligation to fund the

remaining initial capital investment, which represents

additional LIL equity interest for the acquirer.

Cash proceeds from the sale in the amount of $

million is

held in escrow pending finalization of certain agreements

with the LIL general partner. The

escrow

proceeds receivable is held at FV and included in the gain

on sale, after transaction costs. As of

December 31, 2024, the estimated FV of the escrow proceeds

receivable is $

million. In Q2 2024, a

gain on sale, after transaction costs, of $

182

million, ($

107

million, after tax and transaction costs), was

recognized in “Other Income, net” on the Consolidated

Statements of Income and included in the Other

segment. In Q4 2024, Emera recognized a $

million tax benefit due to the reversal of a prior year

valuation allowance related to loss carryforwards applied against

a portion of the taxable capital gain on

the sale of LIL. This tax benefit was recorded in “Income Tax

(Recovery) Expense” on the Consolidated

Statements of Income in Q4 2024 and included in the

Other segment.

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 (“CODM”). Emera’s CODM is the Chief Executive Officer.

For the Company’s reportable segments, the CODM uses several measures to allocate capital and

resources for each segment, predominantly in the annual budget and forecasting processes. The CODM

evaluates segment performance by considering budget-to-actual variances for these measures monthly.

The measure used by the CODM that is the most consistent with USGAAP measurement principles is net

income attributable to common shareholders.

Florida

Canadian

Gas Utilities

Other

Inter-

Electric

and

Electric

Segment

millions of dollars

Utility

Utilities

Infrastructure

Utilities

Other

Eliminations

Total

For the year ended December 31, 2024

Operating revenues from

external customers (1)

3,451

1,855

1,595

566

(267)

7,200

Inter-segment revenues

(1)

(42)

Total operating revenues

3,460

1,855

1,609

566

(248)

(42)

7,200

Regulated fuel for generation

and purchased power

852

859

295

(14)

1,992

Regulated cost of natural gas

396

OM&G

779

408

454

143

154

(20)

1,918

Provincial, state and municipal

taxes

273

103

427

Depreciation and amortization

622

282

182

1,162

Impairment charges

214

225

Income from equity

investments

Other income, net

203

Interest expense, net

(2)

265

168

151

367

973

Income tax expense

(recovery)

(41)

(302)

(159)

NCI in subsidiaries

Preferred stock dividends

Net income (loss) attributable

to common shareholders

641

232

259

(686)

494

Capital expenditures

1,942

481

619

3,127

As at December 31, 2024

Total assets

24,375

7,609

8,439

1,444

1,810

(726)

42,951

Investments subject to

significant influence

475

124

654

Goodwill

5,035

823

5,858

(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 $

million for the year ended

December 31, 2024, between the Gas Utilities

and Infrastructure and Other segments.

Florida

Canadian

Gas Utilities

Other

Inter-

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)

(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

OM&G

830

384

405

130

151

(21)

1,879

Provincial, state and municipal

taxes

289

433

Depreciation and amortization

571

276

126

1,049

Income from equity

investments

109

146

Other income, net

158

Interest expense, net

(2)

271

170

129

332

925

Income tax expense (recovery)

117

(9)

(44)

128

NCI in subsidiaries

Preferred stock dividends

Net income (loss) attributable

to common shareholders

627

247

214

(147)

978

Capital expenditures

1,736

450

664

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

1,402

Goodwill

4,628

1,240

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 $

million for the year ended

December 31, 2023, between the Florida Electric

Utility, 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

2024

2023

United States

4,712

5,310

Canada

1,922

1,727

Barbados

427

389

The Bahamas

139

137

7,200

7,563

PP&E:

As at

December 31

millions of dollars

2024

2023

United States

(1)

20,084

18,588

Canada

5,068

4,878

Barbados

645

576

The Bahamas

371

334

26,168

24,376

(1) On August 5, 2024, Emera announced an agreement to sell

NMGC. As at December 31, 2024, NMGC's assets

and liabilities were classified as held

for sale and excluded from the table above. For further

details on the pending transaction, refer to note 4.

REVENUE

The following disaggregates the Company’s revenue

by major source:

Electric

Gas

Other

Florida

Canadian

Other

Gas Utilities

Inter-

Electric

and

Segment

millions of dollars

Utility

Utilities

Infrastructure

Other

Eliminations

Total

For the year ended December 31, 2024

Regulated Revenue

Residential

2,063

997

203

712

3,975

Commercial

939

499

300

496

2,234

Industrial

223

276

(14)

607

Other electric

372

420

Regulatory deferrals

(157)

(142)

Other (1)

224

(9)

290

Finance income (2)(3)

Regulated revenue

3,460

1,855

566

1,589

(23)

7,447

Non-Regulated Revenue

Marketing and trading margin (4)

Other non-regulated operating

revenue

(24)

Mark-to-market (3)

(357)

(352)

Non-regulated revenue

(248)

(19)

(247)

Total operating revenues

3,460

1,855

566

1,609

(248)

(42)

7,200

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

(13)

606

Other electric

395

443

Regulatory deferrals

(522)

(510)

Other (1)

199

(8)

254

Finance income (2)(3)

Regulated revenue

3,556

1,671

526

1,503

(21)

7,235

Non-Regulated

Marketing and trading margin (4)

Other non-regulated operating

revenue

(23)

Mark-to-market (3)

216

(9)

207

Non-regulated revenue

339

(32)

328

Total operating revenues

3,556

1,671

526

1,524

339

(53)

7,563

(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, 2024, the

aggregate amount of the transaction price allocated to

remaining performance obligations was $

495

million (2023 – $

488

million), including $

million related to NMGC. This amount includes

135

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

2044

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.

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

millions of dollars

2024 (1)

2023

Regulatory assets

Deferred income tax regulatory assets

1,227

1,233

TEC capital cost recovery for early retired assets

737

671

Storm cost recovery clauses

613

Pension and post-retirement medical plan

395

364

TEC capital cost recovery for retired Polk Unit 1 components

205

Deferrals related to derivative instruments

Cost recovery clauses

151

Environmental remediations

Stranded cost recovery

NSPI FAM

395

Other

(2)

119

100

3,427

3,105

Current

595

339

Long-term

2,832

2,766

Total

regulatory assets

3,427

3,105

Regulatory liabilities

Deferred income tax regulatory liabilities

828

830

Accumulated reserve – COR

733

849

Cost recovery clauses

121

NSPI FAM

Deferrals related to derivative instruments

BLPC Self-insurance fund ("SIF") (note 33)

Other

(2)

1,880

1,772

Current

262

168

Long-term

1,618

1,604

Total

regulatory liabilities

1,880

1,772

(1) On August 5, 2024, Emera announced an

agreement to sell NMGC. As at December

31, 2024, NMGC's assets and liabilities

were classified as held for sale and excluded from

the table above.

For further details on the pending transaction, refer

to note 4.

(2) Comprised of regulatory assets and liabilities

that are not individually significant.

Deferred Income Tax

Regulatory Assets and Liabilities

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

Represents the remaining net book value of Big Bend Power

Station Units 1 through 3 and smart meter

assets that were early 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

years, beginning in January 2022.

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 reserve 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.

NSPI Storm Rider:

NSPI has a UARB approved storm rider for each of 2023,

2024 and 2025, which gives NSPI the ability to

apply to the UARB for recovery of costs if major storm

restoration expenses exceed approximately $

million in a given year. The

storm rider was effective as of the General Rate

Application (“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.

GBPC Storm Restoration:

This asset includes storm restoration costs incurred by

GBPC related to Hurricane Dorian in 2020 and

Hurricane Matthew in 2016.

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, in 2023, NMGC. Deferred costs of postretirement

benefits that are included in expense are

recognized as cost of service for rate-making purposes

as permitted by the FPSC and New Mexico Public

Regulation Commission (“NMPRC”), as applicable and

amortized over the remaining service life of plan

participants.

TEC Capital Cost Recovery for Retired Polk Unit 1

Components

This regulatory asset relates to the remaining net book value

of certain components of Polk Unit 1 that

were early retired on December 31, 2024. The balance earns a

rate of return as permitted by the FPSC

and will be recovered through base rates over an

-year recovery period beginning on January 1, 2025.

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.

Cost Recovery Clauses

These assets and liabilities are clauses and riders related to

TEC, PGS and, in 2023, NMGC.

They are

recovered or refunded through cost-recovery mechanisms

approved by the FPSC or NMPRC, as

applicable, on a dollar-for-dollar basis in a subsequent

period.

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 $

million

USD stranded cost through electricity rates; it is included in

rate base and expected to be included in

rates in future years.

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.

Accumulated Reserve – COR

This regulatory asset or liability represents the non-ARO

COR reserve in TEC, PGS, NSPI and in 2023,

NMGC. 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.

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 2024 and 2023 was

9.25

per cent to

11.25

per cent based on an allowed equity capital structure of

per cent. An ROE of

10.20

per cent (2023 –

10.20

per cent) is used for the calculation of the return

on investments for clauses.

Base Rates:

On April 2, 2024, TEC filed a rate case with the FPSC for

new base rates. On December 3, 2024, the

FPSC rendered a decision which includes annual base

rate increases of $

185

million USD in 2025 and

adjustments of $

million USD and $

million USD in 2026 and 2027, respectively.

The allowed equity in

the capital structure will continue to be

per cent from investor sources of capital and the allowed

regulatory ROE range is

9.50

per cent to

11.50

per cent with a

10.50

per cent midpoint. On February 3,

2025, the FPSC issued the final order approving the decision,

effective January 1, 2025. On February 18,

2025, a motion for reconsideration on certain aspects of the

rate case order was filed with the FPSC.

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 $

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 April 2, 2024, TEC requested a mid-course adjustment

to its fuel and capacity charges, reflecting a

138

million USD reduction over

12 months

, from June 2024 through May 2025. The requested

reduction

was due to a decrease in actual and projected 2024 natural

gas prices since TEC submitted its projected

2024 costs in the fall of 2023. On May 7, 2024, the FPSC

approved the mid-course adjustment.

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.

Storm Reserve:

September 26, 2024, Hurricane Helene passed 100 miles west

of Tampa

and made landfall

approximately 200 miles north of Tampa,

in Taylor

County, as a Category

4 hurricane. TEC’s service

territory was impacted by the tropical storm force winds

and storm surge which resulted in a peak number

of customers out of 100,000. As of December 31, 2024, TEC

deferred $

million USD to the storm

reserve for future recovery.

On October 9, 2024, Hurricane Milton made landfall approximately

50 miles south of Tampa,

near

Sarasota, and was the worst weather event to impact the

area in over 100 years. The Category 3

hurricane had a significant impact on TEC’s service

territory which resulted in a peak number of

customers out of 600,000. As of December 31, 2024, TEC deferred

340

million USD to the storm

reserve for future recovery

As at December 31, 2024, total restoration costs charged

to the storm reserve account have exceeded

the storm reserve balance, and therefore $

377

million USD has been deferred as a regulatory asset

for

future recovery. On February

4, 2025, the FPSC approved TEC’s petition, filed

on December 27, 2024,

for the recovery of $

466

million USD for costs associated with Hurricane Idalia, Hurricane

Debby,

Hurricane Helene and Hurricane Milton and the associated

interest which will replenish the storm reserve

over an 18-month recovery period beginning March 2025.

The amount of cost-recovery is subject to a

true-up mechanism with the FPSC.

In September 2022, TEC was impacted by Hurricane Ian, with

119

million USD of restoration costs

charged against TEC’s FPSC approved storm reserve.

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 $

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. The remaining balance of

million USD as of December 31, 2023, was collected over

12 months in 2024.

Storm Protection Cost Recovery Clause and Settlement

Agreement:

The Storm Protection Plan 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.

The current approved plan addressed the years 2023,

2024

and 2025 and was approved by the FPSC in October,

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 2024 and 2023 was

8.75

per cent to

9.25

per cent based on an actual five

quarter average regulated common equity component

of up to

per cent of approved rate base.

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:

On April 17, 2024, the UARB approved the sale of $

117

million of the FAM regulatory

asset to Invest

Nova Scotia, a provincial Crown corporation. On April

30, 2024, the transaction closed and the $

117

million was remitted to NSPI, which resulted in a corresponding

decrease of the FAM regulatory

asset.

NSPI is collecting the amortization and financing costs

related to the $

117

million from customers on

behalf of Invest Nova Scotia over a

-year period, which began in Q2 2024, and is

remitting those

amounts to Invest Nova Scotia quarterly.

Federal Loan Guarantee (“FLG”):

On September 24, 2024, the Government of Canada finalized

an agreement with NSPI, NSPML and the

Province of Nova Scotia (the “Province”) on terms and

conditions for a FLG of $

500

million in debt to be

issued by NSPML to help Nova Scotia customers manage

unrecovered costs of the replacement energy

that was required during the several years of delay in the

Muskrat Falls hydroelectricity project. On

September 25, 2024, NSPI and NSPML filed applications

with the UARB related to the FLG. On

November 29, 2024, the UARB approved NSPML’s

application to issue the debt, transfer the proceeds

NSPI as a refund of a portion of previous NSPML assessment

payments, and to increase its annual

assessment charge to NSPI to recover the refund and

related financing costs over a

-year period. On

December 16, 2024, the net proceeds of the NSPML debt

issuance were transferred to NSPI and applied

against the FAM regulatory

asset balance. On February 18, 2025, the UARB approved

NSPI's application

to increase 2025 fuel rates to service the incremental

NSPML debt.

Storm Rider:

On December 2, 2024, the UARB approved the recovery

of $

million of major storm restoration and

incremental financing costs deferred to NSPI’s storm

rider in 2023 to be recovered over a

-month

period beginning on January 1, 2025.

Hurricane Fiona:

On June 27, 2024, the UARB approved the deferred recognition

of $

million in incremental operating

costs incurred during the Hurricane Fiona storm restoration

efforts in September 2022. Following UARB

approval, the $

million was reclassified to “Regulatory assets”

from “Other long-term assets”. The

UARB also directed NSPI to reclassify $

million of undepreciated costs related to assets retired

because of Hurricane Fiona to “Regulatory assets” from “PP&E”

on the Consolidated Balance Sheets.

NSPI began amortizing both of these regulatory assets

over a

-year period beginning July 1, 2024.

Nova Scotia Cap-and-Trade

(“Cap-and-Trade”)

Program:

On December 31, 2022, the FAM

included a cumulative $

166

million in fuel costs related to the accrued

purchase of emissions credits and $

million related to credits purchased from provincial auctions.

March 16, 2023, the Province 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

The credits NSPI purchased from provincial auctions

in the amount of $

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 $

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

per cent.

Newfoundland and Labrador Hydro’s (“NLH”) Nova

Scotia Block (“NS Block”) delivery obligations

commenced in 2021 and delivery will continue over the next

35 years

pursuant to the agreements.

On September 24, 2024, the Government of Canada finalized

an agreement with NSPI, NSPML, and the

Province on terms and conditions for a FLG of $

500

million in debt to be issued by NSPML. For further

information, refer to the NSPI section above.

On November 29, 2024, NSPML received approval from the

UARB to collect up to $

197

million in 2025

from NSPI; which includes $

158

million for the recovery of costs associated with the Maritime

Link, and

million associated with the additional FLG debt and financing costs

noted in the NSPI section above.

Payments from NSPI are subject to a holdback of up to $

million per month. There was

holdback

recorded for the year ended December 31, 2024.

On December 21, 2023, NSPML received approval from the

UARB to collect up to $

164

million in 2024

from NSPI for the recovery of costs associated with the

Maritime Link subject to a holdback of $

million

per month.

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

million ($

million related to 2022 and $

million

related 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”. The UARB also

confirmed that NSPML can apply for termination of the

holdback mechanism upon

per cent of NS

Block deliveries being 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

per cent of the contracted annual amount. In addition,

the UARB increased the

monthly holdback amount from $

million to $

million beginning December 1, 2023.

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 2024 and 2023

was

9.15

per cent to

11.15

per cent with a

10.15

per cent

midpoint, based on an allowed equity capital structure

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 $

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.

Fuel Recovery:

PGS recovers the costs it pays for gas supply and

interstate transportation for system supply through its

Purchased Gas Adjustment Clause (“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 2024 and 2023

was

9.375

per cent on an allowed equity capital structure of

per cent.

Base Rates:

On September 14, 2023, NMGC filed a rate case with

the NMPRC for new base rates.

On March 1, 2024,

NMGC filed with the NMPRC a settlement with the support

of all parties in the case for an increase of $

million USD in annual base revenues and maintaining

NMGC’s ROE at

9.375

per cent. The rates reflect

the recovery of increased operating costs and capital investments

in pipeline projects and related

infrastructure, as well as a new customer information and

billing system. NMGC also agreed to withdraw,

and to not reassert in a future rate case application,

its request for a regulatory asset for costs associated

with its 2022 application for a certificate of public convenience

and necessity for a liquefied natural gas

storage facility in New Mexico. The NMPRC approved

the rate case settlement on July 25, 2024. New

rates became effective October 1, 2024.

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 2024, for the four-year period

ending December 2028.

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 US. Brunswick Pipeline entered

into a

-year firm service agreement commencing in July

2009 with Repsol Energy Canada. 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

per cent for 2024 and 2023.

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 $

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

per cent,

a directive to update the major components of rate base

to September 16, 2022, and a directive to

establish regulatory liabilities totalling approximately $

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. The appeal is

currently scheduled to be heard in 2025.

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

Rider (“CETR”):

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 CETR (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 CETR. On May 6, 2024, the

FTC approved the recovery of a

MW battery

storage system through the CETR.

Barbados Domestic Tax

Rate Change:

On May 24, 2024, the Government of Barbados signed

the Income Tax

(Amendment and Validation)

Act

into law. The legislation, effective

January 1, 2024, implemented a corporate income

tax rate of

per

cent, requiring BLPC to remeasure its deferred income

tax liabilities. On July 18, 2024, BLPC requested

the deferred recovery of the $

million USD remeasurement. BLPC is seeking amortization

of the costs

over a period to be approved by the FTC during a future

rate setting process.

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

8.52

per cent for 2024 (2023 –

8.32

per cent).

Electricity Act, 2024:

On June 1, 2024, the Electricity Act, 2024 took effect.

The legislation purports to remove the jurisdiction of

the GBPA over GBPC

and to have the Utilities Regulation and Competition

Authority, another

Bahamian

regulator, regulate GBPC.

Base Rates:

There is a fuel pass-through mechanism and tariff review

policy with new rates submitted every three

years. On August 1, 2024, as required by the GBPA

Operating Protocol and Regulatory Framework

Agreement, GBPC filed a rate plan proposal and is awaiting

regulatory review.

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. In 2023 and 2024,

the fuel pass

through charge was adjusted monthly,

in-line with actual fuel costs.

INVESTMENTS SUBJECT TO SIGNIFICANT INFLUENCE AND EQUITY INCOME

Equity Income

Percentage

Carrying Value

For the year ended

As at December 31

December 31

Ownership

millions of dollars

2024

2023

2024

2023

2024

NSPML

475

489

100.0

M&NP

(1)

124

118

12.9

Lucelec

(1)

19.5

LIL

(2)

747

Bear Swamp

(3)

50.0

654

1,402

146

(1) 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.

(2) On June 4, 2024, Emera completed the sale

of its equity interest in the LIL. For further

details, refer to note 4.

(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 $

million (2023 – $

million) is recorded in Other long-term liabilities

on the

Consolidated Balance Sheets.

Equity investments include a $

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 33).

NSPML's consolidated summarized balance sheets are illustrated

as follows:

As at

December 31

millions of dollars

2024

2023

Balance Sheets

Current assets

PP&E

1,425

1,473

Regulatory assets

(1)

778

272

Non-current assets

Total

assets

2,267

1,795

Current liabilities

Long-term debt

(2)

1,570

1,109

Non-current liabilities

167

149

Equity

475

489

Total

liabilities and equity

2,267

1,795

(1) On November 29, 2024, the UARB approved

the creation of a $

500

million regulatory asset for debt issued as a

result of the

FLG. For further details, refer to note 7.

(2) On December 16, 2024, NSPML issued a

500

million bond under the FLG. For further details

refer to note 7.

OTHER INCOME, NET

For the

Year ended December 31

millions of dollars

2024

2023

Gain on sale of LIL, net of transaction costs

(1)

182

AFUDC

Pension non-current service cost recovery

Interest income

Transaction costs related to the pending sale of NMGC

(1)

(25)

Charges related to wind-down costs and certain asset impairments (2)

(29)

FX (losses) gains

(58)

Other

203

158

(1) For more information related to the gain

on sale, after transaction costs, of Emera's indirect

minority interest in the LIL and the

pending sale of NMGC, refer to note 4.

(2) Primarily related to the wind-down of Block

Energy LLC

INTEREST EXPENSE, NET

Interest expense, net consisted of the following:

For the

Year ended December 31

millions of dollars

2024

2023

Interest on debt

1,004

954

Allowance for borrowed funds used during construction

(23)

(16)

Other

(8)

(13)

973

925

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

2024

2023

Income before provision for income taxes

409

1,173

Statutory income tax rate

29.0%

Income taxes, at statutory income tax rate

119

340

Deferred income taxes on regulated income recorded as regulatory assets and

regulatory liabilities

(90)

(72)

Interest and financing expenses

(58)

Valuation allowance

(58)

Tax

credits

(57)

(53)

Goodwill impairment charge

Amortization of deferred income tax regulatory liabilities

(36)

(33)

Foreign tax rate variance

(31)

(36)

Additional impact from the sale of LIL equity interest

Tax

effect of equity earnings

(14)

(15)

Manufacturing allowance

(9)

(8)

Other

Income tax (recovery) expense

(159)

128

Effective income tax rate

(39%)

11%

Bahamian Domestic Minimum Top

-up Tax

Act (“Domestic Top

-up Tax

Act”):

On November 28, 2024, the Domestic Top

-up Tax

Act was enacted with an effective date of January

2024.The Domestic Top

-up Tax

Act did not have an impact on the Company.

Excessive Interest and Financing Expenses Limitation

(“EIFEL”) Regime:

On June 20, 2024, Bill C-59, an Act to implement certain provisions

of the fall economic statement tabled

in Parliament on November 21, 2023, and certain provisions

of the budget tabled in Parliament on March

28, 2023, was enacted.

Bill C-59 includes the EIFEL regime, which is effective

January 1, 2024. EIFEL

applies to limit a company’s net interest and financing

expense deduction to no more than 30 per cent of

earnings before interest, income taxes, depreciation, and amortization

for tax purposes. Any denied

interest and financing expenses under the EIFEL regime can

be carried forward indefinitely.

During 2024, the Company incurred $

185

million of interest and financing expenses in connection with

specific financing structure. The interest and financing expenses

related to the financing structure as well

as $

million of other interest and financing expenses are expected

to be denied under the EIFEL

regime. It was determined that the Company is more likely

than not to realize the tax benefit of the denied

interest and financing expenses in future periods and therefore

a $

million deferred income tax asset

has been recorded as at December 31, 2024. In Q4 2024, the

Company recognized a $

million tax

benefit related to the denied interest and financing expenses

and the reversal of the related deferred

income tax liability in connection with the financing structure

and its wind-up.

Canadian Global Minimum Tax

Act (“GMTA”):

On June 20, 2024, the GMTA

was enacted with an effective date of January

1, 2024. The GMTA

did not

have an impact on the Company.

Barbados Domestic Tax

Rate Change:

On May 24, 2024, the Government of Barbados signed the

Income Tax

(Amendment and Validation)

Act

into law. The legislation, effective

January 1, 2024, implemented a corporate income tax

rate of

per

cent, requiring BLPC to remeasure its deferred income

tax liabilities.

Barbados Corporation Top

-up Tax

(Amendment) Act (“Top

-up Tax

Act”):

On May 24, 2024, the Top

-up Tax

Act was enacted with an effective date of January

1, 2024. The Top

-up

Tax

Act did not have an impact on the Company

United States Inflation Reduction Act (“IRA”):

On August 16, 2022, the 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, 2024, the

Company has recorded a $

million (December

31, 2023 – $

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

2024

2023

Current income taxes

Canada

United States

Deferred income taxes

Canada

(200)

United States

155

128

Adjustments to beginning of the year valuation allowance

Canada

(61)

Investment tax credits

United States

(6)

(29)

Operating loss carryforwards

Canada

(4)

(93)

United States

(76)

(2)

Income tax (recovery) expense

(159)

128

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

2024

2023

Canada

156

171

United States

203

964

Other

Income before provision for income taxes

409

1,173

The deferred income tax assets and liabilities presented in

the Consolidated Balance Sheets as at

December 31 consisted of the following:

millions of dollars

2024

2023

Deferred income tax assets:

Tax

loss carryforwards

1,118

1,195

Tax

credit carryforwards

534

454

Regulatory liabilities

225

175

Derivative instruments

144

205

Other

462

372

Total

deferred income tax assets before valuation allowance

2,483

2,401

Valuation allowance

(322)

(363)

Total

deferred income tax assets after valuation allowance

2,161

2,038

Deferred income tax liabilities:

PP&E

(3,421)

(3,223)

Regulatory assets

(198)

(196)

Derivative instruments

(105)

(235)

Investments subject to significant influence

(46)

(216)

Other

(330)

(312)

Total

deferred income tax liabilities

(4,100)

(4,182)

Consolidated Balance Sheets presentation:

Long-term deferred income tax assets

392

208

Long-term deferred income tax liabilities

(2,331)

(2,352)

Net deferred income tax liabilities

(1,939)

(2,144)

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 $

322

million has been recorded as at December 31, 2024 (2023

– $

363

million)

related to the loss carryforwards, long-term debt and investments.

During 2024, the Company recognized

a $

million tax benefit primarily due to the utilization of certain

loss carryforwards, which were subject to

a valuation allowance as at December 31, 2023.

The Company intends to indefinitely reinvest earnings

from certain foreign operations. Accordingly,

4.7

billion as at December 31, 2024 (2023 – $

4.7

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,

2024 consisted of the following:

Subject to

Tax

Valuation

Net Tax

Expiration

millions of dollars

Carryforwards

Allowance

Carryforwards

Period

Canada

NOL

2,420

(967)

1,453

2026 - 2044

Capital loss

(55)

Indefinite

Tax Credit

(1)

2028 - 2042

United States

Federal NOL

1,587

(1)

1,586

2036 - Indefinite

State NOL

1,351

(1)

1,350

2026 - Indefinite

Tax credit

533

(3)

530

2025 - 2044

Other

NOL

(23)

2025 - 2031

The following table provides details of the change in unrecognized

tax benefits for the years ended

December 31 as follows:

millions of dollars

2024

2023

Balance, January 1

Increases due to tax positions related to current year

Increases due to tax positions related to a prior year

Decreases due to tax positions related to a prior year

(3)

(2)

Balance, December 31

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, 2024 was $

million (2023 – $

million), which would affect the effective

tax rate if recognized. The

total amount of accrued interest with respect to unrecognized tax

benefits was $

million (2023 – $

million) with $

million interest expense recognized in the Consolidated

Statements of Income (2023 – $

million).

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.

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 (2023 – $

126

million), including interest. NSPI has prepaid $

million

(2023 – $

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,

2024, the Company’s tax years still open to examination

by taxing authorities include 2006 and

subsequent years.

COMMON STOCK

Authorized

: Unlimited number of non-par value common shares.

2024

2023

Issued and outstanding:

millions

of shares

millions of

dollars

millions of

dollars

Balance, January 1

284.12

8,462

269.95

7,762

Issuance of common stock under ATM program

(1)(2)

5.12

261

8.29

397

Issued under the DRIP,

net of discounts

6.10

291

5.26

272

Senior management stock options exercised and Employee Share

Purchase Plan

0.60

0.62

Balance, December 31

295.94

9,042

284.12

8,462

(1) 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).

(2) For the year ended December 31, 2024, a

total of

5,117,273

common shares were issued under Emera's ATM program at an

average price of $

51.52

per share for gross proceeds of $

264

million ($

261

million net of after-tax issuance costs). As at December

31, 2024, an aggregate gross sales limit of $

336

million remained available for issuance under the

ATM program.

As at December 31, 2024, the following common shares

were reserved for issuance:

million (2023 –

million) under the senior management stock option plan,

million (2023 –

million) under the employee

common share purchase plan and

million (2023 –

million) under the DRIP.

The issuance of common shares under the common share compensation

arrangements does not allow

the plans to exceed

per cent of Emera's outstanding common shares. As at

December 31, 2024,

Emera was in compliance with this requirement.

ATM Equity Program

On November 18, 2024, Emera increased the size of

the ATM Program to

allow the Company to issue up

to $

billion 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 increased by an amendment dated November 18,

2024 to its prospectus supplement dated November 14, 2023 and

an amendment dated November 13,

2024 to its short form base shelf prospectus dated October 3,

2023.

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)

2024

2023

Numerator

Net income attributable to common shareholders

493.6

977.7

Diluted numerator

493.6

977.7

Denominator

Weighted average shares of common stock outstanding – basic

289.1

273.6

Stock-based compensation

0.1

0.2

Weighted average shares of common stock outstanding – diluted

289.2

273.8

Earnings per common share

Basic

1.71

3.57

Diluted

1.71

3.57

ACCUMULATED OTHER

COMPREHENSIVE INCOME

The components of AOCI are as follows:

millions of dollars

Unrealized gain

(loss) on

translation of

self-sustaining

foreign

operations

Net change

in net

investment

hedges

Gains (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, 2024

Balance, January 1, 2024

369

(24)

(2)

(52)

305

OCI before

reclassifications

1,027

(139)

890

Amounts reclassified from

AOCI

(2)

Net current period OCI

1,027

(139)

(2)

956

Balance, December 31, 2024

1,396

(163)

1,261

For the year ended December 31, 2023

Balance, January 1, 2023

639

(62)

(2)

(13)

578

OCI before

reclassifications

(270)

(232)

Amounts reclassified from

AOCI

(2)

(39)

(41)

Net current period OCI

(270)

(2)

(39)

(273)

Balance, December 31, 2023

369

(24)

(2)

(52)

305

The reclassifications out of AOCI are as follows:

For the

Year ended December 31

millions of dollars

2024

2023

Affected line item in the Consolidated Financial Statements

Gains on derivatives recognized as cash flow hedges

Interest rate hedge

Interest expense, net

(2)

Net change in unrecognized pension and post-retirement benefit costs

Actuarial losses

Other income, net

Past service (gains) costs

Other income, net

(2)

Amounts reclassified into obligations

Pension and post-retirement benefits

(40)

Total

before tax

(38)

Income tax expense

(1)

Total

net of tax

(39)

Total reclassifications out of AOCI, net of tax, for the period

(41)

INVENTORY

As at

December 31

millions of dollars

2024

2023

Materials

453

408

Fuel

328

382

Total

781

790

DERIVATIVE

INSTRUMENTS

Derivative assets and liabilities relating to the foregoing categories

consisted of the following:

Derivative Assets

Derivative Liabilities

As at

December 31

millions of dollars

2024

2023

2024

2023

Regulatory deferral:

Commodity swaps and forwards

FX forwards

HFT derivatives:

Power swaps and physical contracts

Natural gas swaps, futures, forwards, physical

contracts

236

319

660

531

270

348

690

567

Other derivatives:

Equity derivatives

FX forwards

Total

gross current derivatives

322

389

773

653

Impact of master netting agreements:

Regulatory deferral

(7)

(3)

(7)

(3)

HFT derivatives

(148)

(146)

(148)

(146)

Total

impact of master netting agreements

(155)

(149)

(155)

(149)

Less: Derivatives classified as held for sale

(1)

Total derivatives

166

240

617

504

Current

(2)

115

174

526

386

Long-term

(2)

118

Total derivatives

166

240

617

504

(1) On August 5, 2024, Emera announced an

agreement to sell NMGC. As at December

31, 2024, NMGC's assets and liabilities

were classified as held for sale. For further details

on the pending transaction, refer to note 4.

(2) 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 $

million that is being amortized through

interest expense over

10 years

as the underlying hedged item settles. As of December 31,

2024, the

unrealized gain in AOCI was $

million, after-tax (December 31, 2023 – $

million, after-tax). For the

year ended December 31, 2024, unrealized gains of $

million (2023 – $

million) have been reclassified

from AOCI into interest expense, net. The Company expects

million of unrealized gains currently in

AOCI to be reclassified into net income within the next

twelve months.

Regulatory Deferral

The Company has recorded the following changes with

respect to derivatives receiving regulatory

deferral:

Commodity

Physical

Commodity

swaps and

natural gas

swaps and

millions of dollars

forwards

purchases

forwards

For the year ended December 31

2024

2023

Unrealized gain (loss) in regulatory assets

(27)

(109)

(3)

Unrealized gain (loss) in regulatory liabilities

(3)

(73)

Realized gain in regulatory assets

(8)

(5)

Realized loss in regulatory liabilities

Realized (gain) loss in inventory

(1)

(8)

(10)

Realized (gain) loss in regulated fuel for generation

and purchased power

(2)

(6)

(49)

(9)

(4)

Other

(14)

Total

change in derivative instruments

(52)

(204)

(17)

(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, 2024, the Company had the following

notional volumes designated for regulatory

deferral that are expected to settle as outlined below:

millions

2025

2026-2027

Physical natural gas purchases:

Natural gas (MMBtu)

Commodity swaps and forwards purchases:

Natural gas (MMBtu)

Power (MWh)

Coal (metric tonnes)

FX forwards:

FX contracts (millions of USD)

208

Weighted average rate

1.3361

1.3296

% of USD requirements

50%

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

2024

2023

Power swaps and physical contracts in non-regulated operating revenues

(6)

Natural gas swaps, forwards, futures and physical contracts in non-regulated

operating revenues

195

1,043

Total

gains in net income

207

1,037

As at December 31, 2024, the Company had the following

notional volumes of outstanding HFT

derivatives that are expected to settle as outlined below:

2029 and

millions

2025

2026

2027

2028

thereafter

Natural gas purchases (Mmbtu)

262

111

Natural gas sales (Mmbtu)

299

Power purchases (MWh)

Power sales (MWh)

Other Derivatives

As at December 31, 2024, the Company had equity

derivatives in place to manage 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 2025. The

FX forwards have a

combined notional amount of $

520

million USD and expire in 2025 through 2026.

For the

Year ended December 31

millions of dollars

2024

2023

Equity

Forwards

Derivatives

Forwards

Derivatives

Unrealized gain (loss) in OM&G

(2)

Unrealized gain (loss) in other income, net

(44)

Realized gain (loss) in OM&G

(13)

Realized loss in other income, net

(12)

(11)

Total

gains (losses) in net income

(56)

(9)

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, 2024, the maximum exposure the

Company had to credit risk was $

1.3

billion (2023

– $

1.2

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, 2024 was

303

million (2023 – $

310

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, 2024, the Company had $

140

million (2023 – $

142

million) in financial assets,

considered to be past due, which have been outstanding for

an average

days. The FV of these

financial assets was $

128

million (2023 – $

127

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, 2024

December 31, 2023

millions of

dollars

% of total

exposure

millions of

dollars

% of total

exposure

Receivables, net

Regulated utilities:

Residential

376

22%

476

31%

Commercial

184

11%

194

13%

Industrial

Other

105

103

Cash collateral

784

46%

951

62%

Trading group:

Credit rating of A- or above

Credit rating of BBB- to BBB+

Not rated

165

10%

108

295

17%

188

12%

Other accounts receivable

331

20%

151

10%

Classification as assets held for sale

(1)

118

1,528

90%

1,290

84%

Derivative Instruments

(current and long-term)

Credit rating of A- or above

138

Credit rating of BBB- to BBB+

Not rated

166

10%

240

16%

1,694

100%

1,530

100%

(1) On August 5, 2024, Emera announced the

sale of NMGC. As at December 31, 2024

NMGC's assets and liabilities were

classified as held for sale. For further details, refer

to note 4.

Cash Collateral

The Company’s cash collateral positions consisted

of the following:

As at

December 31

millions of dollars

2024

2023

Cash collateral provided to others

198

101

Cash collateral received from others

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, 2024, the total FV of derivatives

in a liability position was $

617

million (December 31,

2023

–

504

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.

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, 2024

millions of dollars

Level 1

Level 2

Level 3

Total

Assets

Regulatory deferral:

Commodity swaps and forwards

FX forwards

HFT derivatives:

Power swaps and physical contracts

Natural gas swaps, futures, forwards, physical

contracts and related transportation

122

Less: Derivatives classified as held for sale

(1)

Total assets

104

166

Liabilities

Regulatory deferral:

Commodity swaps and forwards

FX forwards

HFT derivatives:

Power swaps and physical contracts

Natural gas swaps, futures, forwards and physical

contracts

(11)

437

515

(9)

110

441

542

Other derivatives:

FX forwards

Equity derivatives

Less: Derivatives classified as held for sale

(1)

Total liabilities

165

441

617

Net assets (liabilities)

(61)

(409)

(451)

(1) On August 5, 2024, Emera announced an

agreement to sell NMGC. As at December

31, 2024, NMGC's assets and liabilities

were classified as held for sale. For further details

on the pending transaction, refer to note 4

As at

December 31, 2023

millions of dollars

Level 1

Level 2

Level 3

Total

Assets

Regulatory deferral:

Commodity swaps and forwards

FX forwards

HFT derivatives:

Power swaps and physical contracts

(5)

Natural gas swaps, futures, forwards, physical

contracts and related transportation

108

184

131

202

Other derivatives:

FX forwards

Equity derivatives

Total assets

158

240

Liabilities

Regulatory deferral:

Commodity swaps and forwards

FX forwards

HFT derivatives:

Power swaps and physical contracts

Natural gas swaps, futures, forwards and physical

contracts

365

397

365

421

Other derivatives:

FX forwards

Total liabilities

365

504

Net assets (liabilities)

(8)

(331)

(264)

The change in the FV of the Level 3 financial assets and liabilities

for the year ended December 31, 2024

was as follows:

HFT Derivatives

millions of dollars

Power

Natural gas

Total

Assets

Balance, beginning of period

Total

realized and unrealized gains (losses) included in non-regulated operating

revenues

(7)

(2)

Balance, December 31, 2024

Liabilities

Balance, beginning of period

365

Total

realized and unrealized gains (losses) included in non-regulated operating

revenues

Balance, December 31, 2024

437

441

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

Unobservable Input

Low

High

average

(1)

Assets

Liabilities

As at December 31, 2024

HFT derivatives – Power

Third-party pricing

$25.60

$139.65

$82.63

swaps and physical contracts

HFT derivatives – Natural

437

Third-party pricing

$2.20

$17.54

$8.57

gas swaps, futures, forwards

and physical contracts

Total

441

Net liability

409

As at December 31, 2023

HFT derivatives – Natural

365

Third-party pricing

$1.27

$16.25

$4.85

gas swaps, futures, forwards

and physical contracts

Total

365

Net liability

331

(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

Level 1

Level 2

Level 3

Total

December 31, 2024

18,407

17,941

17,688

253

17,941

December 31, 2023

18,365

16,621

16,363

258

16,621

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, 2024, the FV of the Hybrid Notes

was $

1.2

billion (2023 – $

1.2

billion). An after-tax foreign currency loss of $

139

million was recorded in

AOCI for the year ended December 31, 2024 (2023

– $

million after-tax gain).

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

a recovery of $

324

million for the year ended December 31, 2024 (2023

–

163

million expense). 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 $

million for the year ended December 31, 2024 (2023

– $

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, 2024 and at December 31, 2023.

RECEIVABLES AND OTHER CURRENT ASSETS

As at

December 31

millions of dollars

2024

2023

Customer accounts receivable – billed

834

805

Customer accounts receivable – unbilled

342

363

Capitalized transportation capacity

(1)

216

358

Cash collateral provided to others

198

101

Prepaid expenses

105

Income tax receivable

Allowance for credit losses

(12)

(15)

Other

106

Total

receivables and other current assets

1,811

1,817

(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.

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 61 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

millions of dollars

Classification

2024

2023

Right-of-use asset

Other long-term assets

Lease liabilities

Current

Other current liabilities

Long-term

Other long-term liabilities

Total

lease liabilities

The Company recorded lease expense of $

123

million for the year ended December 31, 2024 (2023

–

127

million), of which $

112

million (2023 – $

119

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

2025

2026

2027

2028

2029

Thereafter

Total

Minimum lease payments

115

132

Less imputed interest

(75)

Total

Additional information related to Emera's leases is as follows:

Year ended December 31

For the

2024

2023

Cash paid for amounts included in the measurement of lease liabilities:

Operating cash flows for operating leases (millions of dollars)

Right-of-use assets obtained in exchange for lease obligations:

Operating leases (millions of dollars)

Weighted average remaining lease term (years)

Weighted average discount rate-

operating leases

3.96%

3.93%

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 $

million USD.

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

millions of dollars

2024

2023

Total

minimum lease payment to be received

1,310

1,360

Less: amounts representing estimated executory costs

(182)

(190)

Minimum lease payments receivable

1,128

1,170

Estimated residual value of leased property (unguaranteed)

183

Less: Credit loss reserve

(2)

Less: unearned finance lease income

(655)

(693)

Net investment in direct finance and sales-type leases

654

658

Principal due within one year (included in "Receivables and other

current assets")

Net Investment in direct finance and sales type leases – long-term

610

621

As at December 31, 2024, future minimum lease payments

to be received for each of the next five years

and in aggregate thereafter were as follows:

millions of dollars

2025

2026

2027

2028

2029

Thereafter

Total

Minimum lease payments to be

received

100

819

1,310

Less: executory costs

(182)

Total

1,128

PROPERTY,

PLANT AND EQUIPMENT

PP&E consisted of the following regulated and non-regulated

assets:

As at

December 31

millions of dollars

Estimated useful life

2024 (1)

2023

Generation

131

14,297

13,500

Transmission

3,106

2,835

Distribution

8,512

7,417

Gas transmission and distribution

4,658

5,536

General plant and other

(2)

3,078

2,985

Total

cost

33,651

32,273

Less: Accumulated depreciation

(2)

(10,442)

(9,994)

23,209

22,279

Construction work in progress

(2)

2,959

2,097

Net book value

26,168

24,376

(1) On August 5, 2024, Emera announced an

agreement to sell NMGC. As at December

31, 2024, NMGC's assets and liabilities

were classified as held for sale and excluded from

the table above.

For further details on the pending transaction, refer

to note 4.

(2) SeaCoast owns a

% undivided ownership interest in a jointly

owned

-mile pipeline lateral located in Florida, which went

into

service in 2020. At December 31, 2024, SeaCoast’s

share of plant in service was $

million USD (2023 – $

million USD), and

accumulated depreciation of $

million USD (2023 – $

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.

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. The Company also provides non-pension benefits

for its retirees.

Emera’s net periodic benefit cost included the following:

Benefit Obligation and Plan Assets:

Changes in the benefit obligation and plan assets, and

the funded status for plans were as follows:

For the

Year ended December 31

millions of dollars

2024

2023

DB pension

plans

Non-pension

benefit plans

DB pension

plans

Non-pension

benefit plans

Change in Projected Benefit Obligation ("PBO") and Accumulated Post-retirement Benefit Obligation

("APBO"):

Balance, January 1

2,273

227

2,158

243

Service cost

Plan participant contributions

Interest cost

110

111

Plan amendments

(14)

Benefits paid

(153)

(21)

(147)

(29)

Actuarial losses (gains)

(1)

(3)

146

Settlements and curtailments

(8)

FX translation adjustment

(23)

(5)

Balance, December 31

2,367

241

2,273

227

Change in plan assets:

Balance, January 1

2,298

2,163

Employer contributions

Plan participant contributions

Benefits paid

(153)

(21)

(147)

(29)

Actual return on assets, net of expenses

226

262

Settlements and curtailments

(8)

FX translation adjustment

(20)

(1)

Balance, December 31

2,493

2,298

Funded status, end of year

126

(187)

(179)

(1) 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 pension plans where

the PBO or APBO (for post-retirement benefit

plans) exceeded the plan assets for the years ended December

31 were as follows:

millions of dollars

2024

2023

DB pension

plans

Non-pension

benefit plans

DB pension

plans

Non-pension

benefit plans

PBO/APBO

219

120

205

FV of plan assets

Funded status

(84)

(219)

(83)

(205)

Plans with Accumulated Benefit Obligation (“ABO”)

in Excess of Plan Assets:

The ABO for the DB pension plans was $

2,255

million as at December 31, 2024 (2023 – $

2,172

million).

The aggregate financial position for those plans with an ABO

in excess of the plan assets for the years

ended December 31 were as follows:

millions of dollars

2024

2023

DB pension

plans

DB pension

plans

ABO

114

FV of plan assets

Funded status

(79)

(77)

Balance Sheet:

The amounts recognized in the Consolidated Balance Sheets

consisted of the following:

As at

December 31

millions of dollars

2024

2023

DB pension

plans

Non-pension

benefit plans

DB pension

plans

Non-pension

benefit plans

Other current liabilities

(5)

(21)

(5)

(18)

Liabilities associated with assets held for

sale

(1)

Long-term liabilities

(78)

(196)

(78)

(187)

Other long-term assets

208

108

Assets held for sale

(1)

AOCI, net of tax and regulatory assets

354

385

Deferred income tax expense in AOCI

(8)

(1)

(8)

(1)

Net amount recognized

472

(166)

402

(160)

(1) On August 5, 2024, Emera announced an

agreement to sell NMGC. As at December

31, 2024, NMGC's assets and liabilities

were classified as held for sale. For further details

on the pending transaction, refer to note 4.

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

millions of dollars

DB Pension Plans:

Balance, January 1, 2024

324

Amortized in current period

(9)

(3)

Current year additions

(67)

Change in FX rate

Balance, December 31, 2024

363

(17)

Non-pension benefits plans:

Balance, January 1, 2024

(8)

(2)

Amortized in current period

Current year reductions

(5)

(1)

Change in FX rate

Balance, December 31, 2024

(8)

As at

December 31

millions of dollars

2024

2023

DB pension

plans

Non-pension

benefit plans

DB pension

plans

Non-pension

benefit plans

Actuarial (gains) losses

(17)

(8)

Past service gains

(2)

Deferred income tax expense

AOCI, net of tax

(9)

(7)

(9)

Regulatory assets

363

324

AOCI, net of tax and regulatory assets

354

385

Benefit Cost Components:

Emera's net periodic benefit cost included the following:

As at

Year ended December 31

millions of dollars

2024

2023

DB pension

plans

Non-pension

benefit plans

DB pension

plans

Non-pension

benefit plans

Service cost

Interest cost

110

111

Expected return on plan assets

(160)

(2)

(161)

(2)

Current year amortization of:

Actuarial losses (gains)

(2)

(3)

Past service gains

(2)

Regulatory assets

(2)

Settlement, curtailments

Total

(3)

(11)

The expected return on plan assets is determined based on

the market-related value of plan assets of

2,571

million as at January 1, 2024 (2023 – $

2,577

million), adjusted for interest on certain cash flows

during the year.

The market-related value of assets is based on a 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 multi-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.

Further, within each asset class,

a 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:

Asset Class

Target

Range at Market

Canadian Pension Plans:

Short-term securities

10%

Fixed income

34%

49%

Equities:

Canadian

15%

Non-Canadian

37%

61%

Non-Canadian Pension Plans:

Cash and cash equivalents

10%

Fixed income

29%

49%

Equities

48%

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 (for more information on the FV hierarchy

and measurement, refer to note 17):

millions of dollars

NAV

Level 1

Level 2

Total

Percentage

As at

December 31, 2024

Cash and cash equivalents

Net in-transits

(27)

(1)

Equity securities:

Canadian equity

109

United States equity

312

Other equity

140

Fixed income securities:

Government

132

Corporate

Other

Mutual funds

Open-ended investments

measured at NAV

(1)

1,142

Common collective trusts

measured at NAV

(2)

519

Total

1,661

586

246

2,493

100

As at

December 31, 2023

Cash and cash equivalents

Net in-transits

(9)

Equity securities:

Canadian equity

United States equity

141

Other equity

112

Fixed income securities:

Government

172

Corporate

Other

Mutual funds

Other

(1)

Open-ended investments

measured at NAV

(1)

1,006

Common collective trusts

measured at NAV

(2)

586

Total

1,592

440

266

2,298

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.

Non-Pension Benefit Plans:

There are no assets set aside to pay for most of the Company’s

non-pension benefit plans. As is common

practice, post-retirement health benefits are paid from

general accounts as required. The exception to this

is the NMGC Retiree Medical Plan, which is fully funded.

Investments in Emera:

As at December 31, 2024 and 2023, 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

DB pension

plans

Non-pension

benefit plans

Expected employer contributions

2025

Expected benefit payments

2025

175

2026

179

2027

182

2028

184

2029

186

2030 – 2034

950

103

Assumptions:

The following table shows the assumptions that have been

used in accounting for DB pension and other

post-retirement benefit plans:

2024

2023

(weighted average assumptions)

DB pension

plans

Non-pension

benefit plans

DB pension

plans

Non-pension

benefit plans

Benefit obligation – December 31:

Discount rate - past service

5.07

4.91

4.89

Discount rate - future service

5.12

5.00

4.88

4.89

Rate of compensation increase

3.73

3.72

3.87

3.85

Health care trend

initial (next year)

6.53

6.04

ultimate

3.77

3.76

year ultimate reached

2044

2043

Benefit cost for year ended December 31:

Discount rate - past service

4.89

5.33

5.31

Discount rate - future service

4.88

4.89

5.34

5.32

Expected long-term return on plan assets

6.43

3.69

6.56

2.16

Rate of compensation increase

3.87

3.85

3.62

3.61

Health care trend

initial (current year)

6.04

5.40

ultimate

3.76

3.77

year ultimate reached

2043

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.

DC Pension Plan:

Emera also provides a DC pension plan for certain employees.

The Company’s contribution for the year

ended December 31, 2024 was $

million (2023 – $

million).

GOODWILL

The change in goodwill for the year ended December 31

was due to the following:

millions of dollars

2024

2023

Balance, January 1

5,871

6,012

Change in FX rate

504

(141)

Impairment charges

(214)

Classified as assets held for sale

(1)

(303)

Balance, December 31

5,858

5,871

(1) As at December 31, 2024, NMGC's assets

and liabilities were classified as held for

sale. For further details on the pending

transaction, refer to note 4.

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, 2024, related to TECO Energy,

Inc. (reporting

units with goodwill are TEC, PGS, and NMGC).

On August 5, 2024, Emera announced an agreement to sell

NMGC. As the expected transaction

proceeds on the pending sale will be less than the NMGC carrying

amount, the Company performed a

quantitative goodwill impairment assessment for the NMGC

reporting unit. It was determined that the

NMGC carrying amount exceeded the FV of the expected transaction

proceeds, and as a result, a non-

cash goodwill impairment charge of $

210

million, pre-tax, was recorded in Q3 2024, reducing the

NMGC

reporting unit goodwill balance to $

303

million as at December 31, 2024. This non-cash charge

included in “Impairment charges” on the Consolidated

Statements of Income.

In 2024, a qualitative assessment was performed for TEC

given the significant excess of FV over carrying

amounts calculated during the last quantitative test in

Q4 2023. Management concluded it was more likely

than not that the FV of this reporting unit exceeded

its carrying amount, including goodwill. As such, no

quantitative testing was required. Given the length of time

passed since the last quantitative impairment

test for the PGS reporting unit, Emera elected to bypass

a qualitative assessment and performed a

quantitative impairment assessment in Q4 2024 using a combination

of the income and market approach.

This assessment estimated that the FV of the PGS reporting

unit exceeded its carrying amount, including

goodwill, and as a result, no impairment charges were

recognized.

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

2024

Weighted

average

interest rate

2023

Weighted

average

interest rate

Florida Electric Utility

Advances on revolving credit facilities

915

4.77

277

5.68

Gas Utilities and Infrastructure

PGS – Advances on revolving credit facilities

199

5.36

6.36

NMGC – Advances on revolving credit facilities

5.52

6.46

Other Electric Utilities

GBPC – Advances on revolving credit facilities

7.20

5.54

Other

TECO Finance – Advances on revolving credit and term facilities

265

5.53

245

6.54

Emera – Bank indebtedness

Emera – Non-revolving term facilities

796

6.07

1,446

1,433

Adjustment

Classification as liabilities held for sale

(1)

(46)

Short-term debt

1,400

1,433

(1) On August 5, 2024, Emera announced an agreement

to sell NMGC. As at December 31, 2024,

NMGC's liabilities were classified

as held for sale. For further details on the pending

transaction, refer to note 4.

The Company’s total short-term unsecured revolving

and non-revolving credit facilities, outstanding

borrowings and available capacity as at December 31 were

as follows:

millions of dollars

Maturity

2024

2023

TEC – committed revolving credit facility

2028

1,151

401

TECO Finance – committed revolving credit facility

2028

576

529

PGS – revolving credit facility

2028

360

331

NMGC – revolving credit facility

2026

180

165

Emera – non-revolving term facility

2024

400

Emera – non-revolving term facility

2024

400

TEC – revolving facility

2024

265

TEC – revolving facility

2024

265

Other – committed revolving credit facilities

Various

Total

2,302

2,773

Less:

Advances under revolving credit and term facilities

1,400

1,433

Letters of credit issued within the credit facilities

Total

advances under available facilities

1,404

1,436

Available capacity under existing agreements

898

1,337

The weighted average interest rate on outstanding short-term

debt at December 31, 2024 was

5.05

per

cent (2023 –

5.95

per cent).

Recent Significant Financing Activity by Segment

Florida Electric Utilities

On April 1, 2024, TEC amended its $

800

million USD unsecured committed revolving credit facility

extend the maturity date from

December 17, 2026

December 1, 2028

. There were no other changes in

commercial terms from the prior agreement.

Other

On June 24, 2024, Emera repaid its $

400

million unsecured non-revolving term facility set to mature in

August 2024.

On June 17, 2024, Emera repaid $

200

million on the December 2024 unsecured non-revolving

term

facility, decreasing

the facility from $

400

million to $

200

million. In December 2024, Emera repaid the

200

million upon maturity.

On April 1, 2024, TECO Finance amended its $

400

million USD unsecured committed revolving credit

facility to extend the maturity date from

December 17, 2026

December 1, 2028

. There were no other

changes in commercial terms from the prior agreement.

OTHER CURRENT LIABILITIES

As at

December 31

millions of dollars

2024

2023

Accrued charges

189

172

Accrued interest on long-term debt

106

107

Pension and post-retirement liabilities (note 22)

Sales and other taxes payable

Income tax payable

Other

153

112

489

427

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

2024

2023

Maturity

2024

2023

Florida Electric Utility

Senior unsecured notes

4.36%

4.61%

2029 - 2051

5,720

5,654

Canadian Electric Utilities

NSPI – Commercial paper

(2)

Variable

2029

177

721

NSPI – Senior unsecured notes

5.12%

5.13%

2025 - 2097

3,184

3,165

3,361

3,886

Gas Utilities and Infrastructure

PGS – Senior unsecured notes

5.63%

2028 - 2053

1,331

1,223

NMGC – Senior unsecured notes

3.78%

2026 - 2051

698

642

NMGC – Unsecured loan notes

N/A

Variable

2024

NMGI – Senior unsecured notes

N/A

3.64%

2024

198

EBP – Secured loan notes

Variable

2028

250

246

2,279

2,339

Other Electric Utilities

Unsecured loan notes

4.06%

4.78%

2025 - 2028

143

121

Unsecured loan notes

Variable

2025 - 2027

104

Secured senior notes and debentures

(3)

2.38%

3.06%

2026 - 2040

169

197

416

422

Other

Unsecured loan notes

Variable

2026 - 2029

992

465

Senior unsecured notes

3.99%

3.65%

2026 - 2046

3,525

3,637

Senior unsecured notes

4.84%

2030

500

Fixed to floating subordinated notes

(4)

6.75%

2076

1,727

1,587

Junior subordinated notes

7.63%

0.00%

2054

720

7,464

6,189

Adjustments

Debt issuance costs

(137)

(125)

Classification as liabilities held for sale

(5)

(696)

Amount due within one year

(6)

(234)

(676)

(1,067)

(801)

Long-Term Debt

18,173

17,689

(1) Weighted average interest rate of fixed rate long-term debt.

(2) Discount notes are backed by a revolving

credit facility which matures in 2029.

(3) Notes are issued and payable in either USD

or BBD.

(4) In 2024, the Company recognized $

110

million in interest expense (2023 – $

109

million) related to its fixed to floating

subordinated notes.

(5) On August 5, 2024, Emera announced an

agreement to sell NMGC. As at December

31, 2024, NMGC's liabilities were

classified as held for sale.

For further details on the pending transaction,

refer to note 4.

(6) Excludes NMGC amounts which are classified

as current liabilities associated with assets held

for sale.

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

2024

2023

Emera – committed revolving credit facility

(1)

June 2029

1,300

900

NSPI – revolving credit facility

(1)

June 2029

800

Emera – Unsecured non-revolving credit facility

February 2026

200

400

TEC – Unsecured committed revolving credit facility

December 2026

657

NSPI – non-revolving credit facility

July 2024

400

NMGC – Unsecured non-revolving credit facility

March 2024

ECI – revolving credit facilities

October 2024

Total

2,300

3,197

Less:

Borrowings under credit facilities

1,169

1,884

Letters of credit issued inside credit facilities

Use of available facilities

1,181

1,890

Available capacity under existing agreements

1,119

1,307

(1) Advances on the revolving credit facility can be

made by way of overdraft on accounts up to

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, 2024

Emera

Syndicated credit facilities

Debt to capital ratio

Less than or equal to

0.70

to 1

0.55

: 1

Recent Significant Financing Activity by Segment

Florida Electric Utility

On July 12, 2024, TEC repaid a $

300

million USD note upon maturity.

This note was repaid with

proceeds from commercial paper.

On January 30, 2024, TEC issued $

500

million USD of senior unsecured bonds that bear interest

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

-year credit facility.

Canadian Electric Utilities

On June 24, 2024, NSPI amended its unsecured non-revolving

credit facility to extend the maturity date

from

July 15, 2024

June 24, 2025

and reduce the facility from $

400

million to $

300

million. On

December 16, 2024, NSPI repaid the $

300

million unsecured non-revolving credit facility.

On June 24, 2024, NSPI amended its unsecured committed

revolving credit facility to extend the maturity

date from

December 16, 2027

June 24, 2029

. There were no other material changes in commercial

terms from the prior agreement.

On June 13, 2024, NSPI entered a non-revolving credit

facility to finance the Battery Energy Storage

Project. NSPI can request funds under the facility quarterly

for amounts related to incurred project costs

up to the total commitment of the lessor of $

120

million and

45.06

per cent of the total eligible project

costs over the term of the agreement. The facility will be

available until

months after completion of the

project, not to exceed

May 21, 2027

, and matures

years following the end of the period. As at

December 31, 2024, NSPI had utilized $

million from the facility,

which bears interest at

2.51

per cent.

Gas Utilities and Infrastructure

On December 10, 2024, Brunswick Pipeline amended

its non-revolving loan agreement. The maturity

date was extended to December 2028 and now includes

annual principal repayments.

On July 30, 2024, New Mexico Gas Intermediate, Inc. repaid

its $

150

million USD fixed rate notes upon

maturity.

Other Electric Utilities

On May 2, 2024, BLPC amended its $

million Barbadian dollar ($

million USD) loan facility to extend

the maturity date from

February 19, 2025

July 19, 2028

. There were no other material changes in

commercial terms from the prior agreement.

Other

On June 24, 2024, Emera amended its unsecured committed

revolving credit facility increasing the facility

from $

900

million to $

1,300

million. Emera also extended the maturity date from

June 24, 2027

June

24, 2029

. There were no other material changes in commercial terms

from the prior agreement.

On June 15, 2024, Emera Finance repaid its $

300

million USD senior notes upon maturity.

On June 18, 2024, EUSHI Finance, Inc., completed an issuance

of $

500

million USD fixed-to-fixed reset

rate junior subordinated notes. The notes initially bear

interest at a rate of

7.625

per cent, and will reset

on December 15, 2029, and every

five years

thereafter, to a rate per annum

equal to the five-year U.S.

treasury rate plus

3.136

per cent. The notes mature on

December 15, 2054

. EUSHI Finance, Inc., at its

option, may redeem the notes, in whole or in part,

90 days

prior to the first interest reset date, and any

semi-annual interest payment date thereafter,

at a redemption price equal to the principal amount.

On February 16, 2024, Emera amended its $

400

million unsecured non-revolving facility to extend the

maturity date from

February 19, 2024

February 19, 2025

. There were no other changes in commercial

terms from the prior agreement. On July 19, 2024, Emera reduced

the amount of the facility from $

400

million to $

200

million. On February 20, 2025, Emera extended the agreement

for an additional year to

February 2026 with no other changes in terms. This facility

was classified as long-term debt at December

31, 2024.

Long-Term Debt Maturities

As at December 31, 2024, 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

2025

2026

2027

2028

2029

Thereafter

Total

Florida Electric Utility

720

5,000

5,720

Canadian Electric Utilities

125

217

2,979

3,361

Gas Utilities and

Infrastructure

132

535

1,519

2,279

Other Electric Utilities

101

116

416

Other

3,006

792

3,666

7,464

Total

234

3,279

120

651

1,764

13,192

19,240

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

2024

2023

Balance, January 1

192

174

Additions

Accretion included in depreciation expense

Change in FX rate

(1)

Revisions in estimated cash flows

Accretion deferred to regulatory asset (included in PP&E)

Classified as assets held for sale

(1)

Liabilities settled

(2)

(8)

Balance, December 31

217

192

(1) As at December 31, 2024, NMGC's assets

and liabilities were classified as held for

sale. For further details on the pending

transaction, refer to note 4.

COMMITMENTS AND CONTINGENCIES

Commitments

As at December 31, 2024, 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

2025

2026

2027

2028

2029

Thereafter

Total

Purchased power

(1)

307

277

368

369

4,487

6,176

Transportation

(2)(3)

742

545

544

454

412

3,228

5,925

Capital projects

604

287

915

Fuel, gas supply and storage

(4)

591

711

Other

160

264

717

2,404

1,298

1,037

886

840

7,979

14,444

As detailed below, contractual obligations at December 31, 2024 includes

those related to NMGC. On completion of

the sale of

NMGC, all remaining future contractual obligations will

be transferred to the buyer. For further details on the pending

transaction, refer

to note 4.

(1) Annual requirement to purchase electricity production

from IPPs or other utilities over varying contract lengths.

(2) Includes $

million related to NMGC (2025: $

million, 2026: $

million, 2027: $

million, 2028: $

million, 2029: $

million).

(3) Purchasing commitments for transportation of

fuel and transportation capacity on various pipelines.

Includes a commitment of

135

million related to a gas transportation contract between

PGS and SeaCoast through 2040.

(4) Includes $

177

million related to NMGC (2025: $

109

million, 2026: $

million, 2027: $

million, 2028: $

million)

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 November

2024, the UARB approved the collection of up to

197

million from NSPI for the recovery of Maritime Link

costs in 2025. The timing and amounts payable

to NSPML for the remainder of the

-year commitment period are subject to UARB

approval.

Emera has committed to obtain certain transmission rights

in New Brunswick during summer periods

(April through October, inclusive)

for NLH's use, if requested, effective August 15,

2021 and continuing for

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, 2024, the aggregate financial

liability of the Florida utilities is estimated to be

million ($

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,

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 have

a material adverse effect on Emera or its

subsidiaries, or their business operations, liquidity or access

to or cost of capital, financial position,

prospects, and/or results of operations (herein considered a “Material

Adverse Effect”). Risks associated

with derivative instruments and FV measurements are

discussed in note 16 and note 17.

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

risks are appropriately identified, assessed, monitored

and subject to appropriate controls. The Board of

Directors has a Risk and Sustainability Committee (‘RSC”)

to assist 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.

Regulatory and Political Risk

The Company’s rate-regulated subsidiaries and certain

investments are subject to complex legislative

and regulatory frameworks that cover material aspects

of their businesses. These frameworks influence

key factors such as rates and cost structures, revenue requirements,

allowed ROEs, capital structures,

rate base and capital investments, and the recovery

of purchased electricity and fuel costs and other

costs. Regulators also review the prudency of costs and make

other decisions that can impact customer

rates and the reliability of service. Emera’s cost

-of-service utilities must obtain regulatory approvals for

material aspects of their businesses, including changing

or adding rates and/or riders. Such approvals

often require public hearing proceedings involving numerous

stakeholders, and there is no assurance in

the outcomes or impact of any regulatory process or decision.

If Emera is unable to recover in a timely manner a material

amount of costs or a return on invested capital

through regulatory mechanisms or otherwise, is disallowed

the recovery of certain costs, is subject to

regulatory penalties, is not permitted to make certain capital

investments, or is not permitted to invest in or

divest certain utility assets, it could result in a Material Adverse

Effect, including valuation impairments.

Regulatory lag, the time between the incurrence of costs

and the granting of the rates to recover those

costs by regulators, may also result in a Material Adverse

Effect.

Aspects of the acquisition, ownership, operations, siting, planning,

construction, and decommissioning of

electric generation, storage, transmission and distribution facilities

and natural gas transportation and

distribution systems are also subject to regulatory processes

and approvals of regulators, government

departments and agencies, and other third parties. The failure

to obtain, maintain, and renew such

approvals or significant changes in the terms and conditions

thereof could have a Material Adverse Effect.

The regulatory framework, process and regulatory decisions

may also be adversely affected by changes

in government, shifts in government or public policy,

legislative changes, regulatory decisions, geopolitical

changes, changes in the economic environment, or other

factors. Government interference in the

regulatory process or regulatory decisions can undermine regulatory

stability, predictability,

and

independence. Any such changes could have a Material

Adverse Effect.

Foreign Exchange Risk

The Company is exposed to foreign currency exchange rate changes.

Emera operates internationally,

with a significant 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.

Emera manages currency risks through matching US denominated

debt to finance its US 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 Markets

Risk

Liquidity risk relates to Emera’s ability to ensure sufficient

funds are available to meet its financial

obligations. 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

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.

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 have

a Material Adverse Effect. 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.

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 Markets

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.

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.

Regulated Utilities:

The Company’s utility fuel supply is exposed to

broader global market 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, tariffs,

trade sanctions or embargos.

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, any of which could result in a Material Adverse

Effect.

Emera Energy Marketing and Trading:

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, imposition of tariffs 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.

Income Tax Risk

The computation of the Company’s provision for

income taxes is impacted by changes in tax legislation in

Canada, the US and the Caribbean and any such changes

could have a Material Adverse Effect. 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.

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 were not included within

the Consolidated Balance Sheets as at

December 31, 2024

TECO Holdings, Inc. (“TECO Holdings”) has a guarantee

in connection with SeaCoast’s performance

obligations under a gas transportation precedent agreement.

The guarantee is for a maximum potential

amount of $

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. The counterparty has the right to require

TECO Holdings to provide replacement credit

support either in the form of a substitute guarantee from

an affiliate with an investment grade credit

rating

or a letter of credit or cash deposit of $

million USD.

TECO Holdings has 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 $

million USD if SeaCoast fails to pay or perform under the

firm service agreement. The

counterparty has the right to require TECO Holdings to provide

replacement credit support in the form of

either a substitute guarantee from an affiliate

with an investment grade credit rating or a letter of credit

cash deposit of $

million USD.

Emera has a guarantee of $

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 guarantees on behalf of its subsidiary,

NS Power Energy Marketing Incorporated, in the amount

of $

104

million USD (2023 – $

104

million USD) with terms of varying lengths.

The Company has standby letters of credit and surety

bonds in the amount of $

105

million USD

(December 31, 2023 – $

103

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, 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 2025. The amount committed

as at December 31, 2024 was $

million (December 31, 2023 – $

million).

Emera has provided an indemnity to a counterparty in

relation to certain future tax amounts that could

arise from specific future changes in Canadian federal

law, subject to certain conditions

and limitations.

No such changes in law have been proposed at this time.

A reasonable estimate of the potential amount

of future payments that could result from future claims

under this indemnity cannot be calculated, but the

risk of having to make any significant payments under

this indemnity is considered to be remote.

Collaborative Arrangements

For the years ended December 31, 2024 and 2023, 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 2024, NSPI recognized

million net expense (2023 – $

million) in “Regulated fuel for generation and purchased

power” and $

million (2023 – $

million) in

“OM&G” on the Consolidated Statements of Income.

CUMULATIVE PREFERRED STOCK

Authorized:

Unlimited number of First Preferred shares, issuable in

series.

Unlimited number of Second Preferred shares, issuable in

series.

December 31, 2024

December 31, 2023

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

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)

Annual

Dividend

Rate

(%)

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

2.182

0.5456

1.84

August 15, 2025

25.00

Series B

Series C

6.434

1.6085

2.65

August 15, 2028

25.00

Series D

Series F

(5)(6)

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

6.324

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

(7)

4.500

1.1250

25.00

Series L

(8)

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,

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 January 8, 2025, Emera announced

that it would not redeem the outstanding Preferred

Shares, Series F on February 15, 2025.

During

the conversion period between January 15,

2025 and January 31,2025, subject to

certain conditions, the holders of Series

F shares had the

right, at their option, to convert all or

any of their Series F shares, on a one-for-one

basis into Cumulative Floating Rate

First Preferred Shares,

Series G on February 15, 2025. On February

6, 2025, Emera announced after having taken

into account all conversion notices received

from

holders, no Series F were converted

into Series G shares.

(6) On January 16, 2025, Emera announced

that the annual fixed dividend per share

for Series F shares will be reset from $

1.0505

to $

1.4372

for the five-year period from and including

February 15, 2025.

(7) First Preferred Shares, Series E are redeemable

at $

25.00

per share.

(8) 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.

NON-CONTROLLING INTEREST IN SUBSIDIARIES

As at

December 31

millions of dollars

2024

2023

Preferred shares of GBPC

Preferred shares of GBPC:

Authorized:

10,000

non-voting cumulative redeemable variable perpetual

preferred shares.

2024

2023

Issued and outstanding:

number of

millions of

dollars

number of

millions of

dollars

Outstanding as at December 31

10,000

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.

SUPPLEMENTARY

INFORMATION TO CONSOLIDATED

STATEMENTS

CASH FLOWS

For the

Year ended December 31

millions of dollars

2024

2023

Changes in non-cash working capital:

Inventory

(31)

Receivables and other current assets

(1)

(154)

653

Accounts payable

536

(538)

Other current liabilities

(2)

(179)

Total

non-cash working capital

452

(95)

(1) The year ended December 31, 2023, includes $

162

million related to the January 2023 NMGC gas

hedges. Offsetting change in

regulatory liabilities is included in operating cash

flow before working capital resulting in no

impact to net cash provided by operating

activities.

(2) The year ended December 31, 2023, includes ($

166

) million related to the decreased accrual for

the Nova Scotia Cap-

and-Trade emissions compliance charges. 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

2024

2023

Supplemental disclosure of cash paid:

Interest

989

930

Income taxes

Supplemental disclosure of non-cash activities:

Accrued proceeds from disposal of investment subject to significant influence

Common share dividends reinvested

291

271

Reclassification of short-term debt to long-term debt

657

Decrease in accrued capital expenditures

(19)

Supplemental disclosure of operating activities:

Net change in short-term regulatory assets and liabilities

(118)

123

STOCK-BASED COMPENSATION

ECSPP and Common Shareholders DRIP

Eligible employees can participate in the ECSPP. As of December 31, 2024, the plan allows employees

to make cash contributions of a minimum of $25 per month 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 for where prohibited by law.

The

maximum aggregate number of Emera common shares

reserved for issuance under this plan is

million

common shares. As at December 31, 2024, Emera was

in compliance with this requirement.

Compensation cost for shares issued under the ECSPP for the

year ended December 31, 2024 was $

million (2023 – $

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 with the reinvestment of cash dividends. The discount was 2 per cent in 2024.

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, 2024, 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

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:

2024

2023

Weighted average FV per option

4.66

6.32

Expected term

(1)

years

Risk-free interest rate

(2)

3.56

3.53

Expected dividend yield

(3)

6.11

5.05

Expected volatility

(4)

20.67

20.07

(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

2024:

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, 2023

3,095,604

51.20

1,253,255

5.17

Granted

792,600

46.97

792,600

4.66

Exercised

(78,839)

39.86

N/A

Forfeited

(13,325)

56.14

N/A

Vested

N/A

(438,365)

4.58

Options outstanding December 31, 2024

3,796,040

50.53

1,607,490

5.08

Options exercisable December 31, 2024

(2)(3)

2,188,550

50.07

(1) As at December 31, 2024, there was $

million of unrecognized compensation related to

stock options not yet vested which is

expected to be recognized over a weighted

average period of approximately

years (2023 – $

million,

years).

(2) As at December 31, 2024, the weighted

average remaining term of vested options was

years with an aggregate intrinsic value of

million (2023 –

years, $

million).

(3) As at December 31, 2024, the FV of options

that vested in the year was $

million (2023 – $

million).

Compensation cost recognized for stock options for the year

ended December 31, 2024 was $

million

(2023 – $

million), which was included in “OM&G” on the Consolidated

Statements of Income.

As at December 31, 2024, cash received from option exercises

was $

million (2023 – $

million). The

total intrinsic value of options exercised for the year ended

December 31, 2024 was $

million (2023 – $

million). The range of exercise prices for the options outstanding

as at December 31, 2024 was $

39.93

60.03

(2023 – $

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. Unless otherwise determined by the

Management Resources and Compensation Committee (“MRCC”), 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 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, 2024

is presented in the following table:

Employee

DSU

Weighted

Average

Grant Date

Director

DSU

Weighted

Average

Grant Date

Outstanding as at December 31, 2023

712,963

42.29

729,058

46.24

Granted including DRIP

86,417

45.20

134,795

48.98

Exercised

(10,292)

38.77

(34,997)

36.04

Outstanding and exercisable as at December 31, 2024

789,088

42.65

828,856

47.12

Compensation cost recognized for employee and director

DSU’s for the year ended December 31, 2024

was $

million (2023 – $

million cost recovery). Tax

benefits related to this compensation cost for share

units realized for the year ended December 31, 2024

were $

million (2023 – $

million tax expense). The

aggregate intrinsic value of the outstanding shares for the year

ended December 31, 2024 for employees

was $

million (2023 – $

million). The aggregate intrinsic value of the outstanding

shares for the year

ended December 31, 2024 for directors was $

million (2023 – $

million). Cash payments made

during the year ended December 31, 2024 associated with

the DSU plan were $

million (2023 – $

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. Unless otherwise determined by the MRCC, 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, 2024 is presented

in the following table:

Employee PSU

Weighted Average

Grant Date FV

Aggregate intrinsic value

Outstanding as at December 31, 2023

743,365

55.13

Granted including DRIP

354,793

48.69

Exercised

(253,136)

54.66

Forfeited

(12,929)

52.53

Outstanding as at December 31, 2024

832,093

52.57

Compensation cost recognized for the PSU plan for the

year ended December 31, 2024 was $

million

(2023 – $

million). Tax

benefits related to this compensation cost for share

units realized for the year

ended December 31, 2024 were $

million (2023 – $

million). Cash payments made during the year

ended December 31, 2024 associated with the PSU plan were

million (2023 – $

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. Unless otherwise determined by the MRCC, 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, 2024 is presented

in the following table:

Employee RSU

Weighted Average

Grant Date FV

Aggregate intrinsic value

Outstanding as at December 31, 2023

562,641

55.01

Granted including DRIP

287,976

48.65

Exercised

(183,241)

54.66

Forfeited

(14,228)

52.45

Outstanding as at December 31, 2024

653,148

52.36

Compensation cost recognized for the RSU plan for the

year ended December 31, 2024 was $

million

(2023 – $

million). Tax

benefits related to this compensation cost for share

units realized for the year

ended December 31, 2024 were $

million (2023 – $

million). Cash payments made during the year

ended December 31, 2024 associated with the RSU plan were

million (2023– $

million).

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, NLH 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, 2024

December 31, 2023

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)

475

489

SUBSEQUENT EVENTS

These financial statements and notes reflect the Company’s

evaluation of events occurring subsequent to

the balance sheet date through February 21, 2025, 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 21, 2025, with respect to the consolidated balance sheets of Emera Incorporated as at December 31, 2024 and 2023, 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 21, 2025

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;<br>
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a<br>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,<br>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<br>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<br>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<br>prepared;
---	---
b)	Designed such internal control over financial reporting, or caused such internal control over financial<br>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<br>principles;
---	---
c)	Evaluated the effectiveness of the issuer’s disclosure controls and procedures and presented in this<br>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<br>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<br>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<br>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<br>the issuer’s internal control over financial reporting.
---	---
Date: February 21, 2025
---
/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;<br>
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a<br>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,<br>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<br>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<br>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<br>prepared;
---	---
b)	Designed such internal control over financial reporting, or caused such internal control over financial<br>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<br>principles;
---	---
c)	Evaluated the effectiveness of the issuer’s disclosure controls and procedures and presented in this<br>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<br>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<br>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<br>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<br>the issuer’s internal control over financial reporting.
---	---
Date: February 21, 2025
---
/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, 2024 (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<br>Act of 1934; and
(ii)	the information contained in the Report fairly presents, in all material respects, the financial condition and<br>results of operations of the Company.
---	---
Date: February 21, 2025
---
/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

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<br>Act of 1934; and
(ii)	the information contained in the Report fairly presents, in all material respects, the financial condition and<br>results of operations of the Company.
---	---
Date: February 21, 2025
---
/s/ Gregory W. Blunden
Gregory W. Blunden
Chief Financial Officer